Gran Tierra Energy (GTE) 10-K 20 Feb 24 2023 FY Annual report Financial data

Cover Page

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

Audit Information

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

Consolidated Statements of Oper

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.

Consolidated Statements of Op_2

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

Consolidated Balance Sheets

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.

Consolidated Balance Sheets (Pa

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

Consolidated Statements of Cash

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	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

Consolidated Statements of Shar

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.

Description of Business

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.

Significant Accounting Policies

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.

Accounts Receivable

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

Property, Plant and Equipment

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

Asset impairment

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 p er 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.

Accounts Payable and Accrued Li

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

Debt and Debt Issuance Costs

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 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 As of December 31, 2023, the Company’s finance leases had remaining useful lives ranging from one one 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

Share Capital

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 $10.59 per share. As of December 31, 2023, all 3,603,396 shares re-purchased under the 2022 Program and 1,013,192 shares re-purchased under the 2023 Program were cancelled subsequent to re-purchase. Equity Compensation Awards The Company has an equity compensation program for its executives, employees, and directors. Executives and employees are given equity compensation grants that vest based on a recipient’s continued employment. In the case of Performance Share Units (“PSUs”), the number of units that vest is dependent upon the achievement of specific key performance measures. Equity based awards consist of 80% of PSUs and 20% of stock options. The Company’s stock-based compensation awards outstanding as at December 31, 2023, include PSUs, deferred share units (“DSUs”), and stock options. In accordance with the 2007 Equity Incentive Plan, as amended, the Company’s Board of Directors is authorized to issue options or other rights to acquire shares of the Company’s Common Stock. On June 27, 2012, the s hareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder fro m 2,330,610 shares to 3,980,610 shares. On June 2, 2021, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 3,980,610 shares to 5,480,610 shares. On May 4, 2022, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 5,480,610 shares to 5,980,610 shares. The following table provides information about PSU, DSU and stock option activity for the year ended December 31, 2023: PSUs DSUs Stock Options Number of Outstanding Share Units Number of Outstanding Share Units Number of Outstanding Stock Options Weighted Average Exercise Price ($) 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 wa s $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 remainin g contractual t erm 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 wa s 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)

Asset Retirement Obligation

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).

Revenue

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.

Taxes

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.

Commitments and Contingencies

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 totali ng $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.

Financial Instruments, Fair Val

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 respectivel y, 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.

Supplemental Cash Flow Informat

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

Supplementary Data (Unaudited)

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 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

Pay vs Performance Disclosure

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

Insider Trading Arrangements

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

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Basis of Consolidation	Basis of Consolidation
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
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
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.
Asset Retirement Obligation	Asset Retirement Obligation
Other Capital Assets	Other Capital Assets
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.
Debt extinguishment and debt modification accounting	Debt extinguishment and debt modification accounting
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.
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.
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.

Accounts Receivable (Tables)

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

Property, Plant and Equipment (

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

Accounts Payable and Accrued _2

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

Debt and Debt Issuance Costs (T

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 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

Share Capital (Tables)

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

Asset Retirement Obligation (Ta

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

Taxes (Tables)

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

Commitments and Contingencies (

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.

Financial Instruments, Fair V_2

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

Supplemental Cash Flow Inform_2

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

Supplementary Data (Unaudited)

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)
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 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

Significant Accounting Polici_3

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

Accounts Receivable (Details)

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

Property, Plant and Equipment -

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

Property, Plant and Equipment_2

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%
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

Property, Plant and Equipment_3

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

Asset impairment (Details)

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%
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

Accounts Payable and Accrued _3

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

Debt and Debt Issuance Costs -

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%
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

Debt and Debt Issuance Costs _2

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%
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

Debt and Debt Issuance Costs _3

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%
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%
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%
Senior Notes
Debt Instrument [Line Items]
Debt instrument, senior notes, percentage						1%
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%
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%
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%
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%
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%
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%

Debt and Debt Issuance Costs _4

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%	80%
Liquidity, ratio	115%	115%
Scenario, Plan
Line of Credit Facility [Line Items]
Debt instrument, net present value as percent of consolidated future cash flows	90%	90%
Minimum
Line of Credit Facility [Line Items]
Global coverage ratio		150%
Discount rate over outstanding balance		0.10
Prepayment life coverage ratio		150%
Risk- Free Rate By Federal Reserve Bank Of New York
Line of Credit Facility [Line Items]
Basis spread on variable rate		6%
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

Debt and Debt Issuance Costs _5

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

Debt and Debt Issuance Costs _6

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

Share Capital - Schedule of Com

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

Share Capital - Additional Info

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%
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity awards granted (as a percent)		20%
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%	10%
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

Share Capital - Schedule of Inf

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

Share Capital - PSUs (Narrative

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%
Award subject to targets relating to net asset value (as a percent)	25%	25%	25%
Net present value discount rate		10%	10%
Free cash flows required	$ 20
Award subject to targets relating to execution of corporate strategy (as a percent)	25%
PSUs | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs that vest (as a percent)	0%
PSUs | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs that vest (as a percent)	200%

Share Capital - Stock Options (

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	$ 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

Share Capital - Schedule of Ass

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%	77%	78%
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility, minimum	82%	77%	71%
Volatility, maximum	90%	81%	80%
Risk free interest rate, minimum	3.60%	1.40%	0.40%
Risk free interest rate, maximum	4.70%	4%	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

Share Capital - Schedule Of Wei

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

Share Capital - Weighted Averag

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

Asset Retirement Obligation - S

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

Asset Retirement Obligation - N

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

Revenue (Details)

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%	17%	15%
Accrued sales revenue	$ 0	$ 0	$ 0
Revenue from Contract with Customer | Product Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	100%	100%	100%
Revenue from Contract with Customer | Product Concentration Risk | Colombia | Customer 1
Concentration Risk [Line Items]
Concentration risk, percentage	97%	78%	66%
Revenue from Contract with Customer | Product Concentration Risk | Colombia | Customer 2
Concentration Risk [Line Items]
Concentration risk, percentage		22%	19%
Revenue from Contract with Customer | Product Concentration Risk | Colombia | Customer 3
Concentration Risk [Line Items]
Concentration risk, percentage			12%
Revenue from Contract with Customer | Product Concentration Risk | Ecuador | Customer 1
Concentration Risk [Line Items]
Concentration risk, percentage	1%

Taxes - Schedule of Income Tax

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%	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	0	0	525
Total income tax expense (recovery)	$ 112,447	$ 105,906	$ (19,346)
Effective tax rate	106%	43%	(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)

Taxes - Schedule of Deferred Ta

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

Taxes - Narrative (Details)

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

Commitments and Contingencies -

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

Commitments and Contingencies_2

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

Financial Instruments, Fair V_3

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%
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

Financial Instruments, Fair V_4

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%
Colombia
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revenues received in U.S. dollars (as a percent)	100%	100%	100%
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%	100%
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%
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%
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

Financial Instruments, Fair V_5

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

Supplemental Cash Flow Inform_3

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

Supplemental Cash Flow Inform_4

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

Supplemental Cash Flow Inform_5

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

Supplementary Data (Unaudited_2

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
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

Supplementary Data (Unaudited_3

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

Supplementary Data (Unaudited_4

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

Supplementary Data (Unaudited_5

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

Supplementary Data (Unaudited_6

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

Supplementary Data (Unaudited_7

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

Supplementary Data (Unaudited_8

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

Supplementary Data (Unaudited_9

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