EDGAR 10-K Filing

Company CIK: 1273441
Filing Year: 2024
Filename: 1273441_10-K_2024_0001273441-24-000006.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 oil and gas exploration and production with assets currently in Colombia and Ecuador. Our Colombian properties represented 94% of our proved reserves NAR at December 31, 2023. For the year ended December 31, 2023, 97% (2022 - 100%) of our revenue 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.
On May 5, 2023, the Company completed a 1-for-10 reverse stock split of the Company’s Common Stock. As a result of the reverse stock split, every ten of the Company’s issued shares of Common Stock were automatically combined into one issued share of Common Stock, without any change to the par value per share. All share and per share numbers in this Annual Report on Form 10-K have been adjusted to reflect the reverse stock split.
2023 Operational Highlights
During the year ended December 31, 2023, we drilled 25 wells (17 development, and eight water injectors), all in Colombia and incurred capital expenditures of $218.9 million, the majority of which were incurred in Colombia.
We drilled eight development and five water injector wells in Midas Block and nine development and three water injector wells in Chaza Block. As at December 31, 2023, of the 17 development wells drilled during the year, two were in-progress and the remainder were producing.
2024 Outlook
Our Colombian development operation is expected to represent 93% of our production and approximately 60% - 70% of our 2024 capital budget, with the remainder allocated to exploration activities.
The table below shows the break-down of our 2024 capital program:
Number of Wells
(Gross) Number of Wells
(Net) 2024 Capital Budget
($ million)
Development - Colombia 13 - 17
12 - 16
130 - 140
Exploration - Colombia and Ecuador 6 - 9
6 - 9
80 - 100
19 - 26
18 - 25
210 - 240
Our base capital program for 2024 is $210 million to $240 million for exploration and development activities. Based on the mid-point of the 2024 guidance, the capital budget is forecasted to be approximately 60% - 70% directed to development and 40% - 30% to exploration activities. Approximately 20% of the development activities included in the 2024 capital program are expected to be directed to facilities to support future production growth and enhance recovery factors.
We expect our 2024 capital program to be fully funded by cash flows from operations. Funding this program from cash flows from operations relies in part on Brent oil prices being $70 per bbl for 2024.
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 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 a 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, 2023, excluding blocks subject to relinquishment, we had interests in 22 blocks in Colombia, three blocks in Ecuador, and are the operator of 24 of these blocks.
Exploration Blocks & Commitments
The following table provides a summary of our exploration commitments for certain blocks as of December 31, 2023:
Basin Block Current Phase Remaining Commitments, Current Phase
Colombia
Putumayo Alea
1848-A N/A** evaluation program
Putumayo PUT-1 2* two 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-31 1* 201.9 km 2D seismic, one exploration well
Putumayo NBM N/A** two exploration wells
Llanos LLA-1 1* 98 km2 3D seismic one exploration well
Llanos LLA-22 1 & 2* 85 km2 3D seismic, one exploration well (45% working interest)
Llanos LLA-70 1* 163 km2 3D seismic, one exploration well
Llanos LLA-85 1 one exploration well
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 20 km 2D seismic, 238 km2 3D seismic, five exploration wells
Oriente Chanangue 1 four exploration wells
Oriente Iguana 1 two exploration wells
* As of December 31, 2023, exploration has been suspended due to licensing restrictions, security issues or social reasons.
** As of December 31, 2023, exploration commitments in the exploration block are not subject to phasing.
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 fixed rates for existing production of 32% and 20%, respectively. New discoveries and incremental production are subject to sliding scale royalties duly approved by the ANH. In addition to the sliding scale royalty, there are additional x-factor economic rights of 1%
for Llanos-22, Putumayo-4, Putumayo-7, Putumayo-21 and VMM-24; 2% for Llanos-85; 3% for VMM-2, 5% for Putumayo-1; 12% for Putumayo-31; 31% for Llanos-1 and Llanos-70.
For gas fields, the royalty is based 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 2,280 to 3,420 MMcf of gas per day. For gross production in excess of 3,420 MMcf of gas per day the royalty rate is fixed at 20%.
Additional high price rights (“HPR”) are applicable to exploration and production contracts signed under the 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 the Q factor, which is calculated as follows:
Q factor = (WTI price - Base Price (1))/WTI Price * S(2)
(1) Base Price is determined annually by the ANH, based on a formula defined in the contract. For 2023 and 2022, the base price was set as follows:
Year Ended December 31,
Quality (Oil API) Base Price ($/bbl)
< 10 o
Nil Nil
10o to 15o
64.54 58.67
15o to 22o
45.18 41.07
22o to 29o
43.56 39.60
> 29o
41.93 38.12
At December 31, 2023, 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 January 2023, Llanos-22 reached accumulated production of 5 MMbbls which triggered its HPR.
(2) S percentage of HPR participation is 30% flat for Chaza and Midas Blocks. For Llanos-22, the percentage is variable compared to WTI price as per below:
S percentage
Base Price ≤ WTI < 2x Base Price 30%
2x Base Price ≤ WTI < 3x Base Price 35%
3x Base Price ≤ WTI < 4x Base Price 40%
4x Base Price ≤ WTI < 5x Base Price 45%
5x Base Price ≤ WTI 50%
In addition to these government royalties and rights, 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 a 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 and rights. 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, 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.
We currently hold Participation Sharing Contracts (“PSC”) for the three Blocks (Charapa, Chanangue and Iguana) in the Oriente Basin in Ecuador. Unlike traditional PSCs, these contracts do not include cost oil or royalties. Instead, the entire production is placed into a profit-sharing pool that is split between the Company and the government based on a percentage derived from a biddable price component and a production component. The biddable price component is a sliding scale that is based on the Oriente oil price ranging from $30 per bbl to $120 per bbl, with the Company’s production share varying between 87.5% and 40%, respectively. The Company’s share in production would only drop below 50% if the Oriente oil prices exceed $100 per bbl. The production component is a tier-based mechanic increasing from 0% to 6% based on the PSC’s daily production. For the year ended December 31, 2023, the share of production retained by the government of Ecuador was recorded as royalties in-kind.
Administrative Facilities
Our principal executive office is located in Calgary, Alberta, Canada. The Calgary office lease will expire on November 30, 2028. Office leases in Colombia and Ecuador will expire on February 28, 2026, and June 30, 2025, respectively.
Estimated Reserves
Our 2023 reserves were independently prepared by McDaniel & Associates (“McDaniel”). McDaniel 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.
All of our reserves are evaluated by an independent reservoir engineering firm, at least annually. We have developed internal controls over estimation and evaluation of reserves. Our internal controls over reserve estimates include an independent internal review of assumptions used for 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 to 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 estimates 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 by 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, 2023, were based on both the greater percentage of recovery of the hydrocarbons in place than assumed for proved reserves, as well as the 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, 2023, 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 located in Colombia and Ecuador which were 100% oil as of December 31, 2023:
Oil
Reserves Category (Mbbl)
Proved
Total proved developed reserves 39,599
Total proved undeveloped reserves 34,697
Total proved reserves (2)
74,296
Probable (1)
Total probable developed reserves 12,139
Total probable undeveloped reserves 34,109
Total probable reserves (3)
46,248
Possible (1)
Total possible developed reserves 11,362
Total possible undeveloped reserves (4)
37,144
Total possible reserves 48,506
(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.
(2) Includes proved developed oil reserves of 0.7 MMbbl and proved undeveloped oil reserves of 4.0 MMbbl related to Ecuador.
(3) Includes probable developed oil reserves of 0.1 MMbbl and probable undeveloped oil reserves of 5.9 MMbbl related to Ecuador.
(4) Includes possible developed oil reserves of 0.2 MMbbl and possible undeveloped oil reserves of 6.9 MMbbl related to Ecuador.
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 based on unweighted arithmetic average ICE Brent price as of the first-day-of-the-month for the 12-month period ended December 31, 2023:
Oil ($/bbl) - Colombia $ 69.91
Oil ($/bbl) - Ecuador $ 77.44
ICE Brent - average of the first day of each month price for the 12-month period $ 82.51
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
As at December 31, 2023, we had total proved undeveloped reserves NAR of 34.7 MMBOE (December 31, 2022 - 25.0 MMBOE), which were 89% in Colombia, with the remainder in Ecuador (December 31, 2022 - 92% in Colombia with the remainder in Ecuador). Approximately 33%, 20%, and 19% for a total of 72% of proved undeveloped reserves are located in our Acordionero, Costayaco fields and Suroriente Block, respectively, in Colombia. None of our proved undeveloped reserves at December 31, 2023, 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, 2023 are shown in the table below:
Total Company - Oil Equivalent
(MMBOE)
Balance, December 31, 2022
25.0
Converted to proved producing (5.5)
Technical revisions 1.0
Extensions and discoveries 14.2
Balance, December 31, 2023
34.7
Changes in proved undeveloped reserves during the year ended December 31, 2023, shown in the table above primarily resulted from the following significant factors:
Converted to Proved Producing. In 2023, we converted 5.5 MMBOE, or 22% of 2022 proved undeveloped reserves to developed status (1.7 MMBOE in the Acordionero, 2.3 MMBOE in the Costayaco and 1.5 MMBOE in the Moqueta fields). In 2023, the conversion of proved producing volumes was a result of capital expenditures of $67.3 million in Colombia associated with drilling eight wells in Midas Block and nine in Chaza Block.
Technical and Economic Revisions. During the year ended December 31, 2023, there were additions of 1.0 MMBOE proved undeveloped reserves with 0.3 MMBOE added in Colombia primarily due to continued waterflood performance in the Costayaco and Acordionero fields and 0.7 MMBOE added in Ecuador Blocks due to production type curve changes in the Chanangue and Charapa Blocks.
Extensions and Discoveries. We added 14.2 MMBOE to proved undeveloped reserves during the year ended December 31, 2023, of which 13.0 MMBOE were in Colombia and 1.2 MMBOE in Ecuador. In Colombia, we had extensions of 1.2 MMBOE, 3.5 MMBOE, 2.0 MMBOE and 6.3 MMBOE in the Acordionero, Costayaco, Moqueta fields and the Suroriente Block, respectively. In Ecuador, we had a discovery of 1.2 MMBOE in the Chanangue Block due to successful testing results from a newly productive zone in the existing well.
Production, Revenue and Price History
Certain information concerning production, prices, revenues, and operating expenses for the years ended December 31, 2023, 2022, and 2021 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 over NAR oil production from our major fields (Acordionero, Costayaco, Moqueta, Cohembi) and total for all our properties for the three years ended December 31, 2023, 2022, and 2021, respectively:
Acordionero (1)
Costayaco (1)
Moqueta (1)
Cohembi (1)
Total for all
properties (2)
Year Ended December 31, 2023
Oil production NAR bbl 4,924,313 1,690,718 666,827 1,069,585 9,526,270
Average sales price of oil per bbl $ 67.82 $ 66.41 $ 66.57 $ 65.23 $ 66.86
Operating expenses of oil per bbl (3)
$ 13.68 $ 17.22 $ 24.34 $ 32.02 $ 21.14
Year Ended December 31, 2022
Oil production NAR bbl 4,491,574 1,621,073 542,796 1,105,451 8,692,689
Average sales price of oil per bbl $ 83.65 $ 81.85 $ 80.38 $ 80.87 $ 81.84
Operating expenses of oil per bbl (3)
$ 15.07 $ 18.30 $ 24.10 $ 25.10 $ 19.85
Year Ended December 31, 2021
Oil production NAR bbl 4,183,773 1,435,434 605,926 797,196 7,879,794
Average sales price of oil per bbl $ 62.17 $ 59.93 $ 58.80 $ 55.01 $ 60.12
Operating expenses of oil per bbl (3)(4)
$ 13.35 $ 20.12 $ 24.91 $ 20.14 $ 18.70
(1) 100% of product sales were oil
(2) Includes de minimis natural gas production from non-core properties from Colombia of 9,682 Mcf (1,614 boe) and 119,046 Mcf (19,841 boe) for each of the years ended December 31, 2022 and 2021, respectively. There was no gas production for the year ended December 31, 2023
(3) Operating expenses include operating and transportation expenses
(4) Covid-19 costs per bbl, which were presented separately for the year ended December 31, 2021, were re-classified back to operating and transportation costs to conform with December 31, 2023 and 2022 presentation
We prepared the estimate of a 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, 2023, 2022, or 2021. 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.
2023 2022 2021
Gross and Net Gross and Net Gross and Net
Colombia
Exploration
Productive - 2 -
Dry - 2 -
Development
Productive 15 20 18
In-progress 2 - 1
Service
Water injectors 8 8 3
25 32 22
Ecuador
Exploration
Productive - 2 -
- 2 -
Total 25 34 22
Well Statistics
The following table sets forth our productive wells as of December 31, 2023:
Oil Wells
Gross Net
Colombia (1)
303 269
Ecuador 2 2
305 271
(1) Includes 80 gross and 75 net water injector wells and 104 gross and 102 net wells with multiple completions.
We commenced the execution of our 2024 capital program as planned, and as of February 15, 2024, have drilled three development wells in the Chaza Block and six in the Midas Block.
Developed and Undeveloped Acreage
At December 31, 2023, our acreage was located 91% in Colombia and 9% in Ecuador. The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2023:
Developed Undeveloped (2)
Total
Gross Net Gross Net Gross Net
Colombia (1)
330,025 239,692 1,072,874 1,063,331 1,402,899 1,303,023
Ecuador (3)
- - 138,239 138,239 138,239 138,239
Total 330,025 239,692 1,211,113 1,201,570 1,541,138 1,441,262
(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, 2023
(2) As of December 31, 2023, the exploration phase for 0.5 million gross and net undeveloped acres expires within the next three years, with
an option to extend the exploration phase for 50% of the expired area
(3) During the year ended December 31, 2023, we started production in Ecuador which is executed under the evaluation permits of exploration phase, therefore the entire acreage for Ecuador is reported as undeveloped
Marketing and Major Customers
Colombia represents approximately 97% of our production with oil reserves and production 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 52% of total Company production for the year ended December 31, 2023. The Putumayo production is approximately 27° API for Chaza Block and 18° API for Suroriente Block, representing 25% and 13%, respectively, of the total Company production for the year ended December 31, 2023.
We have entered into numerous sales agreements for our production from MMV and the Putumayo Basin with domestic customers selling crude oil for export purposes. These agreements are subject to renegotiation terms between twelve and thirty 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 and since October 2022 does include volumes relating to HPR royalties.
All of our Putumayo production is sold at the wellhead. The oil is picked up by the customer at the 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. In order to capture the best market value and optimize our netback, our marketing strategy is to sell a blend “Chaza Heavy” of the entire Putumayo production with an average quality of 25° API. Production from the Acordionero field in MMV is trucked and sold at various terminals or pipeline inlets and various distances from the Acordionero field, depending on our marketing strategy to optimize the value. Production from MMV minor fields is sold at wellhead.
In 2023, all of our MMV and Putumayo production was sold to one domestic marketer. The sales agreements for Putumayo and MMV production expire on March 31, 2025. The loss of any individual sales customer will not have a material adverse impact on our Company as customers can be substituted or we could market the crude directly ourselves.
During the fourth quarter of 2022, we commenced production in Ecuador, which contributed 3% of the total production for the year ended December 31, 2023. Bocachico produces approximately 19° API oil and Charapa produces approximately 28° API oil. All of Ecuador production was sold to two international marketers and is sold at port of shipment.
We receive revenues for our Colombian and Ecuador oil sales in U.S. dollars. Oil prices for sales of our crude oil are defined by agreements with the purchasers of the oil. They 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, while trucking costs are in Colombian Pesos in Colombia and U.S. dollars in Ecuador.
Competition
The oil and gas industry is highly competitive. We face competition from both local and multinational companies. This competition impacts our ability to acquire properties, contract drilling and other oil field equipment, and secure trained personnel. Many competitors, such as Colombian and Ecuadorian 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 consummate transactions in a highly competitive environment. There is substantial competition for land contracts, prospects, and resources in the oil and 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 to deliver our products, maintain a skilled workforce, and obtain quality services and materials.
Geographic Information
Based on the geographic organization, Colombia is the only reportable segment. We also have Participation Sharing Contracts (“PSCs”) for the three Blocks in Ecuador. For the years ended December 31, 2023, 2022 and 2021, 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, 2023, and 2022 and were included in 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 relating to exploration, development, and production activities are explicit for each project; economics is governed by a royalty and 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 an opportunity for extension.
Colombia Administration
We operate in Colombia through Colombian branches of the following entities: Gran Tierra Energy Colombia GmbH, Gran Tierra Operations Colombia GmbH, and Gran Tierra Energy Resources Inc. These entities are currently qualified as operators of oil and gas properties by the ANH. The entities operate under a special regime for hydrocarbon companies in Colombia that entitle them to collect proceeds from oil sales abroad in U.S. dollars.
In Colombia, the ANH is the administrator of the hydrocarbons in the country, as delegated by the Ministry of Mining and Energy, 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 integrated oil company. In addition, Ecopetrol is a major purchaser and marketer of oil in Colombia and directly or through its subsidiaries operates most of the oil pipeline transportation and refining infrastructure in the country. Ecopetrol Group also owns a majority stake in the Colombian energy transmission sector.
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 right 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 and a production periods. The exploration period contains a number of exploration phases, and each phase has an associated work commitment. The production period usually lasts 24 years 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. Ecopetrol uses various forms of contracts, which contain exploration and development phases. Duration of contracts can be life of field or up to a specific date and the terms of such contracts vary depending on the type of contract. Under the Ecopetrol contract, the partner retains its working interest rights to produce all reserves, production and income from any new exploration and evaluation block, subject to existing royalty and tax regulations during the duration of such contract.
When operating under the ANH 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. Under the Ecopetrol contract, each party owns its working interest of the hydrocarbons extracted.
The contracts in place with ANH and Ecopetrol are agreements among both parties duly protected by regulation and, therefore, cannot be unilaterally adjusted at election of the Government. Contracts include the instances for remediation, arbitration and other protection measures. In addition, investment protection treaties and Colombian regulation protect the sanctity of the existing contract.
Ecuador Administration
We operate in Ecuador through the Ecuadorian branch of Gran Tierra Energy Colombia, GmbH.
In Ecuador, the Ministry of Energy and Mines (“MEM”) is responsible for signing 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 MEM uses service and participation contracts for the exploration and/or exploitation of hydrocarbons (“Participation Contracts”). We currently hold three Participation Contracts which provide for full risk for the contractor and production sharing with the MEM and contain an exploration and exploitation periods. The exploration period has an associated work
commitment and lasts typically 4 years. The participation contracts include a provision to extend the exploration period for up to two years, on the grounds of, among others, delays caused by the Ecuadorian government in the environmental licensing procedures. In the second quarter of 2021, we received a two-year extension of the exploration period for all three Participation Contracts, under the aforementioned provision. The exploitation period usually lasts 20 years from the approval of the development plan for one of several commercial hydrocarbon discoveries. Such contracts may be terminated at the election of the MEM 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 MEM 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 people, 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 in a timely basis, which could result in delays and have an adverse effect on our operations. Spills and releases of petroleum products into the environment 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 new developments. 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 International Finance Corporation 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 the environmental risk management program and robust waste management procedures. Air, soil and water testing occurs 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 the Health Safety and Environment 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.
Human Capital Management
At December 31, 2023, we had 351 full-time employees (December 31, 2022 - 336): 94 located in the Calgary corporate office, 234 in Colombia (166 staff in Bogota and 68 field personnel), 23 in Ecuador (three staff in Quito and 20 field personnel). None of our employees are represented by labor unions, and we consider our employee relations to be good.
Health and Safety
Safety is our top priority, and we have implemented safety management systems, procedures, and tools to protect our employees and contractors. As part of our Health and Safety Management System, we identify potential risks associated with the workplace and develop measures to mitigate possible hazards. We support our employees with general safety training and
implement specific programs for those working in all our operations, such as equipment and machinery safety, chemical management, and electrical safety.
Workplace Practices and Policies
Gran Tierra is an equal opportunity employer committed to equality and sourcing local employees, contractors, and suppliers. We have a program to increase gender and diversity representation, including guidelines to prevent gender discrimination in selection and recruitment by contractors, incentives to promote the recruitment of women throughout the supply chain, training to increase the competitiveness of female employees and candidates, and guarantees of fair working conditions including schedules and salaries.
We are committed to enabling employees and contractors to grow within their roles to advance by offering coaching and mentoring programs. An example of this is our Te Enseña (Learn with Gran Tierra) program. It involves independent training sessions across several departments, where participants improve internal knowledge and further develop their skill sets. We also offer employee-led virtual training sessions that promote individual growth and create a space to learn from their peers. These programs have fostered interdepartmental connections between employees and contractors providing ability to work remotely.
Compensation
We believe that all employees deserve competitive compensation and standard short and long-term incentives that enable employees to share success of the Company.
Engagement
We believe that open, honest, and transparent communication among the team members, managers, and senior management promotes company engagement and offers a strong understanding of our business’s big picture. We regularly encourage employees to learn about the organization’s strategic objectives and understand company’s decisions and how those decisions impact them specifically. We undertake quarterly reviews to inform our team about the Company’s performance and future goals. We believe these key strategies have led to strategic alignment across the organization.
Available Information
We file or furnish annual, quarterly and current reports, proxy statements and other documents with the 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. 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 quality differentials and transportation. The differentials and transportation costs can change over time and have a detrimental impact on realized prices.
Future decreases in the prices of oil, sustained low prices, periods of extended pricing volatility, and increasing borrowing costs 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 or public health crises
Global epidemics and public health crises and fear of such events may adversely impact our operations and the global economy, including the worldwide demand for oil and natural gas. The extent to which our business, results of operations and financial condition will be affected by such events depend on future developments, many of which are outside of our control, such as the duration, severity, and sustained geographic spread of the virus, and the impact and effectiveness of governmental actions to contain and treat outbreaks, including government policies and restrictions; vaccine hesitancy, vaccine mandates, and voluntary or mandatory quarantines; and the global response surrounding such uncertainties. To the extent any global epidemic or public health crisis may adversely affect our business, operations, financial condition and operating results, it may also have the effect of heightening the other risks described herein.
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 flows 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, security, 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 and Ecuador; however, we may eventually expand to other countries. Exploration and production operations are subject to legal, social, security, political and economic uncertainties, including terrorism, social unrest and activism, illegal 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 may experience future political and economic instability. Colombia has experienced social, economic and security turmoil related to security, guerilla and narcotrafficking. Political changes because of future electoral processes 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 as was the case in 2022; 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 Colombia or Ecuador are beyond our control and may significantly hamper our ability to expand our operations or operate our business at a profit. Colombia has investment protection treaties in place with the United States and Canada as well as a history of sanctity of contracts.
Oil production in Ecuador has recently been impacted by outages experienced by the nation’s two major pipelines (the Sistema de Oleoductos Trans Ecuadoriano (“SOTE”) and the Oleoducto de Crudos Pesados (“OCP”) pipelines) caused by physical damage from significant soil erosion in areas along the Coca river. While these pipelines have now been rerouted and are back in service, there remains some risk to our ability to transport oil to market through these systems from future, unforeseen natural events that could again generate outages in the OCP and SOTE pipelines. Such events could include, but are not limited to, earthquakes, volcanic eruptions and additional significant soil erosion. GTE mitigates this risk through the maintenance of surplus storage capacity at its facilities (typically 3-days by design) and the optionality of trucking oil to points of sale.
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, 2023, the Acordionero, Costayaco, Moqueta and Cohembi fields collectively generated 88% of our production and at December 31, 2023, these four fields accounted for 84% 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.
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. In 2023, the Colombian government is undertaking other peace process conversations with illegal groups in the country.
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 the 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 former FARC dissident groups and other illegal 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, increased eradication by the Colombian government of illicit crops, as well as the continuing attempts by the Colombian government to reduce or prevent activity of guerrilla dissidents and of farmers, 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 have experienced social turmoil related to changes in economic policy, which have resulted in illegal road blockades throughout the countries, and illegal invasions to private property and impacting regions where our operating
activities are located. While blockages have been historically directed at the State, the resulting impact may hinder our ability to mobilize oil, personnel and equipment, resulting in temporary shut-in of production or negatively impacting our assets.
Colombia and Ecuador also both have a history of security problems. Our efforts to ensure the security of our personnel and physical assets may not be successful and there can also be no assurance that we can maintain the safety of our field personnel 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.
Certain acquisitions could adversely affect our financial results
We may pursue strategic acquisitions as part of our business strategy from time to time. There is no assurance that we will be able to find suitable acquisition candidates or be able to complete acquisitions on favorable terms, if at all. We may also discover liabilities or deficiencies associated with any acquisitions that were not identified in advance, which may result in unanticipated costs. Additionally, integration efforts associated with our acquisitions may require significant capital and operating expense.
We intend to pay for future acquisitions using cash, stock, notes, debt, assumption of indebtedness or any combination of the foregoing. To the extent that we do not generate sufficient cash internally to provide the capital we require to fund our growth strategy and future operations, we will require additional debt or equity financing. This additional financing may not be available or, if available, may not be on terms acceptable to us. Further, high volatility in the capital markets and in our stock price may make it difficult for us to access the capital markets at attractive prices, if at all.
In addition, the anticipated benefits of an acquisition may not be realized fully or at all, or may take longer to realize than we expect. If we are not able to realize the anticipated benefits expected from our acquisitions within a reasonable time, our business, financial condition and results of operations may be adversely affected.
The threat and impact of cybersecurity incidents 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 risks and 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.
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 2024 is $210.0 million to $240.0 million for exploration and development activities. We expect to fund our 2024 capital program through cash flows from operations. Funding this program from cash flows from operations relies in part on Brent oil prices being $70 per barrel or greater. For the period from January 1 to February 15, 2024, the average price of Brent oil was $79.58 per barrel.
If cash flows from operations and cash on hand 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.
Public and investor sentiment towards climate change, fossil fuels and other Environmental, Social and Governance (“ESG”) matters could adversely affect our cost of capital and the price of our common stock
Certain numbers of investment community (including investment fund managers, sovereign wealth, pension and endowment funds, and individual investors) have promoted the divestment of fossil fuel equities and pressured lenders to cease or limit funding to companies engaged in the extraction of fossil fuel reserves, including recent divestment actions by several prominent New York State and New York public employee pension funds. There has also been pressure on lenders and other financial services companies to limit or curtail financing of companies in the oil and gas industry. Such environmental initiatives aimed at targeting climate changes could ultimately interfere with our access to capital and ability to finance our operations.
Some members of the investment community have increased their focus on ESG practices and disclosures by public companies, including practices and disclosures related to climate change and sustainability, Diversity, Equity and Inclusion (“DEI”) initiatives, and heightened governance standards. Furthermore, concerns over climate change have resulted in, and are expected to continue to result in, the adoption of regulatory requirements for climate-related disclosures. As a result, we may continue to face increasing pressure regarding our ESG disclosures and practices, and mandatory reporting obligations could increase our compliance burden and costs. We publish a Sustainability Report, which outlines our progress and ongoing efforts to advance
our ESG initiatives. Our disclosures on these matters rely on management’s expectations as of the date the statements are first made, as well as standards for measuring progress that are still in development, and may change or fail to be realized. These expectations and standards may continue to evolve.
A failure to meet goals or evolving stakeholder expectations of ESG practices and reporting may potentially harm our reputation and impact employee retention, customer relationships, and access to capital.
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 transactions are translated to U.S. dollars, our reporting 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.
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.
In Colombia, the ANH is delegated by the Ministry of Mining and Energy to offer and award new blocks through exploration and production (“E&P) and technical evaluation agreement contract terms. The new administration has stated that no new bid rounds for exploration blocks will be done until it is decided differently by the government. In addition, in 2023 the government issued a new decree eliminating the obligation of ANH to offer bid rounds for new blocks to Companies. Under new Colombia regulation, we may not be able to obtain new exploration licenses which can have adverse impact on our future exploration activities, production and 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, it 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, including demand for our products, our financial condition and results of operations
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, emissions, carbon and other regulations impacting climate and climate related matters are constantly evolving. 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. 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. In 2023, El-Niño-induced drought across Colombia, the decrease in power generated from hydroelectricity increased power costs, which resulted in higher operating expenses.
Risks Related to Ownership of our Common Stock
Shares of our Common Stock are listed on the NYSE American, the Toronto Stock Exchange (“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 shares of Common Stock are 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 shares of Common Stock on any of these exchanges or the volume of shares 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.

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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 have several lawsuits and claims pending. The outcome of the lawsuits and disputes 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. 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 15, 2024:
Name Age Position
Gary S. Guidry 68 President and Chief Executive Officer, Director
Ryan Ellson 48 Chief Financial Officer and Executive Vice President, Finance
Sebastien Morin 47 Chief Operating Officer
Phillip Abraham 53 Vice President, Legal and Business Development
James Evans 58 Vice President, Corporate Services
•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. Mr. Guidry was on the board of PetroTal Corp. from December 2017 until September 2022. 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 24 years of experience in a broad range of international corporate finance and accounting roles. Mr. Ellson is currently a Director of Canary Biofuels and Beyond Renewables (both private companies) and until September 2022 was a Director at 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.(“Caracal”), 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. 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 Masters of Professional Accounting from the University of Saskatchewan. Mr. Ellson has completed the Leadership for Senior Executives program at Harvard Business School and the General Management Program at the Wharton School of the University of Pennsylvania.
•Sebastien Morin, Chief Operating Officer. Mr. Morin was appointed as Gran Tierra’s Chief Operations Officer on November 6, 2023. Mr. Morin has more than 20 years of experience in the oil and gas industry in various management positions. Prior to his appointment as Chief Operating Officer of the Company, Mr. Morin served as President and Chief Operating Officer at WesternZagros Resources, a privately-owned petroleum operating company with production sharing contracts in the Kurdistan region of Iraq, from October 2021 to October 2023. Prior to his role at WesternZagros, Mr. Morin was Vice President Global Drilling and Completions at Gran Tierra, leading up to that he held progressively more senior positions at Gran Tierra in Colombia and in the Corporate Office in Calgary from August 2014 to September 2021. From May 2001 to July 2014, Mr. Morin worked at Imperial Oil (Esso) and ExxonMobil, where he achieved more senior technical and managerial positions in upstream and downstream including roles in drilling and completions, reservoir development, production, customer service and distribution, mostly onshore but also with experience offshore in the Gulf of Mexico. Mr. Morin has a Bachelor of Science degree in Geological Engineering from the University of Waterloo in 2001.
•Phillip Abraham, Vice President, Legal and Business Development. Mr. Abraham has been with Gran Tierra in a variety of roles since January 2016 and, in addition to his current role as Vice President, Legal and Business Development, is also Gran Tierra’s Corporate Secretary. He is a lawyer with over 25 years of corporate and legal experience. His legal experience includes positions at prominent law firms and is broadly based with a focus on international energy law. Mr. Abraham’s corporate experience extends to a variety of leadership positions with Cenovus Energy, Encana Corporation and Nexen Inc. His experience in oil and gas includes onshore and offshore projects located in Canada and various international jurisdictions in Latin America, Europe, Africa, Asia and the Middle East. Mr. Abraham is a member of Law Society of Alberta, holds both a B.A. and an LL.M. from the University of Calgary and a LL.B. from the University of Victoria, and was first called to the bar in British Columbia in 1997. He is credited as the author of various publications and has presented in numerous professional forums.
•James Evans, Vice President, Corporate Services. Mr. Evans has been Gran Tierra’s Vice President, Corporate Services, since May 2015. Mr. Evans has over 30 years of experience including working the last 19 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.
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 TSX and on the LSE under the symbol “GTE”.
As of February 15, 2024, there were approximately 32 holders of record of shares of our Common Stock and 32,246,501 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.
Issuer Purchases of Equity Securities
(a)
Total Number of Shares Purchased (b)
Average Price Paid per Share (1)
(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (d)
Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs (2)
October 1-31, 2023 - $ - - 3,234,914
November 1-30, 2023 755,790 $ 6.34 755,790 2,479,124
December 1-31, 2023 286,014 $ 5.87 286,014 2,193,110
Total 1,041,804 $ 6.21 1,041,804 2,193,110
(1) Including commission fees paid to the broker to re-purchase the shares of Common Stock.
(2) On October 31, 2023, we implemented a share re-purchase program (the “2023 Program”) through the facilities of the TSX, the NYSE American or alternative trading programs in Canada or the United States commencing November 3, 2023 and ending on November 2, 2024. Under the 2023 Program, we are able to purchase at prevailing market prices up to 3,234,914 shares of Common Stock, representing approximately 10% of the public float of common shares as of October 20, 2023.
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. This Management’s Discussion and Analysis of Financial Condition and Results of Operations generally discusses items related to the fiscal year ended December 31, 2023, and year-to-year comparisons between the fiscal years ended December 31, 2023, and 2022, respectively. Discussions of items related to the fiscal year ended December 31, 2022 and year-to-year comparisons between the fiscal years ended December 31, 2022 and 2021, respectively, that are not included in this Annual Report on Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. On May 5, 2023, the Company completed 1-for-10 reverse stock split of the Company’s Common Stock. As a result of the reverse stock split, every ten of the Company’s issued shares of Common Stock were automatically combined into one issued share of Common Stock. All share and per share data included in this Annual Report on Form 10-K have been retroactively adjusted to reflect the reverse stock split.
Overview
We are a company focused on oil and gas exploration and production with assets currently in Colombia and Ecuador. Our Colombian properties represented 94% of our proved reserves NAR at December 31, 2023. For the year ended December 31, 2023, 97% of our revenue was generated in Colombia (2022 - 100% and 2021 -100%). We are headquartered in Calgary, Alberta, Canada.
As of December 31, 2023, we had estimated proved reserves NAR of 74.3 MMBOE, a 13% increase from the prior year, of which 53% were proved developed reserves and 100% were oil.
Financial and Operational Highlights
Key Highlights
•Net loss in 2023 was $6.3 million or $(0.19) per share basic and diluted compared to a net income of $139.0 million or $3.81 per share basic and $3.76 per share diluted in 2022
•Income before income taxes in 2023 was $106.2 million compared to $244.9 million in 2022
•Adjusted EBITDA(2) for 2023 was $399.4 million compared to $481.9 million in 2022
•In 2023, we re-purchased 1.3 million and 1.0 million shares of Common Stock through the 2022 and 2023 share re-purchase programs, representing about 4% and 3%, respectively, of shares outstanding as of December 31, 2023
•Our total 2023 average production NAR was 26,099 BOPD, an increase from 23,815 BOPD in 2022 as a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador
•Our total 2023 oil sales volumes NAR increased by 9% to 25,947 BOPD compared to 23,696 BOPD in 2022
•Oil sales for 2023 decreased by 10% to $637.0 million compared to $711.4 million in 2022, primarily as a result of a 17% decrease in Brent price and higher Castilla and Vasconia differentials, partially offset by 9% increase in sales volumes and lower transportation discounts
•Oil sales per bbl for 2023 were $67.26, 18% lower compared to 2022, as a result of a decrease in benchmark oil prices
•In 2023, we generated net cash provided by operating activities of $228.0 million, a decrease of 47% from $427.7 million in 2022
•During 2023, the Company generated $57.9 million of free cash flow(2) which was used for debt reduction and share re-purchases
•Operating expenses per bbl for 2023 were $19.73, 5% higher compared to 2022, primarily due to higher lifting costs attributed to road and pipeline maintenance, power generation and equipment rental, offset by lower workovers. Total operating expenses were $186.9 million in 2023, compared to $162.4 million in 2022, representing a 15% increase
•Quality and transportation discounts per bbl decreased in 2023 to $14.90 when compared to $16.79 in 2022. The decrease was due to the utilization of more favorable delivery points than in 2022
•Transportation expenses per bbl for 2023 increased by 31% to $1.54 compared to $1.18 in 2022, primarily due to utilization of new transportation routes in Colombia and Ecuador related to exploration wells and the depreciation of U.S. dollar against the Colombian peso during 2023
•General and administrative (“G&A”) expenses before stock-based compensation per bbl for 2023 increased by 15% to $4.24 compared to $3.69 in 2022 due to business development activities, higher salaries related to increased headcount in Ecuador to support ramp-up of operations and the strengthening of the Colombian peso during 2023. G&A expenses before stock-based compensation were $40.1 million in 2023 compared to $31.9 million in 2022, representing a 26% increase
•Capital expenditures decreased by $17.7 million or 7% to $218.9 million compared to 2022 due to a more condensed drilling program during 2023
(Thousands of U.S. Dollars, unless otherwise noted) Year Ended December 31,
2023 % Change 2022 % Change 2021
SEC Compliant Reserves, NAR (MMBOE)
Estimated proved oil and gas reserves 74 12 66 (1) 67
Estimated probable oil and gas reserves 46 28 36 - 36
Estimated possible oil and gas reserves 49 26 39 26 31
Average Consolidated Daily Volumes (BOPD)
Working interest (“WI”) production before royalties 32,647 6 30,746 16 26,507
Royalties (6,548) (6) (6,931) 41 (4,919)
Production NAR 26,099 10 23,815 10 21,588
(Increase) decrease in inventory (152) (28) (119) (1,290) 10
Sales (1)
25,947 9 23,696 10 21,598
Net (Loss) Income
$ (6,287) (105) $ 139,029 227 $ 42,482
Operating Netback
Oil sales $ 636,957 (10) $ 711,388 50 $ 473,722
Operating expenses (186,864) 15 (162,385) 20 (135,722)
Transportation expenses (14,546) 43 (10,197) (12) (11,618)
Operating netback (2)
$ 435,547 (19) $ 538,806 65 $ 326,382
G&A Expenses Before Stock-Based Compensation $ 40,124 26 $ 31,908 15 $ 27,867
G&A Stock-Based Compensation $ 5,722 (37) $ 9,049 8 $ 8,396
Adjusted EBITDA (2)
$ 399,355 (17) $ 481,882 101 $ 240,134
Net Cash Provided By Operating Activities $ 227,992 (47) $ 427,711 75 $ 244,834
Funds Flow From Operations (2)
$ 276,785 (24) $ 366,024 96 $ 186,485
Capital Expenditures
$ 218,882 (7) $ 236,604 58 $ 149,879
As at December 31,
(Thousands of U.S. Dollars) 2023 % Change 2022 % Change 2021
Cash and cash equivalents $ 62,146 (51) $ 126,873 386 $ 26,109
Credit facility
$ 36,364 100 $ - (100) $ 67,500
Senior Notes $ 536,619 (7) $ 579,909 (3) $ 600,000
(1) Sales volumes represent production NAR adjusted for inventory changes
(2) Non-GAAP measures
Operating netback, EBITDA, adjusted EBITDA, funds flow from operations, and free cash flow are non-GAAP measures which do not have any standardized meaning prescribed under General Accepted Accounting Principles (“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 non-cash lease expense,
lease payments, foreign exchange gains or losses, unrealized derivative instruments gains or losses, other financial instruments gains or losses, other non-cash gains or 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 a useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income or loss to EBITDA and adjusted EBITDA is as follows:
Year Ended Three Months Ended
December 31, December 31, September 30,
(Thousands of U.S. Dollars) 2023 2022 2021 2023 2022 2023
Net (loss) income $ (6,287) $ 139,029 $ 42,482 $ 7,711 $ 33,275 $ 6,527
Adjustments to reconcile net (loss) income to EBITDA and Adjusted EBITDA
DD&A expenses 215,584 180,280 139,874 52,635 51,781 55,019
Interest expense 55,806 46,493 54,381 17,789 10,750 13,503
Income tax expense (recovery) 112,447 105,906 (19,346) 5,499 5,966 40,333
EBITDA (non-GAAP) $ 377,550 $ 471,708 $ 217,391 $ 83,634 $ 101,772 $ 115,382
Non-cash lease expense 4,967 2,818 1,667 1,479 809 1,235
Lease payments (3,018) (1,666) (1,621) (1,100) (532) (676)
Foreign exchange loss 11,822 2,578 20,477 3,696 2,092 1,717
Unrealized derivative instruments gain - - (9,589) - - -
Other financial instruments loss (gain) 15 (7) 3,369 15 (7) -
Other non-cash loss (gain)
2,297 (2,598) 44 3,266 - (354)
Stock-based compensation expense
5,722 9,049 8,396 1,974 2,673 1,931
Adjusted EBITDA (non-GAAP) $ 399,355 $ 481,882 $ 240,134 $ 92,964 $ 106,807 $ 119,235
Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, 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, unrealized derivative instruments gains or losses, other financial instruments gains or losses, and other non-cash gains or losses. Management uses this financial 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 also useful supplemental information for investors to analyze performance and our financial results. Free cash flow, as presented, is defined as funds flow less capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income or loss to funds flow from operations and free cash flow is as follows:
Year Ended Three Months Ended,
December 31, December 31, September 30,
(Thousands of U.S. Dollars) 2023 2022 2021 2023 2022 2023
Net (loss) income
$ (6,287) $ 139,029 $ 42,482 $ 7,711 $ 33,275 $ 6,527
Adjustments to reconcile net (loss) income to funds flow from operations
DD&A expenses 215,584 180,280 139,874 52,635 51,781 55,019
Deferred tax expense (recovery) 56,759 25,340 (23,825) 13,517 (11,528) 13,990
Stock-based compensation expense 5,722 9,049 8,396 1,974 2,673 1,931
Amortization of debt issuance costs 5,831 3,528 3,809 2,437 759 1,594
Non-cash lease expense 4,967 2,818 1,667 1,479 809 1,235
Lease payments (3,018) (1,666) (1,621) (1,100) (532) (676)
Unrealized foreign exchange (gain) loss (5,085) 10,251 21,879 2,729 4,113 (266)
Unrealized derivative instruments gain - - (9,589) - - -
Other financial instruments loss (gain) 15 (7) 3,369 15 (7) -
Other non-cash loss (gain) 2,297 (2,598) 44 3,266 - (354)
Funds flow from operations (non-GAAP) $ 276,785 $ 366,024 $ 186,485 $ 84,663 $ 81,343 $ 79,000
Capital expenditures $ 218,882 $ 236,604 $ 149,879 $ 39,175 $ 72,887 $ 43,080
Free cash flow (non-GAAP) $ 57,903 $ 129,420 $ 36,606 $ 45,488 $ 8,456 $ 35,920
Consolidated Results of Operations
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 % Change 2022 % Change 2021
Oil sales $ 636,957 (10) $ 711,388 50 $ 473,722
Operating expenses 186,864 15 162,385 20 135,722
Transportation expenses 14,546 43 10,197 (12) 11,618
Operating netback (1)
435,547 (19) 538,806 65 326,382
DD&A expenses 215,584 20 180,280 29 139,874
G&A expenses before stock-based compensation 40,124 26 31,908 15 27,867
G&A stock-based compensation expense 5,722 (37) 9,049 8 8,396
Foreign exchange loss 11,822 359 2,578 (87) 20,477
Derivative instruments loss - (100) 26,611 (46) 48,838
Other financial instruments loss (gain) 15 314 (7) (100) 3,369
Interest expense 55,806 20 46,493 (15) 54,381
329,073 11 296,912 (2) 303,202
Other (loss) gain (2,297) (188) 2,598 6,005 (44)
Interest income 1,983 348 443 100 -
Income before income taxes 106,160 (57) 244,935 959 23,136
Current income tax expense 55,688 (31) 80,566 1,699 4,479
Deferred income tax expense (recovery) 56,759 124 25,340 206 (23,825)
Total income tax expense (recovery) 112,447 6 105,906 647 (19,346)
Net (loss) income $ (6,287) (105) $ 139,029 227 $ 42,482
Sales Volumes (NAR)
Total sales volumes, BOPD 25,947 9 23,696 10 21,598
Brent Price per bbl $ 82.16 (17) $ 99.04 40 $ 70.95
Consolidated Results of Operations per bbl Sales Volumes (NAR)
Oil sales $ 67.26 (18) $ 82.25 37 $ 60.09
Operating expenses 19.73 5 18.77 9 17.22
Transportation expenses 1.54 31 1.18 (20) 1.48
Operating netback (1)
45.99 (26) 62.30 51 41.39
DD&A expenses 22.76 9 20.84 17 17.74
G&A expenses before stock-based compensation 4.24 15 3.69 5 3.53
G&A stock-based compensation expense 0.60 (43) 1.05 (2) 1.07
Foreign exchange loss 1.25 317 0.30 (88) 2.60
Derivative instruments loss - (100) 3.08 (50) 6.19
Other financial instruments loss
- - - (100) 0.43
Interest expense 5.89 9 5.38 (22) 6.90
34.74 1 34.34 (11) 38.46
Other (loss) gain (0.24) (180) 0.30 3,100 (0.01)
Interest income 0.21 320 0.05 100 -
Income before income taxes 11.22 (60) 28.31 870 2.92
Current income tax expense 5.88 (37) 9.31 1,533 0.57
Deferred income tax expense (recovery) 5.99 104 2.93 197 (3.02)
Total income tax expense (recovery) 11.87 (3) 12.24 600 (2.45)
Net (loss) income $ (0.65) (104) $ 16.07 199 $ 5.37
(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) 2023 2022 2021
WI production before royalties 32,647 30,746 26,507
Royalties (6,548) (6,931) (4,919)
Production NAR 26,099 23,815 21,588
(Increase) decrease in inventory (152) (119) 10
Sales 25,947 23,696 21,598
Royalties, % of working interest production before royalties 20 % 23 % 19 %
Oil production NAR for the year ended December 31, 2023, increased by 10% to 26,099 BOPD compared to 23,815 in 2022. The increase in production was a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador.
Royalties as a percentage of production for the year ended December 31, 2023, decreased compared to 2022 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia.
Oil production NAR for the year ended December 31, 2022, increased by 10% to 23,815 BOPD compared to 21,588 BOPD in 2021. Production increased as a result of successful drilling and workover campaigns in Acordionero and Costayaco fields, less disruptions from blockades in Suroriente and production from exploration success in Ecuador.
The Midas Block includes the Acordionero field, the Suroriente Block includes the Cohembi field, and the Chaza Block includes the Costayaco and Moqueta fields. Ecuador includes the Charapa, Chanangue and Iguana Blocks.
Oil Sales
Oil sales for the year ended December 31, 2023, decreased by 10% to $637.0 million compared to $711.4 million in 2022, primarily as a result of a 17% decrease in Brent price and higher Castilla and Vasconia differentials partially offset by 9% higher sales volumes and lower transportation discounts in 2023. Castilla and Vasconia differentials increased to $10.22 and $5.39 from $9.81 and $4.99 per bbl in 2022, respectively. During the year ended December 31, 2023, we commenced sales in Ecuador which were subject to a $9.91 per bbl Oriente differential.
On a per bbl basis, average realized prices decreased by 18% to $67.26 for the year ended December 31, 2023, compared to $82.25 in 2022, primarily as a result of the decrease in benchmark oil prices and higher Castilla and Vasconia differentials in 2023.
Oil sales for the year ended December 31, 2022, increased by 50% to $711.4 million compared to $473.7 million in 2021, primarily as a result of a 40% increase in Brent price, 10% higher sales volumes, partially offset by 55% higher quality and transportation discounts in 2022. Castilla and Vasconia differentials increased to $9.81 and $4.99 from $5.74 and $3.52, respectively, per bbl in 2021.
On a per bbl basis, average realized prices increased by 37% to $82.25 for the year ended December 31, 2022, compared to $60.09 in 2021, primarily as a result of the increase in benchmark oil prices, offset by higher Castilla and Vasconia differentials in 2022.
The following table shows the effect of changes in realized price and sales volumes on our oil sales for the years ended December 31, 2023, 2022, and 2021:
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Oil sales for the comparative year $ 711,388 $ 473,722 $ 237,838
Realized sales price (decrease) increase effect (141,997) 191,664 219,641
Sales volume increase effect 67,566 46,002 16,243
Oil sales for the current year $ 636,957 $ 711,388 $ 473,722
Operating Expenses
Operating expenses for the year ended December 31, 2023, increased by 15% to $186.9 million compared to $162.4 million in 2022. On a per bbl basis, despite significant inflationary pressures operating expenses only increased by only 5% or $0.96 to $19.73 compared to $18.77 in the prior year, primarily as a result of $2.23 per bbl higher lifting costs associated with road and pipeline maintenance, power generation attributed to higher compressed natural gas purchases, diesel tariffs and equipment rental associated with testing exploratory wells, offset by $1.27 per bbl of lower workovers. As a result of an El-Niño-induced drought, power costs have increased across Colombia, which relies on hydroelectricity for more than two-thirds of its installed power capacity. In addition, operating costs increased as a result of the depreciation of U.S. dollar against the Colombian peso in 2023.
Operating expenses for the year ended December 31, 2022, increased by 20% to $162.4 million compared to $135.7 million in 2021. On a per bbl basis, operating expenses increased by 9% or $1.55 to $18.77 compared to $17.22 in 2021, primarily as a result of $0.48 per bbl higher workovers and $1.07 per bbl higher lifting costs mainly attributed to higher power generation due to increased activities attributed to higher production and water flood program in all major fields.
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 and Ecuador using each transportation method for each of the three years ended December 31, 2023:
Year Ended December 31,
2023 2022 2021
Volume transported through pipelines 2 % - % 12 %
Volume sold at wellhead 47 % 47 % 34 %
Volume transported via truck to pipelines 51 % 53 % 54 %
100 % 100 % 100 %
Colombian volumes transported through pipelines or via trucks 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. Volumes sold in Ecuador are transported via pipeline. We focus on maximizing operating netback (1) per bbl when choosing a transportation method.
Transportation expenses for the year ended December 31, 2023, increased by 43% to $14.5 million or by $0.36 to $1.54 per bbl compared to $10.2 million or $1.18 per bbl in 2022, as a result of the utilization of new transportation routes related to sales from exploration wells in Colombia and Ecuador, the depreciation of the U.S. dollar against the Colombian peso and higher sales volumes.
Transportation expenses for the year ended December 31, 2022, decreased by 12% to $10.2 million or by $0.30 per bbl to $1.18 per bbl compared to $11.6 million or $1.48 per bbl in 2021. The decrease in transportation expenses per bbl was a result of the higher volumes sold at the wellhead and higher sales volumes in 2022 compared to the corresponding year of 2021. In addition, during 2021, alternative transportation routes were utilized due to maintenance of the Impala terminal, which had higher transportation costs per bbl.
The following table shows the variance in our average realized price net of transportation expenses in Colombia and Ecuador for each of the three years ended December 31, 2023:
Year Ended December 31,
(U.S. Dollars per bbl Sales Volumes NAR) 2023 2022 2021
Average Brent price $ 82.16 $ 99.04 $ 70.95
Average realized price, net of transportation expenses for the comparative period $ 81.07 $ 58.61 $ 30.78
(Decrease) increase in benchmark prices (16.88) 28.09 27.74
Decrease (increase) in quality and transportation discounts 1.89 (5.93) 0.12
(Increase) decrease in transportation expense (0.36) 0.30 (0.03)
Average realized price, net of transportation expenses for the year $ 65.72 $ 81.07 $ 58.61
Average realized price, net of transportation expenses as a % of Brent
80 % 82 % 83 %
Operating Netbacks
Year Ended December 31,
Consolidated 2023 2022 2021
(Thousands of U.S. Dollars)
Oil sales $ 636,957 $ 711,388 $ 473,722
Transportation expenses (14,546) (10,197) (11,618)
622,411 701,191 462,104
Operating expenses (186,864) (162,385) (135,722)
Operating netback (1)
$ 435,547 $ 538,806 $ 326,382
(U.S. Dollars per bbl Sales Volumes NAR)
Brent $ 82.16 $ 99.04 $ 70.95
Quality and transportation discounts (14.90) (16.79) (10.86)
Average realized price 67.26 82.25 60.09
Transportation expenses (1.54) (1.18) (1.48)
Average realized price, net of transportation expenses 65.72 81.07 58.61
Operating expenses (19.73) (18.77) (17.22)
Operating netback (1)
$ 45.99 $ 62.30 $ 41.39
(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.
DD&A Expenses
Year Ended December 31,
2023 2022 2021
DD&A Expenses, Thousands of U.S. Dollars $ 215,584 $ 180,280 $ 139,874
DD&A Expenses, U.S. Dollars per bbl $ 22.76 $ 20.84 $ 17.74
DD&A expenses for the year ended December 31, 2023, increased by 20% or $1.92 per bbl from 2022. On a per bbl basis, the DD&A increase in 2023 was due to increased production and higher costs in the depletable base as a result of higher future development costs compared to 2022.
DD&A expenses for the year ended December 31, 2022, increased 29% or $3.10 per bbl from 2021. On a per bbl basis, the DD&A increase in 2022 was due to increased production and higher costs in the depletable base compared to 2021.
Asset Impairment
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 unweighted arithmetic average of the first-day-of-the month Brent price for the 12-month period prior to the ending date of the period covered by the balance sheet. 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 years ended December 31, 2023, 2022, and 2021, we had no ceiling test impairment losses. In accordance with GAAP, we used an average Brent price of $82.51 per bbl less corresponding differentials for the purpose of the December 31, 2023 ceiling test calculation (2022 and 2021 - $97.98 and $68.92 per bbl, respectively).
G&A Expenses
(Thousands of U.S. Dollars) Year Ended December 31,
2023 % change 2022 % change 2021
G&A expenses before stock-based compensation $ 40,124 26 $ 31,908 15 $ 27,867
G&A stock-based compensation 5,722 (37) 9,049 8 8,396
G&A expenses including stock-based compensation $ 45,846 12 $ 40,957 13 $ 36,263
(U.S. Dollars Per bbl Sales Volumes NAR)
G&A expenses before stock-based compensation $ 4.24 15 $ 3.69 5 $ 3.53
G&A stock-based compensation 0.60 (43) 1.05 (2) 1.07
G&A expenses including stock-based compensation $ 4.84 2 $ 4.74 3 $ 4.60
On a per bbl basis, G&A expenses before stock-based compensation for the year ended December 31, 2023, increased by 15% to $4.24 compared to 2022 due to costs attributed to business development activities, higher salaries related to increased headcount in Ecuador to support ramp-up of operations and the strengthening of the Colombian peso against the U.S. dollar. Total G&A expenses before stock-based compensation for the year ended December 31, 2023, increased by 26% to $40.1 million compared to 2022 for the same reason mentioned above.
On a per bbl basis, G&A expenses before stock-based compensation for the year ended December 31, 2022, increased by 5% to $3.69 compared to 2021 due to higher costs for optimization projects and lease obligations expenses related to additional leases capitalized during 2022. Total G&A expenses before stock-based compensation for the year ended December 31, 2022, increased 15% to $31.9 million compared to 2021 for the same reason mentioned above.
On a per bbl basis, G&A expenses after stock-based compensation for the year ended December 31, 2023, increased by 2% to $4.84 compared to 2022 due to higher G&A expenses before stock-based compensation, partially offset by 43% decrease in stock-based compensation expense which was a result of lower share price in 2023. Total G&A expenses after stock-based compensation for the year ended December 31, 2023, increased by 12% to $45.8 million, compared to 2022 for the same reason mentioned above.
On a per bbl basis, G&A expenses after stock-based compensation costs for the year ended December 31, 2022, increased by 3% to $4.74 per bbl compared to 2021 for the same reason mentioned above and higher stock-based compensation expense. Stock-based compensation per bbl decreased by 2% due to higher sales volumes in proportion to the increase in stock-based compensation expense in 2022. Total G&A expenses after stock-based compensation increased 13% to $41.0 million due to higher stock-based compensation expense for the year ended December 31, 2022, compared to 2021.
Foreign Exchange Losses
For the years ended December 31, 2023, 2022 and 2021, we had foreign exchange losses of $11.8 million, $2.6 million and $20.5 million, respectively. The main sources of foreign exchange gains and losses are the revaluation of taxes receivable and payable, deferred tax assets and liabilities and accounts payable. Under GAAP, income taxes, deferred taxes and accounts payable are considered monetary assets and liabilities and require translation from local currency to the U.S. dollar functional currency at each balance sheet date.
The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the last three years ended December 31, 2023:
Year Ended December 31,
2023 2022 2021
Change in the U.S. dollar against the Colombian peso
weakened by strengthened by strengthened by
21 % 21 % 16 %
Change in the U.S. dollar against the Canadian dollar
weakened by strengthened by consistent
2 % 7 % - %
Financial Instruments Gains or Losses
The following table presents the nature of our financial instruments gains or losses for each of the three years ended December 31, 2023:
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Commodity price derivative loss
$ - $ 26,611 $ 48,723
Foreign currency derivative loss - - 115
$ - $ 26,611 $ 48,838
Unrealized investment loss $ - $ - $ 2,032
Loss on sale of investment - - 1,355
Other financial instruments loss (gain) 15 (7) (18)
$ 15 $ (7) $ 3,369
Income Tax Expense and Recovery
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Income before income taxes $ 106,160 $ 244,935 $ 23,136
Current income tax expense $ 55,688 $ 80,566 $ 4,479
Deferred income tax expense (recovery) 56,759 25,340 (23,825)
Total income tax expense (recovery) $ 112,447 $ 105,906 $ (19,346)
Effective tax rate 106 % 43 % (84) %
Current income tax expense for the year ended December 31, 2023, was $55.7 million (2022 - $80.6 million; 2021 - $4.5 million). Current income tax expense decreased for the year ended December 31, 2023, compared to 2022, primarily due to a decrease in taxable income.
The deferred income tax expense of $56.8 million and $25.3 million for the years ended December 31, 2023 and 2022, respectively, were primarily a result of tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia. The deferred income tax recovery of $23.8 million for the year ended December 31, 2021, was mainly a result of the release of the valuation allowance in Colombia, which was partially offset by excess tax depreciation compared with accounting depreciation and the use of tax losses to offset taxable income in Colombia.
Our effective tax rate was 106% for the year ended December 31, 2023, compared to 43% in 2022. The increase in the effective tax rate was primarily due to an increase in non-deductible foreign exchange adjustments, impact of foreign taxes and other permanent differences. These were partially offset by a decrease in valuation allowance and non-deductible stock-based compensation.
Our effective tax rate was 43% for the year ended December 31, 2022, compared with (84)% in 2021. The increase in the effective tax rate was primarily due to an increase in valuation allowance, other permanent differences, stock-based compensation costs, and non-deductible third party royalties in Colombia. These were slightly offset by a decrease foreign currency translation adjustment and the impact of foreign taxes.
The difference between our effective tax rate of 106% for the year ended December 31, 2023, and the 45% Colombian statutory tax rate was primarily due to an increase in non-deductible foreign exchange adjustments, other permanent differences, the impact of foreign taxes, non-deductible royalties in Colombia and non-deductible stock-based compensation. These were partially offset by a decrease in valuation allowance.
The difference between our effective tax rate of 43% for the year ended December 31, 2022, and the 35% Colombian statutory rate was primarily due to $26.6 million of hedging loss, $46.5 million of financing cost mainly related to the senior notes, and $23.1 million of stock-based compensation and G&A cost, which were incurred in jurisdictions where no tax benefit is recognized. These were partially offset by $13.2 million of non-taxable foreign exchange gain.
The difference between our effective tax rate of (84)% for the year ended December 31, 2021, and the 31% Colombian statutory was primarily due to a decrease in the valuation allowance and other permanent differences, which were partially offset by an increase in foreign currency translation adjustment, foreign taxes, stock-based compensation costs, non-deductible third party royalties in Colombia, and non-deductible investment loss on PetroTal.
Net Income (Loss) and Funds Flow From Operations (a Non-GAAP Measure)
(Thousands of U.S. Dollars) Fourth quarter 2023 compared with third quarter 2023
% change Fourth quarter 2023 compared with fourth quarter 2022
% change Year ended December 31, 2023 compared with year ended December 31, 2022
% change
Net income for the comparative period
$ 6,527 $ 33,275 $ 139,029
Increase (decrease) due to:
Sales volumes (9,865) (4,521) 67,566
Prices (15,112) (3,172) (141,997)
Expenses:
Cash operating expenses 1,730 (1,518) (24,479)
Transportation (105) (1,514) (4,349)
Cash G&A, excluding stock-based compensation expense (2,765) (3,074) (8,216)
Interest, net of amortization of debt issuance costs (3,443) (5,361) (7,010)
Realized foreign exchange gain (loss)
1,016 (2,988) (24,580)
Settlement of financial instruments - - 26,611
Current taxes 34,361 25,512 24,878
Net lease payments (180) 102 797
Interest income 26 (146) 1,540
Net change in funds flow from operations (1) from comparative period
5,663 3,320 (89,239)
Expenses:
Depletion, depreciation and accretion 2,384 (854) (35,304)
Inventory impairment
- - -
Deferred tax 473 (25,045) (31,419)
Amortization of debt issuance costs (843) (1,678) (2,303)
Net lease payments 180 (102) (797)
Stock-based compensation (43) 699 3,327
Other non-cash loss
(3,620) (3,266) (4,895)
Financial instruments loss, net of financial instruments settlements (15) (22) (22)
Unrealized foreign exchange (loss) gain
(2,995) 1,384 15,336
Net change in net income
1,184 (25,564) (145,316)
Net income (loss) for the current period
$ 7,711 18 % $ 7,711 (77) % $ (6,287) (105) %
(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.
2024 Work Program and Capital Expenditures
Our Colombian development operation is expected to represent 93% of our production and approximately 60% - 70% of our 2024 capital budget, with the remainder allocated to exploration activities.
The table below shows the break-down of our 2024 capital program:
Number of Wells
(Gross) Number of Wells
(Net) 2024 Capital Budget
($ million)
Development - Colombia 13 - 17
12 - 16 130 - 140
Exploration - Colombia and Ecuador 6 - 9
6 - 9 80 - 100
19 - 26 18 - 25 210 - 240
Our base capital program for 2024 is $210 million to $240 million for exploration and development activities. Based on the mid-point of the 2024 guidance, the capital budget is forecasted to be approximately 60% directed to development and 40% to exploration activities. Approximately 20% of the development activities included in the 2024 capital program are expected to be directed to facilities to support future production growth and enhance recovery factors.
We expect our 2024 capital program to be fully funded by cash flows from operations. Funding this program from cash flows from operations relies in part on Brent oil prices being $70 per bbl for 2024.
Capital Program
Capital expenditures during the year ended December 31, 2023 were $218.9 million.
During the year ended December 31, 2023, we spud the following wells in Colombia:
Number of Wells
(Gross and Net)
Colombia
Development 17.0
Service 8.0
Total 25.0
In 2023, we spud 17 development and eight service wells in Colombia and none in Ecuador. Of the wells drilled in Colombia, 13 were drilled in Midas Block and 12 in Chaza Block. As at December 31, 2023, of the 17 development wells 15 were producing, and two were in-progress.
On April 11, 2023, we and Ecopetrol S.A. renegotiated the terms of the contract for our operatorship of the Suroriente Block which was previously scheduled to end in mid-2024 and executed the Suroriente Continuation Agreement. The duration of the contract was extended for 20 years from September 1, 2023 (the “Effective Date”), the date on which we satisfied the relevant conditions precedent and regulatory approval was received. We continue to be the operator of the Suroriente Block. In connection with the contract extension, we paid cash consideration of $6.2 million and provided letters of credit of $123.0 million (refer to Note 12 to the Consolidated Financial Statements) related to committed capital investments to be made over a three-year period from the Effective Date.
Liquidity and Capital Resources
As at December 31,
(Thousands of U.S. Dollars) 2023 % Change 2022 % Change 2021
Cash and cash equivalents $ 62,146 (51) $ 126,873 386 $ 26,109
Credit facility
$ 36,364 100 $ - (100) $ 67,500
Senior Notes $ 536,619 (7) $ 579,909 (3) $ 600,000
We believe that our capital resources, including cash on hand and cash generated from operations will provide us with sufficient liquidity to maintain current operations and execute the capital program for the next 12 months and beyond, given current oil price trends and production levels. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial, or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions. We intend to pursue growth opportunities and acquisitions from time to time, which may require significant capital, be located in basins or countries beyond our current operations, involve joint ventures, or be sizable compared to our current assets and operations.
During the year ended December 31, 2023, we, as guarantor, and Gran Tierra Energy Colombia GmbH and Gran Tierra Operations Colombia GmbH, as borrowers, had a credit facility of $50 million which was paid in full and terminated on February 6, 2024. Interest under the credit facility was based on the secured overnight financing rate posted by the Federal Reserve Bank of New York plus a credit margin of 6.00% and a credit-adjusted spread of 0.26% with undrawn amounts under the credit facility bearing interest at 2.10% per annum, based on the amount available. Prior to termination, the credit facility was secured by our Colombian assets and economic rights and had a final maturity date of August 15, 2024. As of December 31, 2023, the credit facility was drawn by $36.4 million. During the year ended December 31, 2023, we incurred the weighted-average interest rate on credit facility of 11.59%.
On October 20, 2023, we completed exchange offers of $247.1 million of 6.25% Senior Notes (the “6.25% Senior Notes”) and $275.8 million of 7.75% Senior Notes (the “7.75% Senior Notes”) for $487.6 million 9.50% Senior Secured Notes due 2029 (the “9.50% Senior Notes” and, together with the 7.75% Senior Notes and the 6.25% Senior Notes, the “Senior Notes”). The exchange consideration for $242.5 million of 6.25% Senior Notes included early participation premium of $80 for each $1,000 aggregate principal amount with the remainder of $4.6 million exchanged at $1,000 and for $274.2 million of 7.75% Senior Notes early participation premium of $20 for each $1,000 aggregate principal amount with the remainder of $1.6 million of 7.75% Senior Notes exchanged at $950 for each $1,000 aggregate principal amount. In addition, the Company paid cash consideration of $60.0 million for 6.25% Senior Notes exchanged as part of total consideration to eligible holders on a pro-rata basis, for each $1,000 aggregate principal amount tendered and accepted for the early exchange deadline. The Senior Notes tendered and accepted for exchange, as well as the notes held as treasury bonds, were cancelled. The exchange of the 6.25% Senior Notes was accounted for as debt extinguishment and resulted in a gain of $5.3 million. The exchange of 7.75% Senior Notes was accounted for as debt modification and resulted in a loss of $6.1 million related to third party fees.
At December 31, 2023, we had $24.8 million of 6.25% Senior Notes due 2025, $24.2 million of 7.75% Senior Notes due 2027, and $487.6 million of 9.50% Senior Notes due 2029.
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 re-purchased.
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 re-purchased.
The 9.50% Senior Notes bear interest at a rate of 9.50% per year, payable semi-annually in arrears on April 15 and October 15 of each year, beginning on April 15, 2024. The 9.50% will mature on October 15, 2029.
The principal amount of 9.50% Senior Notes is to be repaid as follows: (i) October 15, 2026, 25% of the principal amount; (ii) October 15, 2027, 5% of the principal amount; (iii) October 15, 2028, 30% of the principal amount; and (iv) October 15, 2029, the remainder of the principal amount.
On February 6, 2024, we issued additional $100.0 million of 9.50% Senior Notes and received net cash proceeds of $88.0 million as a result of this issuance. The newly issued 9.50% Senior Notes have the same terms and provisions, except for the issue price, as original $487.6 million 9.50% Senior Notes outstanding at December 31, 2023 and will be combined together with originally issued 9.50% Senior Notes in respect of interest payments.
During the year ended December 31, 2023, we purchased in the open market $8.0 million of 6.25% Senior Notes for cash consideration of $6.8 million, including interest payable of $0.1 million. The purchase resulted in a $1.1 million gain, which
included the write-off of deferred financing fees of $0.1 million. The Company canceled all previously purchased 6.25% Senior Notes as at December 31, 2023.
During the year ended December 31, 2023, we implemented a share re-purchase program (the “2023 Program”) through the facilities of the TSX, the NYSE or alternative trading programs in Canada or the United States, if eligible. Under the 2023 Program, we are able to purchase up to 3,234,914 shares of Common Stock, representing 10% of the public float as of October 20, 2023, at prevailing market prices at the time of purchase. The 2023 Program will continue for one year and expire on November 2, 2024, or earlier if the 10% maximum is reached.
During the year ended December 31, 2023, we re-purchased 1,041,804 shares of Common Stock at a weighted average price of approximately $6.21 per share under the 2023 Program and 1,328,650 shares of Common Stock at a weighted average price of $8.15 per share, under the 2022 share re-purchase program (“2022 Program”), implemented in 2022 with similar terms to that of the 2023 Program. The 2022 Program expired in May 2023 when 10% share maximum was reached. The weighted average price per share under the 2022 Program was $10.59 per share. As of December 31, 2023, all 3,603,396 shares re-purchased under the 2022 Program and 1,041,804 shares re-purchased under 2023 Program were cancelled subsequent to re-purchase.
Cash and Cash Equivalents Held Outside of Canada and the United States
At December 31, 2023, 100% of our cash and cash equivalents were held by subsidiaries outside Canada and the United States.
Cash Flows
The following table presents our sources and uses of cash and cash equivalents for the periods presented:
Year Ended December 31,
2023 2022 2021
Sources of Cash and Cash Equivalents:
Net (loss) income $ (6,287) $ 139,029 $ 42,482
Adjustments to reconcile net (loss) income to funds flow from operations
DD&A expenses 215,584 180,280 139,874
Deferred tax expense (recovery) 56,759 25,340 (23,825)
Stock-based compensation expense 5,722 9,049 8,396
Amortization of debt issuance costs 5,831 3,528 3,809
Unrealized foreign exchange (gain) loss (5,085) 10,251 21,879
Other non-cash loss (gain)
2,297 (2,598) 44
Derivative instruments loss - 26,611 48,838
Cash settlement on derivative instruments - (26,611) (58,427)
Other financial instruments loss (gain)
15 (7) 3,369
Non-cash lease expenses 4,967 2,818 1,667
Lease payments (3,018) (1,666) (1,621)
Funds flow from operations (1)
276,785 366,024 186,485
Changes in non-cash operating working capital - 64,317 59,154
Changes in non-cash investing working capital - 26,273 1,431
Proceeds from exercise of stock options 8 1,300 100
Proceeds from debt, net of issuance costs 48,014 - -
Proceeds on disposition of investment, net of transaction costs - - 43,126
Foreign exchange gain on cash and cash equivalents and restricted cash and cash equivalents
5,869 - -
330,676 457,914 290,296
Uses of Cash and Cash Equivalents:
Additions to property, plant and equipment (218,882) (236,604) (149,879)
Repayment of Senior Notes (60,000) - -
Proceeds from debt, net of issuance costs - - (228)
Repayment of debt (13,636) (67,803) (122,500)
Lease payments (6,527) (2,228) (2,182)
Proceeds from other debt, net of issuance costs (13,351) - -
Changes in non-cash operating working capital (48,416) - -
Changes in non-cash investing working capital (7,702) - -
Cash settlement of asset retirement obligation (377) (2,630) (805)
Re-purchase of shares of Common Stock (17,300) (27,317) -
Re-purchase of Senior Notes (6,805) (17,274) -
Foreign exchange loss on cash and cash equivalents and restricted cash and cash equivalents
- (2,104) (821)
(392,996) (355,960) (276,415)
Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents $ (62,320) $ 101,954 $ 13,881
(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.
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, 2023:
(Thousands of U.S. Dollars) Total 2024 2025-2026
2027-2028
2029 and beyond
Credit facility $ 36,364 $ 36,364 $ - $ - $ -
6.25% Senior Notes
24,828 - 24,828 - -
7.75% Senior Notes
24,201 - - 24,201 -
9.50% Senior Notes
487,590 - 121,898 170,657 195,035
Total debt
572,983 36,364 146,726 194,858 195,035
Interest payments (1)
217,704 49,682 90,583 61,911 15,528
Facilities 8,317 2,483 4,952 882 -
Operating leases 12,857 4,309 4,909 3,639 -
Finance leases 31,630 10,607 12,310 8,713 -
Software and Telecommunication 396 332 64 - -
Total $ 843,887 $ 103,777 $ 259,544 $ 270,003 $ 210,563
(1) Interest payments were calculated on our credit facility till termination date on February 6, 2024, and on our 6.25% Senior Notes, 7.75% Senior Notes, and 9.50% Senior Notes under assumption that Senior Notes will be held until their maturity dates of February 2025, May 2027, and October 2029, respectively. Actual results will differ from these estimates and assumptions.
At December 31, 2023, we provided promissory notes totaling $220.1 million (2022 - $111.1 million) to support letters of credit relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, the Suroriente Block and other capital or operating requirements.
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 9 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.
Climate Change
We have considered the impact of the climate events on the following items presented in this Annual Report on Form 10-K for the fiscal year ended December 31, 2023:
Impairment
We have considered the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in the ceiling test impairment assessment on oil and gas properties. The estimated ceiling amount of our oil and gas properties was based on proved reserves, the life of which is generally less than 15 years. The ultimate period in which global energy markets can transition from carbon-based sources to alternative energy is highly uncertain. However, the majority of the cash flows associated with proved reserves per the 2023 reserve report should be realized prior to the potential elimination of carbon-based energy.
Expenditures on property, plant and equipment
From 2018 to 2023, we incurred $22.9 million on gas-to-power facilities in the Acordionero field to reduce emissions principally by the recovery and use of natural gas in the field for power generation and reduction of diesel use for power generation. In 2023, the Acordionero field represented 52% of our production. As of the end of 2023, Gran Tierra converts gas to power at seven of our facilities located in the Acordionero, Costayaco, Moqueta, Mono Arana, Los Angeles Cohembi and Juglar fields. In total, we converted 2.7 billion standard cubic feet of natural gas into electricity instead of being flared for the
year ended December 31, 2023 and have incurred capital expenditures of $28.5 million since 2018. The extent of spending on projects directly linked to reducing the climate impact of our operations.
We voluntarily support projects for the protection of the environment. Through programs like Gran Tierra’s flagship environmental initiative, NaturAmazonas, in partnership with the international non-governmental organization Conservation International, we have committed to reforesting 1,000 hectares of land and securing and maintaining 18,000 hectares of forest in the Andes-Amazon rainforest corridor. The NaturAmazonas project alone is expected to sequester approximately 8.7 million tonnes of carbon dioxide over its lifetime. During the year ended December 31, 2023, Gran Tierra signed a four-year extension with Conservation International to continue the NaturAmazonas project. This extension will, among other benefits, result in the development of the additional 100 restoration agreements to restore more than 250 additional hectares of land while ensuring the benefits from NaturAmazonas’ first phase sustain. We have planted over 1.5 million trees and conserved, preserved, or reforested more than 3,800 hectares of land through all of our environmental efforts since 2018. We will continue to implement projects that focus on environmental protection, conservation and reforestation efforts.
Current assets and current liabilities
These amounts are short-term in nature, and during the year ended December 31, 2023, management was not aware of any material impacts on these items related to climate change and climate events. We did not experience material credit losses on our accounts receivable during 2023.
Share capital
The evolving energy transition and general sentiment to the oil and gas industry may result in reduced access to capital markets.
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 the 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 and the impact of estimated proved oil and gas reserves on the calculations of depletion expense and the ceiling test related to 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.”
Our estimates of proved oil and natural 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 impact oil and natural 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 reservoir engineering specialists.
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 test calculation dictates that a 10% discount factor be used and future net revenues are calculated using the unweighted arithmetic average of the first-day-of-the month Brent price for the 12-month period prior to the ending date of the period covered by the balance sheet. 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, 2023 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 reservoir engineering specialists 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 reservoir engineering specialists, their independence.
For the years ended December 31, 2023, 2022 and 2021 we had no ceiling test impairment losses. We used an average Brent price of $82.51 per bbl less corresponding differentials for the purposes of the December 31, 2023 ceiling test calculations (2022 and 2021 - $97.98 and $68.92, respectively).
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 (“ARO”)
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.
Income Taxes
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. This determination involves numerous judgments and assumptions and includes estimating factors such as commodity prices, production and other operating conditions. If any of those factors, assumptions or judgments change, the deferred tax asset could change, and in particular decrease in a period where we determine it is more likely than not that the asset will not be realized. Alternatively, a valuation allowance may be reversed where it is determined it is more likely not that the asset will be realized.
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 amount 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.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our principal market risk relates to oil prices. Oil prices are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Our revenues are from oil sales at Brent pricing and adjusted for quality.
Foreign Currency Risk
Foreign currency risk is a factor for our company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. Our reporting currency is U.S. dollars and 100% of our revenues are related to the U.S. dollar price of Brent or WTI oil. In Colombia, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures are in U.S. dollars or are based on U.S. dollar prices. The majority of income and VAT and G&A expenses in all locations are in local currency.
Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our accounts payable, taxes receivable and payable and deferred tax assets and liabilities in Colombia are denominated in the local currency of the Colombian foreign operations which are our monetary assets. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency. A one percent strengthening in Colombian peso against the U.S. dollar results in foreign exchange loss of approximately 0.4 million U.S. dollars on accounts payable, gain of approximately $0.3 million U.S. dollars on taxes receivable and payable and loss of approximately $0.4 million U.S. dollars on deferred tax assets and liabilities.
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our credit facility, which bears floating rates of interest. At December 31, 2023, our credit facility was drawn by $36.4 million (December 31, 2022 - undrawn).
Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issues at overnight rates, or U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. A 10% change in interest rates would not have a material effect on the value of our investment portfolio. We do not hold any of these investments for trading purposes.
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Shareholders and 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. and subsidiaries (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, 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, 2023, 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 20, 2024 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 Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates 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 a critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of estimated proved oil and gas reserves on the calculations of depletion expense and the ceiling test related to Colombian 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 are depleted over the estimated proved oil and gas reserves. As discussed in Note 4 to the consolidated financial statements, the Company recorded depletion and depreciation expense of $209.7 million for the year ended December 31, 2023, a portion of which related to Colombian oil and gas properties. Additionally, as discussed in Note 2 to the consolidated financial statements, the Company performs a ceiling test calculation as of each quarter end on a country-by-country basis. In performing its quarterly ceiling test, the Company limits the capitalized costs of proved oil and 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 limitation, the Company will record a ceiling test impairment to the extent of such excess. As discussed in Note 5 to the consolidated financial statements, the Company did not record a ceiling test impairment in 2023 related to Colombian oil and gas properties. 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 assumptions related to forecasted production and forecasted operating, royalty and capital costs (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 Colombian 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 test. 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 tests.
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. This included controls related to the:
•calculation of depletion expense and the ceiling test
•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 2023 actual production and 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.
/s/ KPMG LLP
Chartered Professional Accountants
We have served as the Company’s auditor since 2018
Calgary, Canada
February 20, 2024
Gran Tierra Energy Inc.
Consolidated Statements of Operations
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
Year Ended December 31,
2023 2022 2021
OIL SALES (NOTE 10)
$ 636,957 $ 711,388 $ 473,722
EXPENSES
Operating 186,864 162,385 135,722
Transportation 14,546 10,197 11,618
Depletion, depreciation and accretion (Note 4)
215,584 180,280 139,874
General and administrative (Note 13)
45,846 40,957 36,263
Foreign exchange loss
11,822 2,578 20,477
Derivative instruments loss (Note 13)
- 26,611 48,838
Other financial instruments loss (gain) (Note 13)
15 (7) 3,369
Interest expense (Note 7)
55,806 46,493 54,381
TOTAL EXPENSES 530,483 469,494 450,542
OTHER (LOSS) GAIN (Note 7)
(2,297) 2,598 (44)
INTEREST INCOME 1,983 443 -
INCOME BEFORE INCOME TAXES 106,160 244,935 23,136
INCOME TAX EXPENSE (RECOVERY)
Current (Note 11)
55,688 80,566 4,479
Deferred (Note 11)
56,759 25,340 (23,825)
112,447 105,906 (19,346)
NET AND COMPREHENSIVE (LOSS) INCOME $ (6,287) $ 139,029 $ 42,482
NET (LOSS) INCOME PER SHARE (1)
-BASIC
$ (0.19) $ 3.81 $ 1.16
-DILUTED
$ (0.19) $ 3.76 $ 1.15
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 8)
33,469,828 36,445,546 36,702,290
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 8)
33,469,828 36,928,010 36,787,339
(1) Reflects our 1-for-10 reverse stock split that became effective May 5, 2023. See Note 8 in the notes to the consolidated financial statements for further discussion.
(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,
2023 2022
ASSETS
Current Assets
Cash and cash equivalents $ 62,146 $ 126,873
Accounts receivable (Note 3)
12,359 10,706
Inventory
29,039 20,192
Other current assets (Note 13 and 14)
8,920 10,816
Total Current Assets 112,464 168,587
Oil and Gas Properties (using the full cost method of accounting)
Proved 1,055,070 1,000,424
Unproved 54,116 74,471
Total Oil and Gas Properties 1,109,186 1,074,895
Other capital assets 33,664 26,007
Total Property, Plant and Equipment (Note 4)
1,142,850 1,100,902
Other Long-Term Assets
Taxes receivable 52,089 27,796
Deferred tax assets (Note 11)
10,923 22,990
Other long-term assets (Note 13 and 14)
7,963 15,335
Total Other Long-Term Assets 70,975 66,121
Total Assets $ 1,326,289 $ 1,335,610
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities (Note 6, 7 and 9)
$ 187,007 $ 167,579
Credit facility (Note 7)
35,609 -
Taxes payable (Note 11)
27,219 58,978
Equity compensation award liability (Note 8)
10,419 15,082
Total Current Liabilities 260,254 241,639
Long-Term Liabilities
Long-term debt (Note 7)
519,532 589,593
Deferred tax liabilities (Note 11)
57,453 28
Asset retirement obligation (Note 9)
73,029 63,358
Equity compensation award liabilities (Note 8)
8,750 16,437
Other long-term liabilities (Note 13)
10,877 6,989
Total Long-Term Liabilities 669,641 676,405
Commitments and Contingencies (Note 12)
Shareholders’ Equity (1)
Common Stock (Note 8) (32,275,113 and 36,889,862 issued, 32,246,501 and 34,615,116 outstanding shares of Common Stock, par value $0.001 per share, as at December 31, 2023, and December 31, 2022, respectively)
9,936 10,272
Additional paid in capital 1,249,651 1,291,354
Treasury stock (Note 8)
(163) (27,317)
Deficit (863,030) (856,743)
Total Shareholders’ Equity 396,394 417,566
Total Liabilities and Shareholders’ Equity $ 1,326,289 $ 1,335,610
(1) Reflects our 1-for-10 reverse stock split that became effective May 5, 2023. See Note 8 in the notes to the consolidated financial statements for further discussion.
(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,
2023 2022 2021
Operating Activities
Net (loss) income $ (6,287) $ 139,029 $ 42,482
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 4)
215,584 180,280 139,874
Deferred tax expense (recovery) (Note 11)
56,759 25,340 (23,825)
Stock-based compensation expense (Note 8)
5,722 9,049 8,396
Amortization of debt issuance costs (Note 7)
5,831 3,528 3,809
Non-cash lease expenses 4,967 2,818 1,667
Lease payments (3,018) (1,666) (1,621)
Unrealized foreign exchange (gain) loss (5,085) 10,251 21,879
Derivative instruments loss (Note 13)
- 26,611 48,838
Cash settlement on derivatives instruments (Note 13)
- (26,611) (58,427)
Other financial instruments (gain) loss (Note 13)
15 (7) 3,369
Cash settlement of asset retirement obligation (Note 9)
(377) (2,630) (805)
Other non-cash loss (gain) (Note 7)
2,297 (2,598) 44
Net change in assets and liabilities from operating activities (Note 14)
(48,416) 64,317 59,154
Net cash provided by operating activities 227,992 427,711 244,834
Investing Activities
Additions to property, plant and equipment (Note 4)
(218,882) (236,604) (149,879)
Changes in non-cash investing working capital
(7,702) 26,273 1,431
Proceeds on disposition of investment, net of transaction costs (Note 13)
- - 43,126
Net cash used in investing activities (Note 14) (226,584) (210,331) (105,322)
Financing Activities
Purchase of Senior Notes (Note 7)
(6,805) (17,274) -
Senior Notes issuance costs
(13,351) - -
Repayment of Senior Notes (Note 7)
(60,000) - -
Proceeds from debt, net of issuance costs (Note 7)
48,014 - (228)
Repayment of debt (Note 7)
(13,636) (67,803) (122,500)
Lease payments (6,527) (2,228) (2,182)
Proceeds from exercise of stock options (Note 8)
8 1,300 100
Re-purchase of shares of Common Stock (Note 8)
(17,300) (27,317) -
Net cash used in financing activities (69,597) (113,322) (124,810)
Foreign exchange gain (loss) on cash and cash equivalents and restricted cash and cash equivalents 5,869 (2,104) (821)
Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents (62,320) 101,954 13,881
Cash and cash equivalents and restricted cash and cash equivalents,
beginning of year (Note 14)
133,358 31,404 17,523
Cash and cash equivalents and restricted cash and cash equivalents,
end of year (Note 14)
$ 71,038 $ 133,358 $ 31,404
Supplemental cash flow disclosures (Note 14)
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Consolidated Statements of Shareholders’ Equity
(Thousands of U.S. Dollars)
Year Ended December 31,
2023 2022 2021
Share Capital (1)
Balance, beginning of year $ 10,272 $ 10,270 $ 10,270
Reverse stock split (Note 8)
(299) - -
Cancellation of shares of Common Stock (Note 8)
(37) - -
Issuance of shares of Common Stock, net of issuance costs (Note 8)
- 2 -
Balance, end of year 9,936 10,272 10,270
Additional Paid in Capital
Balance, beginning of year 1,291,354 1,287,582 1,285,018
Reverse stock split (Note 8)
299 - -
Cancellation of shares of Common Stock (Note 8)
(44,417) - -
Exercise of stock options (Note 8)
8 1,298 100
Stock-based compensation (Note 8)
2,407 2,474 2,464
Balance, end of year 1,249,651 1,291,354 1,287,582
Treasury Stock
Balance, beginning of year (27,317) - -
Purchase of treasury shares (Note 8)
(17,300) (27,317) -
Cancellation of treasury shares (Note 8)
44,454 - -
Balance, end of year (163) (27,317) -
Deficit
Balance, beginning of year (856,743) (995,772) (1,038,254)
Net (loss) income (6,287) 139,029 42,482
Balance, end of year (863,030) (856,743) (995,772)
Total Shareholders’ Equity $ 396,394 $ 417,566 $ 302,080
(1) Reflects our 1-for-10 reverse stock split that became effective May 5, 2023. See Note 8 in the notes to the consolidated financial statements for further discussion.
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years Ended December 31, 2023, 2022 and 2021
(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. Certain estimates and judgments have a material impact where the assumptions underlying these accounting estimates relate to matters that involve significant estimation uncertainty at the time the estimate or judgement is made or are subjective. These estimates and judgments include, but are not limited to:
•estimated proved and probable reserves volumes and the related cash flows are determined by the independent reservoir engineering specialists and used in several of the estimates made by management in preparing these financial statements. Numerous estimates are required to be made in the reserve report, including forecasted production, forecasted operating and royalty costs, capital cost assumptions, and in certain cases forecasted commodity prices;
•depletion, depreciation and accretion (“DD&A”);
•timing of transfers from oil and gas properties not subject to depletion to the depletable base;
•impairment of proved oil and gas properties as determined using the full cost method of accounting for our oil and natural gas properties in accordance with SEC Regulation S-X Rule 4-10;
•asset retirement obligations;
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.
Some of the Company’s estimates and judgements have a material impact on consolidated financial statements but do not involve significant subjectivity of estimation uncertainty. These estimates and judgements include, but are not limited to;
•income taxes; and
•stock-based compensation
•prepaid equity forwards (“PEF”);
•operating and finance leases; and
•debt extinguishment and debt modification accounting
•assessment of the likely outcome of legal and other contingencies;
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 are comprised of 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.
Prepaid Equity Forwards
The Company is exposed to equity price risk in relation to its long-term incentive plans. The Company utilizes prepaid equity forwards on the equivalent number of the Company’s common shares in order to fix the future settlement cost on a portion of its cash-settled long-term incentive plans.
PEF is recorded in other current and long-term assets on the Company’s balance sheet at fair value, with changes in fair value recognized as G&A expense in the consolidated statements of operations. The Company utilizes PEF to manage equity price risk in relation to its long-term incentive plans.
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 royalties.
Income Taxes
Income taxes are recognized using the asset and 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 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. Valuation allowances are provided if, after considering the 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, 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 the 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 result 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, 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, 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. During any period in which factors indicate impairment, the cumulative costs incurred to date for such property are transferred to the full cost pool and subject to depletion. For countries where a reserve base has not yet been established, the impairment is charged to net income or loss.
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 is 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, 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 expenses as incurred.
Leases
At the 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 the 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.
Debt extinguishment and debt modification accounting
The Company accounts for debt restructuring or exchange of debt transactions as either a debt extinguishment or a debt modification. For instruments not involving conversion options, the Company recognizes an exchange of debt as an extinguishment if the present value of the cash flows under the terms of the new debt instrument is at least 10 percent different from the present value of the remaining cash flows under the terms of the original instrument. If the exchange of debt is accounted for as a debt extinguishment, the carrying value of the original debt including unamortized deferred financing fees is derecognized from our balance sheet and the new debt is recognized at its fair value less applicable deferred financing fees, with the difference between the net carrying value of the original debt and the fair value of the new debt recognized as a gain or loss in the consolidated statements of operations. If the terms of a debt instrument are changed or modified and the cash flow effect on a present value basis is less than 10 percent, the debt instrument is not considered to be substantially different, the Company accounts for this debt instrument as debt modification. If the exchange of debt is accounted for as a debt modification, the change of the carrying amount of the original debt on the balance sheet is adjusted to the net present value of the revised cash flows with the adjustments treated as a capital cost and amortized as an adjustment of interest expense on our statement of operations.
Revenue from Contracts with Customers
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. 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 arrangements 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 the ability to establish prices, or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in the 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 the 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 an agent in transactions, management determines if the Company obtains control of the product. As part of this assessment, management considers the criteria for revenue recognition set out in Accounting Standard Codification 606.
Stock-based Compensation
The Company records stock-based compensation expense in its consolidated financial statements measured at 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, the expense is recognized over the three-year vesting period based on the latest available estimate of the fair value of the awards 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-Merton 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 G&A or operating expenses, as appropriate.
Foreign Currency Translation
The functional currency of the Company, including its subsidiaries, is the U.S. 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.
Net Income or Loss per Share
Basic net income or 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 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 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.
Risks and Measurement Uncertainty
The impacts of ongoing conflicts in several parts of the world coupled with volatility in energy markets, increased interest and inflation rates and constrained supply chains have created a higher level of volatility and uncertainty. Management has, to the reasonable extent, incorporated known facts and circumstances into the estimates made; however, the increased levels of uncertainly and volatility make accounting estimates more judgmental, and the actual results could differ materially from estimates.
Recently Issued Accounting Pronouncements
In October 2023, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standard Update (“ASU”) 2023-06, “Disclosure Improvements.” This ASU includes an update to the disclosures and presentation requirements of a variety of topics. Affected topics include: an update to the statement of cash flows, commitments, earnings per share, derivatives and hedging, extractive activities and credit risk disclosures, among other things. This ASU should be applied prospectively and the effective date will be the date on which the SEC’s removal of the related disclosures from Regulation S-X
becomes effective, with early adoption prohibited. The Company does not expect that adoption of this ASU would have a material impact on the Company’s presentation and disclosures of consolidated financial statements as its currently subject to presentation and disclosures of relevant S-X Regulations.
In November 2023, FASB issued ASU 2023-07, “Improvements to Reportable Segment Disclosures” for interim and annual financial reporting for all public entities, including those that have a single reportable segment. ASU 2023-07 requires to disclose by each reportable segment the significant segment expenses that are regularly provided to chief operating decision maker, amount and composition of other segment items, measure of segment’s profit or loss in assessing segment performance and how resources are allocated if used by chief operating decision maker and title and position of the chief operating decision maker. If a public entity discloses a single reportable segment, it should identify the measure or measures of a segment’s profit or loss that chief operating decision maker uses in assessing segment performance and deciding how to allocate the resources. The public entity is required to recast the prior-period segment expense information to conform to current-period presentation unless it is impracticable to do so. This ASU is effective for fiscal periods beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024 and should be applied retrospectively to all periods presented in the financial statements, with early adoption permitted. The Company adopted ASU 2023-07 effective January 1, 2024.
In December 2023, FASB issued ASU 2023-09, “Improvements to Income Tax Disclosures.” ASU 2023-09 enhances the income tax disclosures to enable investors to better understand entity’s exposure to potential changes in jurisdictional tax legislation and associated risks and opportunities, income tax information that effects cash flow forecasts and potential opportunities to increase future cash flows. This ASU is effective for annual periods beginning after December 15, 2024 and should be applied prospectively, with retrospective application permitted. At December 31, 2023, the Company performed assessment of its income tax disclosures and does not believe that adoption of ASU 2023-09 would have a material impact on disclosures of income taxes.
3. Accounts Receivable
As at December 31,
(Thousands of U.S. Dollars) 2023 2022
Trade $ 5,812 $ 5,601
Other 6,547 5,105
Total Accounts Receivable $ 12,359 $ 10,706
4. Property, Plant and Equipment
As at December 31,
(Thousands of U.S. Dollars) 2023 2022
Oil and natural gas properties
Proved $ 4,876,185 $ 4,617,804
Unproved 54,116 74,471
4,930,301 4,692,275
Other (1)
73,505 61,386
5,003,806 4,753,661
Accumulated depletion, depreciation and impairment (3,860,956) (3,652,759)
$ 1,142,850 $ 1,100,902
(1) The “other” category includes $53.3 million right-of-use assets for finance leases and operating leases, which had a net book value of $32.4 million as at December 31, 2023 (December 31, 2022 - $38.9 million which had a net book value of $24.6 million).
On April 11, 2023, the Company and Ecopetrol S.A. renegotiated the terms of the contract for Company’s operatorship of the Suroriente Block, which was previously scheduled to end in mid-2024 and executed the Suroriente Continuation Agreement. The duration of the contract was extended for 20 years from September 1, 2023 (the “Effective Date”), the date on which the Company satisfied the relevant conditions precedent and regulatory approval was received. The Company continues to be the operator of the Suroriente Block. In connection with the contract extension, the Company paid cash consideration of $6.2 million and provided letters of credit of $123.0 million (Note 12) related to committed capital investments to be made over a three-year period from the Effective Date.
During the year ended December 31, 2023, the Company entered into new lease contracts related to power generating equipment and capitalized $12.4 million right-of-use assets related to those contracts.
Depletion and depreciation expense on property, plant and equipment for the year ended December 31, 2023, was $209.7 million (2022 - $175.8 million; 2021 - $135.7 million). A portion of depletion and depreciation expense was recorded as oil inventory in each year.
Unproved Oil and Natural Gas Properties
At December 31, 2023, 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, 2023, 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, 2023:
Costs Incurred in
(Thousands of U.S. Dollars) 2023 2022 2021 Prior to 2021
Total
Acquisition costs - Colombia $ - $ - $ - $ 5,161 $ 5,161
Exploration costs - Colombia 2,743 6,742 1,736 24,711 35,932
Exploration costs - Ecuador 10,380 499 472 1,672 13,023
$ 13,123 $ 7,241 $ 2,208 $ 31,544 $ 54,116
5. Asset impairment
For the years ended December 31, 2023, 2022 and 2021 the Company had no ceiling test impairment losses. In accordance with GAAP, Gran Tierra used an unweighted arithmetic average of the first-day-of-the-month Brent price of $82.51 per bbl for the December 31, 2023 ceiling test calculations (December 31, 2022, and 2021 - $97.98 and $68.92 per bbl, respectively).
The Company has considered the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in the impairment assessment on oil and gas properties. The estimated ceiling amount of the Company’s oil and gas properties was based on proved reserves, the life of which is generally less than 15 years. The ultimate period in which global energy markets can transition from carbon-based sources to alternative energy is highly uncertain. However, the majority of the cash flows associated with proved reserves per the 2023 reserve report is expected to be realized prior to the potential elimination of carbon-based energy.
At December 31, 2023, a specific adjustment to the discount rate used in the ceiling test to account for the risk of the evolving demand for energy is not permitted as under the full cost accounting the 10% discount rate is prescribed.
6. Accounts Payable and Accrued Liabilities
As at December 31,
(Thousands of U.S. Dollars) 2023 2022
Trade $ 122,709 $ 114,263
Royalties 2,636 2,760
Employee compensation 6,221 3,051
Other 55,441 47,505
$ 187,007 $ 167,579
7. Debt and Debt Issuance Costs
The Company’s debt at December 31, 2023 and 2022, was as follows:
As at December 31,
(Thousands of U.S. Dollars) 2023 2022
Current
Credit Facility
$ 36,364 $ -
Unamortized debt issuance costs (755) -
$ 35,609 $ -
Long-term
6.25% Senior Notes
$ 24,828 $ 279,909
7.75% Senior Notes
24,201 300,000
9.50% Senior Notes
487,590 -
Unamortized Senior Notes discount
(27,958) (4,138)
Unamortized debt issuance costs
(15,679) (6,854)
Long-term lease obligation (1)
26,550 20,676
$ 519,532 $ 589,593
Total Debt
$ 555,141 $ 589,593
(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 $12.1 million as at December 31, 2023 (December 31, 2022 - $4.8 million).
Senior Notes
(Thousands of U.S. Dollars) 6.25% Senior Notes
7.75% Senior Notes
9.50% Senior Notes
Senior Notes, December 31, 2022
$ 279,909 $ 300,000 $ -
Purchased in the open market (1)
(8,000) - -
Principal exchanged for 9.50% Senior Notes (2)
(247,081) (275,799) 522,782
Early participation premiums and discount for principal exchanged (3) (4)
- - 24,808
Principal payment (5)
- - (60,000)
Senior Notes principal, December 31, 2023
$ 24,828 $ 24,201 $ 487,590
(1) During the year ended December 31, 2023, the Company purchased in the open market $8.0 million of 6.25% Senior Notes for cash consideration of $6.8 million. The purchase resulted in a $1.1 million gain, which included the write-off of deferred financing fees of $0.1 million. The purchase gain was recorded in “other gain” in the Company’s consolidated statements of operations. The Company cancelled all previously purchased 6.25% Senior Notes as at December 31, 2023.
(2) $247.1 million of 6.25% Senior Notes principal and $275.8 million of 7.75% Senior Notes principal exchanged for a net $487.6 million newly issued 9.50% Senior Notes.
(3) Early participation premium of $80 for each $1,000 aggregate principal amount and $20 for each $1,000 aggregate principal amount for the 6.25% Senior Notes and 7.75% Senior Notes, respectively. $242.5 million and $274.2 million of 6.25% Senior Notes and 7.75% Senior Notes, respectively, were exchanged for these terms.
(4) $4.6 million of remaining principal exchanged at $1,000 and $1.6 million of remaining principal exchanged at $950 for each $1,000 aggregate principal amount for the 6.25% Senior Notes and 7.75% Senior Notes, respectively.
(5) The Company paid cash consideration of $60.0 million for 6.25% Senior Notes exchanged as part of total consideration to eligible holders on a pro rata basis, for each $1,000 aggregate principal amount tendered and accepted for the early exchange deadline.
The Senior Notes tendered and accepted for exchange, as well as the notes previously held as treasury bonds, were cancelled. The exchange of the 6.25% Senior Notes was accounted for as debt extinguishment.and resulted in a gain of $5.3 million. The exchange of 7.75% Senior Notes was accounted for as debt modification and resulted in a loss of $6.1 million related to third party fees.
At December 31, 2023, the Company had $24.2 million of 7.75% Senior Notes due 2027, $24.8 million of 6.25% Senior Notes due 2025 and $487.6 million of newly issued 9.50% Senior Notes due 2029.
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 re-purchased.
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: 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 re-purchased.
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: 2024 and thereafter - 100%.
The 9.50% Senior Notes bear interest at a rate of 9.50% per year, payable semi-annually in arrears on April 15 and October 15 of each year, beginning on April 15, 2024. The 9.50% Senior Notes will mature on October 15, 2029, unless earlier redeemed or re-purchased.
The principal amount of 9.50% Senior Notes is to be repaid as follows: (i) October 15, 2026, 25% of the principal amount; (ii) October 15, 2027, 5% of the principal amount; (iii) October 15, 2028, 30% of the principal amount; and (iv) October 15, 2029, the remainder of the principal amount.
At any time, prior to October 15, 2026, the Company may redeem 35% of the aggregate principal amount of 9.50% Senior Notes at a redemption price equal to 109.50% of the principal amount. Additionally, the Company may redeem all or a portion of the 9.50% Senior Notes:
(i) prior to October 15, 2026, at a redemption price equal to a 100% principal amount plus an applicable premium, which is the greater of:
•1% of the principal amount of 9.50% Senior Notes, and
•the excess of the present value of the redemption price plus all required interest payments computed using a discount rate equal to the Treasury rate at the redemption date plus 0.5% due to date, excluding accrued but unpaid interest, over the outstanding principal amount of 9.50% Senior Notes
(ii) On or after October 15, 2026, at the following redemption prices: 2026 -104.750%; 2027 -102.375%; 2028 and thereafter - 100%.
If the Company undergoes a change of control, holders may require the Company to repurchase for cash all or any portion of their 9.50% Senior Notes at a change of control repurchase price equal to 101% of the principal amount plus accrued and unpaid interest to, but excluding, the change of control repurchase date.
On February 6, 2024, the Company issued additional $100.0 million of 9.50% Senior Notes and received net cash proceeds of $88.0 million as a result of this issuance. The newly issued 9.50% Senior Notes have the same terms and provisions, except for the issue price, as $487.6 million 9.50% Senior Notes outstanding at December 31, 2023 and will be combined together with originally issued 9.50% Senior Notes in respect of interest payments.
Credit Facility
During the year ended December 31, 2023, the Company, as guarantor, and Gran Tierra Energy Colombia GmbH and Gran Tierra Operations Colombia GmbH, as borrowers, amended and restated their credit facility with a market leader in the global commodities industry. As part of the restatement, the initial commitment was adjusted from $100 million to $50 million (maintaining the potential option of up to an additional $50 million, subject to approval by the lender). Additionally, the availability period for the draws under the amendment to the credit facility was extended until December 31, 2023, following which the credit facility is no longer advanceable. The credit facility continues to bear interest based on the secured overnight financing rate posted by the Federal Reserve Bank of New York, plus a credit margin of 6.00% and a credit-adjusted spread of 0.26%. Undrawn amounts under the credit facility bear interest at 2.10% per annum, based on the amount available. The credit facility is secured by the Company’s Colombian assets and economic rights and has a final maturity date of August 15, 2024. As of December 31, 2023, the credit facility was drawn by $36.4 million. For the year ended December 31, 2023, the Company incurred weighted-average interest rate on the credit facility of 11.59%.
Under the terms of the credit facility, the Company is required to maintain compliance with the following financial covenants:
i.Global Coverage Ratio of at least 150%, calculated using the net present value of the consolidated future cash flows of the Company up to the final maturity date discounted at 10% over the outstanding amount on the credit facility at each reporting period. The net present value of the consolidated future cash flows of the Company is required to be based on 80% of the prevailing ICE Brent forward strip.
ii.Prepayment Life Coverage Ratio of at least 150%, calculated using the estimated aggregate value of commodities to be delivered under the commercial contract from the commencement date to the final maturity date based on 80% of the prevailing ICE Brent forward strip and adjusted for quality and transportation discounts over the outstanding amount on the credit facility including interest and all other costs payable to the lender.
i.Liquidity ratio where the Company’s projected sources of cash exceed projected uses of cash by at least 1.15 times in each quarter period included in one year consolidated future cash flows. The future cash flows represent forecasted expected cash flows from operations, less anticipated capital expenditures, and certain other adjustments. The commodity pricing assumption used in this covenant is required to be 90% of the prevailing Brent forward strip for the projected future cash flows.
As of December 31, 2023, the Company was in compliance with all the above covenants.
On February 6, 2024, the outstanding balance under the credit facility was fully re-paid and the credit facility was terminated.
Leases
During the year ended December 31, 2023, the Company recorded three new finance leases for power generating equipment totaling $12.4 million which had the useful life ranging from one to three years and weighted average discount rate of 7.31%.
As of December 31, 2023, the Company’s finance leases had remaining useful lives ranging from one to four years and the weighted average discount rate of 8.45% and operating leases had remaining useful lives ranging from one to five years and the weighted average discount rate of 8.01%.
Interest Expense
The following table presents the total interest expense recognized in the accompanying consolidated statements of operations:
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Contractual interest and other financing expenses $ 49,975 $ 42,965 $ 50,572
Amortization of debt issuance costs 5,831 3,528 3,809
$ 55,806 $ 46,493 $ 54,381
The Company incurred debt issuance costs in connection with the issuance of the 9.50% Senior Notes and its credit facility. As at December 31, 2023, 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.
8. Share Capital
Shares of Common Stock
Shares issued and outstanding, December 31, 2020
36,698,156
Options exercised 16,294
Shares issued and outstanding, December 31, 2021
36,714,450
Options exercised 175,412
Shares issued, December 31, 2022
36,889,862
Shares re-purchased (1)
(2,274,746)
Shares issued and outstanding, December 31, 2022
34,615,116
Options exercised 1,839
Shares re-purchased and canceled (2,341,842)
Shares issued, December 31, 2023
32,275,113
Treasury stock (28,612)
Shares issued and outstanding at December 31, 2023
32,246,501
(1 2,274,746 re-purchased shares in 2022 were canceled during the year ended December 31, 2023.
The Company’s authorized share capital consists of 82 million shares of capital stock, of which 57 million was designated as Common Stock, par value $0.001 per share and 25 million as Preferred Stock, par value $0.001 per share.
On May 5, 2023, the Company completed a 1-for-10 reverse stock split of the Company’s Common Stock. As a result of the reverse stock split, every ten of the Company’s issued shares of Common Stock were automatically combined into one issued share of Common Stock, without any change to the par value per share. All share and per share numbers have been adjusted to reflect the reverse stock split. The Company’s outstanding options were also proportionately adjusted as a result of the reverse stock split to increase the exercise price and reduce the number of shares issuable upon exercise.
Share Re-purchase Program
During the year ended December 31, 2023, the Company implemented a share re-purchase program (the “2023 Program”) through the facilities of the Toronto Stock Exchange, the NYSE American or alternative trading programs in Canada or the United States, if eligible. Under the 2023 Program, the Company is able to purchase up to 3,234,914 shares of Common Stock, representing 10% of the public float as of October 20, 2023, at prevailing market prices at the time of purchase. The 2023 Program will continue for one year and expire on November 2, 2024, or earlier if the 10% maximum is reached.
During the year ended December 31, 2023, the Company re-purchased 1,041,804 shares of Common Stock at a weighted average price of approximately $6.21 per share under the 2023 Program and 1,328,650 shares at a weighted average price of $8.15 per share under the 2022 Program implemented in 2022 with similar terms to that of the 2023 Program. The 2022 Program expired in May 2023 when 10% share maximum was reached. The weighted average price per share under the 2022 Program was $10.59 per share. As of December 31, 2023, all 3,603,396 shares re-purchased under the 2022 Program and 1,013,192 shares re-purchased under the 2023 Program were cancelled subsequent to re-purchase.
Equity Compensation Awards
The Company has an equity compensation program for its executives, employees, and directors. Executives and employees are given equity compensation grants that vest based on a recipient’s continued employment. In the case of Performance Share Units (“PSUs”), the number of units that vest is dependent upon the achievement of specific key performance measures. Equity based awards consist of 80% of PSUs and 20% of stock options. The Company’s stock-based compensation awards outstanding as at December 31, 2023, include PSUs, deferred share units (“DSUs”), and stock options.
In accordance with the 2007 Equity Incentive Plan, as amended, the Company’s Board of Directors is authorized to issue options or other rights to acquire shares of the Company’s Common Stock. On June 27, 2012, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 2,330,610 shares to 3,980,610 shares. On June 2, 2021, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 3,980,610 shares to 5,480,610 shares. On May 4, 2022, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 5,480,610 shares to 5,980,610 shares.
The following table provides information about PSU, DSU and stock option activity for the year ended December 31, 2023:
PSUs DSUs Stock Options
Number of Outstanding Share Units Number of Outstanding Share Units Number of Outstanding Stock Options Weighted Average Exercise Price ($)
Balance, December 31, 2022
3,152,823 656,186 1,730,286 11.52
Granted 2,288,515 120,424 461,858 8.39
Exercised (1,523,408) - (1,839) 4.17
Forfeited (21,574) - (24,072) 7.04
Expired - - (138,426) 25.30
Balance, December 31, 2023
3,896,356 776,610 2,027,807 9.93
Vested and exercisable, at December 31, 2023
1,232,629 10.13
Vested, or expected to vest, at December 31, 2023 through the life of the options
2,002,537 9.93
For the year ended December 31, 2023, Stock-based compensation expense was $5.7 million (2022 - $9.0 million; 2021 - $8.4 million) and was recorded in G&A expenses.
At December 31, 2023, there was $8.6 million (December 31, 2022 - $10.5 million) of unrecognized compensation cost related to unvested PSUs and stock options 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, 2023, is 2.3 years.
PSUs
PSUs entitle the holder to receive, at the option of the Company, either the underlying number of shares of the Company’s Common Stock upon vesting of such units or a cash payment equal to the value of the underlying shares. PSUs will cliff vest after three years, subject to the grantee’s continued employment. 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, 2023, 1.8 million (December 31, 2022 - 1.2 million) of PSUs had vested and will settle in cash. The performance targets for the PSUs outstanding as at December 31, 2023, 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.2021 and 2022 awards: 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;
2023 awards: 25% of the award is subject to compliance with financial covenants and $20 million free cash flow (1);
and
iii.25% of the award is subject to targets relating to the execution of corporate strategy.
(1) Defined as funds flow from operations less capital expenditures before exploration expense and short-term incentive plan.
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. In excess of the target number granted, PSUs 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, 2023, DSUs were granted to directors and will be settled 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 and vest over three years. The term of the stock options granted is five years or three months after the grantee’s end of service to the Company, whichever occurs first.
For the year ended December 31, 2023, 1,839 stock options were exercised, and $8.0 thousand cash proceeds were received (2022 - 175,412 stock options were exercised, and $1.3 million cash proceeds were received and 2021 - 16,294 stock options were exercised, and $0.1 million cash proceeds were received).
At December 31, 2023 and 2022, the weighted average remaining contractual term for outstanding stock options was 2.3 and 2.5 years, respectively, and for exercisable stock options was 1.5 and 1.9 years, respectively.
The fair value of each stock option award is estimated on the date of grant using the Black-Scholes Merton option-pricing model based on assumptions noted in the following table:
Year Ended December 31,
2023 2022 2021
Dividend yield (per share) Nil Nil Nil
Volatility 82% to 90%
77% to 81%
71% to 80%
Weighted average volatility 88 % 77 % 78 %
Risk-free interest rate 3.6% to 4.7%
1.4% to 4.0%
0.4% to 0.9%
Expected term 4 - 5 years
5 years
4 - 5 years
The weighted average grant date fair value for options granted in the year ended December 31, 2023 was $5.57 (2022 - $8.83; 2021 - $4.67) per option. The weighted average grant date fair value for options vested in the year ended December 31, 2023 was $4.77 (2022 - $5.81; 2021 - $5.19) per option. The total fair value of stock options vested during the year ended December 31, 2023 was $2.3 million (2022 - $2.2 million; 2021 - $2.1 million).
Weighted Average Shares Outstanding
Year Ended December 31,
2023 2022 2021
Weighted average number of common shares outstanding 33,469,828 36,445,546 36,702,290
Shares issuable pursuant to stock options - 1,184,732 159,210
Shares assumed to be purchased from proceeds of stock options - (702,268) (74,161)
Weighted average number of diluted common shares outstanding 33,469,828 36,928,010 36,787,339
For the year ended December 31, 2023, all options were excluded from the diluted (loss) earnings per share calculation as the options were anti-dilutive (2022 - 590,025; 2021 - 1,555,982)
9. 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) 2023 2022
Balance, beginning of year $ 63,499 $ 54,525
Liability incurred 4,671 5,025
Settlements (377) (2,630)
Accretion 5,387 4,498
Revisions in estimated liability 328 2,081
Balance, end of year $ 73,508 $ 63,499
Current (1)
$ 479 $ 141
Long-term $ 73,029 $ 63,358
Balance, end of year $ 73,508 $ 63,499
(1) Current portion of asset retirement obligation is included in accounts payable and accrued liabilities on the Company’s balance sheet
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, 2023, the fair value of assets that were legally restricted for purposes of settling asset retirement obligations was $8.9 million (December 31, 2022 - $6.5 million). These assets were accounted for as restricted cash and cash equivalents on the Company’s balance sheet (Note 14).
10. Revenue
During the year ended December 31, 2023, the Company started sales in Ecuador. All of the Company’s revenue is generated from oil sales at prices that 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 (Colombia sales) and Oriente (Ecuador sales) crude differentials, and quality and transportation discounts each month. For the year ended December 31, 2023, 100% (2022 and 2021 - 100%) of the Company's revenue resulted from oil sales and quality and transportation discounts were 18% (2022 - 17%; 2021 - 15%) of the ICE Brent price. During the year ended December 31, 2023, the Company’s production was sold primarily to one major customer representing, 97% of total sales volumes in Colombia and 1% in Ecuador (2022 - two, representing 78% and 22% of total sales volumes in Colombia and 2021 - three, representing 66%, 19% and 12% of total sales volumes in Colombia).
As at December 31, 2023, 2022 and 2021, accounts receivable included nil accrued sales revenue related to December production of each respective year.
11. 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) 2023 2022 2021
Income (loss) before income taxes
United States $ (40,589) $ (38,161) $ (31,329)
Foreign 146,749 283,096 54,465
106,160 244,935 23,136
Statutory rate (1)
45 % 35% 31%
Income tax expense expected 47,772 85,727 7,172
Impact of foreign taxes 21,139 8,876 9,723
Foreign currency translation 39,995 (4,641) 14,450
Stock-based compensation 2,127 5,804 1,708
Change in valuation allowance (10,632) 2,386 (53,434)
Non-deductible third party royalty in Colombia 3,253 3,422 1,568
Other permanent differences 8,793 4,332 (1,058)
Non-deductible investment loss
- - 525
Total income tax expense (recovery) $ 112,447 $ 105,906 $ (19,346)
Effective tax rate 106 % 43% (84)%
Current income tax expense
Foreign 55,688 80,566 4,479
55,688 80,566 4,479
Deferred income tax expense (recovery)
Foreign 56,759 25,340 (23,825)
Total income tax expense (recovery) $ 112,447 $ 105,906 $ (19,346)
(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, 2023, 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 December 2022, the Colombian Government enacted a new tax reform bill which was effective January 1, 2023. The reform includes significant changes to the income tax regime applicable to oil companies, including the elimination of the tax deductibility of royalties paid-in cash, cost associated to royalties paid-in kind in the calculation of taxable income, and the introduction of a surcharge to the current 35% tax rate. The surcharge is determined by comparing the average inflation-adjusted Brent price during the taxation year to the monthly inflation-adjusted Brent price for the prior 120 months. When the Brent price during the taxation year exceeds the 30th percentile of the historical price range, a 5% surtax is applied. It increases to 10% and 15% when the Brent price during the taxation year exceeds the 45th and 60th percentiles, respectively. The 2023 calculation of current and deferred income tax has been prepared with a surtax of 10% for an aggregated income tax rate of 45%. Additionally, during the year ended December 31, 2023, the Constitutional Court declared unconstitutional prohibition for oil and gas and mining companies to deduct for income tax purposes the non-renewable natural resources royalty payments to the Colombian Government. The Company has considered the impact of these changes on its income tax provision.
The table below presents the components of the deferred tax liabilities and assets as at December 31, 2023 and 2022:
As at December 31,
(Thousands of U.S. Dollars) 2023 2022
Tax benefit of operating loss carryforwards $ 29,448 $ 53,720
Book basis in excess of tax basis
(86,510) (20,349)
Foreign tax credits
66,515 66,515
Other accruals
51,022 37,185
Deferred tax assets before valuation allowance 60,475 137,071
Valuation allowance (107,005) (114,109)
Net deferred tax (liabilities) assets
$ (46,530) $ 22,962
Deferred tax assets
10,923 22,990
10,923 22,990
Deferred tax liabilities
57,453 28
57,453 28
Net deferred tax (liabilities) assets
$ (46,530) $ 22,962
At December 31, 2023, the Company has not recognized the benefit of unused non-capital loss carryforwards of $58.8 million (2022 - $91.3 million, 2021 - $62.1 million) for federal purposes in the United States, which expire from 2031 to 2042.
At December 31, 2023, the Company has recognized the benefit of unused non-capital loss carryforwards of $16.5 million (2022 - $40.7 million, 2021 - $102.4 million), out of a total of $20.3 million for federal purposes in Colombia, some of which will expire from 2031 to 2034 and majority be carried forward indefinitely.
As at December 31, 2023, Gran Tierra had $0.8 million of unrecognized tax benefits and related interest and penalties included in its deferred tax assets and current tax liabilities on 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 year ended December 31, 2023. 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 2017 through 2023 in certain jurisdictions.
12. Commitments and Contingencies
Purchase Obligations, Firm Agreements and Leases
As at December 31, 2023, 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 2024 2025 2026 2027 2028 Thereafter
Facilities 8,317 2,483 2,476 2,476 882 - -
Operating leases (1)
12,857 4,309 2,951 1,958 1,985 1,654 -
Finance leases (1)
31,630 10,607 7,322 4,988 3,179 5,534 -
Software and Telecommunication 396 332 64 - - - -
$ 53,200 $ 17,731 $ 12,813 $ 9,422 $ 6,046 $ 7,188 $ -
(1) Including maintenance and operating costs.
Gran Tierra has operating leases for office spaces, vehicles, and tanks and finance leases for power generation and enhanced oil recovery facilities, storage tanks, and compressors.
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, 2023, the Company had provided letters of credit and other credit support totaling $220.1 million (December 31, 2022 - $111.1 million) as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, the Suroriente Block (Note 4), and other capital or operating requirements.
Contingencies
Gran Tierra has several lawsuits and claims pending. The outcome of the 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.
13. Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk
Financial Instruments
Financial instruments are initially recorded at fair value, defined as the price that would be received to sell an asset or paid to market participants to settle liability at the measurement date. For financial instruments carried at fair value, 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 representing quoted market prices in active markets for identical assets and liabilities
•Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the assets and liabilities, either directly or indirectly
•Level 3 - Unobservable inputs for assets and liabilities
The Company’s financial instruments recognized on the balance sheet consist of cash and cash equivalents, restricted cash and cash equivalents(1), accounts receivable, PEF, other long-term assets, accounts payable and accrued liabilities, credit facility, long-term debt and other long-term liabilities. The Company’s valuation techniques to measure the fair values of assets and liabilities are described in the subsequent disclosures.
Fair Value Measurement
The following table presents the Company’s fair value measurements of its financial instruments as of December 31, 2023 and 2022:
As at December 31,
2023 2022
(Thousands of U.S. Dollars)
Level 1
Assets
PEF - current (1)
$ 5,630 $ 5,981
PEF - long-term (2)
- 9,975
$ 5,630 $ 15,956
Liabilities
6.25% Senior Notes
$ 22,994 $ 243,801
7.75% Senior Notes
20,744 241,455
9.50% Senior Notes
429,018 -
$ 472,756 $ 485,256
Level 2
Assets
Restricted cash and cash equivalents - long-term (2)
$ 7,750 $ 5,343
$ 7,750 $ 5,343
(1) Included in the other current assets on the Company’s balance sheet
(2) The long-term portion of restricted cash and PEF are included in the other long-term assets on the Company’s balance sheet
The fair values of cash and cash equivalents, current restricted cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities and credit facility approximate their carrying amounts due to the short-term maturity of these instruments.
Restricted cash - long-term
The fair value of long-term restricted cash and cash equivalents approximate its carrying value because interest rates are variable and reflective of market rates.
PEF
To reduce the Company’s exposure to changes in the trading price of the Company’s common shares on outstanding PSUs and DSU’s, the Company entered into PEF. At the end of the term, the counterparty will pay the Company an amount equivalent to the notional amount of the shares using the price of the Company’s shares of Common Stock at the valuation date. The Company has the discretion to increase or decrease the notional amount of the PEF or terminate the agreement early. As at December 31, 2023, the Company’s PEF had a notional amount of 1.0 million shares and a fair value of $5.6 million. During the year ended December 31, 2023, the Company recorded a loss of $5.0 million on the PEF in G&A expenses (December 31, 2022 - $1.3 million gain and 2021 - $0.9 million). The fair value of PEF asset was estimated using Company’s share price quoted in active markets at the end of each reporting period.
Senior Notes
Financial instruments recorded at amortized costs at December 31, 2023, include the Senior Notes (Note 7). The Senior Notes are publicly traded on Singapore Exchange and the fair value is determined using the Senior Notes trading prices at the end of each reporting period.
At December 31, 2023, the carrying amounts of the 6.25% Senior Notes, 7.75% Senior Notes and 9.50% Senior Notes were $24.6 million, $23.8 million and $444.6 million, respectively, which represents the aggregate principal amounts less unamortized debt issuance costs and discounts.
Derivative asset and derivative liability
As at December 31, 2023, the Company did not have any outstanding derivative positions.
The following table presents the nature of our financial instruments gains or losses for each of the three years ended December 31, 2023:
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Commodity price derivative loss
$ - $ 26,611 $ 48,723
Foreign currency derivative loss - - 115
$ - $ 26,611 $ 48,838
Unrealized investment loss $ - $ - $ 2,032
Loss on sale of investment - - 1,355
Other financial instruments loss (gain)
15 (7) (18)
$ 15 $ (7) $ 3,369
Commodity Price Risk
The Company may at times 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, 2023, the Company had no outstanding commodity price derivative positions.
Foreign Exchange Risk
The Company is exposed to foreign exchange risk in relation to its Colombian operations predominantly in operating and transportation costs and G&A expenses. To mitigate exposure to fluctuations in foreign exchange, the Company may enter into foreign currency exchange derivatives. As at December 31, 2023, the Company had no outstanding foreign currency exchange derivative positions.
Unrealized foreign exchange gains and losses primarily result from fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s accounts payable, tax and deferred tax assets and liabilities 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 one percent strengthening in Colombian peso against the U.S. dollar results in foreign exchange loss of approximately $0.4 million of U.S. dollars on accounts payable, gain of approximately $0.3 million of U.S. dollars on taxes receivable and payable and loss of approximately $0.4 million of U.S. dollars on deferred tax assets and liabilities. This effect was calculated based on the Company’s December 31, 2023, accounts payable, deferred tax assets, and taxes payable.
For the years ended December 31, 2023, 97% of the Company oil sales were generated in Colombia and 3% of oil sales generated in Ecuador (2022 and 2021 respectively, 100% of the Company's oil sales were generated in Colombia). In Colombia and Ecuador, 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 cash equivalents accounts receivable reflects management’s assessment of credit risk.
At December 31, 2023, cash and cash equivalents and restricted cash and cash equivalents 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. Additionally, the Company reduces the credit risk exposure by managing its accounts receivable which are paid on a weekly basis. For the year ended December 31, 2023, the Company had one customer (2022 - two and 2021 - three) which accounted for over 95% 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.
14. 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 such amounts shown in the consolidated statements of cash flows:
As at December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Cash and cash equivalents $ 62,146 $ 126,873 $ 26,109
Restricted cash and cash equivalents - current(1)
1,142 1,142 392
Restricted cash and cash equivalents - long-term (1)
7,750 5,343 4,903
$ 71,038 $ 133,358 $ 31,404
(1) The current portion of restricted cash and cash equivalents is included in other current assets and long-term portion of restricted cash and cash equivalents 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) 2023 2022 2021
Accounts receivable and other long-term assets $ (1,628) $ 2,352 $ (5,686)
Derivatives - (2,749) 1,797
PEF 11,118 (9,876) (7,605)
Prepaids and inventory (9,557) (5,940) (2,582)
Accounts payable and accrued and other long-term liabilities (1,276) (5,789) 48,206
Taxes receivable and payable
(47,073) 86,319 25,024
Net changes in assets and liabilities from operating activities $ (48,416) $ 64,317 $ 59,154
The following table provides additional supplemental cash flow disclosures:
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Cash paid for income taxes $ 49,323 $ 5,480 $ 2,892
Cash paid for withholding taxes
$ 52,397 $ 31,572 $ 33,460
Cash paid for interest $ 43,755 $ 43,363 $ 50,109
Non-cash investing activities
Net liabilities related to property, plant and equipment, end of year $ 47,416 $ 55,118 $ 30,142
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 Net After Royalty (“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, 2021, 2022, and 2023, and the changes in total net proved reserves during the three-year period ended December 31, 2023.
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, 2023, have been evaluated by independent reservoir engineering specialist, 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.
Liquids (1)
Gas
(Mbbl) (MMcf)
Proved NAR Reserves, December 31, 2020
64,692 1,655
Improved recoveries 2,057 -
Extensions (2)
7,475 -
Technical revisions 1,009 133
Production (8,668) (119)
Proved NAR Reserves, December 31, 2021
66,565 1,669
Extensions and discoveries (2)
6,273 -
Technical revisions (2)
1,558 (208)
Production
(9,129) (15)
Proved NAR Reserves, December 31, 2022
65,267 1,446
Extensions and discoveries (2)
17,808 -
Technical revisions (2)
725 (1,446)
Production (3)
(9,504) -
Proved NAR Reserves, December 31, 2023
74,296 -
Proved Developed Reserves NAR, December 31, 2020
38,660 633
Proved Developed Reserves NAR, December 31, 2021
41,869 880 880
Proved Developed Reserves NAR, December 31, 2022
40,360 858 858
Proved Developed Reserves NAR, December 31, 2023
39,599 -
Proved Undeveloped Reserves NAR, December 31, 2020
26,032 1,022
Proved Undeveloped Reserves NAR, December 31, 2021
24,696 789
Proved Undeveloped Reserves NAR, December 31, 2022
24,907 588
Proved Undeveloped Reserves NAR, December 31, 2023
34,697 -
(1) At December 31, 2023, 2022, and 2021, liquids reserves are 100% oil.
(2) Includes the following volumes related to Ecuador: 2023 - 1.5 MMbbl of extensions and 0.6 MMbbl of technical revisions; 2022 - 2.5 MMbbl of extensions and (0.2) MMbbl of technical revisions; 2021 - 0.5 MMbbl of extensions
(3) Includes 0.2 MMbbl of production related to Ecuador for the year ended December 31, 2023
Changes in proved reserves during the years ended December 31, 2023, 2022 and 2021 shown in the table above primarily resulted from the following significant factors:
Improved Recoveries. There were no improved recoveries for the years ended December 31, 2023 and 2022, respectively. There were 2.1 MMbbl of improved recoveries of heavy oil in the Acordionero field for the year ended December 31, 2021.
Extensions and Discoveries. Added 17.8 MMbbl of proved reserves during the year ended December 31, 2023, of which 16.3 MMbbl were extensions in Colombia and 1.5 MMbbl were discoveries in Ecuador. In Colombia, we had 1.2, 3.5, 2.0 and 9.6 MMbbl of extensions in the Acordionero, Costayaco and Moqueta fields and Suroriente Block respectively, with a 1.5 MMbbl discovery in the Chanangue Block (2022 - 6.3 MMbbl due to reserve extensions in the Acordionero and Costayaco fields and the Charapa and Chanangue Blocks and a discovery in the Alea-1848 Block and 2021 - 7.5 MMbbl, due to reserve extensions in the Acordionero, Costayaco, Moqueta and Charapa fields).
Technical and Economic Revisions. Added 0.7 MMbbl of proved oil reserves and removed all gas reserves during the year ended December 31, 2023. In Colombia this was primarily due to continued waterflood performance in the Costayaco and Acordionero fields as well as production type curve increases in the Ecuador Blocks (2022 - 1.6 MMBOE related to positive technical revisions based on increased drilling and continued waterflood performance in the Acordionero and Costayaco fields and 2021 - 1.0 MMBOE, related to positive technical revisions based on performance and waterflood response in the Acordionero and Costayaco 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, 2023:
(Thousands of U.S. Dollars) Proved Properties Unproved Properties Accumulated
Depletion,
Depreciation
and
Impairment Net Capitalized Costs
Balance, December 31, 2023
$ 4,876,185 $ 54,116 $ (3,821,115) $ 1,109,186
Balance, December 31, 2022
$ 4,617,804 $ 74,471 $ (3,617,380) $ 1,074,895
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) Colombia
Ecuador
Total
Year Ended December 31, 2021
Property acquisition costs
Proved $ - $ - $ -
Unproved $ - $ - $ -
Exploration costs $ 18,080 $ 2,330 $ 20,410
Development costs $ 142,461 $ - $ 142,461
Year Ended December 31, 2022
Property acquisition costs
Proved $ - $ - $ -
Unproved $ - $ - $ -
Exploration costs $ 50,374 $ 39,524 $ 89,898
Development costs $ 160,933 $ - $ 160,933
Year Ended December 31, 2023
Property acquisition costs
Proved $ - $ - $ -
Unproved $ - $ - $ -
Exploration costs $ 15,674 $ 14,188 $ 29,862
Development costs $ 199,240 $ 4,581 $ 203,821
D. Results of Operations for Oil and Gas Producing Activities
(Thousands of U.S. Dollars) Colombia
Ecuador
Total
December 31, 2023
Oil sales $ 621,297 $ 15,660 $ 636,957
Production costs (192,933) (8,477) (201,410)
Exploration expenses - - -
DD&A expenses (207,346) (8,018) (215,364)
Inventory impairment
- - -
Income tax (expense) recovery
(103,491) 90 (103,401)
Results of Operations $ 117,527 $ (745) $ 116,782
December 31, 2022
Oil sales $ 711,388 $ - $ 711,388
Production costs (172,582) - (172,582)
Exploration expenses - - -
DD&A expenses (180,039) - (180,039)
Inventory impairment - - -
Income tax (expense) recovery (105,906) - (105,906)
Results of Operations $ 252,861 $ - $ 252,861
December 31, 2021
Oil sales $ 473,722 $ - $ 473,722
Production costs (147,339) - (147,339)
Exploration expenses - - -
DD&A expenses (139,765) - (139,765)
Inventory impairment - - -
Income tax (expense) recovery 19,346 - 19,346
Results of Operations $ 205,964 $ - $ 205,964
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 Ecuador
Twelve month period unweighted arithmetic average of the wellhead price as of the first day of each month within the twelve month period
2023 $ 69.91 $ 77.44
2022 $ 86.16 $ 91.53
2021 $ 58.07 $ 62.42
Weighted average production costs
2023 $ 18.54 $ 20.66
2022 $ 16.26 $ 19.55
2021 $ 15.55 $ 17.40
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 prescribed 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% prescribed discount rate; 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 Ecuador Total
December 31, 2023
Future cash inflows $ 4,893,758 $ 358,421 $ 5,252,179
Future production costs $ (1,552,227) $ (158,643) $ (1,710,870)
Future development costs $ (460,819) $ (89,639) $ (550,458)
Future asset retirement obligations $ (82,314) $ (3,300) $ (85,614)
Future income tax expense $ (954,973) $ (41,852) $ (996,825)
Future net cash flows $ 1,843,425 $ 64,987 $ 1,908,412
10% discount $ (516,451) $ (22,924) $ (539,375)
Standardized Measure of Discounted Future Net Cash Flows $ 1,326,974 $ 42,063 $ 1,369,037
December 31, 2022
Future cash inflows $ 5,410,256 $ 256,220 $ 5,666,476
Future production costs (1,298,198) (104,614) (1,402,812)
Future development costs (334,560) (63,040) (397,600)
Future asset retirement obligations (50,520) (2,700) (53,220)
Future income tax expense (1,391,436) (33,058) (1,424,494)
Future net cash flows 2,335,542 52,808 2,388,350
10% discount (659,092) (18,632) (677,724)
Standardized Measure of Discounted Future Net Cash Flows $ 1,676,450 $ 34,176 $ 1,710,626
December 31, 2021
Future cash inflows $ 3,880,608 $ 30,573 $ 3,911,181
Future production costs (1,249,901) (13,502) (1,263,403)
Future development costs (365,983) (12,175) (378,158)
Future asset retirement obligations (47,580) (600) (48,180)
Future income tax expense (514,231) (1,866) (516,097)
Future net cash flows 1,702,913 2,430 1,705,343
10% discount (481,504) (2,062) (483,566)
Standardized Measure of Discounted Future Net Cash Flows $ 1,221,409 $ 368 $ 1,221,777
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:
(Thousands of U.S. Dollars) 2023 2022 2021
Balance, beginning of year $ 1,710,626 $ 1,221,777 $ 727,487
Sales and transfers of oil and gas produced, net of production costs (739,703) (433,676) (244,486)
Net changes in prices and production costs related to future production (924,346) 1,373,950 1,217,785
Extensions, discoveries and improved recovery, less related costs 583,254 384,414 382,423
Previously estimated development costs incurred during the year (156,664) (136,856) (98,724)
Revisions of previous quantity estimates 981,873 75,460 (191,738)
Accretion of discount 171,063 122,178 72,748
Net change in income taxes 32,875 (739,879) (414,458)
Changes in future development costs (289,941) (156,742) (229,260)
Net (decrease) increase (341,589) 488,849 494,290
Balance, end of year $ 1,369,037 $ 1,710,626 $ 1,221,777
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule 13a-15(b) of the Exchange Act. Based on their evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra’s disclosure controls and procedures were effective as of December 31, 2023, 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, 2023, 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, 2023. The effectiveness of our internal control over financial reporting as of December 31, 2023, 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 fourth quarter ended December 31, 2023, 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 and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2023, 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, 2023, 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, 2023 and 2022, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes (collectively, the consolidated financial statements), and our report dated February 20, 2024 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 20, 2024
Item 9B. Other Information
2024 Annual Meeting
The Board of Directors of Gran Tierra Energy Inc. has established May 2, 2024 as the date of the Company’s 2024 Annual Meeting of Stockholders (the “2024 Annual Meeting”) and March 6, 2024 as the record date for determining stockholders entitled to notice of, and to vote at, the 2024 Annual Meeting. The time and location of the 2024 Annual Meeting will be as set forth in the Company’s proxy materials for the 2024 Annual Meeting.
Credit Facility
The Amendment made various changes to the Credit Facility, including: (i) the initial commitment was adjusted from $100 million to $50 million (maintaining the potential option of up to an additional $50 million, subject to approval by the lender) (ii) the availability period for the draw under the Credit Facility was extended from August 20, 2023 (extended under the Amended Credit Facility) until December 31, 2023.
The Credit Facility, as amended and restated, remains secured by Gran Tierra’s Colombian assets and economic rights and its remaining commercial terms remain unchanged. The Credit Facility has a final maturity date of August 15, 2024. As of February 20, 2024, the credit facility has been drawn by $36 million.
Trading Arrangements
During the three months ended December 31, 2023, no director or Section 16 officer adopted or terminated any Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements (in each case, as defined in Item 408(a) of Regulation S-K).
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required regarding our directors is incorporated herein by reference from the information contained in the section entitled “Proposal 1 - Election of Directors” in our definitive Proxy Statement for the 2024 Annual Meeting of Stockholders (our “Proxy Statement”), a copy of which will be filed with the SEC within 120 days after December 31, 2023. 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), Chief Financial Officer and Executive Vice President, Finance (Principal Financial and Accounting Officer) and Chief Operating Officer (Principal Operating Officer) Gran Tierra has made the Code available on its website at www.grantierra.com.
Gran Tierra intends to satisfy the public disclosure requirements regarding (1) any amendments to the Code, or (2) any waivers under the Code given to Gran Tierra’s Principal Executive Officer, Principal Financial and Accounting Officer and Principal Operating 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.
Item 11. Executive Compensation
The information required regarding the compensation of our directors and executive officers is incorporated herein by reference from the information contained in the section entitled “Executive Compensation and Related Information” in our Proxy Statement, including under the subheadings “Director Compensation,” “Compensation Committee Report,” and “Compensation Committee Interlocks and Insider Participation”.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Security Ownership of Certain Beneficial Owners and Management
The information required regarding security ownership of our 10% or greater stockholders and of our directors and management is incorporated herein by reference from the information contained in the section entitled “Security Ownership of Certain Beneficial Owners and Management” in our Proxy Statement.
The following table provides certain information with respect to securities authorized for issuance under Gran Tierra’s equity compensation plans in effect as of the end of December 31, 2023:
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 2,027,807 9.93 1,640,219
Equity compensation plans not approved by security holders - - -
2,027,807 9.93 1,640.219
(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 (“PSUs”), and deferred share units (“DSUs”), 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, 2023, 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, 2023, 4,672,966 shares were issued and outstanding relating to PSUs and DSUs and would represent a 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 1.0 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 Incentive Plan.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required regarding related transactions is incorporated herein by reference from the information contained in the section entitled “Certain Relationships and Related Transactions” and, with respect to director independence, the section entitled “Proposal 1 - Election of Directors”, in our Proxy Statement.
Item 14. Principal Accounting Fees and Services
The information required is incorporated herein by reference from the information contained in the sections entitled “Principal Accountant Fees and Services” and “Pre-Approval Policies and Procedures” in the proposal entitled “Ratification of Selection of Independent Auditors” in our Proxy Statement.
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as part of this Annual Report on Form 10-K:
(1) Financial Statements
Page
Report of Independent Registered Public Accounting Firm 53
Consolidated Statements of Operations 56
Consolidated Balance Sheets 57
Consolidated Statements of Cash Flow 58
Consolidated Statements of Shareholders’ Equity 59
Notes to the Consolidated Financial Statements 60
Supplementary Data (Unaudited) 79
(2) Financial Statement Schedules
None.
(3) Exhibits
Exhibit No. Description Reference
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 Certificate of Amendment to Certificate of Incorporation of Gran Tierra Energy Inc., effective May 5, 2023. Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, filed with the SEC on May 5, 2023 (SEC File No. 001-34018).
3.3 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).
3.4 Amendment No.1 to Bylaws 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 August 4, 2021 (SEC File No. 001-34018).
4.1 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).
4.2 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).
4.3 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).
4.4 Form of 6.25% Senior Notes due 2025.
Incorporated by reference to Exhibit 4.2 (included as Exhibit A 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).
4.5 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).
4.6 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 Indenture related to the 9.50% Senior Notes due 2029, dated as of October 20, 2023, 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 October 24, 2023 (SEC File No. 001-34018).
4.12 Form of 9.500% Senior Secured Amortizing Notes due 2029 (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 October 24, 2023 (SEC File No. 001-34018).
4.13 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 Amended and Restated 2007 Equity Incentive Plan*
Incorporated by reference to Appendix of the Definitive Proxy Statement filed with the SEC on March 25, 2022 (SEC File No. 001-34018).
10.2 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).
10.3 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).
10.4 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).
10.5 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).
10.6 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).
10.7 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).
10.71 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).
10.72 Executive Employment Agreement effective November 6, 2023, between GTE Alberta Inc, Gran Tierra Energy Inc. and Sebastien Morin.*
Filed herewith.
10.73 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).
10.74 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).
10.75 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).
10.76 Credit Agreement, dated as of August 18, 2022, by and among Gran Tierra Energy Inc., Gran Tierra Energy Colombia GMBH, Gran Tierra Operations Colombia GMBH and Trafigura PTE Ltd. as a lender
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with SEC on August 23, 2022 (SEC File No. 001-34018).
10.77 Deed of Amendment and Restatement to Credit Agreement dated September 19, 2023 by and among Gran Tierra Energy Inc., Gran Tierra Energy Colombia GmbH, Gran Tierra Operations Colombia GmbH. and Trafigura PTE Ltd. as a lender.
Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the SEC on November 1, 2023 (SEC File No. 001-34018).
10.78 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).
10.79 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).
10.80 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).
10.81 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).
10.82 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).
10.83 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).
10.84 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).
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.
97.1 Gran Tierra Energy Inc. Clawback Policy
Filed herewith.
99.1 Gran Tierra Energy Inc. Reserves Assessment and Evaluation of Oil and Gas Properties Corporate Summary, effective December 31, 2023.
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.
Item 16. Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
GRAN TIERRA ENERGY INC.
Date: February 20, 2024
/s/ Gary S. Guidry
By: Gary S. Guidry
President and Chief Executive Officer, Director
(Principal Executive Officer)
Date: February 20, 2024
/s/ Ryan Ellson
By: Ryan Ellson
Chief Financial Officer and Executive Vice President, Finance
(Principal Financial and Accounting Officer)
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Gary S. Guidry and Ryan Ellson, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
Name Title Date
/s/ Gary S. Guidry President and Chief Executive Officer, Director February 20, 2024
Gary S. Guidry (Principal Executive Officer)
/s/ Ryan Ellson Chief Financial Officer and Executive Vice President, Finance February 20, 2024
Ryan Ellson (Principal Financial and Accounting Officer)
/s/ Peter Dey Director February 20, 2024
Peter Dey
/s/ Evan Hazell Director February 20, 2024
Evan Hazell
/s/ Alison Redford Director February 20, 2024
Alison Redford
/s/ Robert B. Hodgins Director February 20, 2024
Robert B. Hodgins
/s/ Ronald Royal Director February 20, 2024
Ronald Royal
/s/ Sondra Scott Director February 20, 2024
Sondra Scott
/s/ David P. Smith Director February 20, 2024
David P. Smith
/s/ Brooke Wade Director February 20, 2024
Brooke Wade

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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. This Management’s Discussion and Analysis of Financial Condition and Results of Operations generally discusses items related to the fiscal year ended December 31, 2023, and year-to-year comparisons between the fiscal years ended December 31, 2023, and 2022, respectively. Discussions of items related to the fiscal year ended December 31, 2022 and year-to-year comparisons between the fiscal years ended December 31, 2022 and 2021, respectively, that are not included in this Annual Report on Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. On May 5, 2023, the Company completed 1-for-10 reverse stock split of the Company’s Common Stock. As a result of the reverse stock split, every ten of the Company’s issued shares of Common Stock were automatically combined into one issued share of Common Stock. All share and per share data included in this Annual Report on Form 10-K have been retroactively adjusted to reflect the reverse stock split.
Overview
We are a company focused on oil and gas exploration and production with assets currently in Colombia and Ecuador. Our Colombian properties represented 94% of our proved reserves NAR at December 31, 2023. For the year ended December 31, 2023, 97% of our revenue was generated in Colombia (2022 - 100% and 2021 -100%). We are headquartered in Calgary, Alberta, Canada.
As of December 31, 2023, we had estimated proved reserves NAR of 74.3 MMBOE, a 13% increase from the prior year, of which 53% were proved developed reserves and 100% were oil.
Financial and Operational Highlights
Key Highlights
•Net loss in 2023 was $6.3 million or $(0.19) per share basic and diluted compared to a net income of $139.0 million or $3.81 per share basic and $3.76 per share diluted in 2022
•Income before income taxes in 2023 was $106.2 million compared to $244.9 million in 2022
•Adjusted EBITDA(2) for 2023 was $399.4 million compared to $481.9 million in 2022
•In 2023, we re-purchased 1.3 million and 1.0 million shares of Common Stock through the 2022 and 2023 share re-purchase programs, representing about 4% and 3%, respectively, of shares outstanding as of December 31, 2023
•Our total 2023 average production NAR was 26,099 BOPD, an increase from 23,815 BOPD in 2022 as a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador
•Our total 2023 oil sales volumes NAR increased by 9% to 25,947 BOPD compared to 23,696 BOPD in 2022
•Oil sales for 2023 decreased by 10% to $637.0 million compared to $711.4 million in 2022, primarily as a result of a 17% decrease in Brent price and higher Castilla and Vasconia differentials, partially offset by 9% increase in sales volumes and lower transportation discounts
•Oil sales per bbl for 2023 were $67.26, 18% lower compared to 2022, as a result of a decrease in benchmark oil prices
•In 2023, we generated net cash provided by operating activities of $228.0 million, a decrease of 47% from $427.7 million in 2022
•During 2023, the Company generated $57.9 million of free cash flow(2) which was used for debt reduction and share re-purchases
•Operating expenses per bbl for 2023 were $19.73, 5% higher compared to 2022, primarily due to higher lifting costs attributed to road and pipeline maintenance, power generation and equipment rental, offset by lower workovers. Total operating expenses were $186.9 million in 2023, compared to $162.4 million in 2022, representing a 15% increase
•Quality and transportation discounts per bbl decreased in 2023 to $14.90 when compared to $16.79 in 2022. The decrease was due to the utilization of more favorable delivery points than in 2022
•Transportation expenses per bbl for 2023 increased by 31% to $1.54 compared to $1.18 in 2022, primarily due to utilization of new transportation routes in Colombia and Ecuador related to exploration wells and the depreciation of U.S. dollar against the Colombian peso during 2023
•General and administrative (“G&A”) expenses before stock-based compensation per bbl for 2023 increased by 15% to $4.24 compared to $3.69 in 2022 due to business development activities, higher salaries related to increased headcount in Ecuador to support ramp-up of operations and the strengthening of the Colombian peso during 2023. G&A expenses before stock-based compensation were $40.1 million in 2023 compared to $31.9 million in 2022, representing a 26% increase
•Capital expenditures decreased by $17.7 million or 7% to $218.9 million compared to 2022 due to a more condensed drilling program during 2023
(Thousands of U.S. Dollars, unless otherwise noted) Year Ended December 31,
2023 % Change 2022 % Change 2021
SEC Compliant Reserves, NAR (MMBOE)
Estimated proved oil and gas reserves 74 12 66 (1) 67
Estimated probable oil and gas reserves 46 28 36 - 36
Estimated possible oil and gas reserves 49 26 39 26 31
Average Consolidated Daily Volumes (BOPD)
Working interest (“WI”) production before royalties 32,647 6 30,746 16 26,507
Royalties (6,548) (6) (6,931) 41 (4,919)
Production NAR 26,099 10 23,815 10 21,588
(Increase) decrease in inventory (152) (28) (119) (1,290) 10
Sales (1)
25,947 9 23,696 10 21,598
Net (Loss) Income
$ (6,287) (105) $ 139,029 227 $ 42,482
Operating Netback
Oil sales $ 636,957 (10) $ 711,388 50 $ 473,722
Operating expenses (186,864) 15 (162,385) 20 (135,722)
Transportation expenses (14,546) 43 (10,197) (12) (11,618)
Operating netback (2)
$ 435,547 (19) $ 538,806 65 $ 326,382
G&A Expenses Before Stock-Based Compensation $ 40,124 26 $ 31,908 15 $ 27,867
G&A Stock-Based Compensation $ 5,722 (37) $ 9,049 8 $ 8,396
Adjusted EBITDA (2)
$ 399,355 (17) $ 481,882 101 $ 240,134
Net Cash Provided By Operating Activities $ 227,992 (47) $ 427,711 75 $ 244,834
Funds Flow From Operations (2)
$ 276,785 (24) $ 366,024 96 $ 186,485
Capital Expenditures
$ 218,882 (7) $ 236,604 58 $ 149,879
As at December 31,
(Thousands of U.S. Dollars) 2023 % Change 2022 % Change 2021
Cash and cash equivalents $ 62,146 (51) $ 126,873 386 $ 26,109
Credit facility
$ 36,364 100 $ - (100) $ 67,500
Senior Notes $ 536,619 (7) $ 579,909 (3) $ 600,000
(1) Sales volumes represent production NAR adjusted for inventory changes
(2) Non-GAAP measures
Operating netback, EBITDA, adjusted EBITDA, funds flow from operations, and free cash flow are non-GAAP measures which do not have any standardized meaning prescribed under General Accepted Accounting Principles (“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 non-cash lease expense,
lease payments, foreign exchange gains or losses, unrealized derivative instruments gains or losses, other financial instruments gains or losses, other non-cash gains or 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 a useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income or loss to EBITDA and adjusted EBITDA is as follows:
Year Ended Three Months Ended
December 31, December 31, September 30,
(Thousands of U.S. Dollars) 2023 2022 2021 2023 2022 2023
Net (loss) income $ (6,287) $ 139,029 $ 42,482 $ 7,711 $ 33,275 $ 6,527
Adjustments to reconcile net (loss) income to EBITDA and Adjusted EBITDA
DD&A expenses 215,584 180,280 139,874 52,635 51,781 55,019
Interest expense 55,806 46,493 54,381 17,789 10,750 13,503
Income tax expense (recovery) 112,447 105,906 (19,346) 5,499 5,966 40,333
EBITDA (non-GAAP) $ 377,550 $ 471,708 $ 217,391 $ 83,634 $ 101,772 $ 115,382
Non-cash lease expense 4,967 2,818 1,667 1,479 809 1,235
Lease payments (3,018) (1,666) (1,621) (1,100) (532) (676)
Foreign exchange loss 11,822 2,578 20,477 3,696 2,092 1,717
Unrealized derivative instruments gain - - (9,589) - - -
Other financial instruments loss (gain) 15 (7) 3,369 15 (7) -
Other non-cash loss (gain)
2,297 (2,598) 44 3,266 - (354)
Stock-based compensation expense
5,722 9,049 8,396 1,974 2,673 1,931
Adjusted EBITDA (non-GAAP) $ 399,355 $ 481,882 $ 240,134 $ 92,964 $ 106,807 $ 119,235
Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, 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, unrealized derivative instruments gains or losses, other financial instruments gains or losses, and other non-cash gains or losses. Management uses this financial 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 also useful supplemental information for investors to analyze performance and our financial results. Free cash flow, as presented, is defined as funds flow less capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income or loss to funds flow from operations and free cash flow is as follows:
Year Ended Three Months Ended,
December 31, December 31, September 30,
(Thousands of U.S. Dollars) 2023 2022 2021 2023 2022 2023
Net (loss) income
$ (6,287) $ 139,029 $ 42,482 $ 7,711 $ 33,275 $ 6,527
Adjustments to reconcile net (loss) income to funds flow from operations
DD&A expenses 215,584 180,280 139,874 52,635 51,781 55,019
Deferred tax expense (recovery) 56,759 25,340 (23,825) 13,517 (11,528) 13,990
Stock-based compensation expense 5,722 9,049 8,396 1,974 2,673 1,931
Amortization of debt issuance costs 5,831 3,528 3,809 2,437 759 1,594
Non-cash lease expense 4,967 2,818 1,667 1,479 809 1,235
Lease payments (3,018) (1,666) (1,621) (1,100) (532) (676)
Unrealized foreign exchange (gain) loss (5,085) 10,251 21,879 2,729 4,113 (266)
Unrealized derivative instruments gain - - (9,589) - - -
Other financial instruments loss (gain) 15 (7) 3,369 15 (7) -
Other non-cash loss (gain) 2,297 (2,598) 44 3,266 - (354)
Funds flow from operations (non-GAAP) $ 276,785 $ 366,024 $ 186,485 $ 84,663 $ 81,343 $ 79,000
Capital expenditures $ 218,882 $ 236,604 $ 149,879 $ 39,175 $ 72,887 $ 43,080
Free cash flow (non-GAAP) $ 57,903 $ 129,420 $ 36,606 $ 45,488 $ 8,456 $ 35,920
Consolidated Results of Operations
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 % Change 2022 % Change 2021
Oil sales $ 636,957 (10) $ 711,388 50 $ 473,722
Operating expenses 186,864 15 162,385 20 135,722
Transportation expenses 14,546 43 10,197 (12) 11,618
Operating netback (1)
435,547 (19) 538,806 65 326,382
DD&A expenses 215,584 20 180,280 29 139,874
G&A expenses before stock-based compensation 40,124 26 31,908 15 27,867
G&A stock-based compensation expense 5,722 (37) 9,049 8 8,396
Foreign exchange loss 11,822 359 2,578 (87) 20,477
Derivative instruments loss - (100) 26,611 (46) 48,838
Other financial instruments loss (gain) 15 314 (7) (100) 3,369
Interest expense 55,806 20 46,493 (15) 54,381
329,073 11 296,912 (2) 303,202
Other (loss) gain (2,297) (188) 2,598 6,005 (44)
Interest income 1,983 348 443 100 -
Income before income taxes 106,160 (57) 244,935 959 23,136
Current income tax expense 55,688 (31) 80,566 1,699 4,479
Deferred income tax expense (recovery) 56,759 124 25,340 206 (23,825)
Total income tax expense (recovery) 112,447 6 105,906 647 (19,346)
Net (loss) income $ (6,287) (105) $ 139,029 227 $ 42,482
Sales Volumes (NAR)
Total sales volumes, BOPD 25,947 9 23,696 10 21,598
Brent Price per bbl $ 82.16 (17) $ 99.04 40 $ 70.95
Consolidated Results of Operations per bbl Sales Volumes (NAR)
Oil sales $ 67.26 (18) $ 82.25 37 $ 60.09
Operating expenses 19.73 5 18.77 9 17.22
Transportation expenses 1.54 31 1.18 (20) 1.48
Operating netback (1)
45.99 (26) 62.30 51 41.39
DD&A expenses 22.76 9 20.84 17 17.74
G&A expenses before stock-based compensation 4.24 15 3.69 5 3.53
G&A stock-based compensation expense 0.60 (43) 1.05 (2) 1.07
Foreign exchange loss 1.25 317 0.30 (88) 2.60
Derivative instruments loss - (100) 3.08 (50) 6.19
Other financial instruments loss
- - - (100) 0.43
Interest expense 5.89 9 5.38 (22) 6.90
34.74 1 34.34 (11) 38.46
Other (loss) gain (0.24) (180) 0.30 3,100 (0.01)
Interest income 0.21 320 0.05 100 -
Income before income taxes 11.22 (60) 28.31 870 2.92
Current income tax expense 5.88 (37) 9.31 1,533 0.57
Deferred income tax expense (recovery) 5.99 104 2.93 197 (3.02)
Total income tax expense (recovery) 11.87 (3) 12.24 600 (2.45)
Net (loss) income $ (0.65) (104) $ 16.07 199 $ 5.37
(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) 2023 2022 2021
WI production before royalties 32,647 30,746 26,507
Royalties (6,548) (6,931) (4,919)
Production NAR 26,099 23,815 21,588
(Increase) decrease in inventory (152) (119) 10
Sales 25,947 23,696 21,598
Royalties, % of working interest production before royalties 20 % 23 % 19 %
Oil production NAR for the year ended December 31, 2023, increased by 10% to 26,099 BOPD compared to 23,815 in 2022. The increase in production was a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador.
Royalties as a percentage of production for the year ended December 31, 2023, decreased compared to 2022 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia.
Oil production NAR for the year ended December 31, 2022, increased by 10% to 23,815 BOPD compared to 21,588 BOPD in 2021. Production increased as a result of successful drilling and workover campaigns in Acordionero and Costayaco fields, less disruptions from blockades in Suroriente and production from exploration success in Ecuador.
The Midas Block includes the Acordionero field, the Suroriente Block includes the Cohembi field, and the Chaza Block includes the Costayaco and Moqueta fields. Ecuador includes the Charapa, Chanangue and Iguana Blocks.
Oil Sales
Oil sales for the year ended December 31, 2023, decreased by 10% to $637.0 million compared to $711.4 million in 2022, primarily as a result of a 17% decrease in Brent price and higher Castilla and Vasconia differentials partially offset by 9% higher sales volumes and lower transportation discounts in 2023. Castilla and Vasconia differentials increased to $10.22 and $5.39 from $9.81 and $4.99 per bbl in 2022, respectively. During the year ended December 31, 2023, we commenced sales in Ecuador which were subject to a $9.91 per bbl Oriente differential.
On a per bbl basis, average realized prices decreased by 18% to $67.26 for the year ended December 31, 2023, compared to $82.25 in 2022, primarily as a result of the decrease in benchmark oil prices and higher Castilla and Vasconia differentials in 2023.
Oil sales for the year ended December 31, 2022, increased by 50% to $711.4 million compared to $473.7 million in 2021, primarily as a result of a 40% increase in Brent price, 10% higher sales volumes, partially offset by 55% higher quality and transportation discounts in 2022. Castilla and Vasconia differentials increased to $9.81 and $4.99 from $5.74 and $3.52, respectively, per bbl in 2021.
On a per bbl basis, average realized prices increased by 37% to $82.25 for the year ended December 31, 2022, compared to $60.09 in 2021, primarily as a result of the increase in benchmark oil prices, offset by higher Castilla and Vasconia differentials in 2022.
The following table shows the effect of changes in realized price and sales volumes on our oil sales for the years ended December 31, 2023, 2022, and 2021:
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Oil sales for the comparative year $ 711,388 $ 473,722 $ 237,838
Realized sales price (decrease) increase effect (141,997) 191,664 219,641
Sales volume increase effect 67,566 46,002 16,243
Oil sales for the current year $ 636,957 $ 711,388 $ 473,722
Operating Expenses
Operating expenses for the year ended December 31, 2023, increased by 15% to $186.9 million compared to $162.4 million in 2022. On a per bbl basis, despite significant inflationary pressures operating expenses only increased by only 5% or $0.96 to $19.73 compared to $18.77 in the prior year, primarily as a result of $2.23 per bbl higher lifting costs associated with road and pipeline maintenance, power generation attributed to higher compressed natural gas purchases, diesel tariffs and equipment rental associated with testing exploratory wells, offset by $1.27 per bbl of lower workovers. As a result of an El-Niño-induced drought, power costs have increased across Colombia, which relies on hydroelectricity for more than two-thirds of its installed power capacity. In addition, operating costs increased as a result of the depreciation of U.S. dollar against the Colombian peso in 2023.
Operating expenses for the year ended December 31, 2022, increased by 20% to $162.4 million compared to $135.7 million in 2021. On a per bbl basis, operating expenses increased by 9% or $1.55 to $18.77 compared to $17.22 in 2021, primarily as a result of $0.48 per bbl higher workovers and $1.07 per bbl higher lifting costs mainly attributed to higher power generation due to increased activities attributed to higher production and water flood program in all major fields.
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 and Ecuador using each transportation method for each of the three years ended December 31, 2023:
Year Ended December 31,
2023 2022 2021
Volume transported through pipelines 2 % - % 12 %
Volume sold at wellhead 47 % 47 % 34 %
Volume transported via truck to pipelines 51 % 53 % 54 %
100 % 100 % 100 %
Colombian volumes transported through pipelines or via trucks 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. Volumes sold in Ecuador are transported via pipeline. We focus on maximizing operating netback (1) per bbl when choosing a transportation method.
Transportation expenses for the year ended December 31, 2023, increased by 43% to $14.5 million or by $0.36 to $1.54 per bbl compared to $10.2 million or $1.18 per bbl in 2022, as a result of the utilization of new transportation routes related to sales from exploration wells in Colombia and Ecuador, the depreciation of the U.S. dollar against the Colombian peso and higher sales volumes.
Transportation expenses for the year ended December 31, 2022, decreased by 12% to $10.2 million or by $0.30 per bbl to $1.18 per bbl compared to $11.6 million or $1.48 per bbl in 2021. The decrease in transportation expenses per bbl was a result of the higher volumes sold at the wellhead and higher sales volumes in 2022 compared to the corresponding year of 2021. In addition, during 2021, alternative transportation routes were utilized due to maintenance of the Impala terminal, which had higher transportation costs per bbl.
The following table shows the variance in our average realized price net of transportation expenses in Colombia and Ecuador for each of the three years ended December 31, 2023:
Year Ended December 31,
(U.S. Dollars per bbl Sales Volumes NAR) 2023 2022 2021
Average Brent price $ 82.16 $ 99.04 $ 70.95
Average realized price, net of transportation expenses for the comparative period $ 81.07 $ 58.61 $ 30.78
(Decrease) increase in benchmark prices (16.88) 28.09 27.74
Decrease (increase) in quality and transportation discounts 1.89 (5.93) 0.12
(Increase) decrease in transportation expense (0.36) 0.30 (0.03)
Average realized price, net of transportation expenses for the year $ 65.72 $ 81.07 $ 58.61
Average realized price, net of transportation expenses as a % of Brent
80 % 82 % 83 %
Operating Netbacks
Year Ended December 31,
Consolidated 2023 2022 2021
(Thousands of U.S. Dollars)
Oil sales $ 636,957 $ 711,388 $ 473,722
Transportation expenses (14,546) (10,197) (11,618)
622,411 701,191 462,104
Operating expenses (186,864) (162,385) (135,722)
Operating netback (1)
$ 435,547 $ 538,806 $ 326,382
(U.S. Dollars per bbl Sales Volumes NAR)
Brent $ 82.16 $ 99.04 $ 70.95
Quality and transportation discounts (14.90) (16.79) (10.86)
Average realized price 67.26 82.25 60.09
Transportation expenses (1.54) (1.18) (1.48)
Average realized price, net of transportation expenses 65.72 81.07 58.61
Operating expenses (19.73) (18.77) (17.22)
Operating netback (1)
$ 45.99 $ 62.30 $ 41.39
(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.
DD&A Expenses
Year Ended December 31,
2023 2022 2021
DD&A Expenses, Thousands of U.S. Dollars $ 215,584 $ 180,280 $ 139,874
DD&A Expenses, U.S. Dollars per bbl $ 22.76 $ 20.84 $ 17.74
DD&A expenses for the year ended December 31, 2023, increased by 20% or $1.92 per bbl from 2022. On a per bbl basis, the DD&A increase in 2023 was due to increased production and higher costs in the depletable base as a result of higher future development costs compared to 2022.
DD&A expenses for the year ended December 31, 2022, increased 29% or $3.10 per bbl from 2021. On a per bbl basis, the DD&A increase in 2022 was due to increased production and higher costs in the depletable base compared to 2021.
Asset Impairment
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 unweighted arithmetic average of the first-day-of-the month Brent price for the 12-month period prior to the ending date of the period covered by the balance sheet. 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 years ended December 31, 2023, 2022, and 2021, we had no ceiling test impairment losses. In accordance with GAAP, we used an average Brent price of $82.51 per bbl less corresponding differentials for the purpose of the December 31, 2023 ceiling test calculation (2022 and 2021 - $97.98 and $68.92 per bbl, respectively).
G&A Expenses
(Thousands of U.S. Dollars) Year Ended December 31,
2023 % change 2022 % change 2021
G&A expenses before stock-based compensation $ 40,124 26 $ 31,908 15 $ 27,867
G&A stock-based compensation 5,722 (37) 9,049 8 8,396
G&A expenses including stock-based compensation $ 45,846 12 $ 40,957 13 $ 36,263
(U.S. Dollars Per bbl Sales Volumes NAR)
G&A expenses before stock-based compensation $ 4.24 15 $ 3.69 5 $ 3.53
G&A stock-based compensation 0.60 (43) 1.05 (2) 1.07
G&A expenses including stock-based compensation $ 4.84 2 $ 4.74 3 $ 4.60
On a per bbl basis, G&A expenses before stock-based compensation for the year ended December 31, 2023, increased by 15% to $4.24 compared to 2022 due to costs attributed to business development activities, higher salaries related to increased headcount in Ecuador to support ramp-up of operations and the strengthening of the Colombian peso against the U.S. dollar. Total G&A expenses before stock-based compensation for the year ended December 31, 2023, increased by 26% to $40.1 million compared to 2022 for the same reason mentioned above.
On a per bbl basis, G&A expenses before stock-based compensation for the year ended December 31, 2022, increased by 5% to $3.69 compared to 2021 due to higher costs for optimization projects and lease obligations expenses related to additional leases capitalized during 2022. Total G&A expenses before stock-based compensation for the year ended December 31, 2022, increased 15% to $31.9 million compared to 2021 for the same reason mentioned above.
On a per bbl basis, G&A expenses after stock-based compensation for the year ended December 31, 2023, increased by 2% to $4.84 compared to 2022 due to higher G&A expenses before stock-based compensation, partially offset by 43% decrease in stock-based compensation expense which was a result of lower share price in 2023. Total G&A expenses after stock-based compensation for the year ended December 31, 2023, increased by 12% to $45.8 million, compared to 2022 for the same reason mentioned above.
On a per bbl basis, G&A expenses after stock-based compensation costs for the year ended December 31, 2022, increased by 3% to $4.74 per bbl compared to 2021 for the same reason mentioned above and higher stock-based compensation expense. Stock-based compensation per bbl decreased by 2% due to higher sales volumes in proportion to the increase in stock-based compensation expense in 2022. Total G&A expenses after stock-based compensation increased 13% to $41.0 million due to higher stock-based compensation expense for the year ended December 31, 2022, compared to 2021.
Foreign Exchange Losses
For the years ended December 31, 2023, 2022 and 2021, we had foreign exchange losses of $11.8 million, $2.6 million and $20.5 million, respectively. The main sources of foreign exchange gains and losses are the revaluation of taxes receivable and payable, deferred tax assets and liabilities and accounts payable. Under GAAP, income taxes, deferred taxes and accounts payable are considered monetary assets and liabilities and require translation from local currency to the U.S. dollar functional currency at each balance sheet date.
The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the last three years ended December 31, 2023:
Year Ended December 31,
2023 2022 2021
Change in the U.S. dollar against the Colombian peso
weakened by strengthened by strengthened by
21 % 21 % 16 %
Change in the U.S. dollar against the Canadian dollar
weakened by strengthened by consistent
2 % 7 % - %
Financial Instruments Gains or Losses
The following table presents the nature of our financial instruments gains or losses for each of the three years ended December 31, 2023:
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Commodity price derivative loss
$ - $ 26,611 $ 48,723
Foreign currency derivative loss - - 115
$ - $ 26,611 $ 48,838
Unrealized investment loss $ - $ - $ 2,032
Loss on sale of investment - - 1,355
Other financial instruments loss (gain) 15 (7) (18)
$ 15 $ (7) $ 3,369
Income Tax Expense and Recovery
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Income before income taxes $ 106,160 $ 244,935 $ 23,136
Current income tax expense $ 55,688 $ 80,566 $ 4,479
Deferred income tax expense (recovery) 56,759 25,340 (23,825)
Total income tax expense (recovery) $ 112,447 $ 105,906 $ (19,346)
Effective tax rate 106 % 43 % (84) %
Current income tax expense for the year ended December 31, 2023, was $55.7 million (2022 - $80.6 million; 2021 - $4.5 million). Current income tax expense decreased for the year ended December 31, 2023, compared to 2022, primarily due to a decrease in taxable income.
The deferred income tax expense of $56.8 million and $25.3 million for the years ended December 31, 2023 and 2022, respectively, were primarily a result of tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia. The deferred income tax recovery of $23.8 million for the year ended December 31, 2021, was mainly a result of the release of the valuation allowance in Colombia, which was partially offset by excess tax depreciation compared with accounting depreciation and the use of tax losses to offset taxable income in Colombia.
Our effective tax rate was 106% for the year ended December 31, 2023, compared to 43% in 2022. The increase in the effective tax rate was primarily due to an increase in non-deductible foreign exchange adjustments, impact of foreign taxes and other permanent differences. These were partially offset by a decrease in valuation allowance and non-deductible stock-based compensation.
Our effective tax rate was 43% for the year ended December 31, 2022, compared with (84)% in 2021. The increase in the effective tax rate was primarily due to an increase in valuation allowance, other permanent differences, stock-based compensation costs, and non-deductible third party royalties in Colombia. These were slightly offset by a decrease foreign currency translation adjustment and the impact of foreign taxes.
The difference between our effective tax rate of 106% for the year ended December 31, 2023, and the 45% Colombian statutory tax rate was primarily due to an increase in non-deductible foreign exchange adjustments, other permanent differences, the impact of foreign taxes, non-deductible royalties in Colombia and non-deductible stock-based compensation. These were partially offset by a decrease in valuation allowance.
The difference between our effective tax rate of 43% for the year ended December 31, 2022, and the 35% Colombian statutory rate was primarily due to $26.6 million of hedging loss, $46.5 million of financing cost mainly related to the senior notes, and $23.1 million of stock-based compensation and G&A cost, which were incurred in jurisdictions where no tax benefit is recognized. These were partially offset by $13.2 million of non-taxable foreign exchange gain.
The difference between our effective tax rate of (84)% for the year ended December 31, 2021, and the 31% Colombian statutory was primarily due to a decrease in the valuation allowance and other permanent differences, which were partially offset by an increase in foreign currency translation adjustment, foreign taxes, stock-based compensation costs, non-deductible third party royalties in Colombia, and non-deductible investment loss on PetroTal.
Net Income (Loss) and Funds Flow From Operations (a Non-GAAP Measure)
(Thousands of U.S. Dollars) Fourth quarter 2023 compared with third quarter 2023
% change Fourth quarter 2023 compared with fourth quarter 2022
% change Year ended December 31, 2023 compared with year ended December 31, 2022
% change
Net income for the comparative period
$ 6,527 $ 33,275 $ 139,029
Increase (decrease) due to:
Sales volumes (9,865) (4,521) 67,566
Prices (15,112) (3,172) (141,997)
Expenses:
Cash operating expenses 1,730 (1,518) (24,479)
Transportation (105) (1,514) (4,349)
Cash G&A, excluding stock-based compensation expense (2,765) (3,074) (8,216)
Interest, net of amortization of debt issuance costs (3,443) (5,361) (7,010)
Realized foreign exchange gain (loss)
1,016 (2,988) (24,580)
Settlement of financial instruments - - 26,611
Current taxes 34,361 25,512 24,878
Net lease payments (180) 102 797
Interest income 26 (146) 1,540
Net change in funds flow from operations (1) from comparative period
5,663 3,320 (89,239)
Expenses:
Depletion, depreciation and accretion 2,384 (854) (35,304)
Inventory impairment
- - -
Deferred tax 473 (25,045) (31,419)
Amortization of debt issuance costs (843) (1,678) (2,303)
Net lease payments 180 (102) (797)
Stock-based compensation (43) 699 3,327
Other non-cash loss
(3,620) (3,266) (4,895)
Financial instruments loss, net of financial instruments settlements (15) (22) (22)
Unrealized foreign exchange (loss) gain
(2,995) 1,384 15,336
Net change in net income
1,184 (25,564) (145,316)
Net income (loss) for the current period
$ 7,711 18 % $ 7,711 (77) % $ (6,287) (105) %
(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.
2024 Work Program and Capital Expenditures
Our Colombian development operation is expected to represent 93% of our production and approximately 60% - 70% of our 2024 capital budget, with the remainder allocated to exploration activities.
The table below shows the break-down of our 2024 capital program:
Number of Wells
(Gross) Number of Wells
(Net) 2024 Capital Budget
($ million)
Development - Colombia 13 - 17
12 - 16 130 - 140
Exploration - Colombia and Ecuador 6 - 9
6 - 9 80 - 100
19 - 26 18 - 25 210 - 240
Our base capital program for 2024 is $210 million to $240 million for exploration and development activities. Based on the mid-point of the 2024 guidance, the capital budget is forecasted to be approximately 60% directed to development and 40% to exploration activities. Approximately 20% of the development activities included in the 2024 capital program are expected to be directed to facilities to support future production growth and enhance recovery factors.
We expect our 2024 capital program to be fully funded by cash flows from operations. Funding this program from cash flows from operations relies in part on Brent oil prices being $70 per bbl for 2024.
Capital Program
Capital expenditures during the year ended December 31, 2023 were $218.9 million.
During the year ended December 31, 2023, we spud the following wells in Colombia:
Number of Wells
(Gross and Net)
Colombia
Development 17.0
Service 8.0
Total 25.0
In 2023, we spud 17 development and eight service wells in Colombia and none in Ecuador. Of the wells drilled in Colombia, 13 were drilled in Midas Block and 12 in Chaza Block. As at December 31, 2023, of the 17 development wells 15 were producing, and two were in-progress.
On April 11, 2023, we and Ecopetrol S.A. renegotiated the terms of the contract for our operatorship of the Suroriente Block which was previously scheduled to end in mid-2024 and executed the Suroriente Continuation Agreement. The duration of the contract was extended for 20 years from September 1, 2023 (the “Effective Date”), the date on which we satisfied the relevant conditions precedent and regulatory approval was received. We continue to be the operator of the Suroriente Block. In connection with the contract extension, we paid cash consideration of $6.2 million and provided letters of credit of $123.0 million (refer to Note 12 to the Consolidated Financial Statements) related to committed capital investments to be made over a three-year period from the Effective Date.
Liquidity and Capital Resources
As at December 31,
(Thousands of U.S. Dollars) 2023 % Change 2022 % Change 2021
Cash and cash equivalents $ 62,146 (51) $ 126,873 386 $ 26,109
Credit facility
$ 36,364 100 $ - (100) $ 67,500
Senior Notes $ 536,619 (7) $ 579,909 (3) $ 600,000
We believe that our capital resources, including cash on hand and cash generated from operations will provide us with sufficient liquidity to maintain current operations and execute the capital program for the next 12 months and beyond, given current oil price trends and production levels. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial, or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions. We intend to pursue growth opportunities and acquisitions from time to time, which may require significant capital, be located in basins or countries beyond our current operations, involve joint ventures, or be sizable compared to our current assets and operations.
During the year ended December 31, 2023, we, as guarantor, and Gran Tierra Energy Colombia GmbH and Gran Tierra Operations Colombia GmbH, as borrowers, had a credit facility of $50 million which was paid in full and terminated on February 6, 2024. Interest under the credit facility was based on the secured overnight financing rate posted by the Federal Reserve Bank of New York plus a credit margin of 6.00% and a credit-adjusted spread of 0.26% with undrawn amounts under the credit facility bearing interest at 2.10% per annum, based on the amount available. Prior to termination, the credit facility was secured by our Colombian assets and economic rights and had a final maturity date of August 15, 2024. As of December 31, 2023, the credit facility was drawn by $36.4 million. During the year ended December 31, 2023, we incurred the weighted-average interest rate on credit facility of 11.59%.
On October 20, 2023, we completed exchange offers of $247.1 million of 6.25% Senior Notes (the “6.25% Senior Notes”) and $275.8 million of 7.75% Senior Notes (the “7.75% Senior Notes”) for $487.6 million 9.50% Senior Secured Notes due 2029 (the “9.50% Senior Notes” and, together with the 7.75% Senior Notes and the 6.25% Senior Notes, the “Senior Notes”). The exchange consideration for $242.5 million of 6.25% Senior Notes included early participation premium of $80 for each $1,000 aggregate principal amount with the remainder of $4.6 million exchanged at $1,000 and for $274.2 million of 7.75% Senior Notes early participation premium of $20 for each $1,000 aggregate principal amount with the remainder of $1.6 million of 7.75% Senior Notes exchanged at $950 for each $1,000 aggregate principal amount. In addition, the Company paid cash consideration of $60.0 million for 6.25% Senior Notes exchanged as part of total consideration to eligible holders on a pro-rata basis, for each $1,000 aggregate principal amount tendered and accepted for the early exchange deadline. The Senior Notes tendered and accepted for exchange, as well as the notes held as treasury bonds, were cancelled. The exchange of the 6.25% Senior Notes was accounted for as debt extinguishment and resulted in a gain of $5.3 million. The exchange of 7.75% Senior Notes was accounted for as debt modification and resulted in a loss of $6.1 million related to third party fees.
At December 31, 2023, we had $24.8 million of 6.25% Senior Notes due 2025, $24.2 million of 7.75% Senior Notes due 2027, and $487.6 million of 9.50% Senior Notes due 2029.
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 re-purchased.
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 re-purchased.
The 9.50% Senior Notes bear interest at a rate of 9.50% per year, payable semi-annually in arrears on April 15 and October 15 of each year, beginning on April 15, 2024. The 9.50% will mature on October 15, 2029.
The principal amount of 9.50% Senior Notes is to be repaid as follows: (i) October 15, 2026, 25% of the principal amount; (ii) October 15, 2027, 5% of the principal amount; (iii) October 15, 2028, 30% of the principal amount; and (iv) October 15, 2029, the remainder of the principal amount.
On February 6, 2024, we issued additional $100.0 million of 9.50% Senior Notes and received net cash proceeds of $88.0 million as a result of this issuance. The newly issued 9.50% Senior Notes have the same terms and provisions, except for the issue price, as original $487.6 million 9.50% Senior Notes outstanding at December 31, 2023 and will be combined together with originally issued 9.50% Senior Notes in respect of interest payments.
During the year ended December 31, 2023, we purchased in the open market $8.0 million of 6.25% Senior Notes for cash consideration of $6.8 million, including interest payable of $0.1 million. The purchase resulted in a $1.1 million gain, which
included the write-off of deferred financing fees of $0.1 million. The Company canceled all previously purchased 6.25% Senior Notes as at December 31, 2023.
During the year ended December 31, 2023, we implemented a share re-purchase program (the “2023 Program”) through the facilities of the TSX, the NYSE or alternative trading programs in Canada or the United States, if eligible. Under the 2023 Program, we are able to purchase up to 3,234,914 shares of Common Stock, representing 10% of the public float as of October 20, 2023, at prevailing market prices at the time of purchase. The 2023 Program will continue for one year and expire on November 2, 2024, or earlier if the 10% maximum is reached.
During the year ended December 31, 2023, we re-purchased 1,041,804 shares of Common Stock at a weighted average price of approximately $6.21 per share under the 2023 Program and 1,328,650 shares of Common Stock at a weighted average price of $8.15 per share, under the 2022 share re-purchase program (“2022 Program”), implemented in 2022 with similar terms to that of the 2023 Program. The 2022 Program expired in May 2023 when 10% share maximum was reached. The weighted average price per share under the 2022 Program was $10.59 per share. As of December 31, 2023, all 3,603,396 shares re-purchased under the 2022 Program and 1,041,804 shares re-purchased under 2023 Program were cancelled subsequent to re-purchase.
Cash and Cash Equivalents Held Outside of Canada and the United States
At December 31, 2023, 100% of our cash and cash equivalents were held by subsidiaries outside Canada and the United States.
Cash Flows
The following table presents our sources and uses of cash and cash equivalents for the periods presented:
Year Ended December 31,
2023 2022 2021
Sources of Cash and Cash Equivalents:
Net (loss) income $ (6,287) $ 139,029 $ 42,482
Adjustments to reconcile net (loss) income to funds flow from operations
DD&A expenses 215,584 180,280 139,874
Deferred tax expense (recovery) 56,759 25,340 (23,825)
Stock-based compensation expense 5,722 9,049 8,396
Amortization of debt issuance costs 5,831 3,528 3,809
Unrealized foreign exchange (gain) loss (5,085) 10,251 21,879
Other non-cash loss (gain)
2,297 (2,598) 44
Derivative instruments loss - 26,611 48,838
Cash settlement on derivative instruments - (26,611) (58,427)
Other financial instruments loss (gain)
15 (7) 3,369
Non-cash lease expenses 4,967 2,818 1,667
Lease payments (3,018) (1,666) (1,621)
Funds flow from operations (1)
276,785 366,024 186,485
Changes in non-cash operating working capital - 64,317 59,154
Changes in non-cash investing working capital - 26,273 1,431
Proceeds from exercise of stock options 8 1,300 100
Proceeds from debt, net of issuance costs 48,014 - -
Proceeds on disposition of investment, net of transaction costs - - 43,126
Foreign exchange gain on cash and cash equivalents and restricted cash and cash equivalents
5,869 - -
330,676 457,914 290,296
Uses of Cash and Cash Equivalents:
Additions to property, plant and equipment (218,882) (236,604) (149,879)
Repayment of Senior Notes (60,000) - -
Proceeds from debt, net of issuance costs - - (228)
Repayment of debt (13,636) (67,803) (122,500)
Lease payments (6,527) (2,228) (2,182)
Proceeds from other debt, net of issuance costs (13,351) - -
Changes in non-cash operating working capital (48,416) - -
Changes in non-cash investing working capital (7,702) - -
Cash settlement of asset retirement obligation (377) (2,630) (805)
Re-purchase of shares of Common Stock (17,300) (27,317) -
Re-purchase of Senior Notes (6,805) (17,274) -
Foreign exchange loss on cash and cash equivalents and restricted cash and cash equivalents
- (2,104) (821)
(392,996) (355,960) (276,415)
Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents $ (62,320) $ 101,954 $ 13,881
(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.
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, 2023:
(Thousands of U.S. Dollars) Total 2024 2025-2026
2027-2028
2029 and beyond
Credit facility $ 36,364 $ 36,364 $ - $ - $ -
6.25% Senior Notes
24,828 - 24,828 - -
7.75% Senior Notes
24,201 - - 24,201 -
9.50% Senior Notes
487,590 - 121,898 170,657 195,035
Total debt
572,983 36,364 146,726 194,858 195,035
Interest payments (1)
217,704 49,682 90,583 61,911 15,528
Facilities 8,317 2,483 4,952 882 -
Operating leases 12,857 4,309 4,909 3,639 -
Finance leases 31,630 10,607 12,310 8,713 -
Software and Telecommunication 396 332 64 - -
Total $ 843,887 $ 103,777 $ 259,544 $ 270,003 $ 210,563
(1) Interest payments were calculated on our credit facility till termination date on February 6, 2024, and on our 6.25% Senior Notes, 7.75% Senior Notes, and 9.50% Senior Notes under assumption that Senior Notes will be held until their maturity dates of February 2025, May 2027, and October 2029, respectively. Actual results will differ from these estimates and assumptions.
At December 31, 2023, we provided promissory notes totaling $220.1 million (2022 - $111.1 million) to support letters of credit relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, the Suroriente Block and other capital or operating requirements.
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 9 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.
Climate Change
We have considered the impact of the climate events on the following items presented in this Annual Report on Form 10-K for the fiscal year ended December 31, 2023:
Impairment
We have considered the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in the ceiling test impairment assessment on oil and gas properties. The estimated ceiling amount of our oil and gas properties was based on proved reserves, the life of which is generally less than 15 years. The ultimate period in which global energy markets can transition from carbon-based sources to alternative energy is highly uncertain. However, the majority of the cash flows associated with proved reserves per the 2023 reserve report should be realized prior to the potential elimination of carbon-based energy.
Expenditures on property, plant and equipment
From 2018 to 2023, we incurred $22.9 million on gas-to-power facilities in the Acordionero field to reduce emissions principally by the recovery and use of natural gas in the field for power generation and reduction of diesel use for power generation. In 2023, the Acordionero field represented 52% of our production. As of the end of 2023, Gran Tierra converts gas to power at seven of our facilities located in the Acordionero, Costayaco, Moqueta, Mono Arana, Los Angeles Cohembi and Juglar fields. In total, we converted 2.7 billion standard cubic feet of natural gas into electricity instead of being flared for the
year ended December 31, 2023 and have incurred capital expenditures of $28.5 million since 2018. The extent of spending on projects directly linked to reducing the climate impact of our operations.
We voluntarily support projects for the protection of the environment. Through programs like Gran Tierra’s flagship environmental initiative, NaturAmazonas, in partnership with the international non-governmental organization Conservation International, we have committed to reforesting 1,000 hectares of land and securing and maintaining 18,000 hectares of forest in the Andes-Amazon rainforest corridor. The NaturAmazonas project alone is expected to sequester approximately 8.7 million tonnes of carbon dioxide over its lifetime. During the year ended December 31, 2023, Gran Tierra signed a four-year extension with Conservation International to continue the NaturAmazonas project. This extension will, among other benefits, result in the development of the additional 100 restoration agreements to restore more than 250 additional hectares of land while ensuring the benefits from NaturAmazonas’ first phase sustain. We have planted over 1.5 million trees and conserved, preserved, or reforested more than 3,800 hectares of land through all of our environmental efforts since 2018. We will continue to implement projects that focus on environmental protection, conservation and reforestation efforts.
Current assets and current liabilities
These amounts are short-term in nature, and during the year ended December 31, 2023, management was not aware of any material impacts on these items related to climate change and climate events. We did not experience material credit losses on our accounts receivable during 2023.
Share capital
The evolving energy transition and general sentiment to the oil and gas industry may result in reduced access to capital markets.
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 the 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 and the impact of estimated proved oil and gas reserves on the calculations of depletion expense and the ceiling test related to 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.”
Our estimates of proved oil and natural 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 impact oil and natural 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 reservoir engineering specialists.
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 test calculation dictates that a 10% discount factor be used and future net revenues are calculated using the unweighted arithmetic average of the first-day-of-the month Brent price for the 12-month period prior to the ending date of the period covered by the balance sheet. 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, 2023 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 reservoir engineering specialists 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 reservoir engineering specialists, their independence.
For the years ended December 31, 2023, 2022 and 2021 we had no ceiling test impairment losses. We used an average Brent price of $82.51 per bbl less corresponding differentials for the purposes of the December 31, 2023 ceiling test calculations (2022 and 2021 - $97.98 and $68.92, respectively).
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 (“ARO”)
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.
Income Taxes
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. This determination involves numerous judgments and assumptions and includes estimating factors such as commodity prices, production and other operating conditions. If any of those factors, assumptions or judgments change, the deferred tax asset could change, and in particular decrease in a period where we determine it is more likely than not that the asset will not be realized. Alternatively, a valuation allowance may be reversed where it is determined it is more likely not that the asset will be realized.
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 amount 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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our principal market risk relates to oil prices. Oil prices are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Our revenues are from oil sales at Brent pricing and adjusted for quality.
Foreign Currency Risk
Foreign currency risk is a factor for our company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. Our reporting currency is U.S. dollars and 100% of our revenues are related to the U.S. dollar price of Brent or WTI oil. In Colombia, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures are in U.S. dollars or are based on U.S. dollar prices. The majority of income and VAT and G&A expenses in all locations are in local currency.
Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our accounts payable, taxes receivable and payable and deferred tax assets and liabilities in Colombia are denominated in the local currency of the Colombian foreign operations which are our monetary assets. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency. A one percent strengthening in Colombian peso against the U.S. dollar results in foreign exchange loss of approximately 0.4 million U.S. dollars on accounts payable, gain of approximately $0.3 million U.S. dollars on taxes receivable and payable and loss of approximately $0.4 million U.S. dollars on deferred tax assets and liabilities.
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our credit facility, which bears floating rates of interest. At December 31, 2023, our credit facility was drawn by $36.4 million (December 31, 2022 - undrawn).
Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issues at overnight rates, or U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. A 10% change in interest rates would not have a material effect on the value of our investment portfolio. We do not hold any of these investments for trading purposes.

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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. and subsidiaries (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, 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, 2023, 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 20, 2024 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 Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates 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 a critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of estimated proved oil and gas reserves on the calculations of depletion expense and the ceiling test related to Colombian 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 are depleted over the estimated proved oil and gas reserves. As discussed in Note 4 to the consolidated financial statements, the Company recorded depletion and depreciation expense of $209.7 million for the year ended December 31, 2023, a portion of which related to Colombian oil and gas properties. Additionally, as discussed in Note 2 to the consolidated financial statements, the Company performs a ceiling test calculation as of each quarter end on a country-by-country basis. In performing its quarterly ceiling test, the Company limits the capitalized costs of proved oil and 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 limitation, the Company will record a ceiling test impairment to the extent of such excess. As discussed in Note 5 to the consolidated financial statements, the Company did not record a ceiling test impairment in 2023 related to Colombian oil and gas properties. 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 assumptions related to forecasted production and forecasted operating, royalty and capital costs (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 Colombian 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 test. 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 tests.
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. This included controls related to the:
•calculation of depletion expense and the ceiling test
•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 2023 actual production and 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.
/s/ KPMG LLP
Chartered Professional Accountants
We have served as the Company’s auditor since 2018
Calgary, Canada
February 20, 2024
Gran Tierra Energy Inc.
Consolidated Statements of Operations
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
Year Ended December 31,
2023 2022 2021
OIL SALES (NOTE 10)
$ 636,957 $ 711,388 $ 473,722
EXPENSES
Operating 186,864 162,385 135,722
Transportation 14,546 10,197 11,618
Depletion, depreciation and accretion (Note 4)
215,584 180,280 139,874
General and administrative (Note 13)
45,846 40,957 36,263
Foreign exchange loss
11,822 2,578 20,477
Derivative instruments loss (Note 13)
- 26,611 48,838
Other financial instruments loss (gain) (Note 13)
15 (7) 3,369
Interest expense (Note 7)
55,806 46,493 54,381
TOTAL EXPENSES 530,483 469,494 450,542
OTHER (LOSS) GAIN (Note 7)
(2,297) 2,598 (44)
INTEREST INCOME 1,983 443 -
INCOME BEFORE INCOME TAXES 106,160 244,935 23,136
INCOME TAX EXPENSE (RECOVERY)
Current (Note 11)
55,688 80,566 4,479
Deferred (Note 11)
56,759 25,340 (23,825)
112,447 105,906 (19,346)
NET AND COMPREHENSIVE (LOSS) INCOME $ (6,287) $ 139,029 $ 42,482
NET (LOSS) INCOME PER SHARE (1)
-BASIC
$ (0.19) $ 3.81 $ 1.16
-DILUTED
$ (0.19) $ 3.76 $ 1.15
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 8)
33,469,828 36,445,546 36,702,290
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 8)
33,469,828 36,928,010 36,787,339
(1) Reflects our 1-for-10 reverse stock split that became effective May 5, 2023. See Note 8 in the notes to the consolidated financial statements for further discussion.
(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,
2023 2022
ASSETS
Current Assets
Cash and cash equivalents $ 62,146 $ 126,873
Accounts receivable (Note 3)
12,359 10,706
Inventory
29,039 20,192
Other current assets (Note 13 and 14)
8,920 10,816
Total Current Assets 112,464 168,587
Oil and Gas Properties (using the full cost method of accounting)
Proved 1,055,070 1,000,424
Unproved 54,116 74,471
Total Oil and Gas Properties 1,109,186 1,074,895
Other capital assets 33,664 26,007
Total Property, Plant and Equipment (Note 4)
1,142,850 1,100,902
Other Long-Term Assets
Taxes receivable 52,089 27,796
Deferred tax assets (Note 11)
10,923 22,990
Other long-term assets (Note 13 and 14)
7,963 15,335
Total Other Long-Term Assets 70,975 66,121
Total Assets $ 1,326,289 $ 1,335,610
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities (Note 6, 7 and 9)
$ 187,007 $ 167,579
Credit facility (Note 7)
35,609 -
Taxes payable (Note 11)
27,219 58,978
Equity compensation award liability (Note 8)
10,419 15,082
Total Current Liabilities 260,254 241,639
Long-Term Liabilities
Long-term debt (Note 7)
519,532 589,593
Deferred tax liabilities (Note 11)
57,453 28
Asset retirement obligation (Note 9)
73,029 63,358
Equity compensation award liabilities (Note 8)
8,750 16,437
Other long-term liabilities (Note 13)
10,877 6,989
Total Long-Term Liabilities 669,641 676,405
Commitments and Contingencies (Note 12)
Shareholders’ Equity (1)
Common Stock (Note 8) (32,275,113 and 36,889,862 issued, 32,246,501 and 34,615,116 outstanding shares of Common Stock, par value $0.001 per share, as at December 31, 2023, and December 31, 2022, respectively)
9,936 10,272
Additional paid in capital 1,249,651 1,291,354
Treasury stock (Note 8)
(163) (27,317)
Deficit (863,030) (856,743)
Total Shareholders’ Equity 396,394 417,566
Total Liabilities and Shareholders’ Equity $ 1,326,289 $ 1,335,610
(1) Reflects our 1-for-10 reverse stock split that became effective May 5, 2023. See Note 8 in the notes to the consolidated financial statements for further discussion.
(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,
2023 2022 2021
Operating Activities
Net (loss) income $ (6,287) $ 139,029 $ 42,482
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 4)
215,584 180,280 139,874
Deferred tax expense (recovery) (Note 11)
56,759 25,340 (23,825)
Stock-based compensation expense (Note 8)
5,722 9,049 8,396
Amortization of debt issuance costs (Note 7)
5,831 3,528 3,809
Non-cash lease expenses 4,967 2,818 1,667
Lease payments (3,018) (1,666) (1,621)
Unrealized foreign exchange (gain) loss (5,085) 10,251 21,879
Derivative instruments loss (Note 13)
- 26,611 48,838
Cash settlement on derivatives instruments (Note 13)
- (26,611) (58,427)
Other financial instruments (gain) loss (Note 13)
15 (7) 3,369
Cash settlement of asset retirement obligation (Note 9)
(377) (2,630) (805)
Other non-cash loss (gain) (Note 7)
2,297 (2,598) 44
Net change in assets and liabilities from operating activities (Note 14)
(48,416) 64,317 59,154
Net cash provided by operating activities 227,992 427,711 244,834
Investing Activities
Additions to property, plant and equipment (Note 4)
(218,882) (236,604) (149,879)
Changes in non-cash investing working capital
(7,702) 26,273 1,431
Proceeds on disposition of investment, net of transaction costs (Note 13)
- - 43,126
Net cash used in investing activities (Note 14) (226,584) (210,331) (105,322)
Financing Activities
Purchase of Senior Notes (Note 7)
(6,805) (17,274) -
Senior Notes issuance costs
(13,351) - -
Repayment of Senior Notes (Note 7)
(60,000) - -
Proceeds from debt, net of issuance costs (Note 7)
48,014 - (228)
Repayment of debt (Note 7)
(13,636) (67,803) (122,500)
Lease payments (6,527) (2,228) (2,182)
Proceeds from exercise of stock options (Note 8)
8 1,300 100
Re-purchase of shares of Common Stock (Note 8)
(17,300) (27,317) -
Net cash used in financing activities (69,597) (113,322) (124,810)
Foreign exchange gain (loss) on cash and cash equivalents and restricted cash and cash equivalents 5,869 (2,104) (821)
Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents (62,320) 101,954 13,881
Cash and cash equivalents and restricted cash and cash equivalents,
beginning of year (Note 14)
133,358 31,404 17,523
Cash and cash equivalents and restricted cash and cash equivalents,
end of year (Note 14)
$ 71,038 $ 133,358 $ 31,404
Supplemental cash flow disclosures (Note 14)
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Consolidated Statements of Shareholders’ Equity
(Thousands of U.S. Dollars)
Year Ended December 31,
2023 2022 2021
Share Capital (1)
Balance, beginning of year $ 10,272 $ 10,270 $ 10,270
Reverse stock split (Note 8)
(299) - -
Cancellation of shares of Common Stock (Note 8)
(37) - -
Issuance of shares of Common Stock, net of issuance costs (Note 8)
- 2 -
Balance, end of year 9,936 10,272 10,270
Additional Paid in Capital
Balance, beginning of year 1,291,354 1,287,582 1,285,018
Reverse stock split (Note 8)
299 - -
Cancellation of shares of Common Stock (Note 8)
(44,417) - -
Exercise of stock options (Note 8)
8 1,298 100
Stock-based compensation (Note 8)
2,407 2,474 2,464
Balance, end of year 1,249,651 1,291,354 1,287,582
Treasury Stock
Balance, beginning of year (27,317) - -
Purchase of treasury shares (Note 8)
(17,300) (27,317) -
Cancellation of treasury shares (Note 8)
44,454 - -
Balance, end of year (163) (27,317) -
Deficit
Balance, beginning of year (856,743) (995,772) (1,038,254)
Net (loss) income (6,287) 139,029 42,482
Balance, end of year (863,030) (856,743) (995,772)
Total Shareholders’ Equity $ 396,394 $ 417,566 $ 302,080
(1) Reflects our 1-for-10 reverse stock split that became effective May 5, 2023. See Note 8 in the notes to the consolidated financial statements for further discussion.
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years Ended December 31, 2023, 2022 and 2021
(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. Certain estimates and judgments have a material impact where the assumptions underlying these accounting estimates relate to matters that involve significant estimation uncertainty at the time the estimate or judgement is made or are subjective. These estimates and judgments include, but are not limited to:
•estimated proved and probable reserves volumes and the related cash flows are determined by the independent reservoir engineering specialists and used in several of the estimates made by management in preparing these financial statements. Numerous estimates are required to be made in the reserve report, including forecasted production, forecasted operating and royalty costs, capital cost assumptions, and in certain cases forecasted commodity prices;
•depletion, depreciation and accretion (“DD&A”);
•timing of transfers from oil and gas properties not subject to depletion to the depletable base;
•impairment of proved oil and gas properties as determined using the full cost method of accounting for our oil and natural gas properties in accordance with SEC Regulation S-X Rule 4-10;
•asset retirement obligations;
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.
Some of the Company’s estimates and judgements have a material impact on consolidated financial statements but do not involve significant subjectivity of estimation uncertainty. These estimates and judgements include, but are not limited to;
•income taxes; and
•stock-based compensation
•prepaid equity forwards (“PEF”);
•operating and finance leases; and
•debt extinguishment and debt modification accounting
•assessment of the likely outcome of legal and other contingencies;
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 are comprised of 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.
Prepaid Equity Forwards
The Company is exposed to equity price risk in relation to its long-term incentive plans. The Company utilizes prepaid equity forwards on the equivalent number of the Company’s common shares in order to fix the future settlement cost on a portion of its cash-settled long-term incentive plans.
PEF is recorded in other current and long-term assets on the Company’s balance sheet at fair value, with changes in fair value recognized as G&A expense in the consolidated statements of operations. The Company utilizes PEF to manage equity price risk in relation to its long-term incentive plans.
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 royalties.
Income Taxes
Income taxes are recognized using the asset and 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 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. Valuation allowances are provided if, after considering the 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, 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 the 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 result 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, 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, 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. During any period in which factors indicate impairment, the cumulative costs incurred to date for such property are transferred to the full cost pool and subject to depletion. For countries where a reserve base has not yet been established, the impairment is charged to net income or loss.
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 is 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, 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 expenses as incurred.
Leases
At the 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 the 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.
Debt extinguishment and debt modification accounting
The Company accounts for debt restructuring or exchange of debt transactions as either a debt extinguishment or a debt modification. For instruments not involving conversion options, the Company recognizes an exchange of debt as an extinguishment if the present value of the cash flows under the terms of the new debt instrument is at least 10 percent different from the present value of the remaining cash flows under the terms of the original instrument. If the exchange of debt is accounted for as a debt extinguishment, the carrying value of the original debt including unamortized deferred financing fees is derecognized from our balance sheet and the new debt is recognized at its fair value less applicable deferred financing fees, with the difference between the net carrying value of the original debt and the fair value of the new debt recognized as a gain or loss in the consolidated statements of operations. If the terms of a debt instrument are changed or modified and the cash flow effect on a present value basis is less than 10 percent, the debt instrument is not considered to be substantially different, the Company accounts for this debt instrument as debt modification. If the exchange of debt is accounted for as a debt modification, the change of the carrying amount of the original debt on the balance sheet is adjusted to the net present value of the revised cash flows with the adjustments treated as a capital cost and amortized as an adjustment of interest expense on our statement of operations.
Revenue from Contracts with Customers
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. 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 arrangements 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 the ability to establish prices, or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in the 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 the 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 an agent in transactions, management determines if the Company obtains control of the product. As part of this assessment, management considers the criteria for revenue recognition set out in Accounting Standard Codification 606.
Stock-based Compensation
The Company records stock-based compensation expense in its consolidated financial statements measured at 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, the expense is recognized over the three-year vesting period based on the latest available estimate of the fair value of the awards 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-Merton 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 G&A or operating expenses, as appropriate.
Foreign Currency Translation
The functional currency of the Company, including its subsidiaries, is the U.S. 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.
Net Income or Loss per Share
Basic net income or 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 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 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.
Risks and Measurement Uncertainty
The impacts of ongoing conflicts in several parts of the world coupled with volatility in energy markets, increased interest and inflation rates and constrained supply chains have created a higher level of volatility and uncertainty. Management has, to the reasonable extent, incorporated known facts and circumstances into the estimates made; however, the increased levels of uncertainly and volatility make accounting estimates more judgmental, and the actual results could differ materially from estimates.
Recently Issued Accounting Pronouncements
In October 2023, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standard Update (“ASU”) 2023-06, “Disclosure Improvements.” This ASU includes an update to the disclosures and presentation requirements of a variety of topics. Affected topics include: an update to the statement of cash flows, commitments, earnings per share, derivatives and hedging, extractive activities and credit risk disclosures, among other things. This ASU should be applied prospectively and the effective date will be the date on which the SEC’s removal of the related disclosures from Regulation S-X
becomes effective, with early adoption prohibited. The Company does not expect that adoption of this ASU would have a material impact on the Company’s presentation and disclosures of consolidated financial statements as its currently subject to presentation and disclosures of relevant S-X Regulations.
In November 2023, FASB issued ASU 2023-07, “Improvements to Reportable Segment Disclosures” for interim and annual financial reporting for all public entities, including those that have a single reportable segment. ASU 2023-07 requires to disclose by each reportable segment the significant segment expenses that are regularly provided to chief operating decision maker, amount and composition of other segment items, measure of segment’s profit or loss in assessing segment performance and how resources are allocated if used by chief operating decision maker and title and position of the chief operating decision maker. If a public entity discloses a single reportable segment, it should identify the measure or measures of a segment’s profit or loss that chief operating decision maker uses in assessing segment performance and deciding how to allocate the resources. The public entity is required to recast the prior-period segment expense information to conform to current-period presentation unless it is impracticable to do so. This ASU is effective for fiscal periods beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024 and should be applied retrospectively to all periods presented in the financial statements, with early adoption permitted. The Company adopted ASU 2023-07 effective January 1, 2024.
In December 2023, FASB issued ASU 2023-09, “Improvements to Income Tax Disclosures.” ASU 2023-09 enhances the income tax disclosures to enable investors to better understand entity’s exposure to potential changes in jurisdictional tax legislation and associated risks and opportunities, income tax information that effects cash flow forecasts and potential opportunities to increase future cash flows. This ASU is effective for annual periods beginning after December 15, 2024 and should be applied prospectively, with retrospective application permitted. At December 31, 2023, the Company performed assessment of its income tax disclosures and does not believe that adoption of ASU 2023-09 would have a material impact on disclosures of income taxes.
3. Accounts Receivable
As at December 31,
(Thousands of U.S. Dollars) 2023 2022
Trade $ 5,812 $ 5,601
Other 6,547 5,105
Total Accounts Receivable $ 12,359 $ 10,706
4. Property, Plant and Equipment
As at December 31,
(Thousands of U.S. Dollars) 2023 2022
Oil and natural gas properties
Proved $ 4,876,185 $ 4,617,804
Unproved 54,116 74,471
4,930,301 4,692,275
Other (1)
73,505 61,386
5,003,806 4,753,661
Accumulated depletion, depreciation and impairment (3,860,956) (3,652,759)
$ 1,142,850 $ 1,100,902
(1) The “other” category includes $53.3 million right-of-use assets for finance leases and operating leases, which had a net book value of $32.4 million as at December 31, 2023 (December 31, 2022 - $38.9 million which had a net book value of $24.6 million).
On April 11, 2023, the Company and Ecopetrol S.A. renegotiated the terms of the contract for Company’s operatorship of the Suroriente Block, which was previously scheduled to end in mid-2024 and executed the Suroriente Continuation Agreement. The duration of the contract was extended for 20 years from September 1, 2023 (the “Effective Date”), the date on which the Company satisfied the relevant conditions precedent and regulatory approval was received. The Company continues to be the operator of the Suroriente Block. In connection with the contract extension, the Company paid cash consideration of $6.2 million and provided letters of credit of $123.0 million (Note 12) related to committed capital investments to be made over a three-year period from the Effective Date.
During the year ended December 31, 2023, the Company entered into new lease contracts related to power generating equipment and capitalized $12.4 million right-of-use assets related to those contracts.
Depletion and depreciation expense on property, plant and equipment for the year ended December 31, 2023, was $209.7 million (2022 - $175.8 million; 2021 - $135.7 million). A portion of depletion and depreciation expense was recorded as oil inventory in each year.
Unproved Oil and Natural Gas Properties
At December 31, 2023, 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, 2023, 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, 2023:
Costs Incurred in
(Thousands of U.S. Dollars) 2023 2022 2021 Prior to 2021
Total
Acquisition costs - Colombia $ - $ - $ - $ 5,161 $ 5,161
Exploration costs - Colombia 2,743 6,742 1,736 24,711 35,932
Exploration costs - Ecuador 10,380 499 472 1,672 13,023
$ 13,123 $ 7,241 $ 2,208 $ 31,544 $ 54,116
5. Asset impairment
For the years ended December 31, 2023, 2022 and 2021 the Company had no ceiling test impairment losses. In accordance with GAAP, Gran Tierra used an unweighted arithmetic average of the first-day-of-the-month Brent price of $82.51 per bbl for the December 31, 2023 ceiling test calculations (December 31, 2022, and 2021 - $97.98 and $68.92 per bbl, respectively).
The Company has considered the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in the impairment assessment on oil and gas properties. The estimated ceiling amount of the Company’s oil and gas properties was based on proved reserves, the life of which is generally less than 15 years. The ultimate period in which global energy markets can transition from carbon-based sources to alternative energy is highly uncertain. However, the majority of the cash flows associated with proved reserves per the 2023 reserve report is expected to be realized prior to the potential elimination of carbon-based energy.
At December 31, 2023, a specific adjustment to the discount rate used in the ceiling test to account for the risk of the evolving demand for energy is not permitted as under the full cost accounting the 10% discount rate is prescribed.
6. Accounts Payable and Accrued Liabilities
As at December 31,
(Thousands of U.S. Dollars) 2023 2022
Trade $ 122,709 $ 114,263
Royalties 2,636 2,760
Employee compensation 6,221 3,051
Other 55,441 47,505
$ 187,007 $ 167,579
7. Debt and Debt Issuance Costs
The Company’s debt at December 31, 2023 and 2022, was as follows:
As at December 31,
(Thousands of U.S. Dollars) 2023 2022
Current
Credit Facility
$ 36,364 $ -
Unamortized debt issuance costs (755) -
$ 35,609 $ -
Long-term
6.25% Senior Notes
$ 24,828 $ 279,909
7.75% Senior Notes
24,201 300,000
9.50% Senior Notes
487,590 -
Unamortized Senior Notes discount
(27,958) (4,138)
Unamortized debt issuance costs
(15,679) (6,854)
Long-term lease obligation (1)
26,550 20,676
$ 519,532 $ 589,593
Total Debt
$ 555,141 $ 589,593
(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 $12.1 million as at December 31, 2023 (December 31, 2022 - $4.8 million).
Senior Notes
(Thousands of U.S. Dollars) 6.25% Senior Notes
7.75% Senior Notes
9.50% Senior Notes
Senior Notes, December 31, 2022
$ 279,909 $ 300,000 $ -
Purchased in the open market (1)
(8,000) - -
Principal exchanged for 9.50% Senior Notes (2)
(247,081) (275,799) 522,782
Early participation premiums and discount for principal exchanged (3) (4)
- - 24,808
Principal payment (5)
- - (60,000)
Senior Notes principal, December 31, 2023
$ 24,828 $ 24,201 $ 487,590
(1) During the year ended December 31, 2023, the Company purchased in the open market $8.0 million of 6.25% Senior Notes for cash consideration of $6.8 million. The purchase resulted in a $1.1 million gain, which included the write-off of deferred financing fees of $0.1 million. The purchase gain was recorded in “other gain” in the Company’s consolidated statements of operations. The Company cancelled all previously purchased 6.25% Senior Notes as at December 31, 2023.
(2) $247.1 million of 6.25% Senior Notes principal and $275.8 million of 7.75% Senior Notes principal exchanged for a net $487.6 million newly issued 9.50% Senior Notes.
(3) Early participation premium of $80 for each $1,000 aggregate principal amount and $20 for each $1,000 aggregate principal amount for the 6.25% Senior Notes and 7.75% Senior Notes, respectively. $242.5 million and $274.2 million of 6.25% Senior Notes and 7.75% Senior Notes, respectively, were exchanged for these terms.
(4) $4.6 million of remaining principal exchanged at $1,000 and $1.6 million of remaining principal exchanged at $950 for each $1,000 aggregate principal amount for the 6.25% Senior Notes and 7.75% Senior Notes, respectively.
(5) The Company paid cash consideration of $60.0 million for 6.25% Senior Notes exchanged as part of total consideration to eligible holders on a pro rata basis, for each $1,000 aggregate principal amount tendered and accepted for the early exchange deadline.
The Senior Notes tendered and accepted for exchange, as well as the notes previously held as treasury bonds, were cancelled. The exchange of the 6.25% Senior Notes was accounted for as debt extinguishment.and resulted in a gain of $5.3 million. The exchange of 7.75% Senior Notes was accounted for as debt modification and resulted in a loss of $6.1 million related to third party fees.
At December 31, 2023, the Company had $24.2 million of 7.75% Senior Notes due 2027, $24.8 million of 6.25% Senior Notes due 2025 and $487.6 million of newly issued 9.50% Senior Notes due 2029.
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 re-purchased.
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: 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 re-purchased.
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: 2024 and thereafter - 100%.
The 9.50% Senior Notes bear interest at a rate of 9.50% per year, payable semi-annually in arrears on April 15 and October 15 of each year, beginning on April 15, 2024. The 9.50% Senior Notes will mature on October 15, 2029, unless earlier redeemed or re-purchased.
The principal amount of 9.50% Senior Notes is to be repaid as follows: (i) October 15, 2026, 25% of the principal amount; (ii) October 15, 2027, 5% of the principal amount; (iii) October 15, 2028, 30% of the principal amount; and (iv) October 15, 2029, the remainder of the principal amount.
At any time, prior to October 15, 2026, the Company may redeem 35% of the aggregate principal amount of 9.50% Senior Notes at a redemption price equal to 109.50% of the principal amount. Additionally, the Company may redeem all or a portion of the 9.50% Senior Notes:
(i) prior to October 15, 2026, at a redemption price equal to a 100% principal amount plus an applicable premium, which is the greater of:
•1% of the principal amount of 9.50% Senior Notes, and
•the excess of the present value of the redemption price plus all required interest payments computed using a discount rate equal to the Treasury rate at the redemption date plus 0.5% due to date, excluding accrued but unpaid interest, over the outstanding principal amount of 9.50% Senior Notes
(ii) On or after October 15, 2026, at the following redemption prices: 2026 -104.750%; 2027 -102.375%; 2028 and thereafter - 100%.
If the Company undergoes a change of control, holders may require the Company to repurchase for cash all or any portion of their 9.50% Senior Notes at a change of control repurchase price equal to 101% of the principal amount plus accrued and unpaid interest to, but excluding, the change of control repurchase date.
On February 6, 2024, the Company issued additional $100.0 million of 9.50% Senior Notes and received net cash proceeds of $88.0 million as a result of this issuance. The newly issued 9.50% Senior Notes have the same terms and provisions, except for the issue price, as $487.6 million 9.50% Senior Notes outstanding at December 31, 2023 and will be combined together with originally issued 9.50% Senior Notes in respect of interest payments.
Credit Facility
During the year ended December 31, 2023, the Company, as guarantor, and Gran Tierra Energy Colombia GmbH and Gran Tierra Operations Colombia GmbH, as borrowers, amended and restated their credit facility with a market leader in the global commodities industry. As part of the restatement, the initial commitment was adjusted from $100 million to $50 million (maintaining the potential option of up to an additional $50 million, subject to approval by the lender). Additionally, the availability period for the draws under the amendment to the credit facility was extended until December 31, 2023, following which the credit facility is no longer advanceable. The credit facility continues to bear interest based on the secured overnight financing rate posted by the Federal Reserve Bank of New York, plus a credit margin of 6.00% and a credit-adjusted spread of 0.26%. Undrawn amounts under the credit facility bear interest at 2.10% per annum, based on the amount available. The credit facility is secured by the Company’s Colombian assets and economic rights and has a final maturity date of August 15, 2024. As of December 31, 2023, the credit facility was drawn by $36.4 million. For the year ended December 31, 2023, the Company incurred weighted-average interest rate on the credit facility of 11.59%.
Under the terms of the credit facility, the Company is required to maintain compliance with the following financial covenants:
i.Global Coverage Ratio of at least 150%, calculated using the net present value of the consolidated future cash flows of the Company up to the final maturity date discounted at 10% over the outstanding amount on the credit facility at each reporting period. The net present value of the consolidated future cash flows of the Company is required to be based on 80% of the prevailing ICE Brent forward strip.
ii.Prepayment Life Coverage Ratio of at least 150%, calculated using the estimated aggregate value of commodities to be delivered under the commercial contract from the commencement date to the final maturity date based on 80% of the prevailing ICE Brent forward strip and adjusted for quality and transportation discounts over the outstanding amount on the credit facility including interest and all other costs payable to the lender.
i.Liquidity ratio where the Company’s projected sources of cash exceed projected uses of cash by at least 1.15 times in each quarter period included in one year consolidated future cash flows. The future cash flows represent forecasted expected cash flows from operations, less anticipated capital expenditures, and certain other adjustments. The commodity pricing assumption used in this covenant is required to be 90% of the prevailing Brent forward strip for the projected future cash flows.
As of December 31, 2023, the Company was in compliance with all the above covenants.
On February 6, 2024, the outstanding balance under the credit facility was fully re-paid and the credit facility was terminated.
Leases
During the year ended December 31, 2023, the Company recorded three new finance leases for power generating equipment totaling $12.4 million which had the useful life ranging from one to three years and weighted average discount rate of 7.31%.
As of December 31, 2023, the Company’s finance leases had remaining useful lives ranging from one to four years and the weighted average discount rate of 8.45% and operating leases had remaining useful lives ranging from one to five years and the weighted average discount rate of 8.01%.
Interest Expense
The following table presents the total interest expense recognized in the accompanying consolidated statements of operations:
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Contractual interest and other financing expenses $ 49,975 $ 42,965 $ 50,572
Amortization of debt issuance costs 5,831 3,528 3,809
$ 55,806 $ 46,493 $ 54,381
The Company incurred debt issuance costs in connection with the issuance of the 9.50% Senior Notes and its credit facility. As at December 31, 2023, 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.
8. Share Capital
Shares of Common Stock
Shares issued and outstanding, December 31, 2020
36,698,156
Options exercised 16,294
Shares issued and outstanding, December 31, 2021
36,714,450
Options exercised 175,412
Shares issued, December 31, 2022
36,889,862
Shares re-purchased (1)
(2,274,746)
Shares issued and outstanding, December 31, 2022
34,615,116
Options exercised 1,839
Shares re-purchased and canceled (2,341,842)
Shares issued, December 31, 2023
32,275,113
Treasury stock (28,612)
Shares issued and outstanding at December 31, 2023
32,246,501
(1 2,274,746 re-purchased shares in 2022 were canceled during the year ended December 31, 2023.
The Company’s authorized share capital consists of 82 million shares of capital stock, of which 57 million was designated as Common Stock, par value $0.001 per share and 25 million as Preferred Stock, par value $0.001 per share.
On May 5, 2023, the Company completed a 1-for-10 reverse stock split of the Company’s Common Stock. As a result of the reverse stock split, every ten of the Company’s issued shares of Common Stock were automatically combined into one issued share of Common Stock, without any change to the par value per share. All share and per share numbers have been adjusted to reflect the reverse stock split. The Company’s outstanding options were also proportionately adjusted as a result of the reverse stock split to increase the exercise price and reduce the number of shares issuable upon exercise.
Share Re-purchase Program
During the year ended December 31, 2023, the Company implemented a share re-purchase program (the “2023 Program”) through the facilities of the Toronto Stock Exchange, the NYSE American or alternative trading programs in Canada or the United States, if eligible. Under the 2023 Program, the Company is able to purchase up to 3,234,914 shares of Common Stock, representing 10% of the public float as of October 20, 2023, at prevailing market prices at the time of purchase. The 2023 Program will continue for one year and expire on November 2, 2024, or earlier if the 10% maximum is reached.
During the year ended December 31, 2023, the Company re-purchased 1,041,804 shares of Common Stock at a weighted average price of approximately $6.21 per share under the 2023 Program and 1,328,650 shares at a weighted average price of $8.15 per share under the 2022 Program implemented in 2022 with similar terms to that of the 2023 Program. The 2022 Program expired in May 2023 when 10% share maximum was reached. The weighted average price per share under the 2022 Program was $10.59 per share. As of December 31, 2023, all 3,603,396 shares re-purchased under the 2022 Program and 1,013,192 shares re-purchased under the 2023 Program were cancelled subsequent to re-purchase.
Equity Compensation Awards
The Company has an equity compensation program for its executives, employees, and directors. Executives and employees are given equity compensation grants that vest based on a recipient’s continued employment. In the case of Performance Share Units (“PSUs”), the number of units that vest is dependent upon the achievement of specific key performance measures. Equity based awards consist of 80% of PSUs and 20% of stock options. The Company’s stock-based compensation awards outstanding as at December 31, 2023, include PSUs, deferred share units (“DSUs”), and stock options.
In accordance with the 2007 Equity Incentive Plan, as amended, the Company’s Board of Directors is authorized to issue options or other rights to acquire shares of the Company’s Common Stock. On June 27, 2012, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 2,330,610 shares to 3,980,610 shares. On June 2, 2021, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 3,980,610 shares to 5,480,610 shares. On May 4, 2022, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 5,480,610 shares to 5,980,610 shares.
The following table provides information about PSU, DSU and stock option activity for the year ended December 31, 2023:
PSUs DSUs Stock Options
Number of Outstanding Share Units Number of Outstanding Share Units Number of Outstanding Stock Options Weighted Average Exercise Price ($)
Balance, December 31, 2022
3,152,823 656,186 1,730,286 11.52
Granted 2,288,515 120,424 461,858 8.39
Exercised (1,523,408) - (1,839) 4.17
Forfeited (21,574) - (24,072) 7.04
Expired - - (138,426) 25.30
Balance, December 31, 2023
3,896,356 776,610 2,027,807 9.93
Vested and exercisable, at December 31, 2023
1,232,629 10.13
Vested, or expected to vest, at December 31, 2023 through the life of the options
2,002,537 9.93
For the year ended December 31, 2023, Stock-based compensation expense was $5.7 million (2022 - $9.0 million; 2021 - $8.4 million) and was recorded in G&A expenses.
At December 31, 2023, there was $8.6 million (December 31, 2022 - $10.5 million) of unrecognized compensation cost related to unvested PSUs and stock options 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, 2023, is 2.3 years.
PSUs
PSUs entitle the holder to receive, at the option of the Company, either the underlying number of shares of the Company’s Common Stock upon vesting of such units or a cash payment equal to the value of the underlying shares. PSUs will cliff vest after three years, subject to the grantee’s continued employment. 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, 2023, 1.8 million (December 31, 2022 - 1.2 million) of PSUs had vested and will settle in cash. The performance targets for the PSUs outstanding as at December 31, 2023, 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.2021 and 2022 awards: 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;
2023 awards: 25% of the award is subject to compliance with financial covenants and $20 million free cash flow (1);
and
iii.25% of the award is subject to targets relating to the execution of corporate strategy.
(1) Defined as funds flow from operations less capital expenditures before exploration expense and short-term incentive plan.
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. In excess of the target number granted, PSUs 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, 2023, DSUs were granted to directors and will be settled 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 and vest over three years. The term of the stock options granted is five years or three months after the grantee’s end of service to the Company, whichever occurs first.
For the year ended December 31, 2023, 1,839 stock options were exercised, and $8.0 thousand cash proceeds were received (2022 - 175,412 stock options were exercised, and $1.3 million cash proceeds were received and 2021 - 16,294 stock options were exercised, and $0.1 million cash proceeds were received).
At December 31, 2023 and 2022, the weighted average remaining contractual term for outstanding stock options was 2.3 and 2.5 years, respectively, and for exercisable stock options was 1.5 and 1.9 years, respectively.
The fair value of each stock option award is estimated on the date of grant using the Black-Scholes Merton option-pricing model based on assumptions noted in the following table:
Year Ended December 31,
2023 2022 2021
Dividend yield (per share) Nil Nil Nil
Volatility 82% to 90%
77% to 81%
71% to 80%
Weighted average volatility 88 % 77 % 78 %
Risk-free interest rate 3.6% to 4.7%
1.4% to 4.0%
0.4% to 0.9%
Expected term 4 - 5 years
5 years
4 - 5 years
The weighted average grant date fair value for options granted in the year ended December 31, 2023 was $5.57 (2022 - $8.83; 2021 - $4.67) per option. The weighted average grant date fair value for options vested in the year ended December 31, 2023 was $4.77 (2022 - $5.81; 2021 - $5.19) per option. The total fair value of stock options vested during the year ended December 31, 2023 was $2.3 million (2022 - $2.2 million; 2021 - $2.1 million).
Weighted Average Shares Outstanding
Year Ended December 31,
2023 2022 2021
Weighted average number of common shares outstanding 33,469,828 36,445,546 36,702,290
Shares issuable pursuant to stock options - 1,184,732 159,210
Shares assumed to be purchased from proceeds of stock options - (702,268) (74,161)
Weighted average number of diluted common shares outstanding 33,469,828 36,928,010 36,787,339
For the year ended December 31, 2023, all options were excluded from the diluted (loss) earnings per share calculation as the options were anti-dilutive (2022 - 590,025; 2021 - 1,555,982)
9. 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) 2023 2022
Balance, beginning of year $ 63,499 $ 54,525
Liability incurred 4,671 5,025
Settlements (377) (2,630)
Accretion 5,387 4,498
Revisions in estimated liability 328 2,081
Balance, end of year $ 73,508 $ 63,499
Current (1)
$ 479 $ 141
Long-term $ 73,029 $ 63,358
Balance, end of year $ 73,508 $ 63,499
(1) Current portion of asset retirement obligation is included in accounts payable and accrued liabilities on the Company’s balance sheet
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, 2023, the fair value of assets that were legally restricted for purposes of settling asset retirement obligations was $8.9 million (December 31, 2022 - $6.5 million). These assets were accounted for as restricted cash and cash equivalents on the Company’s balance sheet (Note 14).
10. Revenue
During the year ended December 31, 2023, the Company started sales in Ecuador. All of the Company’s revenue is generated from oil sales at prices that 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 (Colombia sales) and Oriente (Ecuador sales) crude differentials, and quality and transportation discounts each month. For the year ended December 31, 2023, 100% (2022 and 2021 - 100%) of the Company's revenue resulted from oil sales and quality and transportation discounts were 18% (2022 - 17%; 2021 - 15%) of the ICE Brent price. During the year ended December 31, 2023, the Company’s production was sold primarily to one major customer representing, 97% of total sales volumes in Colombia and 1% in Ecuador (2022 - two, representing 78% and 22% of total sales volumes in Colombia and 2021 - three, representing 66%, 19% and 12% of total sales volumes in Colombia).
As at December 31, 2023, 2022 and 2021, accounts receivable included nil accrued sales revenue related to December production of each respective year.
11. 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) 2023 2022 2021
Income (loss) before income taxes
United States $ (40,589) $ (38,161) $ (31,329)
Foreign 146,749 283,096 54,465
106,160 244,935 23,136
Statutory rate (1)
45 % 35% 31%
Income tax expense expected 47,772 85,727 7,172
Impact of foreign taxes 21,139 8,876 9,723
Foreign currency translation 39,995 (4,641) 14,450
Stock-based compensation 2,127 5,804 1,708
Change in valuation allowance (10,632) 2,386 (53,434)
Non-deductible third party royalty in Colombia 3,253 3,422 1,568
Other permanent differences 8,793 4,332 (1,058)
Non-deductible investment loss
- - 525
Total income tax expense (recovery) $ 112,447 $ 105,906 $ (19,346)
Effective tax rate 106 % 43% (84)%
Current income tax expense
Foreign 55,688 80,566 4,479
55,688 80,566 4,479
Deferred income tax expense (recovery)
Foreign 56,759 25,340 (23,825)
Total income tax expense (recovery) $ 112,447 $ 105,906 $ (19,346)
(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, 2023, 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 December 2022, the Colombian Government enacted a new tax reform bill which was effective January 1, 2023. The reform includes significant changes to the income tax regime applicable to oil companies, including the elimination of the tax deductibility of royalties paid-in cash, cost associated to royalties paid-in kind in the calculation of taxable income, and the introduction of a surcharge to the current 35% tax rate. The surcharge is determined by comparing the average inflation-adjusted Brent price during the taxation year to the monthly inflation-adjusted Brent price for the prior 120 months. When the Brent price during the taxation year exceeds the 30th percentile of the historical price range, a 5% surtax is applied. It increases to 10% and 15% when the Brent price during the taxation year exceeds the 45th and 60th percentiles, respectively. The 2023 calculation of current and deferred income tax has been prepared with a surtax of 10% for an aggregated income tax rate of 45%. Additionally, during the year ended December 31, 2023, the Constitutional Court declared unconstitutional prohibition for oil and gas and mining companies to deduct for income tax purposes the non-renewable natural resources royalty payments to the Colombian Government. The Company has considered the impact of these changes on its income tax provision.
The table below presents the components of the deferred tax liabilities and assets as at December 31, 2023 and 2022:
As at December 31,
(Thousands of U.S. Dollars) 2023 2022
Tax benefit of operating loss carryforwards $ 29,448 $ 53,720
Book basis in excess of tax basis
(86,510) (20,349)
Foreign tax credits
66,515 66,515
Other accruals
51,022 37,185
Deferred tax assets before valuation allowance 60,475 137,071
Valuation allowance (107,005) (114,109)
Net deferred tax (liabilities) assets
$ (46,530) $ 22,962
Deferred tax assets
10,923 22,990
10,923 22,990
Deferred tax liabilities
57,453 28
57,453 28
Net deferred tax (liabilities) assets
$ (46,530) $ 22,962
At December 31, 2023, the Company has not recognized the benefit of unused non-capital loss carryforwards of $58.8 million (2022 - $91.3 million, 2021 - $62.1 million) for federal purposes in the United States, which expire from 2031 to 2042.
At December 31, 2023, the Company has recognized the benefit of unused non-capital loss carryforwards of $16.5 million (2022 - $40.7 million, 2021 - $102.4 million), out of a total of $20.3 million for federal purposes in Colombia, some of which will expire from 2031 to 2034 and majority be carried forward indefinitely.
As at December 31, 2023, Gran Tierra had $0.8 million of unrecognized tax benefits and related interest and penalties included in its deferred tax assets and current tax liabilities on 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 year ended December 31, 2023. 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 2017 through 2023 in certain jurisdictions.
12. Commitments and Contingencies
Purchase Obligations, Firm Agreements and Leases
As at December 31, 2023, 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 2024 2025 2026 2027 2028 Thereafter
Facilities 8,317 2,483 2,476 2,476 882 - -
Operating leases (1)
12,857 4,309 2,951 1,958 1,985 1,654 -
Finance leases (1)
31,630 10,607 7,322 4,988 3,179 5,534 -
Software and Telecommunication 396 332 64 - - - -
$ 53,200 $ 17,731 $ 12,813 $ 9,422 $ 6,046 $ 7,188 $ -
(1) Including maintenance and operating costs.
Gran Tierra has operating leases for office spaces, vehicles, and tanks and finance leases for power generation and enhanced oil recovery facilities, storage tanks, and compressors.
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, 2023, the Company had provided letters of credit and other credit support totaling $220.1 million (December 31, 2022 - $111.1 million) as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, the Suroriente Block (Note 4), and other capital or operating requirements.
Contingencies
Gran Tierra has several lawsuits and claims pending. The outcome of the 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.
13. Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk
Financial Instruments
Financial instruments are initially recorded at fair value, defined as the price that would be received to sell an asset or paid to market participants to settle liability at the measurement date. For financial instruments carried at fair value, 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 representing quoted market prices in active markets for identical assets and liabilities
•Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the assets and liabilities, either directly or indirectly
•Level 3 - Unobservable inputs for assets and liabilities
The Company’s financial instruments recognized on the balance sheet consist of cash and cash equivalents, restricted cash and cash equivalents(1), accounts receivable, PEF, other long-term assets, accounts payable and accrued liabilities, credit facility, long-term debt and other long-term liabilities. The Company’s valuation techniques to measure the fair values of assets and liabilities are described in the subsequent disclosures.
Fair Value Measurement
The following table presents the Company’s fair value measurements of its financial instruments as of December 31, 2023 and 2022:
As at December 31,
2023 2022
(Thousands of U.S. Dollars)
Level 1
Assets
PEF - current (1)
$ 5,630 $ 5,981
PEF - long-term (2)
- 9,975
$ 5,630 $ 15,956
Liabilities
6.25% Senior Notes
$ 22,994 $ 243,801
7.75% Senior Notes
20,744 241,455
9.50% Senior Notes
429,018 -
$ 472,756 $ 485,256
Level 2
Assets
Restricted cash and cash equivalents - long-term (2)
$ 7,750 $ 5,343
$ 7,750 $ 5,343
(1) Included in the other current assets on the Company’s balance sheet
(2) The long-term portion of restricted cash and PEF are included in the other long-term assets on the Company’s balance sheet
The fair values of cash and cash equivalents, current restricted cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities and credit facility approximate their carrying amounts due to the short-term maturity of these instruments.
Restricted cash - long-term
The fair value of long-term restricted cash and cash equivalents approximate its carrying value because interest rates are variable and reflective of market rates.
PEF
To reduce the Company’s exposure to changes in the trading price of the Company’s common shares on outstanding PSUs and DSU’s, the Company entered into PEF. At the end of the term, the counterparty will pay the Company an amount equivalent to the notional amount of the shares using the price of the Company’s shares of Common Stock at the valuation date. The Company has the discretion to increase or decrease the notional amount of the PEF or terminate the agreement early. As at December 31, 2023, the Company’s PEF had a notional amount of 1.0 million shares and a fair value of $5.6 million. During the year ended December 31, 2023, the Company recorded a loss of $5.0 million on the PEF in G&A expenses (December 31, 2022 - $1.3 million gain and 2021 - $0.9 million). The fair value of PEF asset was estimated using Company’s share price quoted in active markets at the end of each reporting period.
Senior Notes
Financial instruments recorded at amortized costs at December 31, 2023, include the Senior Notes (Note 7). The Senior Notes are publicly traded on Singapore Exchange and the fair value is determined using the Senior Notes trading prices at the end of each reporting period.
At December 31, 2023, the carrying amounts of the 6.25% Senior Notes, 7.75% Senior Notes and 9.50% Senior Notes were $24.6 million, $23.8 million and $444.6 million, respectively, which represents the aggregate principal amounts less unamortized debt issuance costs and discounts.
Derivative asset and derivative liability
As at December 31, 2023, the Company did not have any outstanding derivative positions.
The following table presents the nature of our financial instruments gains or losses for each of the three years ended December 31, 2023:
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Commodity price derivative loss
$ - $ 26,611 $ 48,723
Foreign currency derivative loss - - 115
$ - $ 26,611 $ 48,838
Unrealized investment loss $ - $ - $ 2,032
Loss on sale of investment - - 1,355
Other financial instruments loss (gain)
15 (7) (18)
$ 15 $ (7) $ 3,369
Commodity Price Risk
The Company may at times 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, 2023, the Company had no outstanding commodity price derivative positions.
Foreign Exchange Risk
The Company is exposed to foreign exchange risk in relation to its Colombian operations predominantly in operating and transportation costs and G&A expenses. To mitigate exposure to fluctuations in foreign exchange, the Company may enter into foreign currency exchange derivatives. As at December 31, 2023, the Company had no outstanding foreign currency exchange derivative positions.
Unrealized foreign exchange gains and losses primarily result from fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s accounts payable, tax and deferred tax assets and liabilities 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 one percent strengthening in Colombian peso against the U.S. dollar results in foreign exchange loss of approximately $0.4 million of U.S. dollars on accounts payable, gain of approximately $0.3 million of U.S. dollars on taxes receivable and payable and loss of approximately $0.4 million of U.S. dollars on deferred tax assets and liabilities. This effect was calculated based on the Company’s December 31, 2023, accounts payable, deferred tax assets, and taxes payable.
For the years ended December 31, 2023, 97% of the Company oil sales were generated in Colombia and 3% of oil sales generated in Ecuador (2022 and 2021 respectively, 100% of the Company's oil sales were generated in Colombia). In Colombia and Ecuador, 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 cash equivalents accounts receivable reflects management’s assessment of credit risk.
At December 31, 2023, cash and cash equivalents and restricted cash and cash equivalents 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. Additionally, the Company reduces the credit risk exposure by managing its accounts receivable which are paid on a weekly basis. For the year ended December 31, 2023, the Company had one customer (2022 - two and 2021 - three) which accounted for over 95% 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.
14. 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 such amounts shown in the consolidated statements of cash flows:
As at December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Cash and cash equivalents $ 62,146 $ 126,873 $ 26,109
Restricted cash and cash equivalents - current(1)
1,142 1,142 392
Restricted cash and cash equivalents - long-term (1)
7,750 5,343 4,903
$ 71,038 $ 133,358 $ 31,404
(1) The current portion of restricted cash and cash equivalents is included in other current assets and long-term portion of restricted cash and cash equivalents 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) 2023 2022 2021
Accounts receivable and other long-term assets $ (1,628) $ 2,352 $ (5,686)
Derivatives - (2,749) 1,797
PEF 11,118 (9,876) (7,605)
Prepaids and inventory (9,557) (5,940) (2,582)
Accounts payable and accrued and other long-term liabilities (1,276) (5,789) 48,206
Taxes receivable and payable
(47,073) 86,319 25,024
Net changes in assets and liabilities from operating activities $ (48,416) $ 64,317 $ 59,154
The following table provides additional supplemental cash flow disclosures:
Year Ended December 31,
(Thousands of U.S. Dollars) 2023 2022 2021
Cash paid for income taxes $ 49,323 $ 5,480 $ 2,892
Cash paid for withholding taxes
$ 52,397 $ 31,572 $ 33,460
Cash paid for interest $ 43,755 $ 43,363 $ 50,109
Non-cash investing activities
Net liabilities related to property, plant and equipment, end of year $ 47,416 $ 55,118 $ 30,142
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 Net After Royalty (“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, 2021, 2022, and 2023, and the changes in total net proved reserves during the three-year period ended December 31, 2023.
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, 2023, have been evaluated by independent reservoir engineering specialist, 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.
Liquids (1)
Gas
(Mbbl) (MMcf)
Proved NAR Reserves, December 31, 2020
64,692 1,655
Improved recoveries 2,057 -
Extensions (2)
7,475 -
Technical revisions 1,009 133
Production (8,668) (119)
Proved NAR Reserves, December 31, 2021
66,565 1,669
Extensions and discoveries (2)
6,273 -
Technical revisions (2)
1,558 (208)
Production
(9,129) (15)
Proved NAR Reserves, December 31, 2022
65,267 1,446
Extensions and discoveries (2)
17,808 -
Technical revisions (2)
725 (1,446)
Production (3)
(9,504) -
Proved NAR Reserves, December 31, 2023
74,296 -
Proved Developed Reserves NAR, December 31, 2020
38,660 633
Proved Developed Reserves NAR, December 31, 2021
41,869 880 880
Proved Developed Reserves NAR, December 31, 2022
40,360 858 858
Proved Developed Reserves NAR, December 31, 2023
39,599 -
Proved Undeveloped Reserves NAR, December 31, 2020
26,032 1,022
Proved Undeveloped Reserves NAR, December 31, 2021
24,696 789
Proved Undeveloped Reserves NAR, December 31, 2022
24,907 588
Proved Undeveloped Reserves NAR, December 31, 2023
34,697 -
(1) At December 31, 2023, 2022, and 2021, liquids reserves are 100% oil.
(2) Includes the following volumes related to Ecuador: 2023 - 1.5 MMbbl of extensions and 0.6 MMbbl of technical revisions; 2022 - 2.5 MMbbl of extensions and (0.2) MMbbl of technical revisions; 2021 - 0.5 MMbbl of extensions
(3) Includes 0.2 MMbbl of production related to Ecuador for the year ended December 31, 2023
Changes in proved reserves during the years ended December 31, 2023, 2022 and 2021 shown in the table above primarily resulted from the following significant factors:
Improved Recoveries. There were no improved recoveries for the years ended December 31, 2023 and 2022, respectively. There were 2.1 MMbbl of improved recoveries of heavy oil in the Acordionero field for the year ended December 31, 2021.
Extensions and Discoveries. Added 17.8 MMbbl of proved reserves during the year ended December 31, 2023, of which 16.3 MMbbl were extensions in Colombia and 1.5 MMbbl were discoveries in Ecuador. In Colombia, we had 1.2, 3.5, 2.0 and 9.6 MMbbl of extensions in the Acordionero, Costayaco and Moqueta fields and Suroriente Block respectively, with a 1.5 MMbbl discovery in the Chanangue Block (2022 - 6.3 MMbbl due to reserve extensions in the Acordionero and Costayaco fields and the Charapa and Chanangue Blocks and a discovery in the Alea-1848 Block and 2021 - 7.5 MMbbl, due to reserve extensions in the Acordionero, Costayaco, Moqueta and Charapa fields).
Technical and Economic Revisions. Added 0.7 MMbbl of proved oil reserves and removed all gas reserves during the year ended December 31, 2023. In Colombia this was primarily due to continued waterflood performance in the Costayaco and Acordionero fields as well as production type curve increases in the Ecuador Blocks (2022 - 1.6 MMBOE related to positive technical revisions based on increased drilling and continued waterflood performance in the Acordionero and Costayaco fields and 2021 - 1.0 MMBOE, related to positive technical revisions based on performance and waterflood response in the Acordionero and Costayaco 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, 2023:
(Thousands of U.S. Dollars) Proved Properties Unproved Properties Accumulated
Depletion,
Depreciation
and
Impairment Net Capitalized Costs
Balance, December 31, 2023
$ 4,876,185 $ 54,116 $ (3,821,115) $ 1,109,186
Balance, December 31, 2022
$ 4,617,804 $ 74,471 $ (3,617,380) $ 1,074,895
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) Colombia
Ecuador
Total
Year Ended December 31, 2021
Property acquisition costs
Proved $ - $ - $ -
Unproved $ - $ - $ -
Exploration costs $ 18,080 $ 2,330 $ 20,410
Development costs $ 142,461 $ - $ 142,461
Year Ended December 31, 2022
Property acquisition costs
Proved $ - $ - $ -
Unproved $ - $ - $ -
Exploration costs $ 50,374 $ 39,524 $ 89,898
Development costs $ 160,933 $ - $ 160,933
Year Ended December 31, 2023
Property acquisition costs
Proved $ - $ - $ -
Unproved $ - $ - $ -
Exploration costs $ 15,674 $ 14,188 $ 29,862
Development costs $ 199,240 $ 4,581 $ 203,821
D. Results of Operations for Oil and Gas Producing Activities
(Thousands of U.S. Dollars) Colombia
Ecuador
Total
December 31, 2023
Oil sales $ 621,297 $ 15,660 $ 636,957
Production costs (192,933) (8,477) (201,410)
Exploration expenses - - -
DD&A expenses (207,346) (8,018) (215,364)
Inventory impairment
- - -
Income tax (expense) recovery
(103,491) 90 (103,401)
Results of Operations $ 117,527 $ (745) $ 116,782
December 31, 2022
Oil sales $ 711,388 $ - $ 711,388
Production costs (172,582) - (172,582)
Exploration expenses - - -
DD&A expenses (180,039) - (180,039)
Inventory impairment - - -
Income tax (expense) recovery (105,906) - (105,906)
Results of Operations $ 252,861 $ - $ 252,861
December 31, 2021
Oil sales $ 473,722 $ - $ 473,722
Production costs (147,339) - (147,339)
Exploration expenses - - -
DD&A expenses (139,765) - (139,765)
Inventory impairment - - -
Income tax (expense) recovery 19,346 - 19,346
Results of Operations $ 205,964 $ - $ 205,964
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 Ecuador
Twelve month period unweighted arithmetic average of the wellhead price as of the first day of each month within the twelve month period
2023 $ 69.91 $ 77.44
2022 $ 86.16 $ 91.53
2021 $ 58.07 $ 62.42
Weighted average production costs
2023 $ 18.54 $ 20.66
2022 $ 16.26 $ 19.55
2021 $ 15.55 $ 17.40
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 prescribed 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% prescribed discount rate; 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 Ecuador Total
December 31, 2023
Future cash inflows $ 4,893,758 $ 358,421 $ 5,252,179
Future production costs $ (1,552,227) $ (158,643) $ (1,710,870)
Future development costs $ (460,819) $ (89,639) $ (550,458)
Future asset retirement obligations $ (82,314) $ (3,300) $ (85,614)
Future income tax expense $ (954,973) $ (41,852) $ (996,825)
Future net cash flows $ 1,843,425 $ 64,987 $ 1,908,412
10% discount $ (516,451) $ (22,924) $ (539,375)
Standardized Measure of Discounted Future Net Cash Flows $ 1,326,974 $ 42,063 $ 1,369,037
December 31, 2022
Future cash inflows $ 5,410,256 $ 256,220 $ 5,666,476
Future production costs (1,298,198) (104,614) (1,402,812)
Future development costs (334,560) (63,040) (397,600)
Future asset retirement obligations (50,520) (2,700) (53,220)
Future income tax expense (1,391,436) (33,058) (1,424,494)
Future net cash flows 2,335,542 52,808 2,388,350
10% discount (659,092) (18,632) (677,724)
Standardized Measure of Discounted Future Net Cash Flows $ 1,676,450 $ 34,176 $ 1,710,626
December 31, 2021
Future cash inflows $ 3,880,608 $ 30,573 $ 3,911,181
Future production costs (1,249,901) (13,502) (1,263,403)
Future development costs (365,983) (12,175) (378,158)
Future asset retirement obligations (47,580) (600) (48,180)
Future income tax expense (514,231) (1,866) (516,097)
Future net cash flows 1,702,913 2,430 1,705,343
10% discount (481,504) (2,062) (483,566)
Standardized Measure of Discounted Future Net Cash Flows $ 1,221,409 $ 368 $ 1,221,777
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:
(Thousands of U.S. Dollars) 2023 2022 2021
Balance, beginning of year $ 1,710,626 $ 1,221,777 $ 727,487
Sales and transfers of oil and gas produced, net of production costs (739,703) (433,676) (244,486)
Net changes in prices and production costs related to future production (924,346) 1,373,950 1,217,785
Extensions, discoveries and improved recovery, less related costs 583,254 384,414 382,423
Previously estimated development costs incurred during the year (156,664) (136,856) (98,724)
Revisions of previous quantity estimates 981,873 75,460 (191,738)
Accretion of discount 171,063 122,178 72,748
Net change in income taxes 32,875 (739,879) (414,458)
Changes in future development costs (289,941) (156,742) (229,260)
Net (decrease) increase (341,589) 488,849 494,290
Balance, end of year $ 1,369,037 $ 1,710,626 $ 1,221,777

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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, 2023, 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, 2023, 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, 2023. The effectiveness of our internal control over financial reporting as of December 31, 2023, 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 fourth quarter ended December 31, 2023, 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 and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2023, 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, 2023, 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, 2023 and 2022, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes (collectively, the consolidated financial statements), and our report dated February 20, 2024 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 20, 2024

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
2024 Annual Meeting
The Board of Directors of Gran Tierra Energy Inc. has established May 2, 2024 as the date of the Company’s 2024 Annual Meeting of Stockholders (the “2024 Annual Meeting”) and March 6, 2024 as the record date for determining stockholders entitled to notice of, and to vote at, the 2024 Annual Meeting. The time and location of the 2024 Annual Meeting will be as set forth in the Company’s proxy materials for the 2024 Annual Meeting.
Credit Facility
The Amendment made various changes to the Credit Facility, including: (i) the initial commitment was adjusted from $100 million to $50 million (maintaining the potential option of up to an additional $50 million, subject to approval by the lender) (ii) the availability period for the draw under the Credit Facility was extended from August 20, 2023 (extended under the Amended Credit Facility) until December 31, 2023.
The Credit Facility, as amended and restated, remains secured by Gran Tierra’s Colombian assets and economic rights and its remaining commercial terms remain unchanged. The Credit Facility has a final maturity date of August 15, 2024. As of February 20, 2024, the credit facility has been drawn by $36 million.
Trading Arrangements
During the three months ended December 31, 2023, no director or Section 16 officer adopted or terminated any Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements (in each case, as defined in Item 408(a) of Regulation S-K).

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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 2024 Annual Meeting of Stockholders (our “Proxy Statement”), a copy of which will be filed with the SEC within 120 days after December 31, 2023. 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), Chief Financial Officer and Executive Vice President, Finance (Principal Financial and Accounting Officer) and Chief Operating Officer (Principal Operating Officer) Gran Tierra has made the Code available on its website at www.grantierra.com.
Gran Tierra intends to satisfy the public disclosure requirements regarding (1) any amendments to the Code, or (2) any waivers under the Code given to Gran Tierra’s Principal Executive Officer, Principal Financial and Accounting Officer and Principal Operating 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, 2023:
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 2,027,807 9.93 1,640,219
Equity compensation plans not approved by security holders - - -
2,027,807 9.93 1,640.219
(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 (“PSUs”), and deferred share units (“DSUs”), 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, 2023, 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, 2023, 4,672,966 shares were issued and outstanding relating to PSUs and DSUs and would represent a 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 1.0 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 Incentive 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 53
Consolidated Statements of Operations 56
Consolidated Balance Sheets 57
Consolidated Statements of Cash Flow 58
Consolidated Statements of Shareholders’ Equity 59
Notes to the Consolidated Financial Statements 60
Supplementary Data (Unaudited) 79
(2) Financial Statement Schedules
None.
(3) Exhibits
Exhibit No. Description Reference
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 Certificate of Amendment to Certificate of Incorporation of Gran Tierra Energy Inc., effective May 5, 2023. Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, filed with the SEC on May 5, 2023 (SEC File No. 001-34018).
3.3 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).
3.4 Amendment No.1 to Bylaws 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 August 4, 2021 (SEC File No. 001-34018).
4.1 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).
4.2 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).
4.3 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).
4.4 Form of 6.25% Senior Notes due 2025.
Incorporated by reference to Exhibit 4.2 (included as Exhibit A 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).
4.5 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).
4.6 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 Indenture related to the 9.50% Senior Notes due 2029, dated as of October 20, 2023, 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 October 24, 2023 (SEC File No. 001-34018).
4.12 Form of 9.500% Senior Secured Amortizing Notes due 2029 (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 October 24, 2023 (SEC File No. 001-34018).
4.13 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 Amended and Restated 2007 Equity Incentive Plan*
Incorporated by reference to Appendix of the Definitive Proxy Statement filed with the SEC on March 25, 2022 (SEC File No. 001-34018).
10.2 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).
10.3 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).
10.4 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).
10.5 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).
10.6 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).
10.7 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).
10.71 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).
10.72 Executive Employment Agreement effective November 6, 2023, between GTE Alberta Inc, Gran Tierra Energy Inc. and Sebastien Morin.*
Filed herewith.
10.73 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).
10.74 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).
10.75 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).
10.76 Credit Agreement, dated as of August 18, 2022, by and among Gran Tierra Energy Inc., Gran Tierra Energy Colombia GMBH, Gran Tierra Operations Colombia GMBH and Trafigura PTE Ltd. as a lender
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with SEC on August 23, 2022 (SEC File No. 001-34018).
10.77 Deed of Amendment and Restatement to Credit Agreement dated September 19, 2023 by and among Gran Tierra Energy Inc., Gran Tierra Energy Colombia GmbH, Gran Tierra Operations Colombia GmbH. and Trafigura PTE Ltd. as a lender.
Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the SEC on November 1, 2023 (SEC File No. 001-34018).
10.78 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).
10.79 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).
10.80 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).
10.81 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).
10.82 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).
10.83 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).
10.84 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).
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.
97.1 Gran Tierra Energy Inc. Clawback Policy
Filed herewith.
99.1 Gran Tierra Energy Inc. Reserves Assessment and Evaluation of Oil and Gas Properties Corporate Summary, effective December 31, 2023.
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.