10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

 For the fiscal year ended December 31, 2023

or

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

 For the transition period from __________ to __________

Commission file number 001-34018

GRAN TIERRA ENERGY INC.

(Exact name of registrant as specified in its charter)

 

Delaware				98-0479924
(State or other jurisdiction of incorporation or organization)				(I.R.S. Employer Identification No.)
500 Centre Street S.E.
	Calgary,	Alberta	Canada	T2G 1A6
(Address of principal executive offices, including zip code)

(403) 265-3221

(Registrant’s telephone number, including area code)

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

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.001 per share	GTE	NYSE American
		Toronto Stock Exchange
		London Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.          Yes ☒ No ☐

Indicate by check mark whether the registrant submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes  ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☒
		Emerging growth company	☐

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

Act.                                                       ☐    

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the

effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.                  ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant

to §240.10D-1(b).                                      ☐

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2023, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $158.9 million.

On February 15, 2024, 32,246,501 shares of the registrant’s Common Stock with $0.001 par value were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this report, to the extent not set forth herein, is incorporated by reference from the registrant’s definitive proxy statement relating to the 2024 annual meeting of stockholders, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2023.

Auditor Name: KPMG LLP         Auditor Location: Calgary, Canada         Auditor Firm ID: 85

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Gran Tierra Energy Inc.

Annual Report on Form 10-K

Year Ended December 31, 2023

Table of Contents

 

		Page
PART I
Items 1 and 2.	Business and Properties	5
Item 1A.	Risk Factors	18
Item 1B.	Unresolved Staff Comments	26
Item 1C.	Cybersecurity	26
Item 3.	Legal Proceedings	27
Item 4.	Mine Safety Disclosures	27
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
Item 6.	[Reserved]
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	53
Item 8.	Financial Statements and Supplementary Data	53
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	84
Item 9A.	Controls and Procedures	84
Item 9B.	Other Information	86
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	86
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	86
Item 11.	Executive Compensation	87
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	87
Item 13.	Certain Relationships and Related Transactions, and Director Independence	87
Item 14.	Principal Accounting Fees and Services	88
PART IV
Item 15.	Exhibits, Financial Statement Schedules	88
Item 16.	Form 10-K Summary	91
SIGNATURES		92

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CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this Annual Report on Form 10-K regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of our management for future operations, covenant compliance, capital spending plans and benefits of the changes in our capital program or expenditures, our liquidity and financial condition and those statements preceded by, followed by or that otherwise include the words “believe”, “expect”, “anticipate”, “intend”, “estimate”, “project”, “target”, “goal”, “plan”, “budget”, “objective”, “should”, or similar expressions or variations on these expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct or that, even if correct, intervening circumstances will not occur to cause actual results to be different than expected. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements, including, but not limited to, our operations are located in South America and unexpected problems can arise due to guerilla activity, strikes, local blockades or protests; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; other disruptions to local operations; global health events; global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including inflation and changes resulting from a global health crisis, geopolitical events, including the conflicts in Ukraine and the Gaza region, or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC, such as its decision in June 2023 to cut production and other producing countries and the resulting company or third-party actions in response to such changes; changes in commodity prices, including volatility or a prolonged decline in these prices relative to historical or future expected levels; the risk that current global economic and credit conditions may impact oil prices and oil consumption more than we currently predict which could cause further modification of our strategy and capital spending program; prices and markets for oil and natural gas are unpredictable and volatile; the effect of hedges; the accuracy of productive capacity of any particular field; geographic, political and weather conditions can impact the production, transport or sale of our products; our ability to execute its business plan and realize expected benefits from current initiatives; the risk that unexpected delays and difficulties in developing currently owned properties may occur; the ability to replace reserves and production and develop and manage reserves on an economically viable basis; the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates); the risk profile of planned exploration activities; the effects of drilling down-dip; the effects of waterflood and multi-stage fracture stimulation operations; the extent and effect of delivery disruptions, equipment performance and costs; actions by third parties; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; volatility or declines in the trading price of our common stock or bonds; the risk that we do not receive the anticipated benefits of government programs, including government tax refunds; our ability comply with financial covenants in our indentures and make borrowings under any future credit agreement; and those factors set out in Part I, Item 1A “Risk Factors” in this Annual Report on Form 10-K. The information included herein is given as of the filing date of this Annual Report on Form 10-K with the Securities and Exchange Commission (“SEC”) and, except as otherwise required by the securities laws, we disclaim any obligation or undertaking to publicly release any updates or revisions to, or to withdraw, any forward-looking statement contained in this Annual Report on Form 10-K to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based.

GLOSSARY OF OIL AND GAS TERMS

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

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

Sales volumes represent production NAR adjusted for inventory changes and losses. Our oil and gas reserves are reported NAR. Our production is also reported NAR, except as otherwise specifically noted as “working interest production before royalties”. Gas volumes are converted to BOE at the rate of 6 Mcf of gas per bbl of oil, based upon the approximate relative energy

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content of gas and oil. The rate is not necessarily indicative of the relationship between oil and gas prices. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(iii)Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only

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if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

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

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

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

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

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

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

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

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

PART I

Items 1 and 2. Business and Properties

General

Gran Tierra Energy Inc., together with its subsidiaries (“Gran Tierra”, “the Company”, “us”, “our”, or “we”), is a company focused on oil and gas exploration and production 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.

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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.

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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.

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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%

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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,
	2023	2022
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.

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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

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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

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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.

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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.

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	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

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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

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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

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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

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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.

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.

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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.

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

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

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

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

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

Our business is subject to local legal, social, 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.

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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

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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

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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

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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,

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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

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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.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

Governance

Board of Directors

The Board of Directors (“the Board”) has delegated the primary responsibility to oversee risks from cybersecurity threats to the Audit Committee. The Board and Audit Committee regularly review the measures implemented by the Company to identify and mitigate data protection and cybersecurity risks. The Board and Audit Committee are updated on a quarterly basis by Vice President, Corporate Services on the Company’s internal information technology (“IT”) security testing, any unauthorized attempts to access the Company’s network, any significant developments in cyber security risks and threats, and updates on the Company’s policies and procedures for protecting the Company’s data. We also have processes by which certain cybersecurity incidents are escalated within the Company and, where appropriate, reported in a timely manner to the Board and Audit Committee. All incidents are reported to the Executive Officers (including the President and Chief Executive Officer, Chief Financial Officer and the Chief Operating Officer) who assess the severity and what measures and procedures are necessary.

As part of the Company’s enterprise risk management, the Board of the Company receives, reviews and assesses reports from the Board’s committees and from management relating to enterprise-level risks. The Audit Committee reports its cybersecurity risk assessments to the full Board at each regularly scheduled Board meeting.

Management

The Executive Officers and Vice President, Corporate Services are involved in all significant and appropriate cybersecurity decisions on the implementation and design of our IT architecture. Vice President, Corporate Services, along with support from the Director of IT, is responsible for the assessment and management of risks from cybersecurity threats and oversees the implementation of IT processes, which includes cybersecurity, into the core business of the Company. The Director of IT has extensive cybersecurity knowledge and skills gained from over 20 years of relevant work experience. The Director of IT discusses all potential changes to the Company’s controls or detection systems with the Vice President, Corporate Services prior to implementation. The Vice President, Corporate Services is updated by the Director of IT on a regular basis regarding trends in technology and cybersecurity threats or any potential changes to the Company’s cybersecurity program. The Director of IT is informed about and monitors the prevention, detection, mitigation, and remediation of cybersecurity incidents through a number of experienced direction systems and third party cybersecurity providers. The Vice President, Corporate Services also attends certain meetings of the Audit Committee to report information on material risks from cybersecurity threats. None of our critical core business activities that impact production, transportation or sales of oil and gas are remotely controlled.

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Risk Management and Strategy

We have implemented a cybersecurity program to assess, identify, mitigate and manage risks from cybersecurity threats that may result in material adverse effects on the confidentiality, integrity, and availability of our information systems. As part of this program, we have processes in place that include a variety of controls, systems, and technologies designed to prevent or mitigate data loss, theft, misuse, or other cybersecurity incidents affecting the data we collect, process, store, and transmit as part of our business. We conduct penetration testing and cybersecurity audits, and require all employees to undertake data protection and cybersecurity training on an annual basis. We also use systems and processes designed to oversee and identify risks associated with our use of third-party service providers, including with respect to the occurrence of a cybersecurity incident at a third-party service provider or that otherwise implicates a third-party technology or system we use. We contract cybersecurity specialists to review and implement controls and structural mechanisms in order to enhance our cybersecurity program, and protect against and detect cybersecurity threats.

To our knowledge, we have not experienced any risks from cybersecurity threats or incidents through the date of this annual report that have materially affected or are reasonably likely to materially affect the Company, its business strategy, results of operation or financial condition. This does not guarantee that future incidents or threats will not have a material impact or that we are not currently the subject of an undetected incident or threat that may have such an impact.

Additional information on cybersecurity risks we face is discussed in “Risk Factors” in Item 1A, which should be read in conjunction with the foregoing information.

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.

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.

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•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

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.

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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.

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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

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(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,

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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:

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	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)

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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.

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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.

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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.

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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.

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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		%

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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.

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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

40

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.

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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

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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.

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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.

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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

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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

46

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.

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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.

48

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

49

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

50

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

51

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

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

53

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.

54

/s/ KPMG LLP

Chartered Professional Accountants

We have served as the Company’s auditor since 2018

Calgary, Canada

February 20, 2024

55

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)

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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)

57

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)

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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)

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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.

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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.

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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.

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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.

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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

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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.

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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:

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	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%.

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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.

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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.

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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

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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.

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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).

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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.

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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.

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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

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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

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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

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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.

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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.

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	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).

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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

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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

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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

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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.

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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

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.

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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.

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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).

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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.

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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.

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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.

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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)

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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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EX-10.72

Exhibit 10.72

EXECUTIVE EMPLOYMENT AGREEMENT

BETWEEN:

GTE ALBERTA INC., an Alberta corporation (“GTE INC”) and GRAN TIERRA ENERGY INC., a Delaware corporation (“Gran Tierra”)

(GTE ULC and Gran Tierra are collectively referred to herein as, the “Company”)

- and -

SEBASTIEN MORIN, an individual ordinarily resident in Bragg Creek in the Province of Alberta

(the “Executive”)

(GTE INC, Gran Tierra and the Executive are collectively referred to herein as the “Parties”

and individually referred to herein as a “Party”)

RECITALS:

A.The Executive has been employed by GTE INC since November 6, 2023, in the position of Chief Operating Officer (COO);

B.GTE INC wishes to continue to employ the Executive and the Executive wishes to continue such employment; and

C.The Executive has also been employed by Gran Tierra and served as an officer of Gran Tierra since November 6, 2023.

In consideration of the above and for other good and valuable consideration, including enhancements to the Executive’s entitlement to an annual bonus and increasing the amount payable to the Executive in the event the Executive’s employment is terminated without cause or terminated contemporaneously with a Change of Control (as defined below), the Parties agree as follows:

ARTICLE 1
DUTIES AND RESPONSIBILITIES

1.1Position

On the terms and subject to the conditions hereinafter contained, the Executive will continue in employment with GTE INC as its Chief Operating Officer and as Chief Operating Officer of Gran Tierra. The Executive shall report to and be subject to the general direction of the President and Chief Executive Officer of Gran Tierra (the “President”) and shall undertake those duties customarily performed by a person holding the same or equivalent position in entities of a similar size, engaged in a similar business, as well as such other related duties that may be reasonably assigned by the President.

1.2Exclusive Service & Other Engagements

1

The Executive will faithfully serve the Company and will devote his full time and attention to the business and affairs of the Company and the performance of the Executive's duties and responsibilities hereunder.

The Executive shall not engage in any other business, profession or occupation which would conflict with the performance of his duties and responsibilities under this Agreement, either directly or indirectly, including accepting any appointment to the board of directors of another company without the prior written consent of the board of directors of Gran Tierra (the “Board”).

1.3Reassignment

The Executive agrees that the Company may modify or remove the Executive’s assigned duties; or change the place of the Executive’s employment without additional compensation to the Executive, in accordance with the Company’s needs. The parties acknowledge and agree that any such change of duties and responsibilities will not amount to, or constitute a constructive dismissal at common law, nor provide the Executive with Good Reason, so long as the change in duties and responsibilities are comparable to the Executive’s existing duties and commensurate with the position then held by the Executive.

1.4Travel

The Executive shall work at GTE INC’s offices in Calgary, Alberta. The Executive shall be available for such business-related travel as may be required for the purposes of carrying out the Executive’s duties and responsibilities hereunder. Such travel shall be in accordance with the Company’s travel policy as amended from time to time.

ARTICLE 2
BASE SALARY

The Company will pay the Executive an annual salary of $400,000Canadian Dollars, subject to applicable statutory deductions (the “Base Salary”). The Executive’s Base Salary will be payable in accordance with the Company’s practices and procedures as they may exist from time to time. Base Salary will be reviewed and may be increased on an annual basis.

ARTICLE 3
BONUS

1.1Bonus Eligibility

The Executive shall be eligible to receive a target annual bonus of 80% of Base Salary in addition to the Executive’s Base Salary and other compensation for each year of the Executive’s employment (the “Bonus”).

1.2Bonus Payment

The Bonus shall be payable by the Company shortly after the finalization of year end financials and will be based upon factors determined by the Board, including but not limited to financial, operating, and strategic goals, and the Executive’s performance during the preceding year.

ARTICLE 4
BENEFITS

2

The Executive will be entitled to participate in and to receive all rights and benefits under any life insurance, disability, medical, dental, health and accident plans maintained by the Company for its employees and for its executive officers specifically. The Company will continue to pay the Executive’s Base Salary in the event that the Executive becomes disabled until such time as the Executive begins to receive short-term or long-term disability insurance benefits or a final decision is made that there is no such entitlement.

ARTICLE 5
VACATION

The Executive will be entitled to twenty-five (25) days’ paid vacation per year. This vacation entitlement shall be earned over the course of each year that the Executive is employed, and the Executive shall be entitled to a proportionate period of vacation for any period of less than a full year of employment. The Executive will arrange vacation time to suit the essential business needs of the Company. Unused vacation entitlement in any year will be carried over into the following calendar year to a maximum entitlement of thirty (30) days in any one year. Upon termination for any reason, the Executive will be paid out any accrued but unused vacation entitlement.

ARTICLE 6
LONG TERM INCENTIVE PROGRAM (“LTIP”)

The Executive will be eligible to participate in the Company’s Long Term Incentive Plan. The Executive’s Long Term Incentive target will be 320% of Base Salary, in accordance with the terms and conditions of Gran Tierra’s 2007 Equity Incentive Plan, to be amended from time to time (the “Plan”). The Executive will be eligible to participate in the Plan and in all applicable future stock option plans and/or incentive award plans as approved by the Board. In the event that the Executive’s employment is terminated for any reason, the Executive’s equity in the Company as well as any option grants (vested and non-vested options) in the Company, shall be governed by the terms and conditions of the Plan, without regard to any termination notice, payment in lieu of notice, or combination thereof that may be required pursuant to this Agreement or the common law.

ARTICLE 7
PERQUISITES AND EXPENSES

The Executive shall be reimbursed for all reasonable out of pocket expenses incurred in the course of his employment, upon providing reasonable substantiation and appropriate receipts for such expenditures.

ARTICLE 8
TERM AND TERMINATION OF EMPLOYMENT

1.1Term

The Executive’s term of employment commenced on November 6, 2023 and will continue until terminated in accordance with this Article 8.

1.2Termination Without Notice

This Agreement and the Executive’s employment hereunder may be terminated, without advance notice of termination or pay in lieu of such notice, whether under contract, statute, common law or otherwise, in the following circumstances:

3

(a)Voluntary Resignation

In the event that the Executive voluntarily resigns, except where the Executive resigns for Good Reason, the Executive will give ninety (90) days’ advance written notice. The Executive will not be entitled to receive any further compensation or benefits whatsoever other than those which have accrued up to the Executive’s last day of active service. The Company may, at its discretion, waive in whole or in part such notice by providing the Executive with payment in lieu equal to all amounts that would have been paid to the Executive for the remainder of such notice period;

(b)Cause

The Company may terminate the employment of the Executive at any time without notice for Cause. The Executive will not be entitled to receive any further compensation or benefits whatsoever other than those which have accrued up to the Executive’s last day of active service.

"Cause" means any act or omission of the Executive which would, at common law, permit an employer to, without notice or payment in lieu of notice, terminate the employment of an employee.

(c)Death

In the event of the death of the Executive during the term of this Agreement, the Parties agree and acknowledge that this Agreement and the Executive’s employment hereunder will be deemed to be terminated and the Company will not be obligated to provide the Executive, or his estate, with any additional compensation excepting that which had already accrued to the Executive up to and including the date of termination, and any other death benefits that may be payable pursuant to the terms of applicable insurance coverage.

1.3Termination by the Company without Cause

The Company may terminate the Executive’s employment without Cause at any time by providing the Executive with a separation package (the “Separation Package”) equal to one and a half (1 1/2)times the Base Salary and the Bonus that was paid or was payable to the Executive during the twelve (12) month period prior to the termination date.

The Separation Package shall be payable in a lump sum within thirty (30) days of the termination date. The Executive shall not be required to mitigate any portion of the Separation Package by seeking other employment nor shall it be reduced by any remuneration or compensation earned by the Executive after the termination date.

1.4Termination by the Executive for Good Reason.

Should the Executive terminate his employment for Good Reason, as hereinafter defined, he shall receive the Separation Package set out in section 8.3. Failure of the Executive to terminate his employment on the occurrence of any event which would constitute Good Reason shall not constitute waiver of his rights under section 8.4 or section 8.3, provided that the Executive tenders his resignation within thirty (30) days after the occurrence of the event that forms the basis for the resignation for Good Reason and provided, however, except in the event of a Change of Control (as hereinafter defined), that the Executive has provided written notice to the Company describing the nature of the event that the Executive believes forms the basis for the

4

resignation for Good Reason, and the Company shall thereafter have ten (10) days to cure such event.

“Good Reason” is defined as the occurrence of any of the following without the Executive’s express written consent:

(a)an adverse change in the Executive’s position, titles, duties or responsibilities (including new, additional or changed formal or informal reporting responsibilities) or any failure to re-elect or re-appoint him to any such positions, titles, duties or offices, except in connection with the termination of his employment for Cause;

(b)a reduction by the Company of the Executive’s Base Salary except to the extent that the annual base salaries of all other executive officers of the Company are similarly reduced or any change in the basis upon which the Executive’s annual compensation is determined or paid if the change is or will be adverse to the Executive except that an award of any annual performance bonuses (including the Bonus) by the Company’s Compensation Committee (and approved by the Board) are discretionary and in no instance shall be considered adverse to Executive if such performance bonus is reduced from a prior year or if an annual performance bonus is not paid;

(c)both a Change in Control and a Triggering Event occur:

(d)any breach by the Company of any material provision of this Agreement.

“Change in Control” is defined as:

(a)a dissolution, liquidation, sale, lease or other disposition of all or substantially all of the assets of Gran Tierra or GTE INC;

(b)a majority of the voting securities of GTE INC ceasing to be controlled, directly or indirectly, by Gran Tierra, where “voting securities” means any securities carrying a right to vote in respect of the election of directors under all circumstances or under circumstances that have occurred and are continuing; or

(c)an amalgamation, arrangement, merger or other consolidation of Gran Tierra with or into any one or more other corporations pursuant to which any person or combination of persons thereafter hold a greater number of voting securities or other securities of the successor or continuing corporation having rights of purchase, conversion or exchange into voting securities of the successor or continuing corporation (assuming the purchase, conversion or exchange of such other securities whether then purchasable, convertible or exchangeable or not into the highest number of voting securities of the successor or continuing corporation such persons would be entitled to) than the number of voting securities of the successor or continuing corporation held directly and indirectly by former shareholders of Gran Tierra, where “voting securities” means any securities carrying a right to vote in respect of the election of directors under all circumstances or under circumstances that have occurred and are continuing.

“Triggering Event” means the occurrence of any of the following:

5

(a)the Employer’s material diminution of the Employee’s position, authority or scope or scale of duties or responsibilities as in effect immediately prior to the Change of Control;

(b)a material reduction by the Employer of the Employee’s annual base salary as in effect immediately prior to the Change of Control;

(c)any failure to maintain reasonable and adequate insurance or indemnification in respect of the Employee’s services as an officer or director of the Employer; or

(d)the failure of the Employer to require any successor (by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Employer, by agreement in form and substance reasonably satisfactory to the Employee, to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Employer would be required to perform it if no such succession had taken place.

1.5Resignation of Offices Held

In the event that this Agreement or the Executive’s employment hereunder is terminated for any reason, the Executive agrees to resign effective the termination date from any office or directorship held with or on behalf of Gran Tierra or a subsidiary, affiliated or related corporate entity (”Member Company” or “Member Companies”). The Executive agrees that he shall execute any and all documents appropriate to evidence such resignations and that he will not be entitled to any additional payments or compensation of any kind as consideration for doing so.

ARTICLE 9
DIRECTORS/OFFICERS LIABILITY

1.1Indemnity

Gran Tierra shall provide to the Executive indemnification in accordance with the Indemnification Agreement dated as of November 6, 2023, entered into between Gran Tierra and the Executive.

1.2Insurance

(a)Gran Tierra shall purchase and maintain, throughout the period during which the Executive acts as a director or officer of Gran Tierra or a Member Company and for a period of six yearsafter the date that the Executive ceases to act as a director or officer of Gran Tierra or a Member Company, directors’ and officers’ liability insurance for the benefit of the Executive and the Executive’s heirs, executors, administrators and other legal representatives, such that the Executive’s insurance coverage is, at all times, at least equal to or better than any insurance coverage that Gran Tierra purchases and maintains for the benefit of its then current directors and officers, from time to time.

(b)If for any reason whatsoever, any directors’ and officers’ liability insurer asserts that the Executive or the Executive’s heirs, executors, administrators or other legal representatives are subject to a deductible under any existing or future directors’ and officers’ liability insurance purchased and maintained by Gran Tierra for the benefit of the Executive and the Executive’s heirs, executors, administrators and other legal representatives, Gran Tierra shall pay the

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deductible for and on behalf of the Executive or the Executive’s heirs, executors, administrators or other legal representatives, as the case may be.

1.3Survival

The provisions of sections 9.1 and 9.2 of this Agreement shall survive the termination of this Agreement or the employment of the Executive and such provisions shall continue in full force and effect in accordance with such Indemnification Agreement and the provisions of this Agreement for the benefit of the Executive.

ARTICLE 10
NON-COMPETITION AND CONFIDENTIALITY

1.1Fiduciary Duties & Non-Competition

The Executive recognizes and understands that in performing the duties and responsibilities as outlined in this Agreement, he will occupy a position of high fiduciary trust and confidence, pursuant to which he has developed and will develop and acquire wide experience and knowledge with respect to all aspects of the services and businesses carried on by Gran Tierra and its Member Companies and the manner in which such businesses are conducted. The Executive agrees that such knowledge and experience shall be used solely and exclusively in the furtherance of the business interests of Gran Tierra and its Member Companies and not in any manner detrimental to them. The Executive further agrees that so long as the Executive is employed pursuant to this Agreement, the Executive shall not engage in any practice or business in competition with the business of Gran Tierra or any of its Member Companies. The Executive further agrees that the Executive’s fiduciary duties shall survive the termination of this Agreement in accordance with applicable law.

1.2Confidentiality

The Executive further recognizes and understands that he is a key employee and will become knowledgeable, aware and possessed of confidential and proprietary information, know-how, data, strategic studies, techniques, knowledge and other confidential information of every kind or character relating to or connected with the business or corporate affairs and operations of Gran Tierra and its Member Companies, which may include, without limitation, geophysical studies and data, market data, engineering information, shareholder data, compensation rates and methods and personnel information (collectively “Confidential Information”) concerning the business of Gran Tierra and its Member Companies. The Executive therefore agrees that, except with the consent of the President, he will not disclose such Confidential Information to any unauthorized persons; provided that the foregoing shall not apply to any Confidential Information which is or becomes known to the public or to the competitors of Gran Tierra or its Member Companies other than by a breach of this Agreement.

1.3Following Termination of Agreement

Subject to this Article 10 and without otherwise restricting the fiduciary obligations imposed upon, or otherwise applicable to the Executive as a result of the Executive having been a senior officer and key employee, the Executive shall not be prohibited from obtaining employment with or otherwise forming or participating in a business competitive to the business of the Company after the termination of this Agreement and the Executive’s employment hereunder.

1.4Business Records

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The Executive agrees to promptly deliver to the Company, upon termination of his employment for any reason, or at any other time when the Company so requests, all documents relating to the business of Gran Tierra or its Member Companies, including, without limitation: all reports and related data, such as summaries, memoranda and opinions relating to the foregoing, contract files, notes, records, manuals, correspondence, financial and accounting information, client lists, statistical data and compilations, patents, copyrights, trademarks, trade names, methods, processes, agreements, contacts or any other documents relating to the business of Gran Tierra or its Member Companies, and all copies thereof and therefrom (collectively, the "BusinessRecords"). The Executive confirms that all the Business Records which are required to be delivered to the Company pursuant to this Agreement constitute the exclusive property of Gran Tierra or its Member Companies. The obligations of confidentiality set forth in this Agreement shall continue notwithstanding the Executive’s delivery of any such documents to the Company.

ARTICLE 11
CHANGES TO AGREEMENT

Any modifications or amendments to this Agreement must be in writing and signed by all Parties or else they shall have no force and effect.

ARTICLE 12
ENUREMENT

This Agreement shall enure to the benefit of and be binding upon the Parties and their respective successors and assigns, including without limitation, the Executive’s heirs, executors, administrators, and personal representatives.

ARTICLE 13
GOVERNING LAW AND JURISDICTION

This Agreement shall be construed in accordance with the laws of the Province of Alberta and the federal laws of Canada applicable therein. Any action arising from or relating any way to this Agreement, or otherwise arising from or relating to Executive’s employment hereunder, shall be tried in the Court of Queen's Bench situated in Calgary, Alberta. The Parties consent to jurisdiction and venue in those courts to the greatest extent possible under law.

ARTICLE 14
NOTICES

1.1Notice to Executive

Any notice required or permitted to be given to the Executive shall be deemed to have been received if delivered personally to the Executive or sent by courier to the Executive’s home address last known to the Company.

1.2Notice to Company

Any notice required or permitted to be given to the Company shall be deemed to have been received if delivered personally to, sent by courier, or sent by facsimile to:

Gran Tierra Energy Inc.
500 Centre Street S.E
Calgary, Alberta, Canada, T2G 1A6
Fax: +1 403 265-3242
Attn: President

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ARTICLE 15
WITHHOLDING

All payments made to the Executive hereunder or for the benefit of the Executive shall be less applicable statutory withholdings and deductions.

ARTICLE 16
INDEPENDENT LEGAL ADVICE

The Executive acknowledges that the Executive has been advised to obtain independent legal advice with respect to entering into this Agreement, that he has obtained such independent legal advice or has expressly deemed not to seek such advice, and that the Executive is entering into this Agreement with full knowledge of the contents hereof, of the Executive’s own free will and with full capacity and authority to do so.

ARTICLE 17
COMPANY POLICIES

The Executive will comply with all Company policies and procedures (certain of which may be found on the “Corporate Responsibility” page at www.grantierra.com), as may be amended by the Company from time to time (the "Company Policies"). The Executive agrees to review and provide written acknowledgement on an annual basis of his acceptance of the Company Polices, including policies with respect to business conduct and ethics, insider trading, complaints reporting, foreign corrupt practices, information security, computer use, and disclosure.

ARTICLE 18
WAIVER

No failure or delay by any Party in exercising any right, power or privilege under this Agreement will operate as a waiver of those rights, powers or privileges, nor will any waiver in one instance be deemed to be a continuing waiver in any other instance.

ARTICLE 19
SEVERABILITY AND ENFORCEABILITY

If any court of competent jurisdiction declares any provision of this Agreement invalid, void or unenforceable in whole or in part, for any reason, it shall be deemed not to affect or impair the validity of the remainder of this Agreement, which shall remain in full force and effect. To the extent that any court of competent jurisdiction concludes that any provision of this Agreement is void or voidable, the court shall reform such provision(s) to render the provision(s) enforceable, but only to the extent absolutely necessary to render the provision(s) enforceable.

ARTICLE 20
PRIVACY

The Executive acknowledges and agrees that he will take all necessary steps to protect and maintain the Personal Information (information about an identifiable individual) of the employees, consultants or customers of the Company obtained in the course of the Executive's employment with the Company. The Executive shall at all times comply, and shall assist the Company to comply, with all applicable laws relating to privacy and the collection, use and disclosure of Personal Information in all applicable jurisdictions, including but not limited to the Personal Information Protection Act (Alberta) (“Applicable Privacy Laws”).

9

The Executive acknowledges and agrees that the disclosure of the Executive’s Personal Information may be required as part of the ongoing operations of the Company’s business, as required by law or regulatory agencies, as part of the Company’s audit process, as part of a potential business or commercial transaction or as part of the Company’s management of the employment relationship (the "Personal Information Disclosure"), and the Executive hereby grants consent as may be required by Applicable Privacy Laws to the Personal Information Disclosure.

ARTICLE 21
ENTIRE AGREEMENT

This Agreement, together with the documents referenced herein, constitutes the entire agreement between the Parties with respect to the subject matter hereof and supersedes all prior agreements, understandings, negotiations and discussions, whether oral or written.

[Remainder of page intentionally left blank. Signature page follows.]

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ARTICLE 22
COUNTERPART EXECUTION

This Agreement may be executed in any number of counterparts and each such counterpart shall be deemed an original Agreement for all purposes; provided that no Party shall be bound to this Agreement unless and until all Parties have executed a counterpart. Delivery of a copy of a counterpart by facsimile or email by one Party to the other Party shall be deemed to be delivery of an original by that Party.

IN WITNESS OF WHICH the Parties have duly executed this Agreement on the dates set forth below, with an effective date of October 5, 2023.

GTE Alberta INC, an Alberta corporation By:    /s/Gary Guidry     Name: Gary Guidry Title: President & CEO	GRAN TIERRA ENERGY INC., a Delaware corporation By:    /s/Gary Guidry     Name: Gary Guidry Title: President & CEO
Date:    October 1, 2023	Date:    October 1, 2023
	EXECUTIVE By:    /s/Sebastien Morin     Sebastien Morin
	Date:    October 1, 2023
SIGNED, SEALED & DELIVERED In the presence of: /s/Warren Bell Witness Warren Bell Print Name

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EX-21.1

Exhibit 21.1

SUBSIDIARIES OF GRAN TIERRA ENERGY INC.

The table below sets forth all subsidiaries of Gran Tierra Energy Inc. and the state or other jurisdiction of incorporation or organization of each as of February 15, 2024.

Subsidiary	Jurisdiction of Incorporation
GTE Alberta Inc.	Alberta, Canada
Gran Tierra Energy N.V. ULC	Alberta, Canada
Gran Tierra Energy International Holdings Ltd.	Cayman Islands
Gran Tierra Energy Resources Inc.	Cayman Islands
Petrolifera Petroleum (Colombia) Limited	Cayman Islands
Palomino Insurance Ltd.	Cayman Islands
Gran Tierra Energy Mexico Holdings 1 LLC	Delaware
Gran Tierra Energy Mexico Holdings 2 LLC	Delaware
Gran Tierra Mexico Energy. S.A. de C.V.	Mexico
Gran Tierra UK Holdings Limited	United Kingdom
Gran Tierra Resources GmbH	Switzerland
Gran Tierra Energy CI GmbH	Switzerland
Gran Tierra Operations Colombia GmbH	Switzerland
Gran Tierra Energy Colombia GmbH	Switzerland
Southeast Energy GmbH	Switzerland
Suroco Energy Venezuela	Venezuela
Palomino Rentals S.A.S.	Ecuador

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the registration statement Nos. 333-146815, 333-156994, 333-171122 and 333-183029, on Form S-8, and Registration Statement No. 333-258433 on Form S-3 of Gran Tierra Energy Inc. of our reports dated February 20, 2024, with respect to the consolidated balance sheets of Gran Tierra Energy Inc. 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, and the effectiveness of internal control over financial reporting as of December 31, 2023, which reports appear in the December 31, 2023 annual report on Form 10‑K of Gran Tierra Energy Inc.for the fiscal year ended December 31, 2023.

/s/ KPMG LLP

Chartered Professional Accountants

Calgary, Canada

February 20, 2024

EX-23.2

Exhibit 23.2

Consent of Independent Reserve Engineers

Mr. Ryan Ellson

Chief Financial Officer

Gran Tierra Energy Inc. ("Gran Tierra")

500 Centre Street S.E.,

Calgary, Alberta, Canada T2G 1A6

Re:	Gran Tierra Registration Statement:
	Form S-8 (Reg. Nos. 333-146815, 333-156994, 333-171122 and 333-183029)
	Form S-3 (Reg. No. 333-258433)
	Filed with the United States Securities Exchange Commission

Dear Mr. Ellson:

As the independent reserve engineers for Gran Tierra, McDaniel & Associates Consultants Ltd. ("McDaniel"), hereby confirms that it has granted and not withdrawn its consent to the filing of McDaniel reserve report and to the reference to McDaniel's evaluation of Gran Tierra's reserves as of December 31, 2023, in the form and context disclosed by Gran Tierra in its Annual Report on Form 10-K submission filed with the United States Securities and Exchange Commission on approximately February 20, 2024, for the period ended December 31, 2023, and to the incorporation by reference thereof in the registration statements listed above.

Please do not hesitate to contact us if you have any questions.

McDaniel & Associates Consultants Ltd.

/s/ Cam Boulton

Cam Boulton

Executive Vice President

Dated: February 20, 2024

Calgary, Alberta

CANADA

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Gary S. Guidry, certify that:

1. I have reviewed this Form 10-K of Gran Tierra Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 20, 2024	/s/ Gary S. Guidry
	By: Gary S. Guidry
	President and Chief Executive Officer, Director
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Ryan Ellson, certify that:

1. I have reviewed this Form 10-K of Gran Tierra Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations, and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 20, 2024	/s/ Ryan Ellson
	By: Ryan Ellson
	Chief Financial Officer and Executive Vice President, Finance
	(Principal Financial Officer)

EX-32.1

Exhibit 32.1

Certification of Chief Executive Officer and Chief Financial Officer

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to the requirement set forth in Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Section 1350, Chapter 63 of Title 18 of the United States Code (18 U.S.C-§1350), each of Gary Guidry, President and Chief Executive Officer of Gran Tierra Energy Inc., a Delaware corporation (the “Company”), and Ryan Ellson, Chief Financial Officer of the Company, does hereby certify, to such officer’s knowledge that:

The Annual Report on Form 10-K for the fiscal year ended December 31, 2023 (the “Form 10-K”) to which this Certification is attached as Exhibit 32.1 fully complies with the requirements of Section 13(a) or 15(d) of the Exchange Act. The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, the undersigned have set their hands hereto as of the 20th day of February 2024.

/s/ Gary S. Guidry

By: Gary S. Guidry

President and Chief Executive Officer, Director

/s/ Ryan Ellson

By: Ryan Ellson

Chief Financial Officer and Executive Vice President, Finance

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Section 1350, Chapter 63 of Title 18, United States Code) and is not deemed filed with the Securities and Exchange Commission as part of the Form 10-K or as a separate disclosure document and is not to be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Exchange Act (whether made before or after the date of the Form 10-K), irrespective of any general incorporation language contained in such filing.

EX-97.1

Exhibit 97.1

GRAN TIERRA ENERGY INC.

EXECUTIVE REMUNERATION CLAWBACK POLICY

The Board of Directors (the “Board”) of Gran Tierra Energy Inc. (the “Company”) believes that it is in the best interests of the Company and its shareholders to create and maintain a culture that emphasizes integrity and accountability and that reinforces the Company’s pay-for-performance compensation philosophy. The Board has therefore adopted this executive remuneration clawback policy which permits the recovery of certain executive compensation in accordance with the terms herein (this “Policy”).

A.ADMINISTRATION. This Policy shall be administered by the Compensation Committee of the Board (the “Compensation Committee”), subject to ratification by the independent members of the Board of Directors with respect to application of this Policy to the Company’s Chief Executive Officer, and is intended to comply with, and as applicable to be administered and interpreted consistent with, and subject to the exceptions set forth in, Listing Standard 303A.14 adopted by the New York Stock Exchange to implement Rule 10D-1 under the Securities Exchange Act of 1934, as amended (collectively, “Rule 10D-1”). Any determinations made by the Compensation Committee shall be final and binding on all affected individuals.

B.COVERED EXECUTIVES. This Policy applies to any “officer” of the Company as defined under Rule 16a-1(f) under of the Securities Exchange Act of 1934, as amended (collectively, the “Covered Executives”).

C.RECOUPMENT OF INCENTIVE COMPENSATION. This Policy requires that, in the event the Company is required to prepare an accounting restatement of the Company’s financial statements due to the Company’s material non-compliance with any financial reporting requirement under the federal securities laws (including any such correction that is material to the previously issued financial statements, or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period), the Company will recover on a reasonably prompt basis the amount of any Incentive Compensation Received by a Covered Executive during the Recovery Period that exceeds the amount that otherwise would have been Received had it been determined based on the restated financial statements.

D.CERTAIN DEFINITIONS.

For purposes of this Policy:

•“Incentive Compensation” means any compensation granted, earned, or vested based in whole or in part on the Company’s attainment of a financial reporting measure that was Received by a person (i) on or after October 2, 2023 and after the person began service as a Covered Executive, and (ii) who served as a Covered Executive at any time during the performance period for the Incentive Compensation.

•A “financial reporting measure” is (i) any measure that is determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements and any measure derived wholly or in part from such a measure, and (ii) any measure based in whole or in part on the Company’s stock price or total shareholder return.

•Incentive Compensation is deemed to be “Received” in the fiscal period during which the relevant financial reporting measure is attained, regardless of when the compensation is actually paid or awarded.

The “Recovery Period” means the three completed fiscal years immediately preceding the date that the Company is required to prepare the accounting restatement described in this Policy, all as determined pursuant to Rule 10D-1, and any transition period of less than nine months that is within or immediately following such three fiscal years.

E.ENFORCEMENT OF THIS POLICY. The recoverable amount under this Policy shall be the amount of Incentive Compensation Received by the applicable Covered Executive that exceeds the amount of Incentive Compensation that otherwise would have been received had it been determined based on the restatement. For Incentive Compensation based on stock price or total shareholder return, where the amount of erroneously awarded compensation is not subject to mathematical recalculation directly from the information in an accounting restatement, the Compensation Committee will determine the amount based on a reasonable estimate of the effect of the accounting restatement on the relevant stock price or total shareholder return. In all cases, the calculation of the excess amount of Incentive Compensation to be recovered will be determined without regard to any taxes paid with respect to such compensation.

The Company may effect any recovery pursuant to this Policy by such means as Compensation Committee will determine, in its sole discretion, which may include, without limitation: (a) requiring reimbursement of cash incentive compensation previously paid; (b) seeking recovery of any gain realized on the vesting, exercise, settlement, sale, transfer or other disposition of any equity-based awards; (c) offsetting the recovered amount from any compensation otherwise owed by the Company to the Covered Executive; (d) cancelling outstanding vested or unvested equity awards; or (e) such other means or combination of means permitted by law and determined appropriate by the Compensation Committee.

Notwithstanding the foregoing, the Company need not recover the excess amount of Incentive Compensation if and to the extent that the Compensation Committee determines that such recovery is impracticable, subject to and in accordance with any applicable exceptions under the New York Stock Exchange listing rules, and not required under Rule 10D-1, including if the Compensation Committee determines that the direct expense paid to a third party to assist in enforcing this Policy would exceed the amount to be recovered after making a reasonable attempt to recover such amounts. The Company shall not indemnify any Covered Executive against any loss of Incentive Compensation resulting from the recovery or reimbursement of Incentive Compensation sought or obtained pursuant to this Policy (or provide any advancement of expenses in such instance), including any payment or reimbursement for the cost of third-party

insurance purchased by any Covered Executives to fund potential recovery obligations under this Policy. For the avoidance of doubt, no recovery of Incentive Compensation under this Policy will constitute an event giving rise to a right to resign for “good reason” or a “constructive termination” (or similar term) under any agreement between any Covered Executive and the Company or any of its affiliates.

The Company is authorized to take appropriate steps to implement this Policy with respect to Incentive Compensation arrangements with Covered Executives and will maintain and will provide to the New York Stock Exchange documentation of all determinations and actions taken in complying with this Policy. Any determinations made by the Compensation Committee under this Policy shall be final and binding on all affected individuals.

F.EFFECTIVE DATE. This Policy shall be effective as of October 2, 2023 (the “Effective Date”) and shall only apply to Incentive Compensation that is Received by Covered Executives on or after the Effective Date. As a condition to be eligible to receive Incentive Compensation on or after the Effective Date, the Company shall have each Covered Executive sign an acknowledgement and agreement concerning compliance with this Policy.

G.OTHER LAWS. Any right of recoupment or recovery pursuant to this Policy is in addition to (and not in lieu of) any remedies or rights of recoupment, repayment, forfeiture or right of offset may be available to the Company pursuant to the terms of any other policy, any employment agreement or plan or award terms, and any other legal remedies available to the Company; provided that the Company shall not recoup amounts pursuant to such other policy, terms or remedies to the extent it is recovered pursuant to this Policy.

H.AMENDMENT; TERMINATION. The Board may terminate or amend this Policy at any time and from time to time in its sole discretion pursuant to applicable law.

EX-99.1

Exhibit 99.1

THIRD PARTY REPORT ON RESERVES

By McDaniel & Associates Consultants Ltd. ("McDaniel") - (Independent Qualified Reserves Evaluator)

This report is provided to satisfy the requirements contained in Item 1202(a)(8) of U.S. Securities and Exchange Commission Regulation S-K with respect to Gran Tierra Energy Inc’s (“Gran Tierra”) oil and gas reserves as of December 31, 2023, and to provide the qualifications of the technical person primarily responsible for overseeing the reserve estimation process.

The numbering of items below corresponds to the requirements set out in Item 1202(a)(8) of Regulation S-K. Terms to which a meaning is ascribed in Regulation S-K and Regulation S-X have the same meaning in this report.

i.We have prepared an independent estimate of the oil and gas reserves of Gran Tierra for the management and the board of directors of Gran Tierra. The primary purpose of our evaluation report was to provide estimates of reserves information in support of Gran Tierra’s year-end reserves reporting requirements under U.S. Securities Regulation S-K and for other internal business and financial needs of Gran Tierra.

ii.We estimated the reserves of Gran Tierra as at December 31, 2023. The completion date of our report is January 23, 2024.

iii.McDaniel evaluated 100% of the reserves of Gran Tierra.

The following table sets forth the net after royalty reserves of Gran Tierra which were 100% oil:

Category	Crude Oil Mbbl	Portion of Reserves Evaluated, %
Proved
Developed
Colombia	38,942	100
Ecuador	657	100
Undeveloped
Colombia	30,725	100
Ecuador	3,972	100
Total Proved	74,296	100
Probable
Developed
Colombia	12,000	100
Ecuador	138	100
Undeveloped
Colombia	28,243	100
Ecuador	5,866	100
Total Probable	46,247	100
Possible
Developed
Colombia	11,211	100
Ecuador	151	100
Undeveloped
Colombia	30,292	100
Ecuador	6,852	100
Total Possible	48,506	100

iv.As noted in item iii., our evaluation covered 100% of the reserves of Gran Tierra. The assumptions, methods, and procedures followed in the evaluation reflect the standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") modified as necessary to conform to the standards under the U.S. Financial Accounting Standards Board policies (the “FASB Standards”) and the U.S. Securities and Exchange Commission Regulations (“SEC requirements”).

Data used in our evaluation of Gran Tierra's reserves was obtained from regulatory agencies, public sources, and Gran Tierra personnel and Gran Tierra files. In the preparation of our report, we have accepted as presented, and have relied, without independent verification, upon a variety of information furnished by Gran Tierra such as interests and burdens on properties, recent production volumes, product transportation, and marketing and sales agreements, historical revenue, capital costs, operating expense data, budget forecasts and capital cost estimates and well data for recently drilled wells. If in the course of our evaluation, the validity or sufficiency of any material information was brought into question; we did not rely on such information until such concerns were resolved to our satisfaction.

Gran Tierra warranted in a representation letter to us that, to the best of its knowledge and belief, all data furnished to us was accurate in all material respects, and no material data relevant to our evaluation was omitted.

A field examination of the evaluated properties was not performed, nor was it considered necessary for our report.

In our opinion, estimates provided in our report have, in all material respects, been determined in accordance with the applicable industry standards, and results provided in our report and summarized herein are appropriate for inclusion in filings under Regulation S-K.

v.As required under SEC Regulation S-X, reserves are those quantities of oil and gas that are estimated to be economically producible under existing economic conditions. The primary economic assumptions relate to pricing, capital and operating costs, recoverable volumes and production forecasts.

As specified, in determining economic production, constant product benchmark prices are to be based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the effective date of our report unless prices are defined by contractual or other regulatory arrangements. The relevant benchmark prices for Gran Tierra's reserves is Brent Blend Crude Oil FOB North Sea at $82.51 USD/bbl.

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, referred to herein as “differentials.” The differentials used in the preparation of this report estimated from received price information provided by Gran Tierra.

The average realized prices for Gran Tierra's reserves in the report are:

Oil (USD/bbl) - Colombia	$	69.91
Oil (USD/bbl) - Ecuador	$	77.44

In our economic analysis, operating and capital costs are those costs estimated as applicable at the effective date of our report, with no future escalation. Where deemed appropriate, the capital costs and revised operating costs associated with the implementation of committed projects designed to modify specific field operations in the future may be included in economic projections. Capital costs used in this report were provided by Gran Tierra and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs were assigned to the abandonment of wells assigned reserves, including future wells.

Reserves were assigned by volumetric, material balance, decline analysis or analogy where considered appropriate. In many cases, where sufficient data were available, a combination of the methods were applied.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or analogous locations. For reserves not yet on production, forecast sales were estimated to commence at an anticipated date furnished by Gran Tierra. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

vi. Our report has been prepared assuming the continuation of existing regulatory and fiscal conditions subject to the guidance in the COGE Handbook and SEC regulations. Notwithstanding that Gran Tierra currently has regulatory approval to produce the reserves identified in our report, there is no assurance that changes in regulation will not occur; such changes, which cannot reliably be predicted, could impact Gran Tierra's ability to recover the estimated reserves.

vii. Oil and gas reserves estimates have an inherent degree of associated uncertainty the extent of which is affected by many factors. Reserves estimates will vary due to the limited and imprecise nature of data upon which the estimates of reserves are predicated. Moreover, the methods and data used in estimating reserves are often necessarily indirect or analogical in character rather than direct or deductive. Furthermore, the persons involved in the preparation of

reserves estimates and associated information are required, in applying geosciences, petroleum engineering and evaluation principles, to make numerous unbiased judgments based upon their educational background, professional training, and professional experience. The extent and significance of the judgments to be made are, in themselves, sufficient to render reserves estimates inherently imprecise. Reserves estimates may change substantially as additional data becomes available and as economic conditions impacting oil and gas prices and costs change. Reserves estimates will also change over time due to other factors such as knowledge and technology, fiscal and economic conditions, contractual, statutory and regulatory provisions. 

viii.In our opinion, the reserves information evaluated by us have, in all material respects, been determined in accordance with all appropriate data, assumptions, methods and procedures applicable for the filing of reserves information under U.S. SEC Regulation S-K. All methods and procedures we considered necessary under the circumstances to prepare the report were used.

ix.A summary of Gran Tierra's reserves evaluated by us is provided in item iii. 

McDaniel is a private firm established in 1955 whose business is the provision of independent geological and engineering services to the petroleum industry. McDaniel is among the largest evaluation firms in North America with over 60 professional and technical support personnel. Mr. Boulton coordinated the evaluation and is a qualified, independent reserves evaluator as defined in COGE Handbook, and a registered Practicing Professional Engineer in the Province of Alberta. Mr. Boulton has over 10 years of experience in the evaluation of oil and gas reserves and resources and has been employed at McDaniel as an evaluator/auditor since 2006.

McDaniel & Associates Consultants Ltd.

2000, Eighth Avenue Place, East Tower,

525 – 8 Avenue SW,

Calgary, Alberta, Canada T2P 1G1

Dated: February 20, 2024

/s/ Cam Boulton

Cam Boulton

Executive Vice President

XML

Cover Page - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2023

Feb. 15, 2024

Jun. 30, 2023

Cover [Abstract]

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2023

Current Fiscal Year End Date

--12-31

Document Transition Report

false

Entity File Number

001-34018

Entity Registrant Name

GRAN TIERRA ENERGY INC.

Entity Incorporation, State or Country Code

DE

Entity Tax Identification Number

98-0479924

Entity Address, Address Line One

500 Centre Street S.E.

Entity Address, City or Town

Calgary,

Entity Address, State or Province

AB

Entity Address, Country

CA

Entity Address, Postal Zip Code

T2G 1A6

City Area Code

403

Local Phone Number

265-3221

Title of 12(b) Security

Common Stock, par value $0.001 per share

Trading Symbol

GTE

Security Exchange Name

NYSEAMER

Entity Well-known Seasoned Issuer

No

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Accelerated Filer

Entity Small Business

true

Entity Emerging Growth Company

false

ICFR Auditor Attestation Flag

true

Document Financial Statement Error Correction [Flag]

false

Entity Shell Company

false

Entity Public Float

$ 158.9

Entity Common Stock, Shares Outstanding

32,246,501

Documents Incorporated by Reference

The information required by Part III of this report, to the extent not set forth herein, is incorporated by reference from the registrant’s definitive proxy statement relating to the 2024 annual meeting of stockholders, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2023.

Entity Central Index Key

0001273441

Document Fiscal Year Focus

2023

Document Fiscal Period Focus

FY

Amendment Flag

false

XML

Audit Information	12 Months Ended
	Dec. 31, 2023
Audit Information [Abstract]
Auditor Name	KPMG LLP
Auditor Location	Calgary, Canada
Auditor Firm ID	85

XML

Consolidated Statements of Operations - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Statement [Abstract]
Revenue from Contract with Customer, Product and Service [Extensible Enumeration]		Oil Sales [Member]
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)		0	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	0
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)
Total income tax expense (recovery)		112,447	105,906	(19,346)
NET AND COMPREHENSIVE (LOSS) INCOME		$ (6,287)	$ 139,029	$ 42,482
NET (LOSS) INCOME PER SHARE
Basic (in dollars per share)	[1]	$ (0.19)	$ 3.81	$ 1.16
Diluted (in dollars per share)	[1]	$ (0.19)	$ 3.76	$ 1.15
Weighted average shares outstanding - basic (in shares)		33,469,828	36,445,546	36,702,290
Weighted average shares outstanding - diluted (in shares)		33,469,828	36,928,010	36,787,339

[1] (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.

XML

Consolidated Statements of Operations (Parenthetical)	May 05, 2023
Income Statement [Abstract]
Conversion ratio	0.1

XML

Consolidated Balance Sheets - USD ($) $ in Thousands		Dec. 31, 2023	Dec. 31, 2022
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
Current Liabilities
Accounts payable and accrued liabilities (Note 6, 7 and 9)		187,007	167,579
Credit facility (Note 7)		35,609	0
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
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)	[1]	9,936	10,272
Additional paid in capital	[1]	1,249,651	1,291,354
Treasury stock (Note 8)	[1]	(163)	(27,317)
Deficit	[1]	(863,030)	(856,743)
Total Shareholders’ Equity		396,394	417,566
Total Liabilities and Shareholders’ Equity		$ 1,326,289	$ 1,335,610

[1] (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.

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Common stock, shares issued (in shares)	32,275,113	36,889,862
Common shares, outstanding (in shares)	32,246,501	34,615,116
Common shares, par value (in dollars per share)	$ 0.001	$ 0.001

XML

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Activities
Net (loss) income	$ (6,287,000)	$ 139,029,000	$ 42,482,000
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 4)	215,584,000	180,280,000	139,874,000
Deferred tax expense (recovery) (Note 11)	56,759,000	25,340,000	(23,825,000)
Stock-based compensation expense (Note 8)	5,722,000	9,049,000	8,396,000
Amortization of debt issuance costs (Note 7)	5,831,000	3,528,000	3,809,000
Non-cash lease expenses	4,967,000	2,818,000	1,667,000
Lease payments	(3,018,000)	(1,666,000)	(1,621,000)
Unrealized foreign exchange (gain) loss	(5,085,000)	10,251,000	21,879,000
Derivative instruments loss (Note 13)	0	26,611,000	48,838,000
Cash settlement on derivatives instruments (Note 13)	0	(26,611,000)	(58,427,000)
Other financial instruments (gain) loss (Note 13)	15,000	(7,000)	3,369,000
Cash settlement of asset retirement obligation (Note 9)	(377,000)	(2,630,000)	(805,000)
Other non-cash loss (gain) (Note 7)	2,297,000	(2,598,000)	44,000
Net change in assets and liabilities from operating activities (Note 14)	(48,416,000)	64,317,000	59,154,000
Net cash provided by operating activities	227,992,000	427,711,000	244,834,000
Investing Activities
Additions to property, plant and equipment (Note 4)	(218,882,000)	(236,604,000)	(149,879,000)
Changes in non-cash investing working capital	(7,702,000)	26,273,000	1,431,000
Proceeds on disposition of investment, net of transaction costs (Note 13)	0	0	43,126,000
Net cash used in investing activities (Note 14)	(226,584,000)	(210,331,000)	(105,322,000)
Financing Activities
Purchase of Senior Notes (Note 7)	(6,805,000)	(17,274,000)	0
Senior Notes issuance costs	(13,351,000)	0	0
Repayment of Senior Notes (Note 7)	(60,000,000)	0	0
Proceeds from debt, net of issuance costs (Note 7)	48,014,000	0	(228,000)
Repayment of debt (Note 7)	(13,636,000)	(67,803,000)	(122,500,000)
Lease payments	(6,527,000)	(2,228,000)	(2,182,000)
Proceeds from exercise of stock options (Note 8)	8,000.0	1,300,000	100,000
Re-purchase of shares of Common Stock (Note 8)	(17,300,000)	(27,317,000)	0
Net cash used in financing activities	(69,597,000)	(113,322,000)	(124,810,000)
Foreign exchange gain (loss) on cash and cash equivalents and restricted cash and cash equivalents	5,869,000	(2,104,000)	(821,000)
Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents	(62,320,000)	101,954,000	13,881,000
Cash and cash equivalents and restricted cash and cash equivalents, beginning of year (Note 14)	133,358,000	31,404,000	17,523,000
Cash and cash equivalents and restricted cash and cash equivalents, end of year (Note 14)	$ 71,038,000	$ 133,358,000	$ 31,404,000

XML

Consolidated Statements of Shareholders' Equity - USD ($) $ in Thousands		Total	Share Capital		Additional Paid in Capital	Treasury Stock	Deficit
Balance, beginning of period at Dec. 31, 2020			$ 10,270	[1]	$ 1,285,018	$ 0	$ (1,038,254)
Increase (Decrease) in Stockholders' Equity
Reverse stock split (Note 8)			0	[1]	0
Cancellation of shares of Common Stock (Note 8)			0	[1]	0
Issuance of shares of Common Stock, net of issuance costs (Note 8)	[1]		0
Exercise of stock options (Note 8)					100
Stock-based compensation (Note 8)					2,464
Purchase of treasury shares (Note 8)						0
Cancellation of treasury shares (Note 8)						0
Net (loss) income		$ 42,482					42,482
Balance, end of period at Dec. 31, 2021		302,080	10,270	[1]	1,287,582	0	(995,772)
Increase (Decrease) in Stockholders' Equity
Reverse stock split (Note 8)			0	[1]	0
Cancellation of shares of Common Stock (Note 8)			0	[1]	0
Issuance of shares of Common Stock, net of issuance costs (Note 8)	[1]		2
Exercise of stock options (Note 8)					1,298
Stock-based compensation (Note 8)					2,474
Purchase of treasury shares (Note 8)						(27,317)
Cancellation of treasury shares (Note 8)						0
Net (loss) income		139,029					139,029
Balance, end of period at Dec. 31, 2022		417,566	10,272	[1]	1,291,354	(27,317)	(856,743)
Increase (Decrease) in Stockholders' Equity
Reverse stock split (Note 8)			(299)	[1]	299
Cancellation of shares of Common Stock (Note 8)			(37)	[1]	(44,417)
Issuance of shares of Common Stock, net of issuance costs (Note 8)	[1]		0
Exercise of stock options (Note 8)					8
Stock-based compensation (Note 8)					2,407
Purchase of treasury shares (Note 8)						(17,300)
Cancellation of treasury shares (Note 8)						44,454
Net (loss) income		(6,287)					(6,287)
Balance, end of period at Dec. 31, 2023		$ 396,394	$ 9,936	[1]	$ 1,249,651	$ (163)	$ (863,030)

[1] (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.

XML

Description of Business

12 Months Ended

Dec. 31, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business

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.

XML

Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Significant Accounting Policies

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.

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Accounts Receivable

12 Months Ended

Dec. 31, 2023

Receivables [Abstract]

Accounts Receivable

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

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2023

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

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

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Asset impairment

12 Months Ended

Dec. 31, 2023

Impairment Disclosure [Abstract]

Asset impairment

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.

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Accounts Payable and Accrued Liabilities

12 Months Ended

Dec. 31, 2023

Payables and Accruals [Abstract]

Accounts Payable and Accrued Liabilities

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

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Debt and Debt Issuance Costs

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Debt and Debt Issuance Costs

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.

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Share Capital

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Share Capital

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)

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Asset Retirement Obligation

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

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).

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Revenue

12 Months Ended

Dec. 31, 2023

Revenue from Contract with Customer [Abstract]

Revenue

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.

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Taxes

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Taxes

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.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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.

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Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk

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.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

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

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Supplementary Data (Unaudited)

12 Months Ended

Dec. 31, 2023

Extractive Industries [Abstract]

Supplementary Data (Unaudited)

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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Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net (loss) income	$ (6,287)	$ 139,029	$ 42,482

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Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Basis of Consolidation

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

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

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

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

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 Forward

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

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Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2023

Receivables [Abstract]

Schedule of 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

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2023

Property, Plant and Equipment [Abstract]

Schedule of 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).

Schedule of Oil and Natural Gas Properties

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

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Accounts Payable and Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2023

Payables and Accruals [Abstract]

Schedule of 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

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Debt and Debt Issuance Costs (Tables)

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Schedule of Debt

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).

Schedule of Debt Senior Notes

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

Schedule of Total Interest Expense Recognized

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

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Share Capital (Tables)

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Schedule of Common Stock

	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.

Schedule of Information About PSU, DSU, RSU and Stock Option Activity

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

Schedule of Assumptions Using the Black-Scholes Option Pricing Model

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

Schedule of Weighted Average Number of Shares

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

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Asset Retirement Obligation (Tables)

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Changes in Carrying Amount of 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

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Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense Reported

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.

Schedule of Deferred Tax Assets and Liabilities

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

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Minimum Payments Under Non-Cancelable Agreements

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.

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Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk (Tables)

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

Schedule of Fair Value Measurements

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

Schedule of Losses or Gains on Financial Instruments Recognized

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

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Elements [Abstract]

Schedule of Restrictions on Cash and Cash Equivalents

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.

Schedule of Net Changes in Assets and Liabilities

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

Schedule of Additional Supplemental Cash Flow Disclosures

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

Schedule of 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

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Supplementary Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2023

Extractive Industries [Abstract]

Schedule of Proved Reserves Based on Average Prices

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

Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities

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

Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

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

Schedule of 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

Schedule of Estimates of Net Proved Reserves, Average Unweighted Arithmetic Sale Price and Production Cost

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

Schedule of Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves

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

Schedule of Principal Sources of Change 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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Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Vesting period	3 years

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Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 12,359	$ 10,706
Trade
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	5,812	5,601
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 6,547	$ 5,105

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Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Property, plant, and equipment, gross	$ 5,003,806	$ 4,753,661
Accumulated depletion, depreciation and impairment	(3,860,956)	(3,652,759)
Total Property, Plant and Equipment (Note 4)	1,142,850	1,100,902
Right-of-use asset	53,300	38,900
Operating lease and finance lease, net	32,400	24,600
Oil and natural gas properties
Property, Plant and Equipment [Line Items]
Property, plant, and equipment, gross	4,930,301	4,692,275
Proved
Property, Plant and Equipment [Line Items]
Capitalized Costs	4,876,185	4,617,804
Unproved
Property, Plant and Equipment [Line Items]
Capitalized Costs	54,116	74,471
Other
Property, Plant and Equipment [Line Items]
Property, plant, and equipment, gross	$ 73,505	$ 61,386

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Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Thousands		12 Months Ended
	Apr. 11, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Non-cash lease expenses		$ 4,967	$ 2,818	$ 1,667
Depletion and depreciation expense		$ 209,700	$ 175,800	$ 135,700
Costs not expected to be subject to depletion (as a percent)		100.00%
Period until transferred to depletable base		5 years
New Lease Contracts for Power Generating Equipment
Property, Plant and Equipment [Line Items]
Non-cash lease expenses		$ 12,400
Suroriente Block
Property, Plant and Equipment [Line Items]
Contract term, extension period	20 years
Payments for extension agreement	$ 6,200
Letters of credit and other credit support provided	$ 123,000
Capital investments term	3 years

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Property, Plant and Equipment - Summary of Oil and Natural Gas Properties (Details) - USD ($) $ in Thousands	12 Months Ended			36 Months Ended	72 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2023
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	$ 29,862	$ 89,898	$ 20,410
Properties not subject to depletion	13,123	7,241	2,208	$ 31,544	$ 54,116
Ecuador
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	14,188	39,524	2,330
Reportable Segments | Colombia
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition costs	0	0	0	5,161	5,161
Exploration costs	2,743	6,742	1,736	24,711	35,932
Non-Segment | Ecuador
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	$ 10,380	$ 499	$ 472	$ 1,672	$ 13,023

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Asset impairment (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) $ / bbl	Dec. 31, 2022 USD ($) $ / bbl	Dec. 31, 2021 USD ($) $ / bbl
Property, Plant and Equipment [Line Items]
Impairment of oil and gas properties | $	$ 0	$ 0	$ 0
Oil and gas properties, proved reserves	15 years
Historical prices, discounted rate	10.00%
Crude Oil and NGL
Property, Plant and Equipment [Line Items]
Average brent price per barrel (in dollars per barrel) | $ / bbl	82.51	97.98	68.92

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Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Payables and Accruals [Abstract]
Trade	$ 122,709	$ 114,263
Royalties	2,636	2,760
Employee compensation	6,221	3,051
Other	55,441	47,505
Total	$ 187,007	$ 167,579

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Debt and Debt Issuance Costs - Schedule of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Oct. 20, 2023	Dec. 31, 2022	Feb. 15, 2018
Debt Instrument [Line Items]
Credit facility (Note 7)	$ 36,364		$ 0
Unamortized debt issuance costs	(755)		0
Credit facility (Note 7)	35,609		0
Unamortized Senior Notes discount	(27,958)		(4,138)
Unamortized debt issuance costs	(15,679)		(6,854)
Long-term lease obligation	$ 26,550		$ 20,676
Finance lease, liability, noncurrent, statement of financial position [Extensible Enumeration]	Long-term debt		Long-term debt
Long-term debt (Note 7)	$ 519,532		$ 589,593
Total Debt	$ 555,141		$ 589,593
Finance lease, liability, current, statement of financial position [Extensible Enumeration]	Accounts payable and accrued liabilities (Note 6, 7 and 9)		Accounts payable and accrued liabilities (Note 6, 7 and 9)
Finance lease, liability, current	$ 12,100		$ 4,800
9.50% Senior Notes
Debt Instrument [Line Items]
Stated interest rate	101.00%
Senior Notes | 6.25% Senior Notes
Debt Instrument [Line Items]
Stated interest rate	6.25%	6.25%		6.25%
Long-term debt, gross	$ 24,828		279,909
Senior Notes | 7.75% Senior Notes
Debt Instrument [Line Items]
Stated interest rate	7.75%	7.75%
Long-term debt, gross	$ 24,201		300,000
Senior Notes | 9.50% Senior Notes
Debt Instrument [Line Items]
Stated interest rate	9.50%
Long-term debt, gross	$ 487,590		$ 0

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Debt and Debt Issuance Costs - Schedule of Debt Senior Notes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Oct. 20, 2023	Feb. 15, 2018
9.50% Senior Notes
Debt Instrument [Line Items]
Stated interest rate	101.00%
Senior Notes | 6.25% Senior Notes
Debt Instrument [Line Items]
Stated interest rate	6.25%	6.25%	6.25%
Senior Notes [Roll Forward]
Senior Notes Beginning	$ 279,909
Purchased in the open market	(8,000)
Principal exchanged for senior notes	(247,081)
Early participation premiums and discount for principal exchanged	0
Principal payment	0
Senior Notes, Ending	$ 24,828
Senior Notes | 7.75% Senior Notes
Debt Instrument [Line Items]
Stated interest rate	7.75%	7.75%
Senior Notes [Roll Forward]
Senior Notes Beginning	$ 300,000
Purchased in the open market	0
Principal exchanged for senior notes	(275,799)
Early participation premiums and discount for principal exchanged	0
Principal payment	0
Senior Notes, Ending	$ 24,201
Senior Notes | 9.50% Senior Notes
Debt Instrument [Line Items]
Stated interest rate	9.50%
Senior Notes [Roll Forward]
Senior Notes Beginning	$ 0
Purchased in the open market	0
Principal exchanged for senior notes	522,782
Early participation premiums and discount for principal exchanged	24,808
Principal payment	(60,000)
Senior Notes, Ending	$ 487,590

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Debt and Debt Issuance Costs - Senior Notes (Details) - USD ($)					1 Months Ended	12 Months Ended
	Feb. 06, 2024	Oct. 20, 2023	May 23, 2019	Feb. 15, 2018	Oct. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Repayments of senior debt						$ 60,000,000	$ 0	$ 0
9.50% Senior Notes
Debt Instrument [Line Items]
Stated interest rate						101.00%
9.50% Senior Notes | October 15, 2026
Debt Instrument [Line Items]
Redemption price (as a percent)						109.50%
Debt instrument, redemption price, percentage of principal amount redeemed						35.00%
9.50% Senior Notes | 2026
Debt Instrument [Line Items]
Redemption price (as a percent)						104.75%
9.50% Senior Notes | 2027
Debt Instrument [Line Items]
Redemption price (as a percent)						102.375%
9.50% Senior Notes | 2028 and Thereafter
Debt Instrument [Line Items]
Redemption price (as a percent)						100.00%
Senior Notes
Debt Instrument [Line Items]
Debt instrument, senior notes, percentage						1.00%
Senior Notes | 6.25% Senior Notes
Debt Instrument [Line Items]
Repurchased face amount						$ 8,000,000
Stated interest rate		6.25%		6.25%		6.25%
Repayments of senior debt						$ 6,800,000
Gain on re-purchase						(1,100,000)
Write-off of deferred financing cost						100,000
Debt conversion, converted		$ 247,100,000
Debt instrument, early participation premium		80
Debt instrument, exchanged		4,600,000
Repayments of debt		60,000,000
Gain (loss) on modification of debt		5,300,000
Long-term debt, gross						$ 24,828,000	279,909,000
Senior Notes | 6.25% Senior Notes | 2024 and Thereafter
Debt Instrument [Line Items]
Redemption price (as a percent)				100.00%
Senior Notes | 6.25% Senior Notes | Included Early Participation Premium
Debt Instrument [Line Items]
Debt conversion, converted		$ 242,500,000
Senior Notes | 7.75% Senior Notes
Debt Instrument [Line Items]
Stated interest rate		7.75%				7.75%
Debt conversion, converted		$ 275,800,000
Debt instrument, early participation premium		20
Gain (loss) on modification of debt		(6,100,000)
Long-term debt, gross						$ 24,201,000	300,000,000
Senior Notes | 7.75% Senior Notes | 2024
Debt Instrument [Line Items]
Redemption price (as a percent)			101.938%
Senior Notes | 7.75% Senior Notes | 2025 and Thereafter
Debt Instrument [Line Items]
Redemption price (as a percent)			100.00%
Senior Notes | 7.75% Senior Notes | Included Early Participation Premium
Debt Instrument [Line Items]
Debt conversion, converted		274,200,000
Senior Notes | 7.75% Senior Notes | Exchanged at $950
Debt Instrument [Line Items]
Debt conversion, converted		1,600,000
Senior Notes | 9.50% Senior Notes
Debt Instrument [Line Items]
Stated interest rate						9.50%
Face amount		$ 487,600,000
Long-term debt, gross						$ 487,590,000	$ 0
Redemption price (as a percent)					0.95%
Senior Notes | 9.50% Senior Notes | Subsequent Event
Debt Instrument [Line Items]
Stated interest rate	9.50%
Face amount	$ 100,000,000
Proceeds from issuance of debt	$ 88,000,000
Senior Notes | 9.50% Senior Notes | October 15, 2026
Debt Instrument [Line Items]
Redemption price (as a percent)						100.00%
Debt instrument, treasury redemption price, percentage						0.50%
Senior Notes | 9.50% Senior Notes | To Be Repaid on October 15, 2026
Debt Instrument [Line Items]
Percent of principal amount to be paid						25.00%
Senior Notes | 9.50% Senior Notes | To Be Repaid on October 15, 2027
Debt Instrument [Line Items]
Percent of principal amount to be paid						5.00%
Senior Notes | 9.50% Senior Notes | To Be Repaid on October 15, 2028
Debt Instrument [Line Items]
Percent of principal amount to be paid						30.00%

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Debt and Debt Issuance Costs - Credit Facility (Details) - Credit Agreement - Revolving Credit Facility	3 Months Ended	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2023 USD ($)
Line of Credit Facility [Line Items]
Borrowing base	$ 100,000,000	$ 100,000,000
Interest rate on undrawn amounts		2.10%
Proceeds from lines of credit	$ 36,400,000
Line of credit facility, interest rate during period		11.59%
Debt instrument, net present value as percent of consolidated future cash flows	80.00%	80.00%
Liquidity, ratio	115.00%	115.00%
Scenario, Plan
Line of Credit Facility [Line Items]
Debt instrument, net present value as percent of consolidated future cash flows	90.00%	90.00%
Minimum
Line of Credit Facility [Line Items]
Global coverage ratio		150.00%
Discount rate over outstanding balance		0.10
Prepayment life coverage ratio		150.00%
Risk- Free Rate By Federal Reserve Bank Of New York
Line of Credit Facility [Line Items]
Basis spread on variable rate		6.00%
Adjusted spread	0.26%	0.26%
Readily Available
Line of Credit Facility [Line Items]
Borrowing base	$ 50,000,000	$ 50,000,000
Subject to Additional Approval
Line of Credit Facility [Line Items]
Borrowing base	$ 50,000,000	$ 50,000,000

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Debt and Debt Issuance Costs - Leases (Details) $ in Thousands	Dec. 31, 2023 USD ($) integer	Dec. 31, 2022 USD ($)
Debt Instrument [Line Items]
Long-term lease obligation	$ 26,550	$ 20,676
Discount rate	8.45%
Lessee, operating lease, discount rate	8.01%
Power Generators and Polymer Injection Equipment
Debt Instrument [Line Items]
Number of new financial leases | integer	3
Long-term lease obligation	$ 12,400
Discount rate	7.31%
Minimum
Debt Instrument [Line Items]
Contractual life	1 year
Lessee, operating lease, term of contract	1 year
Minimum | Power Generators and Polymer Injection Equipment
Debt Instrument [Line Items]
Contractual life	1 year
Maximum
Debt Instrument [Line Items]
Contractual life	4 years
Lessee, operating lease, term of contract	5 years
Maximum | Power Generators and Polymer Injection Equipment
Debt Instrument [Line Items]
Contractual life	3 years

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Debt and Debt Issuance Costs - Schedule of Total Interest Expense Recognized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Contractual interest and other financing expenses	$ 49,975	$ 42,965	$ 50,572
Amortization of debt issuance costs	5,831	3,528	3,809
Interest expense	$ 55,806	$ 46,493	$ 54,381

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Share Capital - Schedule of Common Stock (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Stockholders' Equity
Common shares outstanding, as at beginning of period (in shares)	34,615,116
Options exercised (in shares)	1,839
Common stock, shares issued (in shares)	32,275,113	36,889,862
Common shares outstanding, as at period end (in shares)	32,246,501	34,615,116
Shares of Common Stock
Increase (Decrease) in Stockholders' Equity
Common shares outstanding, as at beginning of period (in shares)	34,615,116	36,714,450	36,698,156
Options exercised (in shares)	1,839	175,412	16,294
Common stock, shares issued (in shares)	32,275,113	36,889,862
Treasury stock, common, shares (in shares)	(28,612)
Common shares outstanding, as at period end (in shares)	32,246,501	34,615,116	36,714,450
Share repurchased during period (in shares)	2,341,842	2,274,746

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Share Capital - Additional Information (Details) $ / shares in Units, $ in Thousands		12 Months Ended
	May 05, 2023	Dec. 31, 2023 USD ($) $ / shares shares	Dec. 31, 2022 USD ($) $ / shares shares	Dec. 31, 2021 USD ($) shares	Oct. 20, 2023	May 31, 2023	May 04, 2022 shares	May 03, 2022 shares	Jun. 02, 2021 shares	Jun. 01, 2021 shares	Dec. 31, 2020 shares	Jan. 27, 2012 shares	Jan. 26, 2012 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Authorized share capital (in shares)		82,000,000
Common shares, par value (in dollars per share) | $ / shares		$ 0.001	$ 0.001
Preferred stock, shares authorized (in shares)		25,000,000
Preferred stock, par value (in dollars per share) | $ / shares		$ 0.001
Conversion ratio	0.1
Common shares, outstanding (in shares)		32,246,501	34,615,116
Common stock available for issuance (in shares)							5,980,610	5,480,610	5,480,610	3,980,610		3,980,610	2,330,610
Share-based compensation | $		$ 5,722	$ 9,049	$ 8,396
Unrecognized compensation cost | $		$ 8,600	$ 10,500
Weighted average period of recognition		1 year 8 months 12 days
Weighted average remaining contractual term		2 years 3 months 18 days
PSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity awards granted (as a percent)		80.00%
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity awards granted (as a percent)		20.00%
2023 Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share repurchased during period (in shares)		1,041,804
Stock repurchased during period, weighted average price (in dollars per shares) | $ / shares		$ 6.21
Share repurchased during period cancelled (in shares)		1,013,192
2022 program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share repurchased during period (in shares)		1,328,650
Stock repurchased during period, weighted average price (in dollars per shares) | $ / shares		$ 8.15	$ 10.59
Share repurchased during period cancelled (in shares)		3,603,396
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock purchased as percent of shares issued and outstanding					10.00%	10.00%
Maximum | 2023 Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common shares, outstanding (in shares)		3,234,914
Shares of Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Authorized share capital (in shares)		57,000,000
Common shares, outstanding (in shares)		32,246,501	34,615,116	36,714,450							36,698,156
Share repurchased during period (in shares)		2,341,842	2,274,746

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Share Capital - Schedule of Information About PSU, DSU, RSU and Stock Option Activity (Details)	12 Months Ended
	Dec. 31, 2023 $ / shares shares
Number of Outstanding Stock Options
Balance, beginning of period (in shares)	1,730,286
Granted (in shares)	461,858
Exercised (in shares)	(1,839)
Forfeited (in shares)	(24,072)
Expired (in shares)	(138,426)
Balance, end of period (in shares)	2,027,807
Vested and exercisable, at end of period (in shares)	1,232,629
Vested, or expected to vest, at end of period through the life of the options (in shares)	2,002,537
Weighted Average Exercise Price ($)
Balance, beginning of period (in dollars per share) | $ / shares	$ 11.52
Granted (in dollars per share) | $ / shares	8.39
Exercised (in dollars per share) | $ / shares	4.17
Forfeited (in dollars per share) | $ / shares	7.04
Expired (in dollars per share) | $ / shares	25.30
Balance, end of period (in dollars per share) | $ / shares	9.93
Vested and exercisable, at end of period (in dollars per share) | $ / shares	10.13
Vested, or expected to vest, at end of period through the life of the options (in dollars per share) | $ / shares	$ 9.93
PSUs
Number of Outstanding Share Units
Balance, beginning of period (in shares)	3,152,823
Granted (in shares)	2,288,515
Exercised (in shares)	(1,523,408)
Forfeited (in shares)	(21,574)
Expired (in shares)	0
Balance, end of period (in shares)	3,896,356
DSUs
Number of Outstanding Share Units
Balance, beginning of period (in shares)	656,186
Granted (in shares)	120,424
Exercised (in shares)	0
Forfeited (in shares)	0
Expired (in shares)	0
Balance, end of period (in shares)	776,610

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Share Capital - PSUs (Narrative) (Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
PSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Vested and will be settled in cash (in shares)	1.8	1.2
Award subject to targets relating to total shareholder return (as a percent)	50.00%
Award subject to targets relating to net asset value (as a percent)	25.00%	25.00%	25.00%
Net present value discount rate		10.00%	10.00%
Free cash flows required	$ 20
Award subject to targets relating to execution of corporate strategy (as a percent)	25.00%
PSUs | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs that vest (as a percent)	0.00%
PSUs | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs that vest (as a percent)	200.00%

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Share Capital - Stock Options (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation award, common stock for purchase, exercise price (in shares)	1
Vesting period	3 years
Options exercised (in shares)	1,839
Proceeds from exercise of stock options (Note 8)	$ 8,000.0	$ 1,300,000	$ 100,000
Share-based compensation arrangement by share-based payment award, options, vested and expected to vest, outstanding, weighted average remaining contractual term	2 years 3 months 18 days	2 years 6 months
Weighted average remaining contractual term of exercisable stock options	1 year 6 months	1 year 10 months 24 days
Weighted average grant date fair value for options granted (in dollars per share)	$ 5.57	$ 8.83	$ 4.67
Weighted average grant date fair value for options vested (in dollars per share)	$ 4.77	$ 5.81	$ 5.19
Total fair value of stock options vested	$ 2,300,000	$ 2,200,000	$ 2,100,000
Shares of Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options exercised (in shares)	1,839	175,412	16,294
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Expected term during grantee's service	5 years	5 years
Expected term after end of grantee's service	3 months

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Share Capital - Schedule of Assumptions Using the Black-Scholes Option Pricing Model (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average volatility (as a percent)	88.00%	77.00%	78.00%
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility, minimum	82.00%	77.00%	71.00%
Volatility, maximum	90.00%	81.00%	80.00%
Risk free interest rate, minimum	3.60%	1.40%	0.40%
Risk free interest rate, maximum	4.70%	4.00%	0.90%
Expected term	5 years	5 years
Stock Options | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term	4 years		4 years
Stock Options | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term	5 years		5 years

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Share Capital - Schedule Of Weighted Average Shares Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity [Abstract]
Weighted average number of common shares outstanding (in shares)	33,469,828	36,445,546	36,702,290
Shares issuable pursuant to stock options (in shares)	0	1,184,732	159,210
Shares assumed to be purchased from proceeds of stock options (in shares)	0	(702,268)	(74,161)
Weighted average number of diluted common shares outstanding (in shares)	33,469,828	36,928,010	36,787,339

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Share Capital - Weighted Average Shares Outstanding (Narrative) (Details) - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average options excluded from diluted earnings (loss) per share calculation (in shares)	590,025	1,555,982

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Asset Retirement Obligation - Schedule of Changes in Carrying Amount of Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis
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
Current	479	141
Long-term	73,029	63,358
Balance, end of year	$ 73,508	$ 63,499

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Asset Retirement Obligation - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Fair value of assets legally restricted for purposes of settling asset retirement obligations	$ 8.9	$ 6.5

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Revenue (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Concentration Risk [Line Items]
Variable adjustment for transportation, location, quality, and other elements, percentage	18.00%	17.00%	15.00%
Accrued sales revenue	$ 0	$ 0	$ 0
Revenue from Contract with Customer | Product Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	100.00%	100.00%	100.00%
Revenue from Contract with Customer | Product Concentration Risk | Colombia | Customer 1
Concentration Risk [Line Items]
Concentration risk, percentage	97.00%	78.00%	66.00%
Revenue from Contract with Customer | Product Concentration Risk | Colombia | Customer 2
Concentration Risk [Line Items]
Concentration risk, percentage		22.00%	19.00%
Revenue from Contract with Customer | Product Concentration Risk | Colombia | Customer 3
Concentration Risk [Line Items]
Concentration risk, percentage			12.00%
Revenue from Contract with Customer | Product Concentration Risk | Ecuador | Customer 1
Concentration Risk [Line Items]
Concentration risk, percentage	1.00%

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Taxes - Schedule of Income Tax Expense Reported (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
United States	$ (40,589)	$ (38,161)	$ (31,329)
Foreign	146,749	283,096	54,465
INCOME BEFORE INCOME TAXES	$ 106,160	$ 244,935	$ 23,136
Statutory rate	45.00%	35.00%	31.00%
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	0	0	525
Total income tax expense (recovery)	$ 112,447	$ 105,906	$ (19,346)
Effective tax rate	106.00%	43.00%	(84.00%)
Current income tax expense
Foreign	$ 55,688	$ 80,566	$ 4,479
Current income tax expense	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)

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Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
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)
Deferred tax assets	10,923	22,990
Deferred tax liabilities	57,453	28
Net deferred tax (liabilities)	$ (46,530)
Net deferred tax assets		$ 22,962

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Taxes - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Tax Credit Carryforward [Line Items]
Operating loss carryforwards	$ 20.3
Unrecognized tax benefits	0.8
Internal Revenue Service (IRS)
Tax Credit Carryforward [Line Items]
Operating loss carryforwards	58.8	$ 91.3	$ 62.1
Colombian Tax and Customs National Authority
Tax Credit Carryforward [Line Items]
Operating loss carryforwards	$ 16.5	$ 40.7	$ 102.4

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Commitments and Contingencies - Schedule of Future Minimum Payments Under Non-Cancelable Agreements (Details)	Dec. 31, 2023 USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	$ 53,200,000
2024	17,731,000
2025	12,813,000
2026	9,422,000
2027	6,046,000
2028	7,188,000
Thereafter	0
Operating leases
Total	12,857,000
2024	4,309,000
2025	2,951,000
2026	1,958,000
2027	1,985,000
2028	1,654,000
Thereafter	0
Finance leases
Total	31,630,000
2024	10,607,000
2025	7,322,000
2026	4,988,000
2027	3,179,000
2028	5,534,000
Thereafter	0
Undiscounted excess amount	0
Facilities
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	8,317,000
2024	2,483,000
2025	2,476,000
2026	2,476,000
2027	882,000
2028	0
Thereafter	0
Software and Telecommunication
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	396,000
2024	332,000
2025	64,000
2026	0
2027	0
2028	0
Thereafter	$ 0

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Commitments and Contingencies - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Promissory notes as security for letters of credit	$ 220.1	$ 111.1

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Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk - Schedule of Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Oct. 20, 2023	Dec. 31, 2022	Dec. 31, 2021	Feb. 15, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Restricted cash and cash equivalents - long-term	$ 7,750		$ 5,343	$ 4,903
Total Assets	$ 1,326,289		1,335,610
6.25% Senior Notes | Senior Notes
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Stated interest rate	6.25%	6.25%			6.25%
7.75% Senior Notes | Senior Notes
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Stated interest rate	7.75%	7.75%
9.50% Senior Notes
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Stated interest rate	101.00%
9.50% Senior Notes | Senior Notes
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Stated interest rate	9.50%
Recurring | Level 2
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Total Assets	$ 7,750		5,343
Recurring | Not Designated as Hedging Instrument | Level 1
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
PEF - current	5,630		5,981
PEF - long-term	0		9,975
Liabilities	472,756		485,256
Total Assets	5,630		15,956
Recurring | Not Designated as Hedging Instrument | Level 1 | 6.25% Senior Notes | Senior Notes
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Debt instrument, fair value disclosure	22,994		243,801
Recurring | Not Designated as Hedging Instrument | Level 1 | 7.75% Senior Notes | Senior Notes
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Debt instrument, fair value disclosure	20,744		241,455
Recurring | Not Designated as Hedging Instrument | Level 1 | 9.50% Senior Notes | Senior Notes
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Debt instrument, fair value disclosure	429,018		0
Recurring | Not Designated as Hedging Instrument | Level 2
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Restricted cash and cash equivalents - long-term	$ 7,750		$ 5,343

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Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Oct. 20, 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Outstanding derivative	$ 0
Prepaid equity forwards (in shares)	1,000,000
Investments, fair value	$ 5,600,000
Gain (loss) on prepaid equity forwards	$ (5,000,000)	$ 1,300,000	$ (900,000)
Customer Concentration Risk | Revenue Benchmark | Customer 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Sales to each significant customer as % of oil and gas sales	95.00%
Colombia
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revenues received in U.S. dollars (as a percent)	100.00%	100.00%	100.00%
Colombia | Geographic Concentration Risk | Oil and natural gas sales
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Sales to each significant customer as % of oil and gas sales	97.00%	100.00%
Ecuador | Geographic Concentration Risk | Oil and natural gas sales
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Sales to each significant customer as % of oil and gas sales	3.00%
Accounts Payable
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Unrealized gain (loss), foreign currency	$ (400,000)
Taxes Payable
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Unrealized gain (loss), foreign currency	300,000
Deferred Tax Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Unrealized gain (loss), foreign currency	(400,000)
6.25% Senior Notes | Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 24,600,000
7.75% Senior Notes | Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Stated interest rate	7.75%			7.75%
Long-term debt	$ 23,800,000
9.50% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Stated interest rate	101.00%
9.50% Senior Notes | Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Stated interest rate	9.50%
Long-term debt	$ 444,600,000

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Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk - Schedule of Losses or Gains on Financial Instruments Recognized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative instruments loss (gain)	$ 0	$ 26,611	$ 48,838
Unrealized investment loss	0	0	2,032
Loss on sale of investment	0	0	1,355
Other financial instruments loss (gain)	15	(7)	(18)
Gain (loss) on investments and derivative instruments	15	(7)	3,369
Commodity price derivative loss
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative instruments loss (gain)	0	26,611	48,723
Foreign currency derivative loss
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative instruments loss (gain)	$ 0	$ 0	$ 115

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Supplemental Cash Flow Information - Reconciliation of Cash, Cash Equivalents, and Restricted Cash and Cash Equivalents (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Cash Flow Elements [Abstract]
Cash and cash equivalents	$ 62,146	$ 126,873	$ 26,109
Restricted cash and cash equivalents - current	1,142	1,142	392
Restricted cash and cash equivalents - long-term	7,750	5,343	4,903
Cash, cash equivalents, restricted cash, and restricted cash equivalents	$ 71,038	$ 133,358	$ 31,404	$ 17,523

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Supplemental Cash Flow Information - Schedule of Net Changes in Assets and Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental Cash Flow Elements [Abstract]
Accounts receivable and other long-term assets	$ (1,628)	$ 2,352	$ (5,686)
Derivatives	0	(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

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Supplemental Cash Flow Information - Schedule of Additional Supplemental Cash Flow Disclosures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental Cash Flow Elements [Abstract]
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

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Supplementary Data (Unaudited) - Narrative (Details) - MMBbls	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Reserve Quantities [Line Items]
Reserves, share of equity method investee's net proved oil and gas reserves	1
Improved recovery	0	0	2,100,000
Extensions discoveries, and additions	17,800,000	6,300,000	7,500,000
Colombia
Reserve Quantities [Line Items]
Extensions discoveries, and additions	16,300,000
Colombia | Acordionero
Reserve Quantities [Line Items]
Extensions discoveries, and additions	1,200,000
Colombia | Costayaco
Reserve Quantities [Line Items]
Extensions discoveries, and additions	3,500,000
Colombia | Moqueta
Reserve Quantities [Line Items]
Extensions discoveries, and additions	2,000,000.0
Colombia | Suroriente Block
Reserve Quantities [Line Items]
Extensions discoveries, and additions	9,600,000
Colombia | Chanangue Block
Reserve Quantities [Line Items]
Extensions discoveries, and additions	1,500,000
Ecuador | Mp Gulf Of Mexico Llc
Reserve Quantities [Line Items]
Extensions discoveries, and additions	1,500,000	2,500,000	500,000
Revisions of previous estimates	600,000	(200,000)
Liquids
Reserve Quantities [Line Items]
Improved recovery			2,057,000
Extensions discoveries, and additions	17,808,000	6,273,000	7,475,000
Revisions of previous estimates	725,000	1,558,000	1,009,000

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Supplementary Data (Unaudited) - Schedule of Proved Reserves Based on Average Prices (Details)	12 Months Ended
	Dec. 31, 2023 MMBbls	Dec. 31, 2022 MMBbls	Dec. 31, 2021 MMBbls	Dec. 31, 2020 MMBbls
Proved Developed and Undeveloped Reserves [Roll Forward]
Improved recoveries	0	0	2,100,000
Extensions	17,800,000	6,300,000	7,500,000
Liquid reserves	1	1	1
Ecuador | Mp Gulf Of Mexico Llc
Proved Developed and Undeveloped Reserves [Roll Forward]
Extensions	1,500,000	2,500,000	500,000
Technical revisions	600,000	(200,000)
Production	(200,000)
Liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	65,267,000	66,565,000	64,692,000
Improved recoveries			2,057,000
Extensions	17,808,000	6,273,000	7,475,000
Technical revisions	725,000	1,558,000	1,009,000
Production	(9,504,000)	(9,129,000)	(8,668,000)
Ending balance	74,296,000	65,267,000	66,565,000
Proved Developed Reserves	39,599,000	40,360,000	41,869,000	38,660,000
Proved Undeveloped Reserve	34,697,000	24,907,000	24,696,000	26,032,000
Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	1,446,000	1,669,000	1,655,000
Improved recoveries			0
Extensions	0	0	0
Technical revisions	(1,446,000)	(208,000)	133,000
Production	0	(15,000)	(119,000)
Ending balance	0	1,446,000	1,669,000
Proved Developed Reserves	0	858,000	880,000	633,000
Proved Undeveloped Reserve	0	588,000	789,000	1,022,000

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Supplementary Data (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Accumulated Depletion, Depreciation and Impairment	$ (3,821,115)	$ (3,617,380)
Total Oil and Gas Properties	1,109,186	1,074,895
Proved
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs	4,876,185	4,617,804
Unproved
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs	$ 54,116	$ 74,471

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Supplementary Data (Unaudited) - Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved	$ 0	$ 0	$ 0
Unproved	0	0	0
Exploration costs	29,862	89,898	20,410
Development costs	203,821	160,933	142,461
Colombia
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved	0	0	0
Unproved	0	0	0
Exploration costs	15,674	50,374	18,080
Development costs	199,240	160,933	142,461
Ecuador
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved	0	0	0
Unproved	0	0	0
Exploration costs	14,188	39,524	2,330
Development costs	$ 4,581	$ 0	$ 0

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Supplementary Data (Unaudited) - Schedule of Results of Operations for Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil sales	$ 636,957	$ 711,388	$ 473,722
Production costs	(201,410)	(172,582)	(147,339)
Exploration expenses	0	0	0
DD&A expenses	(215,364)	(180,039)	(139,765)
Inventory impairment	0	0	0
Income tax (expense) recovery	(103,401)	(105,906)	19,346
Results of Operations	116,782	252,861	205,964
Colombia
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil sales	621,297	711,388	473,722
Production costs	(192,933)	(172,582)	(147,339)
Exploration expenses	0	0	0
DD&A expenses	(207,346)	(180,039)	(139,765)
Inventory impairment	0	0	0
Income tax (expense) recovery	(103,491)	(105,906)	19,346
Results of Operations	117,527	252,861	205,964
Ecuador
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil sales	15,660	0	0
Production costs	(8,477)	0	0
Exploration expenses	0	0	0
DD&A expenses	(8,018)	0	0
Inventory impairment	0	0	0
Income tax (expense) recovery	90	0	0
Results of Operations	$ (745)	$ 0	$ 0

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Supplementary Data (Unaudited) - Schedule of Estimates of Net Proved Reserves, Average Unweighted Arithmetic Sale Price and Production Cost (Details) - $ / Unit	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Colombia
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Twelve month period unweighted arithmetic average of the wellhead price as of the first day of each month within the twelve month period	69.91	86.16	58.07
Weighted average production costs	18.54	16.26	15.55
Ecuador
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Twelve month period unweighted arithmetic average of the wellhead price as of the first day of each month within the twelve month period	77.44	91.53	62.42
Weighted average production costs	20.66	19.55	17.40

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Supplementary Data (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 5,252,179	$ 5,666,476	$ 3,911,181
Future production costs	(1,710,870)	(1,402,812)	(1,263,403)
Future development costs	(550,458)	(397,600)	(378,158)
Future asset retirement obligations	(85,614)	(53,220)	(48,180)
Future income tax expense	(996,825)	(1,424,494)	(516,097)
Future net cash flows	1,908,412	2,388,350	1,705,343
10% discount	(539,375)	(677,724)	(483,566)
Standardized Measure of Discounted Future Net Cash Flows	1,369,037	1,710,626	1,221,777	$ 727,487
Colombia
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	4,893,758	5,410,256	3,880,608
Future production costs	(1,552,227)	(1,298,198)	(1,249,901)
Future development costs	(460,819)	(334,560)	(365,983)
Future asset retirement obligations	(82,314)	(50,520)	(47,580)
Future income tax expense	(954,973)	(1,391,436)	(514,231)
Future net cash flows	1,843,425	2,335,542	1,702,913
10% discount	(516,451)	(659,092)	(481,504)
Standardized Measure of Discounted Future Net Cash Flows	1,326,974	1,676,450	1,221,409
Ecuador
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	358,421	256,220	30,573
Future production costs	(158,643)	(104,614)	(13,502)
Future development costs	(89,639)	(63,040)	(12,175)
Future asset retirement obligations	(3,300)	(2,700)	(600)
Future income tax expense	(41,852)	(33,058)	(1,866)
Future net cash flows	64,987	52,808	2,430
10% discount	(22,924)	(18,632)	(2,062)
Standardized Measure of Discounted Future Net Cash Flows	$ 42,063	$ 34,176	$ 368

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Supplementary Data (Unaudited) -Schedule of Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning balance	$ 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
Ending balance	$ 1,369,037	$ 1,710,626	$ 1,221,777