gte-20250331

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2025


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

For the transition period from __________ to __________

Commission file number 001-34018

GRAN TIERRA ENERGY INC.

(Exact name of registrant as specified in its charter)

Delaware

98-0479924

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

500 Centre Street S.E.

Calgary,

Alberta

Canada

T2G 1A6

(Address of principal executive offices, including zip code)

(403) 265-3221

(Registrant’s telephone number, including area code)

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


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

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

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

Yes ☒ No ☐

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


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

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

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

On April 29, 2025, 35,328,985 shares of the registrant’s Common Stock, $0.001 par value, were issued and outstanding.

Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Quarterly Period Ended March 31, 2025

Table of contents


		Page
PART I	Financial Information
Item 1.	Financial Statements	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	40

PART II	Other Information
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 5.	Other information	41
Item 6.	Exhibits	42
SIGNATURES		43

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of our management for future operations, covenant compliance, capital spending plans and benefits of the changes in our capital program or expenditures, our liquidity and financial condition and those statements preceded by, followed by or that otherwise include the words “believe”, “expect”, “anticipate”, “intend”, “estimate”, “project”, “target”, “goal”, “plan”, “budget”, “objective”, “should”, “outlook” or similar expressions or variations on these expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct or that, even if correct, intervening circumstances will not occur to cause actual results to be different than expected. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements, including, but not limited to, our ability to successfully integrate the assets and operations of i3 Energy Plc (“i3Energy”) and realize the anticipated benefits and operating synergies expected from the 2024 acquisition of i3 Energy; certain of our operations are located in South America and unexpected problems can arise due to guerilla activity, strikes, local blockades or protests; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; other disruptions to local operations; global health events; global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and natural gas, including inflation and changes resulting from actual or anticipated tariffs and trade policies, a global health crises, geopolitical events, including the ongoing conflicts in Ukraine and the Gaza region, or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries and the resulting company or third-party actions in response to such changes; changes in commodity prices, including volatility or a prolonged decline in these prices relative to historical or future expected levels; the risk that current global economic and credit conditions may impact oil prices and oil consumption more than we currently predict, which could cause further modification of our strategy and capital spending program; prices and markets for oil and natural gas are unpredictable and volatile; the effect of hedges; the accuracy of productive capacity of any particular field; geographic, political and weather conditions can impact the production, transport or sale of our products; our ability to execute our business plan, which may include acquisitions and realize expected benefits from current or future initiatives; the risk that unexpected delays and difficulties in developing currently owned properties may occur; the ability to replace reserves and production and develop and manage reserves on an economically viable basis; the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates); the risk profile of planned exploration activities; the effects of drilling down-dip; the effects of waterflood and multi-stage fracture stimulation operations; the extent and effect of delivery disruptions, equipment performance and costs; actions by third parties; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; volatility or declines in the trading price of our common stock or bonds; the risk that we do not receive the anticipated benefits of government programs, including government tax refunds; our ability to access debt or equity capital markets from time to time to raise additional capital, increase liquidity, fund acquisitions or refinance debt; our ability to comply with financial covenants in our indentures and make borrowings under our credit agreement; and those factors set out in Part II, Item 1A “Risk Factors” in this Quarterly Report on Form 10-Q and Part I, Item 1A “Risk Factors” in our 2024 Annual Report on Form 10-K (the “2024 Annual Report on Form 10-K”). This information included herein is given as of the filing date of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission (“SEC”) and, except as otherwise required by the securities laws, we disclaim any obligation or undertaking to publicly release any updates or revisions to or to withdraw, any forward-looking statement contained in this Quarterly Report on Form 10-Q to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based.

GLOSSARY OF OIL AND GAS TERMS

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


bbl	barrel	BOEPD	barrels of oil equivalent per day
BOPD	barrels of oil per day	NGL	natural gas liquids
NAR	net after royalty	boe	barrels of oil equivalent

Sales volumes represent production NAR adjusted for inventory changes. Our oil and gas reserves are reported as NAR. Our production is also reported NAR, except as otherwise specifically noted as “working interest production before royalties”.

PART I - Financial Information

Item 1. Financial Statements

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Operations (Unaudited)

(Thousands of U.S. Dollars, Except for Share and Per Share Amounts)


	Three Months Ended March 31,
	2025		2024
OIL, NATURAL GAS AND NGL SALES (Note 9)	$	170,533	$	157,577

EXPENSES
Operating	67,354		48,466
Transportation	6,911		4,584
Depletion, depreciation and accretion (Note 6)	72,202		56,150

General and administrative (Note 12)	11,626		14,143


Foreign exchange loss (gain)	3,838		(815)
Derivative instruments loss	1,467		—
Interest expense (Note 7)	23,235		18,424
	186,633		140,952

INTEREST INCOME	425		692
OTHER LOSS	(52)		—
INCOME (LOSS) BEFORE INCOME TAXES	(15,727)		17,317

INCOME TAX EXPENSE (RECOVERY)
Current (Note 10)	8,265		3,916
Deferred (Note 10)	(4,712)		13,479
	3,553		17,395
NET LOSS	$	(19,280)	$	(78)

OTHER COMPREHENSIVE INCOME
Foreign currency translation adjustment	191		—
NET AND COMPREHENSIVE LOSS	$	(19,089)	$	(78)

NET LOSS PER SHARE
- BASIC and DILUTED	$	(0.54)	$	—

WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC and DILUTED (Note 8)	35,777,367		31,813,072

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

(Thousands of U.S. Dollars, Except for Share Amounts)


	As at March 31, 2025		As at December 31, 2024

ASSETS
Current Assets
Cash and cash equivalents (Note 13)	$	76,566	$	103,379
Accounts receivable	29,183		35,480
Inventory	37,954		43,116
Taxes receivable (Note 5)	20,662		18,095
Other current assets (Note 12 and 13)	9,623		11,201
Total Current Assets	173,988		211,271

Oil and Gas Properties
Proved	1,272,777		1,260,578
Unproved	135,898		119,520
Total Oil and Gas Properties	1,408,675		1,380,098
Other capital assets	46,259		43,033
Total Property, Plant and Equipment (Note 6)	1,454,934		1,423,131

Other Long-Term Assets
Deferred tax assets	20,827		11,718
Taxes receivable long-term (Note 5)	4,583		1,629
Other long-term assets (Note 12 and 13)	8,402		7,038
Total Other Long-Term Assets	33,812		20,385
Total Assets	$	1,662,734	$	1,654,787

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	330,388	$	273,103

Current portion of long-term debt (Note 7 and 12)	—		24,807
Taxes payable (Note 5)	9,047		13,970
Equity compensation award liability (Note 8)	6,147		10,568
Total Current Liabilities	345,582		322,448

Long-Term Liabilities
Long-term debt (Note 7 and 12)	726,299		722,123
Deferred tax liabilities	69,546		64,114
Asset retirement obligation	106,429		105,936
Equity compensation award liability (Note 8)	10,338		17,456
Taxes payable (Note 5)	1,015		—
Other long-term liabilities	9,717		9,142
Total Long-Term Liabilities	923,344		918,771

Contingencies (Note 11)

Shareholders' Equity
Common Stock (35,533,941 and 36,460,141 issued shares and 35,523,941 and 35,972,193 outstanding shares of Common Stock as at March 31, 2025 and December 31, 2024, respectively, par value $0.001 per share), (Note 8)	9,939		9,940
Additional paid-in capital	1,269,557		1,273,343
Treasury Stock (Note 8)	(49)		(3,165)
Accumulated other comprehensive loss	(6,545)		(6,736)
Deficit	(879,094)		(859,814)
Total Shareholders’ Equity	393,808		413,568
Total Liabilities and Shareholders’ Equity	$	1,662,734	$	1,654,787

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)


	Three Months Ended March 31,
	2025		2024
Operating Activities
Net loss	$	(19,280)	$	(78)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 6)	72,202		56,150

Deferred tax (recovery) expense (Note 10)	(4,712)		13,479
Stock-based compensation expense (Note 8)	(517)		3,361
Amortization of debt issuance costs (Note 7)	3,833		3,306
Unrealized foreign exchange loss (gain)	1,687		(2,266)
Loss on bond purchased	52		—
Derivative instruments loss	1,467		—
Cash settlement of asset retirement obligation	(1,807)		(183)
Non-cash lease expenses	1,736		1,413
Lease payments	(1,567)		(1,058)
Cash settlement on derivative instruments	443		—
Net change in assets and liabilities from operating activities (Note 13)	19,693		(13,297)
Net cash provided by operating activities	73,230		60,827

Investing Activities
Additions to property, plant and equipment (Note 6 and 13 )	(67,504)		(38,800)

Net cash used in investing activities	(67,504)		(38,800)

Financing Activities
Proceeds from issuance of Senior Notes, net of issuance costs (Note 7)	—		85,638
Purchase of Senior Notes	(1,712)		—

Repayment of debt (Note 7)	(24,828)		(36,364)
Re-purchase of shares of Common Stock (Note 8)	(2,415)		(4,948)
Proceeds from exercise of stock options	—		161
Lease payments	(2,253)		(1,972)
Net cash (used in) provided by financing activities	(31,208)		42,515

Foreign exchange gain (loss) on cash, cash equivalents and restricted cash and cash equivalents	38		(42)

Net (decrease) increase in cash, cash equivalents and restricted cash and cash equivalents	(25,444)		64,500
Cash and cash equivalents and restricted cash and cash equivalents, beginning of period (Note 13)	111,337		71,038
Cash and cash equivalents and restricted cash and cash equivalents, end of period (Note 13)	$	85,893	$	135,538

Supplemental cash flow disclosures (Note 13)

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)


	Three Months Ended March 31,
	2025		2024
Share Capital
Balance, beginning of period	$	9,940	$	9,936

Cancellation of shares of Common Stock (Note 8)	(1)		(1)
Balance, end of period	$	9,939	$	9,935

Additional Paid-in Capital
Balance, beginning of period	$	1,273,343	$	1,249,651
Exercise of stock options	—		161
Stock-based compensation (Note 8)	1,743		482

Cancellation of shares of Common Stock (Note 8)	(5,529)		(4,907)
Balance, end of period	$	1,269,557	$	1,245,387

Treasury Stock
Balance, beginning of period	$	(3,165)	$	(163)
Re-purchase of shares of Common Stock (Note 8)	(2,414)		(4,948)
Cancellation of shares of Common Stock (Note 8)	5,530		4,908
Balance, end of period	$	(49)	$	(203)

Accumulated and other comprehensive income (loss)
Balance, beginning of period	$	(6,736)	$	—
Other comprehensive income	191		—
Balance, end of period	$	(6,545)	$	—

Deficit
Balance, beginning of period	$	(859,814)	$	(863,030)
Net loss	(19,280)		(78)

Balance, end of period	$	(879,094)	$	(863,108)

Total Shareholders’ Equity	$	393,808	$	392,011

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Notes to the Condensed Consolidated Financial Statements (Unaudited)

(Expressed in U.S. Dollars, unless otherwise indicated)

1. Description of Business

Gran Tierra Energy Inc. a Delaware corporation (the “Company” or “Gran Tierra”), is a publicly traded company focused on oil and natural gas exploration and production with assets currently in Colombia, Ecuador and Canada.

2. Significant Accounting Policies

These interim unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of results for the interim periods.

The note disclosure requirements of annual audited consolidated financial statements provide additional disclosures required for interim unaudited condensed consolidated financial statements. Accordingly, these interim unaudited condensed consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2024, included in the Company’s 2024 Annual Report on Form 10-K.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements, which are included in the Company’s 2024 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial statements. The Company has evaluated all subsequent events to the date these interim unaudited condensed consolidated financial statements were issued.

Recently Adopted Accounting Pronouncements

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 reporting periods beginning after December 15, 2024 and should be applied prospectively, with retrospective application permitted. The Company adopted ASU 2023-09 effective January 1, 2025. The implementation of this update did not have a material impact on income tax disclosures.

3. Business Combination

On October 31, 2024, the Company acquired all of the issued and outstanding common shares of i3 Energy Plc (“i3 Energy”), subsequently renamed as Gran Tierra UK Limited (“Gran Tierra UK”) for $204.5 million, consisting of cash consideration of $161.8 million, cash dividend of $4.0 million, cash settlement of stock options of $2.0 million and 5,808,925 shares of the Company’s Common Stock, the fair value of which was determined to be $36.7 million based on the closing price of the Company’s shares on the acquisition date. The acquisition was accounted for as a business combination using the acquisition method with Gran Tierra being the acquirer, whereby the assets acquired and liabilities assumed were recognized at their fair values as at the i3 Energy acquisition date, and the results of i3 Energy were included with those of Gran Tierra from that date. Fair value estimates were made based on significant unobservable (Level 3) inputs and based on the best information available at the time.

Determining the fair values of the assets and liabilities of i3 Energy and the consideration paid required significant judgment and certain assumptions to be made. The most significant fair value estimates related to the valuation of i3 Energy's proved and unproved oil and natural gas properties. The fair value of proved oil and natural gas properties acquired is based on cash flows associated with estimated acquired proved oil and natural gas reserves and the discount rate. Factors that impact these reserves cash flows include forecasted production, forecasted commodity prices, and forecasted operating, royalty and capital costs. Management is continuing to review and assess information to accurately determine the acquisition date fair value of the proved oil and natural gas properties and deferred tax assets and liabilities acquired.

Due to the timing of acquisition, management is continuing to review and assess information to accurately determine the acquisition date fair value of the proved oil and natural gas properties and deferred tax assets and liabilities acquired. As at March 31, 2025, there were no changes to initial measurement of fair value of the proved oil and natural gas properties and deferred tax assets and liabilities acquired.

Pro Forma Results (unaudited)

Pro forma for the three months ended March 31, 2024 are shown below, as if the i3 Energy acquisition had occurred on January 1, 2024. Pro forma results are not indicative of actual results or future performance:


	Three Months Ended March 31,
(Unaudited, thousands of U.S. Dollars)	2024
Oil, natural gas and NGL sales	$	197,412
Net loss	(7,763)

4. Segment and Geographic Reporting

The Company is primarily engaged in the exploration and production of oil and natural gas. The Company reports segmented information based on internal management reporting used by our Chief Operational Decision Makers (“CODM”), which are the Company’s Chief Executive Officer, Chief Financial Officer, Chief Operating Officer and Vice Presidents across various business functions. CODM allocates resources and assesses performance of each reportable segment based on segmented earnings. The Company determined three reportable segments based on the geographic organization: Colombia, Ecuador and Canada. The “Other” category represents the Company’s corporate activities.

The following tables present information on the Company’s reportable segments and other activities:


	Three Months Ended March 31, 2025
(Thousands of U.S. Dollars)	Colombia		Ecuador		Canada		Other		Total
Oil, natural gas and NGL sales	$	117,648	$	21,023	$	31,862	$	—	$	170,533
Operating expenses	42,754		8,073		16,527		—		67,354
Transportation expenses	3,211		1,093		2,607		—		6,911
Segmented earnings	$	71,683	$	11,857	$	12,728	$	—	$	96,268

DD&A expenses									72,202
General and administrative expenses									11,626
Foreign exchange loss									3,838
Derivative instruments loss									1,467
Interest expense									23,235
Non-segmented expenses									112,368

Other loss									(52)
Interest income									425
Income before income taxes									(15,727)
Income tax expense									3,553
Net loss									$	(19,280)

Segment capital expenditures	$	22,669	$	20,787	$	23,665	$	383	$	67,504


	Three Months Ended March 31, 2024
(Thousands of U.S. Dollars)	Colombia		Ecuador		Canada		Other		Total
Oil, natural gas and NGL sales	$	150,471	$	7,106	$	—	$	—	$	157,577
Operating expenses	45,126		3,340		—		—		48,466
Transportation expenses	4,226		358		—		—		4,584
Segmented earnings	$	101,119	$	3,408	$	—	$	—	$	104,527

DD&A expenses									56,150
General and administrative expenses									14,143


Foreign exchange gain									(815)

Interest expense									18,424
Non-segmented expenses									87,902


Interest income									692
Income before income taxes									17,317
Income tax expense									17,395
Net loss									$	(78)

Segment capital expenditures	$	33,713	$	5,087	$	—	$	—	$	38,800


	As at March 31, 2025
(Thousands of U.S. Dollars)	Colombia		Ecuador		Canada		Other		Total
Property, plant and equipment	$	1,017,033	$	160,826	$	264,250	$	12,825	$	1,454,934
All other assets	107,817		31,567		28,752		39,664		207,800
Total Assets	$	1,124,850	$	192,393	$	293,002	$	52,489	$	1,662,734

	As at December 31, 2024
(Thousands of U.S. Dollars)	Colombia		Ecuador		Canada		Other		Total
Property, plant and equipment	$	1,022,808	$	143,034	$	247,512	$	9,777	$	1,423,131
All other assets	99,100		27,942		62,541		42,073		231,656
Total Assets	$	1,121,908	$	170,976	$	310,053	$	51,850	$	1,654,787

5. Taxes Receivable and Payable

The table below shows the break-down of taxes receivable, which are comprised of value added tax (“VAT”) and income tax receivables and payables:


(Thousands of U.S. Dollars)	As at March 31, 2025		As at December 31, 2024
Taxes Receivable
Current
VAT Receivable	$	3,275	$	657
Income Tax Receivable	17,387		17,438
	$	20,662	$	18,095
Long-Term
Income Tax Receivable	$	4,583	$	1,629

Taxes Payable
Current
VAT Payable	$	(72)	$	(7,640)
Income Tax Payable	(8,975)		(6,330)
	$	(9,047)	$	(13,970)
Long-Term
Income Tax Payable	$	(1,015)	$	—

Total Net Taxes Receivable	$	15,183	$	5,754

The following table shows the movement of VAT and income tax receivables and payables for the period:


(Thousands of U.S. Dollars)	VAT Receivable/(Payable(1))		Income Tax Receivable		Total Net Taxes Receivable
Balance, as at December 31, 2024	$	(6,983)	$	12,737	$	5,754
Collected through direct government refunds	(279)		—		(279)
Collected through sales contracts	(23,654)		—		(23,654)
Taxes paid	33,867		—		33,867
Withholding taxes paid	—		6,784		6,784
Current tax expense	—		(8,265)		(8,265)
Foreign exchange loss	252		724		976
Balance, as at March 31, 2025	$	3,203	$	11,980	$	15,183

(1) VAT is paid on certain goods and services and collected on sales in Colombia at a rate of 19%

6. Property, Plant and Equipment


(Thousands of U.S. Dollars)	As at March 31, 2025		As at December 31, 2024
Oil and natural gas properties
Proved	$	5,373,742	$	5,298,085
Unproved	135,898		119,520
	5,509,640		5,417,605
Other (1)	104,574		97,795
	5,614,214		5,515,400
Accumulated depletion, depreciation and impairment	(4,159,280)		(4,092,269)
	$	1,454,934	$	1,423,131

(1) The “other” category includes right-of-use assets for operating and finance leases of $75.1 million, which had a net book value of $36.7 million as at March 31, 2025 (December 31, 2024 - $70.1 million, which had a net book value of $35.1 million).

During the three months ended March 31, 2025, the Company entered into one finance lease contract related to power generation equipment and capitalized $6.4 million, right-of-use assets in relation to this contract.

For the three months ended March 31, 2025 and 2024, the Company had no ceiling test impairment losses. The Company used a 12-month unweighted average of the first-day-of the month prices prior to the ending date of the period ended March 31, 2025 as follows: Brent Crude $78.90 per boe, Edmonton Light Crude of C$98.11 per boe, Alberta AECO spot price of C$1.51 per MMBtu Edmonton Propane C$32.53 per boe, Edmonton Butane C$48.81 per boe and Edmonton Condensate C$101.71 and for the period ended three months ended March 31, 2024 Brent Crude of $81.58 per boe.

7. Debt and Debt Issuance Costs

The Company’s debt as at March 31, 2025, and December 31, 2024, was as follows:


(Thousands of U.S. Dollars)	As at March 31, 2025		As at December 31, 2024
Current

6.25% Senior Notes, due February 2025 (“6.25% Senior Notes”)	$	—	$	24,828
Unamortized debt issuance costs	—		(21)
	$	—	$	24,807

Long-Term

7.75% Senior Notes, due May 2027 (“7.75% Senior Notes”)	$	24,201	$	24,201
9.50% Senior Notes, due October 2029 (“9.50% Senior Notes”)	735,790		737,590
Unamortized Senior Notes discount	(38,994)		(41,918)
Unamortized Senior Notes issuance costs	(17,047)		(18,075)
	703,950		701,798
Long-term lease obligation (1)	22,349		20,325
	$	726,299	$	722,123
Total Debt	$	726,299	$	746,930

(1) The current portion of the lease obligation has been included in accounts payable and accrued liabilities on the Company’s balance sheet and totaled $15.6 million as at March 31, 2025 (December 31, 2024 - $15.3 million).

Credit Facility

In connection with the i3 Energy acquisition closing on October 31, 2024, the Company amended and restated the existing revolving credit facility agreement of i3 Energy Canada Ltd. with National Bank of Canada dated March 22, 2024. As a result of the amendment and restatement, among other things, the borrowing base was revised to C$100.0 million (US$69.5 million as of March 31, 2025) with available commitment of a C$50.0 million (US$34.8 million as of March 31, 2025) revolving credit facility comprised of C$35.0 million (US$24.3 million as of March 31, 2025) syndicated facility and C$15.0 million (US$10.4 million as of March 31, 2025) of operating facility. Subject to the next borrowing base redetermination which will occur on or before June 30, 2025, the revolving credit facility is available until October 31, 2025 with a repayment date of October 31, 2026, which may be extended by further periods of up to 364 days, subject to lender approval. The drawn down amounts under the revolving credit facility can either be in Canadian or U.S. dollars and bear interest rates equal to either the Canadian prime rate or U.S. Base Rate plus a margin ranging from 2.00% to 4.00% per annum or for CORRA loans and SOFR loans plus a margin ranging from 3.00% to 5.00% per annum. Undrawn amounts under the revolving credit facility bear standby fee ranging from 0.75% to 1.25% per annum. In each case, the margin or standby fee, as applicable is based on Net Debt to EBITDA ratio of Gran Tierra Canada Ltd. As of March 31, 2025, the credit facility was undrawn.

Senior Notes

During the three months ended March 31, 2025, the Company paid at maturity the remaining principal of $24.8 million of 6.25% Senior Notes due in February 2025 for cash consideration of $25.6 million, including interest payable of $0.8 million.

The Company also purchased $1.8 million of 9.50% Senior Notes for cash consideration of $1.7 million resulting in a $0.1 million loss on purchase, which included the write-off of deferred financing fees of $0.1 million.

At March 31, 2025, we had $24.2 million aggregate principal amount of 7.75% Senior Notes due 2027, and $735.8 million aggregate principal amount of 9.50% Senior Notes due 2029, outstanding.

As at March 31, 2025, the Company was in compliance with all applicable covenants related to credit facility and Senior Notes.

Leases

During the three months ended March 31, 2025, the Company recorded one finance lease of $6.4 million. The finance lease has a 2-year term and a discount rate of 9.6%.

Interest Expense

The following table presents the total interest expense recognized in the accompanying interim unaudited condensed consolidated statements of operations:


	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2025		2024
Contractual interest and other financing expenses	$	19,402	$	15,118
Amortization of debt issuance costs	3,833		3,306
	$	23,235	$	18,424

8. Share Capital


			Shares of Common Stock
Shares issued at December 31, 2024			36,460,141
Treasury shares			(487,948)
Shares issued and outstanding at December 31, 2024			35,972,193
Shares issued on option exercise			4,798
Shares re-purchased and cancelled			(443,050)
Shares issued at March 31, 2025			35,533,941
Treasury shares			(10,000)
Shares issued and outstanding at March 31, 2025			35,523,941

During the year ended December 31, 2024, the Company implemented a share re-purchase program (the “2024 Program”) through the facilities of the Toronto Stock Exchange (“TSX”), the NYSE American or alternative programs in Canada or the United States, if eligible. Under the 2024 Program, the Company is able to purchase up to 3,545,872 shares of Common Stock, par value of $0.001 per share (“Common Stock”) representing 10% of the public float as of October 31, 2024. The 2024 Program will continue for one year and expire on November 5, 2025, or earlier if the 10% maximum is reached.

During the three months ended March 31, 2025, the Company re-purchased 453,050 shares at a weighted average price of $5.33 per share (three months ended March 31, 2024 - 886,666 shares under the 2023 program at a weighted average price of $5.58 per share). As of March 31, 2025, the Company cancelled 487,948 shares held as treasury shares at December 31, 2024, and cancelled 453,050 shares re-purchased during the three months ended March 31, 2025. During the period from November 6, 2024 to April 29, 2025, the Company has re-purchased 1,140,752 shares out of a maximum of 3,545,872 under the 2024 Program.

Equity Compensation Awards

The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), restricted share units (“RSUs”) and stock option activity for the three months ended March 31, 2025:


	PSUs	DSUs	RSUs	Stock Options
	Number of Outstanding Share Units	Number of Outstanding Share Units	Number of Outstanding Share Units	Number of Outstanding Stock Options	Weighted Average Exercise Price/Stock Option ($)
Balance, December 31, 2024	5,380,629	904,674	666,127	1,550,497	8.82
Granted	2,346,868	108,835	570,567	—	—
Exercised	(1,066,555)	—	(168,361)	(19,192)	2.30
Forfeited	(64,933)	—	(8,908)	(4,336)	9.90
Expired	—	—	—	(401,508)	7.81
Balance, March 31, 2025	6,596,009	1,013,509	1,059,425	1,125,461	8.85

As at March 31, 2025, the equity compensation award liability on the Company’s balance sheet included $1.0 million of current liability related to the Company’s outstanding stock options.

The fair value of each stock option award was estimated on the modification date using the Black-Scholes-Merton option-pricing model based on the assumptions noted in the following table:


Fair value of option modification			$0.00 - $6.11
Dividend yield (per share)			Nil
Expected volatility			43% to 87%
Risk-free interest rate			4.6% to 5.1%
Expected term			0.1 - 4.9 years
Expected forfeiture rate			0% to 5%

For the three months ended March 31, 2025 and 2024, there was $0.5 million of stock-based compensation recovery and $3.4 million of stock-based compensation expense, respectively.

As at March 31, 2025, there was $26.9 million (December 31, 2024 - $21.9 million) of unrecognized compensation costs related to unvested PSUs, RSUs and stock options, which are expected to be recognized over a weighted-average period of 2.1 years. During the three months ended March 31, 2025, the Company paid out $7.2 million for PSUs vested on December 31, 2024 (three months ended March 31, 2024 - $10.4 million for PSUs vested on December 31, 2023).

During the three months ended March 31, 2025, the Company awarded 0.6 million RSU to employees pursuant to the existing 2007 Equity Incentive Plan. Under the 2007 Equity Incentive Plan, RSUs will vest one-third each year over a three-year period. Upon vesting, RSUs entitle the holder to receive either the underlying number of shares of the Company’s Common Stock or a cash payment equal to the value of the underlying shares of the Company’s Common Stock. The Company intends to settle RSUs outstanding as at March 31, 2025, in cash.

Net Income (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 using the treasury stock method for share-based compensation arrangements. The treasury stock method assumes that any proceeds obtained on the exercise of share-based compensation arrangements would be used to purchase shares of Common Stock at the average market price during the period. The weighted average number of shares is then adjusted by the difference between the number of shares issued from the exercise of share-based compensation arrangements and shares re-purchased from the related proceeds. Anti-dilutive shares represent potentially dilutive securities excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.

Weighted Average Shares Outstanding

For the three months ended March 31, 2025 and 2024 all options were excluded from the diluted loss per share calculation as the options were anti-dilutive.

9. Revenue


	Three Months Ended March 31, 2025
	Crude Oil		Natural Gas		NGL		Total Revenue
Colombia	117,648		—		—		117,648
Ecuador	21,023		—		—		21,023
Canada	18,552		8,727		4,583		31,862
	$	157,223	$	8,727	$	4,583	$	170,533


	Three Months Ended March 31, 2024
	Crude Oil		Natural Gas		NGL		Total Revenue
Colombia	150,471		—		—		150,471
Ecuador	7,106		—		—		7,106
Canada	—		—		—		—
	$	157,577	$	—	$	—	$	157,577

During the three months ended March 31, 2025, the Company’s production was sold primarily to two major customers representing 65% and 20% of the total sales volumes, of which 60% was sold in Colombia, 10% in Ecuador and 30% in Canada (three months ended March 31, 2024 - one major customer representing 100% of the total sales volumes).

As at March 31, 2025, accounts receivable included $14.0 million of accrued sales revenue related to March 2025 production (December 31, 2024 - $13.4 million related to December 2024 production).

10. Taxes

The Company’s effective tax rate was negative 23% for the three months ended March 31, 2025, compared to 100% in the corresponding period of 2024.

Current income tax expense was $8.3 million for the three months ended March 31, 2025, compared to $3.9 million in the corresponding period of 2024, primarily due to an increase in taxable income in Ecuador, Canada and Colombia.

For the three months ended March 31, 2025, the deferred tax recovery of $4.7 million was mainly due to the use of a higher enacted tax rate on Colombian tax losses. These were partially offset by higher tax depreciation relative to accounting depreciation.

For the three months ended March 31, 2024, the deferred income tax expense was $13.5 million mainly as a result of tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia.

For the three months ended March 31, 2025, the difference between the effective tax rate of negative 23% and the 40% Colombian tax rate was primarily due to an increase in the non-deductible foreign translation adjustments, other permanent differences and valuation allowance. This was partially offset by an increase in the impact of foreign taxes.

For the three months ended March 31, 2024, the difference between the effective tax rate of 100% and the 45% Colombian tax rate was primarily due to an increase in the impact of foreign taxes, increase in the valuation allowance, non-deductible foreign translation adjustments, non-deductible stock-based compensation and other permanent differences.

11. Contingencies

Legal Proceedings

The Company has several lawsuits and claims pending. The outcome of the lawsuits and disputes cannot be predicted with certainty; the Company 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. The Company records costs as they are incurred or become probable and determinable.

Letters of Credit and Other Credit Support

At March 31, 2025, the Company had provided letters of credit and other credit support totaling $240.8 million (December 31, 2024 - $244.5 million) as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, the Suroriente Block, and other capital or operating requirements as well as for transportation capacity in Canada.

12. Financial Instruments and Fair Value Measurement

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

At March 31, 2025, the Company’s financial instruments recognized on the balance sheet consist of cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, current portion of long-term debt, long-term debt and other long-term liabilities. The Company uses appropriate valuation techniques based on the available information to measure the fair values of assets and liabilities.

Fair Value Measurement

The following table presents the Company’s fair value measurements of its financial instruments as of March 31, 2025, and December 31, 2024:


(Thousands of U.S. Dollars)	As at March 31, 2025		As at December 31, 2024
Level 1



Liabilities
6.25% Senior Notes	$	—	$	24,133
7.75% Senior Notes	21,422		21,451
9.50% Senior Notes	651,421		688,262
	$	672,843	$	733,846
Level 2
Assets
Restricted cash and cash equivalents - long-term (1)	$	8,185	$	6,816
Commodity derivatives - current (2)	—		712
	$	8,185	$	7,528

Liabilities
Commodity derivatives - current (3)	$	1,290	$	—

(1) The long-term portion of restricted cash and cash equivalents is included in the other long-term assets on the Company’s condensed consolidated balance sheet.

(2) The current portion of commodity derivatives was included into other current assets on the Company’s condensed consolidated balance sheet.

(3) The current portion of commodity derivatives was included into accounts payable balance on the Company’s condensed consolidated balance sheet.

The fair values of cash and cash equivalents, current restricted cash and cash equivalents, accounts receivable and accounts payable, and accrued liabilities approximate their carrying amounts due to the short-term maturity of these instruments.

Restricted Cash and Cash Equivalents - 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.

Prepaid Equity Forward (“PEF”)

During the three months ended March 31, 2024, the Company settled all outstanding notional PEF shares and received net proceeds of $5.1 million resulting in a $0.3 million loss on settlement.

Senior Notes

Financial instruments recorded at amortized cost at March 31, 2025, were the Senior Notes (Note 7).

At March 31, 2025, the carrying amounts of the 7.75% Senior Notes and 9.50% Senior Notes were $23.9 million and $680.0 million, respectively, which represented the aggregate principal amounts less unamortized debt issuance costs and discounts, and the fair values were $21.4 million, and $651.4 million, respectively.

Derivative asset and derivative liability

The fair value of derivatives is estimated based on various factors, including quoted market prices in active markets and quotes from third parties. The Company also performs an internal valuation to ensure the reasonableness of third party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers whether such counterparty has the ability to meet its potential repayment obligations associated with the derivative transactions.

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 March 31, 2025, the Company had outstanding commodity price derivative positions in Canada and Colombia as follows:

CANADA - OIL

Type of Instrument

Start Period

End Period

Volume,
bbl/d

Reference

Price (C$/bbl or $/bbl)

Purchased Put (C$/bbl or $/bbl Weighted Average)

Sold Call
(C$/bbl or $/bbl Weighted Average)

Swap

April 01, 2025

June 30, 2025

1,585

WTI CMA

100.11

—

Swap

April 01, 2025

April 30, 2025

250

WTI CMA

72.73

—

Collar

April 01, 2025

December 31, 2025

500

WTI CMA

—

65.00

77.40

Call option

April 01, 2025

December 31, 2025

250

WTI CMA

—

95.00

Swap

July 01, 2025

September 30, 2025

539

WTI CMA

97.81

—

Call option

January 01, 2026

December 31, 2026

500

WTI CMA

—

107.00

CANADA - NATURAL GAS

Type of Instrument

Start Period

End Period

Volume,
GJ/day

Reference

Sold Swap (C$/GJ, Weighted Average)

Purchased Put (C$/GJ, Weighted Average)

Sold Call
(C$/GJ, Weighted Average)

Swap

April 01, 2025

June 30, 2025

11,648

Aeco 5A

2.99

—

Swap

July 01, 2025

September 30, 2025

12,500

Aeco 5A

3.07

—

Swap

October 01, 2025

December 31, 2025

22,500

Aeco 5A

3.13

—

Put Option

April 01, 2025

September 30, 2025

6,500

Aeco 7A

—

2.00

—


COLOMBIA - OIL
Type of Instrument	Start Period	End Period	Volume, bbl/d	Reference	Purchased Put ($/bbl, Weighted Average)	Sold Call ($/bbl, Weighted Average)	Premium ($/bbl, Weighted Average)
Put Option	April 01, 2025	June 30, 2025	4,000	Brent	69.63	—	3.26
Put Option	July 01, 2025	December 31, 2025	1,000	Brent	68.50	—	3.34
Collar	April 01, 2025	June 30, 2025	5,000	Brent	65.00	79.80	—
Collar	July 01, 2025	September 30, 2025	5,337	Brent	64.06	79.02	—
Collar	October 01, 2025	December 31, 2025	5,000	Brent	64.00	78.90	—
Collar	January 01, 2026	March 31, 2026	1,000	Brent	60.00	76.25	—

Foreign Exchange Risk

The Company is exposed to foreign exchange risk in relation to its Colombian and Canadian 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 March 31, 2025, the Company had no outstanding foreign currency exchange derivative positions.

Subsequent to the three months ended March 31, 2025, the Company entered into the following foreign currency derivative positions:

Period and Type of Instrument

U.S. Dollars Amount Hedged
(Thousands of U.S. Dollars)

COP Equivalent of Amount Hedged (Millions of COP)(1)

Reference

Floor Price
(COP, Weighted Average)

Cap Price (COP, Weighted Average)

Collars: April 16 2025, to April 15, 2026

120,000

503,160

COP

4,430

4,706

(1) At March 31, 2025 foreign exchange rate.

13. Supplemental Cash Flow Information

The following table provides a reconciliation of cash and cash equivalents and restricted cash and cash equivalents shown as a sum of these amounts in the interim unaudited condensed consolidated statements of cash flows:


	As at March 31,				As at December 31,
(Thousands of U.S. Dollars)	2025		2024		2024		2023
Cash and cash equivalents	$	76,566	$	126,618	$	103,379	$	62,146
Restricted cash and cash equivalents - current (1)	1,142		1,142		1,142		1,142
Restricted cash and cash equivalents - long-term (2)	8,185		7,778		6,816		7,750
	$	85,893	$	135,538	$	111,337	$	71,038

(1) Included in other current assets on the Company’s condensed consolidated balance sheet.

(2) Included in other long-term assets on the Company’s condensed consolidated balance sheet.

Net changes in assets and liabilities from operating activities were as follows:


	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2025		2024
Accounts receivable and other long-term assets	$	5,703	$	1,639
PEF	—		6,218
Prepaids and inventory	3,239		1,967
Accounts payable and accrued liabilities, and other long-term liabilities	19,204		(9,995)
Taxes receivable and payable	(8,453)		(13,126)
Net changes in assets and liabilities from operating activities	$	19,693	$	(13,297)

Net changes in working capital from investing activities were as follows:


	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2025		2024
Additions to property, plant and equipment	$	(94,727)	$	(55,331)
Increase in accounts payable and accrued liabilities	26,567		16,587
Increase (decrease) in accounts receivable	656		(56)
Net cash additions to property, plant and equipment	$	(67,504)	$	(38,800)

The Company revised the presentation of cash flows associated with additions to property, plant and equipment within net cash used in investing activities in the Consolidated Statements of Cash Flows for the three months ended March 31, 2024. Additions to property, plant and equipment as previously reported of $55.3 million were presented on an accrual basis before the related decrease in cash outflow due to impact of changes in noncash investing working capital of $16.5 million. The cash outflow associated with additions to property, plant and equipment has been re-casted in accordance with the direct method. There was no change in amount to the Company’s previously reported net cash used in investing activities

The following table provides additional supplemental cash flow disclosures:


	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2025		2024

Cash paid for withholding taxes	$	6,784	$	11,681
Cash paid for interest	$	828	$	1,224

Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	88,338	$	63,947

14. Subsequent Events

On April 16, 2025, the Company, through its wholly owned subsidiary, Gran Tierra Energy Colombia GmbH, a Swiss limited liability company, entered into a US$75 million reserve-based lending facility. Any loans incurred under the new facility will mature on April 16, 2028 and will bear interest at a rate per annum equal to, at Company’s option, either (a) a customary base rate (subject to a floor of 1.00%) plus an applicable margin of 4.50% or (b) a term secured overnight finance rate (“SOFR”) reference rate plus an applicable margin of 4.50%. Interest on base rate borrowings is payable quarterly in arrears and interest on term SOFR borrowings accrues in respect of interest periods of three or six months, at the election of the Company, and is payable on the last day of such interest period.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of our financial condition and results of operations should be read in conjunction with the “Financial Statements” as set out in Part I, Item 1 of this Quarterly Report on Form 10-Q, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the “Financial Statements and Supplementary Data” included in Part II, Items 7 and 8, respectively, of our 2024 Annual Report on Form 10-K. Please see the cautionary language at the beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements and the risk factors described in Part II, Item 1A “Risk Factors” of this Quarterly Report on Form 10-Q, as well as Part I, Item 1A “Risk Factors” in our 2024 Annual Report on Form 10-K.

Financial and Operational Highlights

Key Highlights for the first quarter of 2025

•Net loss for the first quarter of 2025 was $19.3 million or $(0.54) per share basic and diluted, compared to a net loss of $0.1 million or nil per share basic and diluted for the first quarter of 2024 and a net loss of $34.2 million for the prior quarter

•Loss before income taxes for the first quarter of 2025 was $15.7 million, compared to income before income taxes of $17.3 million for the first quarter of 2024 and loss before income taxes of $21.9 million for the prior quarter

•Brent oil price averaged $74.98 per bbl during the quarter, a decrease of 8% from the comparable period in 2024, and a 1% increase from the prior quarter. Castilla, Vasconia and Oriente differentials averaged $5.34, $2.27 and $7.65 per bbl during the quarter, a decrease of 39%, 55% and 5% from the comparable period of 2024, and an increase of 36%, 55% and 19% from the prior quarter, respectively

•Adjusted EBITDA(2) was $85.2 million for the first quarter of 2025, a decrease from $94.8 million in the first quarter of 2024, and an increase from $76.2 million in the prior quarter

•Funds flow from operations(2) decreased to $55.3 million compared to $74.3 million in the first quarter of 2024, and increased from $44.1 million in the prior quarter

•In the first quarter of 2025, we re-purchased 0.5 million shares of Common Stock at a weighted average price of $5.33 per share through the 2024 share re-purchase program. During the period from November 6, 2024 to April 29, 2025, we re-purchased a total of 1.1 million shares or 3% of the outstanding shares as of March 31, 2025

•NAR production for the first quarter of 2025 increased by 49% to 38,563 BOEPD, compared to 25,845 BOEPD in the first quarter of 2024, and increased by 14% from 33,682 BOEPD in the prior quarter

•Sales volumes for the first quarter of 2025 increased by 50% to 39,024 BOEPD, compared to 26,080 BOEPD in the first quarter of 2024 and increased by 18% from 32,970 BOEPD in the prior quarter

•Oil, natural gas and NGL sales for the first quarter of 2025 increased by 8% to $170.5 million, compared to the first quarter of 2024, primarily due to increased sales volumes partially offset by lower oil prices. Oil, natural gas and NGL sales increased by 16% from $147.3 million in the prior quarter due to higher oil and gas prices, lower differentials, and increased sales volumes

•Operating expenses increased by 39% to $67.4 million when compared to the first quarter of 2024, primarily as a result of new Canadian operations and ramp-up of operations in Ecuador. Operating expenses increased by 11% from $60.8 million in the prior quarter as a result of three months of new Canadian operations opposed to two in the prior quarter

•Transportation expenses increased by 51% when compared to the first quarter of 2024 primarily due to 50% higher sales volumes from new Canadian operations and higher sales volumes transported in Ecuador during the period. Transportation expenses increased by 62% compared to the prior quarter for the same reason mentioned above

•Operating netback(2) was $96.3 million compared to $104.5 million in the first quarter of 2024 and $82.2 million in the prior quarter primarily as a result of the addition of the Canadian assets and approximately 50% of Canadian production tied to AECO gas pricing

•Quality and transportation discounts for the first quarter of 2025 increased to $26.43 per boe compared to $15.36 per boe in the first quarter of 2024 and $25.45 per boe in the prior quarter primarily as a result of the change in production mix with the acquisition of Canadian assets

•General and administrative (“G&A”) expenses before stock-based compensation for the first quarter of 2025 increased to $12.1 million compared to $10.8 million in the first quarter of 2024 and $10.2 million in the prior quarter due to the addition of a new Canadian operation employees and three full months of operations in the current quarter compared to two in the prior quarter

•Capital expenditures for the first quarter of 2025 were $94.7 million compared to $55.3 million in the first quarter of 2024 and $78.6 million in the prior quarter due to the addition of the Canadian development program and an active Ecuador exploration program in the first quarter of 2025


(Thousands of U.S. Dollars, unless otherwise indicated)	Three Months Ended March 31,					Three Months Ended December 31,
	2025		2024		% Change	2024
Average Daily Volumes (BOEPD)
Consolidated
Working Interest (“WI”) Production Before Royalties	46,647		32,242		45	41,009
Royalties	(8,084)		(6,397)		26	(7,327)
Production NAR	38,563		25,845		49	33,682
Increase in Inventory	461		235		96	(712)
Sales(1)	39,024		26,080		50	32,970

Net Loss	$	(19,280)	$	(78)	24,618	$	(34,210)

Operating Netback
Oil, natural gas and NGL Sales	$	170,533	$	157,577	8	$	147,290
Operating Expenses	(67,354)		(48,466)		39	(60,770)
Transportation Expenses	(6,911)		(4,584)		51	(4,279)
Operating Netback(2)	$	96,268	$	104,527	(8)	$	82,241

G&A Expenses before Stock-Based Compensation	$	12,143	$	10,782	13	$	10,191
G&A Stock-Based Compensation (Recovery) Expense	(517)		3,361		(115)	3,331
G&A Expenses, including Stock-Based Compensation	$	11,626	$	14,143	(18)	$	13,522

Adjusted EBITDA(2)	$	85,162	$	94,792	(10)	$	76,168

Funds Flow from Operations(2)	$	55,344	$	74,307	(26)	$	44,129

Capital Expenditures	$	94,727	$	55,331	71	$	78,579

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

(2) Non-GAAP measures.

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

Operating netback, as presented, is defined as oil sales less operating and transportation expenses. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from oil sales to operating netback is provided in the table above.

EBITDA, as presented, is defined as net loss adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, lease payments, foreign exchange gain or loss, stock-based compensation expense or recovery, transaction costs related to the acquisition of i3 Energy, other gain or loss and unrealized derivative instruments loss. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net (loss) income to EBITDA and adjusted EBITDA is as follows:


	Three Months Ended March 31,				Three Months Ended December 31,
(Thousands of U.S. Dollars)	2025		2024		2024
Net loss	$	(19,280)	$	(78)	$	(34,210)
Adjustments to reconcile net loss to EBITDA and Adjusted EBITDA
DD&A expenses	72,202		56,150		63,406
Interest expense	23,235		18,424		23,752
Income tax expense	3,553		17,395		12,299
EBITDA (non-GAAP)	$	79,710	$	91,891	$	65,247
Non-cash lease expense	1,736		1,413		1,759
Lease payments	(1,567)		(1,058)		(1,495)
Foreign exchange loss (gain)	3,838		(815)		(496)
Stock-based compensation (recovery) expense	(517)		3,361		3,331
Transaction costs	—		—		4,448
Other loss	52		—		—
Unrealized derivative instruments loss	1,910		—		3,374
Adjusted EBITDA (non-GAAP)	$	85,162	$	94,792	$	76,168

Funds flow from operations, as presented, is defined as net loss adjusted for DD&A expenses, deferred income tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, unrealized derivative instruments loss and other loss. and Management uses this financial measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net loss to funds flow from operations is as follows:


	Three Months Ended March 31,				Three Months Ended December 31,
(Thousands of U.S. Dollars)	2025		2024		2024
Net loss	$	(19,280)	$	(78)	$	(34,210)
Adjustments to reconcile net loss to funds flow from operations
DD&A expenses	72,202		56,150		63,406

Deferred income tax (recovery) expense	(4,712)		13,479		4,444
Stock-based compensation (recovery) expense	(517)		3,361		3,331
Amortization of debt issuance costs	3,833		3,306		3,743
Non-cash lease expense	1,736		1,413		1,759
Lease payments	(1,567)		(1,058)		(1,495)
Unrealized foreign exchange loss (gain)	1,687		(2,266)		(223)
Unrealized derivative instruments loss	1,910		—		3,374
Other loss	52		—		—
Funds flow from operations (non-GAAP)	$	55,344	$	74,307	$	44,129

Additional Operational Results


	Three Months Ended March 31,					Three Months Ended December 31,
(Thousands of U.S. Dollars)	2025		2024		% Change	2024
Oil, natural gas and NGL sales	$	170,533	$	157,577	8	$	147,290
Operating expenses	67,354		48,466		39	60,770
Transportation expenses	6,911		4,584		51	4,279
Operating netback(1)	96,268		104,527		(8)	82,241

DD&A expenses	72,202		56,150		29	63,406

Derivative instruments loss	1,467		—		100	2,271
G&A expenses before stock-based compensation	12,143		10,782		13	10,191
G&A stock-based compensation (recovery) expense	(517)		3,361		(115)	3,331

Foreign exchange loss (gain)	3,838		(815)		571	(496)
Other loss	52		—		100	(1,478)
Interest expense	23,235		18,424		26	23,752
Transaction costs	—		—		—	4,448
	112,420		87,902		28	105,425

Interest income	425		692		(39)	1,273

Income (loss) before income taxes	(15,727)		17,317		(191)	(21,911)

Current income tax expense	8,265		3,916		111	7,855
Deferred income tax (recovery) expense	(4,712)		13,479		(135)	4,444
	3,553		17,395		(80)	12,299
Net loss	$	(19,280)	$	(78)	24,618	$	(34,210)

Sales Volumes (NAR)


Total sales volumes, BOEPD	39,024		26,080		50	32,970

Brent Price per bbl	$	74.98	$	81.76	(8)	$	74.01
WTI Price per bbl	$	71.47	$	77.01	(7)	$	70.42
AECO Price C$ per GJ	2.05		—		—	1.56

Consolidated Results of Operations per boe Sales Volumes NAR
Oil, natural gas and NGL sales	$	48.55	$	66.40	(27)	$	48.56
Operating expenses	19.18		20.42		(6)	20.03
Transportation expenses	1.97		1.93		2	1.41
Operating netback(1)	27.40		44.05		(38)	27.12

DD&A expenses	20.56		23.66		(13)	20.90

Derivative instruments loss	0.42		—		100	0.75
G&A expenses before stock-based compensation	3.46		4.54		(24)	3.36
G&A stock-based compensation (recovery) expense	(0.15)		1.42		(111)	1.10


Foreign exchange loss (gain)	1.09		(0.34)		421	(0.16)
Other loss	0.01		—		100	(0.49)
Interest expense	6.62		7.76		(15)	7.83
Transaction costs	—		—		—	1.47
	32.01		37.05		(14)	34.76

Interest income	0.12		0.29		(58)	0.42

Income (loss) before income taxes	(4.49)		7.29		(162)	(7.22)

Current income tax expense	2.35		1.65		43	2.59
Deferred income tax (recovery) expense	(1.34)		5.68		(124)	1.47
	1.01		7.33		(86)	4.05
Net loss	$	(5.50)	$	(0.04)	13,650	$	(11.27)

(1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition of this measure.

Oil, Natural Gas and NGL Production and Sales Volumes, BOEPD


	Three Months Ended March 31,				Three Months Ended December 31,
Average Daily Volumes (BOEPD) - Colombia	2025		2024		2024
WI production before royalties	25,652		31,026		25,990
Royalties	(4,420)		(5,941)		(4,548)
Production NAR	21,232		25,085		21,442
(Increase) decrease in inventory	(379)		(51)		245
Sales	20,853		25,034		21,687

Royalties, % of working interest production before royalties	17	%	19	%	17	%

	Three Months Ended March 31,				Three Months Ended December 31,
Average Daily Volumes (BOEPD) - Ecuador	2025		2024		2024
WI production before royalties	4,034		1,216		3,705
Royalties	(1,424)		(456)		(1,213)
Production NAR	2,610		760		2,492
Decrease (increase) in inventory	840		286		(957)
Sales	3,450		1,046		1,535

Royalties, % of working interest production before royalties	35	%	38	%	33	%

	Three Months Ended March 31,				Three Months Ended December 31,
Average Daily Volumes (BOEPD) - Canada	2025		2024		2024
WI production before royalties	16,961		—		11,314
Royalties	(2,240)		—		(1,566)
Production NAR	14,721		—		9,748
Sales	14,721		—		9,748

Royalties, % of working interest production before royalties	13	%	—	%	14	%

	Three Months Ended March 31,				Three Months Ended December 31,
Average Daily Volumes (BOEPD) - Total Company	2025		2024		2024
WI production before royalties	46,647		32,242		41,009
Royalties	(8,084)		(6,397)		(7,327)
Production NAR	38,563		25,845		33,682
Decrease (increase) in inventory	461		235		(712)
Sales	39,024		26,080		32,970

Royalties, % of working interest production before royalties	17	%	20	%	18	%

Oil, natural gas and NGL production NAR for the three months ended March 31, 2025, increased by 49% to 38,563 BOEPD compared to the corresponding period of 2024 due to the production from the Canadian operations acquired on October 31, 2024 and positive exploration well drilling results in Ecuador. Oil, natural gas and NGL production NAR increased by 14% compared to the prior quarter as a result of the full three months of operations in Canada and the successful drilling in Ecuador.

Royalties as a percentage of production for the three months ended March 31, 2025 decreased 3% and 1% compared to the corresponding period of 2024 and the prior quarter respectively, commensurate with the decrease in benchmark oil prices and lower royalties for Canadian operations.

The Midas Block includes the Acordionero field, the Suroriente Block includes the Cohembi field, and the Chaza Block includes the Costayaco and Moqueta fields. Ecuador includes the Charapa, Chanangue and Iguana Blocks. Canada includes several areas in the Western Canadian Sedimentary Basin with all production in Alberta, Canada.

Commodity prices:

Colombia and Ecuador

Brent - For the three months ended March 31, 2025, Brent decreased 8% from the comparable period of 2024 and increased 1% from the prior quarter. For the three months ended March 31, 2025, Castilla, Vasconia and Oriente differentials per boe decreased to $5.34, $2.27 and $7.65 compared to $8.82, $5.05 and $8.02, respectively, in the corresponding period of 2024.

During the first quarter of 2025, 100% of sales from South America was priced against Brent.

Canada

Gran Tierra entered Canada with the acquisition of i3 Energy which closed on October 31, 2024, therefore no comparative data is provided for the corresponding period of 2024.

WTI - For the three months ended March 31, 2025, WTI increased 1% from the prior quarter. During the quarter, 21% of NAR production in Canada was oil, comparable with the prior quarter.

NGLs - For the three months ended March 31, 2025 the weighted average NGL price received was 18% of WTI compared to 11% percent of WTI in the prior quarter. During the quarter, 27% of production in Canada were NGLs, comparable with the prior quarter.

AECO - For the three months ended March 31, 2025, AECO price increased 31% from the prior quarter. During the quarter, 52% of production in Canada was natural gas, comparable with the prior quarter.

Oil, natural gas and NGL sales for the three months ended March 31, 2025, increased by 8% to $170.5 million compared to the corresponding period of 2024 due 50% increase in sales volumes and lower differentials offset by 8% decrease in Brent price and lower sales volumes in Colombia. The increase in sales volumes during the current quarter was due to sales from new Canadian operations and higher sales volumes in Ecuador as a result of successful drilling results.

Compared to the prior quarter, oil, natural gas and NGL sales increased by 16%, primarily due to a 1% increase in Brent price, lower differentials, and an 18% increase in sales volumes as a result of full three months of operations in Canada compared to two months in prior quarter and higher sales volumes in Ecuador due to new exploration wells coming on production.

The following table shows the effect of changes in realized price and sale volumes on our oil sales for the three months ended March 31, 2025, compared to the prior quarter and the corresponding periods of 2024:


(Thousands of U.S. Dollars)	Three Months Ended March 31, 2025, Compared with Three Months Ended December 31, 2024		Three Months Ended March 31, 2025, Compared with Three Months Ended March 31, 2024
Oil, natural gas and NGL sales for the comparative period	$	147,290	$	157,577
Realized sales price decrease effect	(16)		(6,555)
Sales volumes increase (decrease) effect	23,259		(12,351)
Oil, natural gas and NGL sales - Canada Operations	—		31,862
Oil, natural gas and NGL sales for the three months ended March 31, 2025	$	170,533	$	170,533

Operating Netback


Colombia	Three Months Ended March 31,				Three Months Ended December 31,
(Thousands of U.S. Dollars)	2025		2024		2024
Oil, natural gas and NGL sales	$	117,648	$	150,471	$	119,309
Transportation expenses	(3,211)		(4,226)		(3,110)
	114,437		146,245		116,199
Operating expenses	(42,754)		(45,126)		(46,613)
Operating netback(1)	$	71,683	$	101,119	$	69,586

(U.S. Dollars Per boe Sales Volumes NAR)
Brent	$	74.98	$	81.76	$	74.01
Quality and transportation discounts	(12.29)		(15.71)		(14.21)
Average realized price	62.69		66.05		59.80
Transportation expenses	(1.71)		(1.86)		(1.56)
Average realized price net of transportation expenses	60.98		64.19		58.24
Operating expenses	(22.78)		(19.81)		(23.36)
Operating netback(1)	$	38.20	$	44.38	$	34.88


Ecuador	Three Months Ended March 31,				Three Months Ended December 31,
(Thousands of U.S. Dollars)	2025		2024		2024
Oil, natural gas and NGL sales	$	21,023	$	7,106	$	9,026
Transportation expenses	(1,093)		(358)		(497)
	19,930		6,748		8,529
Operating expenses	(8,073)		(3,340)		(4,508)
Operating netback(1)	$	11,857	$	3,408	$	4,021

(U.S. Dollars Per boe Sales Volumes NAR)
Brent	$	74.98	$	81.76	$	74.01
Quality and transportation discounts	(7.27)		(7.11)		(10.08)
Average realized price	67.71		74.65		63.93
Transportation expenses	(3.52)		(3.76)		(3.52)
Average realized price net of transportation expenses	64.19		70.89		60.41
Operating expenses	(26.00)		(35.09)		(31.93)
Operating netback(1)	$	38.19	$	35.80	$	28.48


Canada	Three Months Ended March 31,				Three Months Ended December 31,
(Thousands of U.S. Dollars)	2025		2024		2024
Oil, natural gas and NGL sales	$	31,862	$	—	$	18,955
Transportation expenses	(2,607)		—		(672)
	29,255		—		18,283
Operating expenses	(16,527)		—		(9,649)
Operating netback(1)	$	12,728	$	—	$	8,634

(U.S. Dollars Per boe Sales Volumes NAR)
WTI Price per bbl	$	71.47	$	77.01	$	70.42
AECO Price C$ per GJ	2.05		—		1.56

Average realized price	24.05		—		21.14
Transportation expenses	(1.97)		—		(0.75)
Average realized price net of transportation expenses	22.08		—		20.39
Operating expenses	(12.47)		—		(10.76)
Operating netback(1)	$	9.61	$	—	$	9.63


Total Company	Three Months Ended March 31,				Three Months Ended December 31,
(Thousands of U.S. Dollars)	2025		2024		2024
Oil, natural gas and NGL sales	$	170,533	$	157,577	$	147,290
Transportation expenses	(6,911)		(4,584)		(4,279)
	163,622		152,993		143,011
Operating expenses	(67,354)		(48,466)		(60,770)
Operating netback(1)	$	96,268	$	104,527	$	82,241

(U.S. Dollars Per boe Sales Volumes NAR)


Average realized price	48.55		66.40		48.56
Transportation expenses	(1.97)		(1.93)		(1.41)
Average realized price net of transportation expenses	46.58		64.47		47.15
Operating expenses	(19.18)		(20.42)		(20.03)
Operating netback(1)	$	27.40	$	44.05	$	27.12

Operating expenses for the three months ended March 31, 2025, increased by 39% to $67.4 million compared to the corresponding period of 2024 due to new Canadian operations and ramp-up of operations in Ecuador. On a per boe basis, operating expenses decreased by $1.24 to $19.18 compared to the corresponding period of 2024, primarily due to $2.76 per boe lower workover activities which were partially offset by $1.52 per boe higher lifting costs associated with Canadian operations.

Compared to the prior quarter, operating expenses increased by 11% from $60.8 million due to the full three months of new Canadian operations compared to two months in prior quarter, and decreased on a per boe basis by $0.85 from $20.03 primarily due to lower lifting costs associated with lower road maintenance costs in Colombia.

Transportation expenses

We have options to sell our oil through multiple pipelines and various trucking routes. Each option has varying effects on realized sales price and transportation expenses. The following table shows the percentage of oil, natural gas and NGL volumes we sold in Canada, Colombia and Ecuador using each option for the three months ended March 31, 2025 and 2024, and the prior quarter:


	Three Months Ended March 31,				Three Months Ended December 31,
	2025		2024		2024
Volume transported through pipeline	46	%	4	%	34	%
Volume sold at wellhead	25	%	52	%	32	%
Volume transported via truck to sales point	29	%	44	%	34	%
	100	%	100	%	100	%

Volumes transported through pipeline or via truck receive a higher realized price but incur higher transportation expenses. Conversely, volumes sold at the wellhead have the opposite effect of a lower realized price, offset by lower transportation expenses.

Transportation expenses for the three months ended March 31, 2025, increased by 51% to $6.9 million or $0.04 to $1.97 per boe, compared to the corresponding period of 2024, due to new Canadian operations and higher sales volumes transported in Ecuador during the current quarter.

Transportation expenses increased by 62% or $0.56 per boe from $4.3 million or $1.41 per boe in the prior quarter due to the higher sales volumes transported in Ecuador during the current quarter and the three full months of Canadian operations compared to two months in prior quarter.

DD&A Expenses


	Three Months Ended March 31,				Three Months Ended December 31,
	2025		2024		2024
DD&A Expenses, thousands of U.S. Dollars	$	72,202	$	56,150	$	63,406
DD&A Expenses, U.S. Dollars per boe	20.56		23.66		20.90


	Three Months Ended March 31, 2025				Three Months Ended March 31, 2024			Three Months Ended December 31, 2024
	DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per Boe			DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per Boe		DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per Boe
Colombia	$	48,651	$	25.92		$	53,162	$	23.34	$	51,109	$	25.62
Ecuador	10,498		33.81			2,937		30.86		3,266		23.13
Canada	12,941		9.77			—		—		8,941		9.97
Corporate	112		—			51		—		91		—
	$	72,202	$	20.56		$	56,150	$	23.66	$	63,407	$	20.90

DD&A expenses for the three months ended March 31, 2025, increased by 29% due to higher costs in the depletable base for Ecuador and new Canadian operations, compared to the corresponding period of 2024. On a per boe basis, DD&A expenses decreased by $3.10 due to higher sales volumes during the current quarter.

DD&A expenses increased by 14% from $63.4 million when compared to the prior quarter due to higher costs in the depletable base. On a per boe bases were comparable to prior quarter. On a per boe basis, DD&A expenses decreased by $0.34 due to higher sales volumes during the current quarter.

G&A Expenses


	Three Months Ended March 31,					Three Months Ended December 31,
(Thousands of U.S. Dollars)	2025		2024		% Change	2024
G&A Expenses before Stock-Based Compensation	$	12,143	$	10,782	13	$	10,191
G&A Stock-Based Compensation (Recovery) Expense	(517)		3,361		(115)	3,331
G&A Expenses, including Stock-Based Compensation	$	11,626	$	14,143	(18)	$	13,522
(U.S. Dollars Per boe Sales Volumes NAR)
G&A Expenses before Stock-Based Compensation	$	3.46	$	4.54	(24)	$	3.36
G&A Stock-Based Compensation (Recovery) Expense	(0.15)		1.42		(111)	1.10
G&A Expenses, including Stock-Based Compensation	$	3.31	$	5.96	(44)	$	4.46

G&A expenses before stock-based compensation for the three months ended March 31, 2025, increased by 13% compared to the corresponding period of 2024, primarily due to addition of Canadian operations. On per boe basis, G&A expenses before stock-based compensation decreased by $1.08 due to higher sales volumes in the current quarter.

Compared to the prior quarter, G&A expenses before stock-based compensation increased by 19% or $0.10 per boe due to the three full months of operations in Canada during the current quarter compared to two months in the prior quarter.

G&A expenses after stock-based compensation for the three months ended March 31, 2025, decreased by 18% or $2.65 per boe, compared to the corresponding period of 2024, due to stock-based compensation recovery attributed to a lower share price during the current quarter.

Compared to the prior quarter, G&A expenses after stock-based compensation decreased by 14% or $1.15 per bbl for the same reason mentioned above.

Foreign Exchange Gains and Losses

For the three months ended March 31, 2025, we had a $3.8 million loss on foreign exchange compared to a $0.8 million gain on foreign exchange in the corresponding period of 2024, and a $0.5 million gain on foreign exchange in the prior quarter. Accounts payable, taxes receivable and payable and deferred income taxes are considered monetary items and require translation from local currencies to U.S. dollar functional currency at each balance sheet date. This translation was the primary source of the foreign exchange gains and losses in the periods.

The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
	2025	2024
Change in the U.S. dollar against the Colombian peso	weakened by	strengthened by
	5%	1%
Change in the U.S. dollar against the Canadian dollar	weakened by	strengthened by
	—%	2%

Income Tax Expense


	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2025			2024
Income before income tax	$	(15,727)		$	17,317

Current income tax expense	$	8,265		$	3,916
Deferred income tax (recovery) expense	(4,712)			13,479
Income tax expense	$	3,553		$	17,395

Effective tax rate	(23)		%	100		%

The deferred income tax for the three months ended March 31, 2025, was a recovery of $4.7 million mainly due to the use of a higher enacted tax rate on Colombia tax losses. These were partially offset by higher tax depreciation relative to accounting depreciation.

The deferred income tax expense for the three months ended March 31, 2024, was $13.5 million, primarily as a result of tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia.

For the three months ended March 31, 2024, the difference between the effective tax rate of 100% and the 45% Colombian tax rate was primarily due to an increase in the impact of foreign taxes, increase in the valuation allowance, non-deductible stock-based compensation and other permanent differences.

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


(Thousands of U.S. Dollars)	Three Months Ended March 31, 2025, Compared with Three Months Ended December 31, 2024		% change	Three Months Ended March 31, 2025, Compared with Three Months Ended March 31, 2024		% change
Net loss for the comparative period	$	(34,210)		$	(78)
Increase (decrease) due to:
Sales price	(16)			(6,555)
Sales volumes	23,259			(12,351)
Oil, natural gas and NGL sales - Canada Operations	—			31,862
Expenses:
Operating	(6,584)			(18,888)
Transportation	(2,632)			(2,327)
Cash G&A	(1,952)			(1,361)
Net lease payments	(95)			(186)

Interest, excluding amortization of deferred financing fees	607			(4,284)
Realized foreign exchange	(2,424)			(700)
Other gain	(1,478)			—
Cash settlement on derivative instruments	(660)			443
Transaction costs	4,448			—
Current taxes	(410)			(4,349)
Interest income	(848)			(267)
Net change in funds flow from operations(1) from comparative period	11,215			(18,963)
Expenses:
Depletion, depreciation and accretion	(8,796)			(16,052)
Inventory impairment	—			—
Deferred tax	9,156			18,191
Amortization of deferred financing fees	(90)			(527)
Stock-based compensation	3,848			3,878
Derivative instruments gain or loss, net of settlements on derivative instruments	1,464			(1,910)
Unrealized foreign exchange	(1,910)			(3,953)
Other loss	(52)			(52)
Net lease payments	95			186
Net change in net loss	14,930			(19,202)
Net loss for the current period	$	(19,280)	44%	$	(19,280)	(24,618)%

(1) Funds flow from operations is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Non-GAAP measures” in "Financial and Operational Highlights" for a definition and reconciliation of this measure.

Capital expenditures during the three months ended March 31, 2025, were $94.7 million.


(Millions of U.S. Dollars)	Colombia		Ecuador		Canada		Total
Exploration:
Drilling and Completions	$	—	$	14.8	$	—	$	14.8
Civil Works	3.7		0.3		—		4.0
Other	4.0		9.2		—		13.2
Total Exploration	$	7.7	$	24.3			$	32.0
Development:
Drilling and Completions	$	11.2	$	—	$	19.5	$	30.7
Facilities	10.6		—		—		10.6
Civil Works	1.8		—		9.1		10.9
Other	9.8		—		0.7		10.5
Total Development	$	33.4	$	—	$	29.3	$	62.7
Total Company	$	41.1	$	24.3	$	29.3	$	94.7

During the three months ended March 31, 2025, we drilled the following wells:


	Number of wells (Gross)	Number of wells (Net)



Exploration - Ecuador	2	2
Development - Colombia	3	3
Development - Canada	2	0.7
Service - Canada	1	0.3
Total Company	8	6.0

During the three months ended March 31, 2025, we spud two exploration wells in Ecuador, of which one was producing as at March 31, 2025. We spud three development wells in Colombia, two development wells and one service well in Canada and they were all in-progress as of March 31, 2025.

Liquidity and Capital Resources


	As at
(Thousands of U.S. Dollars)	March 31, 2025		% Change	December 31, 2024
Cash and Cash Equivalents	$	76,566	(26)	$	103,379





6.25% Senior Notes due 2025	$	—	(100)	$	24,828

7.75% Senior Notes due 2027	$	24,201	—	$	24,201

9.50% Senior Notes due 2029	$	735,790	—	$	737,590

We believe that our capital resources, including cash on hand, cash generated from operations and available borrowings under our credit facilities, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for the next 12 months, given the current oil price trends and production levels. We may also access capital markets to pursue financing, including for the re-purchase of common stock or the repayment of debt in the future. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings

and short-term liquidity. We believe that our current financial position provides us with the flexibility to respond to both internal growth opportunities and those available through acquisitions. We intend to pursue growth opportunities and acquisitions from time to time, which may require significant capital to be located in basins or countries beyond our current operations, involve joint ventures, or be sizable compared to our current assets and operations.

In connection with the i3 Energy acquisition closing on October 31, 2024, we amended and restated the existing revolving credit facility agreement of i3 Energy Canada Ltd. with National Bank of Canada dated March 22, 2024. As a result of the amendment and restatement, among other things, the borrowing base was revised to C$100.0 million (US$69.5 million) with available commitment of a C$50.0 million (US$34.8 million) revolving credit facility comprised of C$35.0 million (US$24.3 million) syndicated facility and C$15.0 million (US$10.4 million) of operating facility. Subject to the next borrowing base redetermination which will occur on or before June 30, 2025, the revolving credit facility is available until October 31, 2025 with a repayment date of October 31, 2026, which may be extended by further periods of up to 364 days, subject to lender approval. The drawn down amounts under the revolving credit facility can either be in Canadian or U.S. dollars and bear interest rates equal to either the Canadian prime rate or U.S. Base Rate plus a margin ranging from 2.00% to 4.00% per annum or for CORRA loans and SOFR loans plus a margin ranging from 3.00% to 5.00% per annum. Undrawn amounts under the revolving credit facility bear standby fee ranging from 0.75% to 1.25% per annum. In each case, the margin or standby fee, as applicable is based on Net Debt to EBITDA ratio of Gran Tierra Canada Ltd. As of March 31, 2025, the credit facility remained undrawn.

Subsequent to March 31, 2025, we, through its wholly owned subsidiary, Gran Tierra Energy Colombia GmbH, a Swiss limited liability company, entered into a US$75 million reserve-based lending facility. Any loans incurred under the new facility will mature on April 16, 2028 and will bear interest at a rate per annum equal to, at our option, either (a) a customary base rate (subject to a floor of 1.00%) plus an applicable margin of 4.50% or (b) a term SOFR reference rate plus an applicable margin of 4.50%. Interest on base rate borrowings is payable quarterly in arrears and interest on term SOFR borrowings accrues in respect of interest periods of three or six months, at the election of the Company, and is payable on the last day of such interest period.

At March 31, 2025, we had $24.2 million aggregate principal amount of 7.75% Senior Notes due 2027, and $735.8 million aggregate principal amount of 9.50% Senior Notes due 2029, outstanding.

During the three months ended March 31, 2025, we paid at maturity the remaining principal of $24.8 million of 6.25% Senior Notes due in February 2025 for cash consideration of $25.6 million, including interest payable of $0.8 million.

During the three months ended March 31, 2025, we re-purchased 453,050 shares under the 2024 Program at a weighted average price of $5.33 per share (three months ended March 31, 2024 - 886,666 shares under the 2023 program at a weighted average price of $5.58). Under the 2024 Program, we were able to re-purchase at prevailing market prices up to 3,545,872 shares of Common Stock, representing approximately 10% of the public float as of October 31, 2024. We cancelled 487,948 held as treasury shares as at December 31, 2024 and cancelled 443,050 shares re-purchased during the three months ended March 31, 2025, respectively. During the period from November 6, 2024 to April 29, 2025, we have re-purchased 1,140,752 shares under the 2024 Program.

Cash Flows

The following table presents our primary sources and uses of cash and cash equivalents and restricted cash and cash equivalents for the periods presented:


	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2025		2024
Sources of cash and cash equivalents:
Net loss	$	(19,280)	$	(78)
Adjustments to reconcile net loss to Adjusted EBITDA(1) and funds flow from operations(1)
DD&A expenses	72,202		56,150
Cash settlement on derivative instruments	443		—
Interest expense	23,235		18,424
Income tax expense	3,553		17,395
Non-cash lease expenses	1,736		1,413
Lease payments	(1,567)		(1,058)
Foreign exchange (gain) loss	3,838		(815)
Stock-based compensation (recovery) expense	(517)		3,361
Financial instruments loss	1,467		—

Other loss	52		—
Adjusted EBITDA(1)	85,162		94,792
Current income tax expense	(8,265)		(3,916)
Contractual interest and other financing expenses	(19,402)		(15,118)


Realized foreign exchange loss	(2,151)		(1,451)
Funds flow from operations(1)	55,344		74,307
Proceeds from issuance of Senior Notes, net of issuance costs	—		85,638
Proceeds from exercise of stock options	—		161

Foreign exchange gain on cash and cash equivalents and restricted cash and cash equivalents	38		—
Net changes in assets and liabilities from operating activities	19,693		—

	75,075		160,106

Uses of cash and cash equivalents:
Additions to property, plant and equipment	(67,504)		(38,800)
Net changes in assets and liabilities from operating activities	—		(13,297)

Purchase of Senior Notes	(1,712)		—

Repayment of debt	(24,828)		(36,364)
Re-purchase of shares of Common Stock	(2,415)		(4,948)
Settlement of asset retirement obligations	(1,807)		(183)
Lease payments	(2,253)		(1,972)
Foreign exchange loss on cash, and cash equivalents and restricted cash and cash equivalents	—		(42)
	(100,519)		(95,606)
Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents	$	(25,444)	$	64,500

(1) Adjusted EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Refer to note 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition and reconciliation of this measure.

One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices. Sales volume changes, costs related to operations and debt transactions also impact cash flows. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes. During the three months ended March 31, 2025, funds flow from operations decreased by 26% compared to the corresponding period of 2024, due to a decrease in Brent price, higher operating

expenses, higher interest expense and higher current income tax expense partially offset by lower quality and transportation discounts and higher sales volumes.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Item 7 of our 2024 Annual Report on Form 10-K and have not changed materially since the filing of that document.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity price risk

Our principal market risk relates to oil, natural gas and NGL prices which are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Our revenues are from oil sales at Brent or Edmonton Light pricing and for gas at AECO pricing and adjusted for quality.

Foreign currency risk

Foreign currency risk is a factor for our Company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. Our reporting currency is U.S. dollars and 81% of our revenues are related to the U.S. dollar price of Brent with the remainder related to Canadian dollar price of WTI oil or AECO gas. In Colombia and Ecuador, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures is in U.S. dollars or is based on U.S. dollar prices. The majority of income and value added taxes and G&A expenses in all locations are in local currency. In Canada, we receive 100% of our revenue in Canadian dollar and majority of our capital and operating expenditures are in Canadian dollars or are based on Canadian dollar prices.

Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our accounts payable, taxes receivable and payable and deferred tax assets and liabilities in Colombia are denominated in the local currency of the Colombian foreign operations which are our monetary assets. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar reporting currency.

Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to

interest rate fluctuations on our revolving credit facility, which bears floating rates of interest. As of March 31, 2025 the revolving credit facility remained undrawn.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule l3a-15(b) of the Exchange Act. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra’s disclosure controls and procedures were effective as of March 31, 2025.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended March 31, 2025, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II - Other Information

Item 1. Legal Proceedings

See Note 11 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference, for any material developments with respect to matters previously reported in our Annual Report on Form 10-K for the year ended December 31, 2024, and any material matters that have arisen since the filing of such report.

Item 1A. Risk Factors

There are numerous factors that affect our business and results of operations, many of which are beyond our control. In addition to information set forth in this Quarterly Report on Form 10-Q, including in Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, you should carefully read and consider the factors set out in Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2024. These risk factors could materially affect our business, financial condition and results of operations. The unprecedented nature of ongoing conflicts in several parts of the world, along with volatility in the worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities


	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share (1)		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs (2)
January 1-31, 2025	83,420	$	7.65	83,420	2,974,504
February 1-28, 2025	—	—		—	2,974,504
March 1-31, 2025	369,630	$	5.21	369,630	2,604,874
Total	453,050	$	5.66	453,050	2,604,874

(1) Including commission fees paid to the broker to re-purchase the shares of Common Stock.

(2) On October 31, 2024, we implemented a share re-purchase program (the “2024 Program”) through the facilities of the TSX, the NYSE American or alternative programs in Canada or the United States. Under the 2024 Program, the Company is able to purchase at prevailing market prices up to 3,545,872 shares of Common Stock, representing approximately 10% of the public float as of October 31, 2024. The 2024 Program will expire on November 5, 2025.

Item 5. Other Information

During the three months ended March 31, 2025, no director or Section 16 officer adopted or terminated any Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements (in each case, as defined in Item 408(a) of Regulation S-K).

Item 6. Exhibits


Exhibit No.	Description	Reference
3.1	Certificate of Incorporation.	Incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).

3.2	Certificate of Amendment to Certificate of Incorporation of Gran Tierra Energy Inc., effective May 5, 2023	Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, filed with the SEC on May 5, 2023 (SEC File No. 001-34018).

3.3	Bylaws of Gran Tierra Energy Inc.	Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).

3.4	Amendment No.1 to Bylaws of Gran Tierra Energy Inc.	Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the SEC on August 4, 2021 (SEC File No. 001-34018).

31.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith.

31.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith.

32.1	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith.

101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH Inline XBRL Taxonomy Extension Schema Document

101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document

104.The cover page from Gran Tierra Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2025, formatted in Inline XBRL (included within the Exhibit 101 attachments).

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

GRAN TIERRA ENERGY INC.


Date: May 1, 2025						/s/ Gary S. Guidry
						By: Gary S. Guidry
						President and Chief Executive Officer
						(Principal Executive Officer)


Date: May 1, 2025						/s/ Ryan Ellson
						By: Ryan Ellson
						Executive Vice President and Chief Financial Officer
						(Principal Financial and Accounting Officer)