10-Q

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 June 30, 2026

or

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

 For the transition period from __________ to __________

Commission file number 001-34018

GRAN TIERRA ENERGY INC.

(Exact name of registrant as specified in its charter)

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

(403) 265-3221

(Registrant’s telephone number, including area code)

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

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

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 July 31, 2026, 35,380,429 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 June 30, 2026

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	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	53
Item 4.	Controls and Procedures	54
PART II	Other Information
Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	55
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	55
Item 5.	Other information	55
Item 6.	Exhibits	56
SIGNATURES		57

1

 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, certain of our operations are located in South America and the Company is pursuing activities in other international jurisdictions, including Azerbaijan, 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, global health crises, geopolitical events, including the ongoing conflicts in Ukraine, the Middle East and Venezuela, 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; such as the expected effectiveness of the exploration and development production sharing agreement (“EDPSA”) in Azerbaijan and the timing and execution of the related exploration program; 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 2025 Annual Report on Form 10-K (the “2025 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”.

2

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 June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
OIL, NATURAL GAS AND NGL SALES (Note 9)	$	187,181	$	149,357	$	359,238	$	317,530
EXPENSES
Operating	51,561		55,602		117,710		122,692
Transportation	3,907		4,494		9,210		9,045
Other taxes	1,389		577		2,430		1,058
Depletion, depreciation and accretion (Note 5)	62,334		68,635		132,208		140,837
General and administrative	9,462		14,682		44,287		26,091
Severance	95		—		2,563		—
Foreign exchange loss	2,603		3,716		4,028		7,554
Derivative instruments (gain) loss (Note 12)	(11,864)		(14,032)		76,546		(12,565)
Interest expense (Note 6)	24,473		24,366		74,351		47,601
	143,960		158,040		463,333		342,313
INTEREST INCOME	503		251		904		676
OTHER INCOME (Note 6)	1,625		339		2,773		287
INCOME (LOSS) BEFORE INCOME TAXES	45,349		(8,093)		(100,418)		(23,820)
INCOME TAX EXPENSE (RECOVERY)
Current (Note 10)	9,115		2,195		14,965		10,460
Deferred (Note 10)	11,373		2,453		(21,072)		(2,259)
	20,488		4,648		(6,107)		8,201
NET INCOME (LOSS)	$	24,861	$	(12,741)	$	(94,311)	$	(32,021)
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation adjustment	(1,864)		9,583		(2,949)		9,774
COMPREHENSIVE INCOME (LOSS)	$	22,997	$	(3,158)	$	(97,260)	$	(22,247)
NET INCOME (LOSS) PER SHARE
- BASIC and DILUTED	$	0.70	$	(0.36)	$	(2.67)	$	(0.90)
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC and DILUTED (Note 8)	35,368,716		35,334,692		35,334,469		35,554,806

(See notes to the condensed consolidated financial statements)

3

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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

	As at June 30, 2026		As at December 31, 2025
ASSETS
Current Assets
Cash and cash equivalents (Note 13)	$	126,728	$	82,931
Accounts receivable	32,838		32,908
Inventory	48,425		55,384
Taxes receivable (Note 4)	15,038		27,113
Derivatives (Note 12)	3,077		10,147
Prepaid expenses	12,856		5,044
Total Current Assets	238,962		213,527
Oil and Gas Properties
Proved	1,073,792		1,154,836
Unproved	108,769		108,339
Total Oil and Gas Properties	1,182,561		1,263,175
Other capital assets	54,381		41,245
Total Property, Plant and Equipment (Note 5)	1,236,942		1,304,420
Other Long-Term Assets
Deferred tax assets	66,640		56,268
Taxes receivable long-term (Note 4)	10,227		1,912
Other long-term assets (Note 12 and 13)	11,324		9,952
Total Other Long-Term Assets	88,191		68,132
Total Assets	$	1,564,095	$	1,586,079
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable, accrued liabilities and other (Note 6 and 7)	$	383,814	$	314,005
Current portion of long-term debt (Note 6 and 12)	45,717		21,212
Taxes payable (Note 4)	15,109		11,906
Derivatives (Note 12)	30,693		—
Equity compensation award liability (Note 8)	17,991		8,569
Total Current Liabilities	493,324		355,692
Long-Term Liabilities
Long-term debt (Note 6 and 12)	551,812		686,521
Customer advance (Note 7)	201,409		115,909
Deferred tax liabilities	40,740		53,458
Asset retirement obligation	113,527		118,876
Equity compensation award liability (Note 8)	17,032		14,993
Other long-term liabilities (Note 4)	14,019		11,886
Total Long-Term Liabilities	938,539		1,001,643
Contingencies (Note 11)
Shareholders' Equity
Common Stock (35,380,429 and 35,298,774 issued and outstanding shares of Common Stock as at June 30, 2026 and December 31, 2025, respectively, par value $0.001 per share), (Note 8)	9,939		9,939
Additional paid-in capital	1,269,926		1,269,178
Accumulated other comprehensive (loss) gain	(389)		2,560
Deficit	(1,147,244)		(1,052,933)
Total Shareholders’ Equity	132,232		228,744
Total Liabilities and Shareholders’ Equity	$	1,564,095	$	1,586,079

(See notes to the condensed consolidated financial statements)

4

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)

	Six Months Ended June 30,
	2026		2025
Operating Activities
Net loss	$	(94,311)	$	(32,021)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 5)	132,208		140,837
Deferred tax recovery (Note 10)	(21,072)		(2,259)
Stock-based compensation expense (Note 8)	15,919		29
Amortization of debt issuance costs (Note 6)	13,015		7,915
Unrealized foreign exchange loss	2,663		4,801
(Gain) loss on bond repurchases and exchange (Note 6)	(728)		90
Unrealized derivative instruments loss (gain) (Note 12)	31,432		(10,491)
Cash settlement of asset retirement obligation	(1,510)		(3,045)
Non-cash lease expenses	2,971		3,461
Non-cash interest expense	10,647		—
Lease payments	(3,320)		(3,112)
Net change in assets and liabilities from operating activities (Note 13)	142,234		1,702
Net cash provided by operating activities	230,148		107,907
Investing Activities
Additions to property, plant and equipment (Note 5 and 13)	(102,517)		(153,971)
Proceeds on disposition of property, plant and equipment (Note 5)	57,944		—
Proceeds from assets exchange (Note 5)	583		—
Net cash used in investing activities	(43,990)		(153,971)
Financing Activities
Proceeds from long-term debt, net of issuance costs	—		44,781
Repayment of long-term debt	—		(1,894)
Re-purchase of Senior Notes (Note 6)	(8,087)		(1,712)
Repayment of Senior Notes (Note 6)	(125,000)		(24,828)
Re-purchase of shares of Common Stock (Note 8)	—		(3,466)
Proceeds from exercise of stock options	748		22
Lease payments	(8,347)		(7,849)
Net cash (used in) provided by financing activities	(140,686)		5,054
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(297)		(766)
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	45,175		(41,776)
Cash and cash equivalents and restricted cash and cash equivalents, beginning of period (Note 13)	92,666		111,337
Cash and cash equivalents and restricted cash and cash equivalents, end of period (Note 13)	$	137,841	$	69,561
Supplemental cash flow disclosures (Note 13)

(See notes to the condensed consolidated financial statements)

5

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)

	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
Share Capital
Balance, beginning of period	$	9,939	$	9,939	$	9,939	$	9,940
Cancellation of shares of Common Stock (Note 8)	—		—		—		(1)
Balance, end of period	$	9,939	$	9,939	$	9,939	$	9,939
Additional Paid-in Capital
Balance, beginning of period	$	1,269,611	$	1,269,557	$	1,269,178	$	1,273,343
Exercise of stock options	315		22		748		22
Stock-based compensation (Note 8)	—		175		—		1,918
Cancellation of shares of Common Stock  (Note 8)	—		(1,100)		—		(6,629)
Balance, end of period	$	1,269,926	$	1,268,654	$	1,269,926	$	1,268,654
Treasury Stock
Balance, beginning of period	$	—	$	(49)	$	—	$	(3,165)
Re-purchase of shares of Common Stock (Note 8)	—		(1,051)		—		(3,465)
Cancellation of shares of Common Stock (Note 8)	—		1,100		—		6,630
Balance, end of period	$	—	$	—	$	—	$	—
Accumulated other comprehensive income (loss)
Balance, beginning of period	$	1,475	$	(6,545)	$	2,560	$	(6,736)
Other comprehensive (loss) income	(1,864)		9,583		(2,949)		9,774
Balance, end of period	$	(389)	$	3,038	$	(389)	$	3,038
Deficit
Balance, beginning of period	$	(1,172,105)	$	(879,094)	$	(1,052,933)	$	(859,814)
Net income (loss)	24,861		(12,741)		(94,311)		(32,021)
Balance, end of period	$	(1,147,244)	$	(891,835)	$	(1,147,244)	$	(891,835)
Total Shareholders’ Equity	$	132,232	$	389,796	$	132,232	$	389,796

(See notes to the condensed consolidated financial statements)

6

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, 2025, included in the Company’s 2025 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 2025 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 July 2025, FASB issued ASU 2025-05 “Financial Instruments—Credit Losses: Amendments to the Measurement of Credit Losses on Certain Financial Assets”. This ASU provides a practical expedient for estimating expected credit losses on certain short-term receivables and contract assets arising from revenue transactions within the scope of ASC 606. Under the practical expedient, all entities may elect to assume that current conditions as of the balance sheet date would not change for the remaining life of the asset when developing reasonable and supportable forecasts. The ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2025, early adoption is permitted for both interim and annual reporting periods. The Company adopted this ASU effective January 1, 2026. The implementation of this update did not have a material impact on its balance sheet, statement of operations or financial statements disclosures.

Recently Issued Accounting Pronouncements

In May 2026, the FASB issued ASU 2026-02, Environmental Credits and Environmental Credit Obligations, which establishes guidance on the recognition, measurement, and disclosure of environmental credits and related obligations. The ASU requires entities to recognize qualifying environmental credits as assets measured at cost and to record environmental credit obligations as emissions occur, measured based on the carrying amount of credits held and the fair value of any additional credits required for settlement. The ASU is effective for annual reporting periods beginning after December 15, 2027, including interim periods within those years, with early adoption permitted. The Company is currently assessing the impact this update will have on its financial statements.

3. 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 Operating 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.

7

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

	Three Months Ended June 30, 2026
(Thousands of U.S. Dollars)	Colombia		Ecuador		Canada		Other		Total
Oil, natural gas and NGL sales	$	118,136	$	41,964	$	27,081	$	—	$	187,181
Operating expenses	33,152		6,196		12,213		—		51,561
Transportation expenses	2,327		1,182		398		—		3,907
Segmented earnings	$	82,657	$	34,586	$	14,470	$	—	$	131,713
Other taxes									1,389
Depletion, depreciation and accretion (“DD&A”) expenses									62,334
General and administrative expenses									9,462
Severance									95
Foreign exchange loss									2,603
Derivative instruments gain									(11,864)
Interest expense									24,473
Non-segmented expenses									88,492
Other income									1,625
Interest income									503
Income before income taxes									45,349
Income tax expense									20,488
Net income									$	24,861
Segment capital expenditures	$	49,886	$	4,206	$	6,885	$	—	$	60,977

	Six Months Ended June 30, 2026
(Thousands of U.S. Dollars)	Colombia		Ecuador		Canada		Other		Total
Oil, natural gas and NGL sales	$	220,460	$	82,709	$	56,069	$	—	$	359,238
Operating expenses	68,194		22,148		27,368		—		117,710
Transportation expenses	4,599		3,736		875		—		9,210
Segmented earnings	$	147,667	$	56,825	$	27,826	$	—	$	232,318
Other taxes									2,430
Depletion, depreciation and accretion (“DD&A”) expenses									132,208
General and administrative expenses									44,287
Severance									2,563
Foreign exchange loss									4,028
Derivative instruments loss									76,546
Interest expense									74,351
Non-segmented expenses									336,413
Other income									2,773
Interest income									904
Loss before income taxes									(100,418)

8

Income tax recovery									(6,107)
Net loss									$	(94,311)
Segment capital expenditures	$	70,759	$	19,952	$	11,806	$	—	$	102,517

	Three Months Ended June 30, 2025
(Thousands of U.S. Dollars)	Colombia		Ecuador		Canada		Other		Total
Oil, natural gas and NGL sales	$	109,692	$	8,495	$	31,170	$	—	$	149,357
Operating expenses	38,180		4,122		13,300		—		55,602
Transportation expenses	3,735		441		318		—		4,494
Segmented earnings	$	67,777	$	3,932	$	17,552	$	—	$	89,261
Other taxes									577
Depletion, depreciation and accretion (“DD&A”) expenses									68,635
General and administrative expenses									14,682
Foreign exchange loss									3,716
Derivative instruments gain									(14,032)
Interest expense									24,366
Non-segmented expenses									97,944
Other income									339
Interest income									251
Loss before income taxes									(8,093)
Income tax expense									4,648
Net loss									$	(12,741)
Segment capital expenditures	$	37,749	$	24,800	$	23,871	$	47	$	86,467

	Six Months Ended June 30, 2025
(Thousands of U.S. Dollars)	Colombia		Ecuador		Canada		Other		Total
Oil, natural gas and NGL sales	$	227,340	$	29,518	$	60,672	$	—	$	317,530
Operating expenses	80,670		12,195		29,827		—		122,692
Transportation expenses	6,946		1,534		565		—		9,045
Segmented earnings	$	139,724	$	15,789	$	30,280	$	—	$	185,793
Other taxes									1,058
Depletion, depreciation and accretion (“DD&A”) expenses									140,837
General and administrative expenses									26,091
Foreign exchange loss									7,554
Derivative instruments gain									(12,565)
Interest expense									47,601
Non-segmented expenses									210,576
Other income									287

9

Interest income									676
Loss before income taxes									(23,820)
Income tax expense									8,201
Net loss									$	(32,021)
Segment capital expenditures	$	60,418	$	45,587	$	47,536	$	430	$	153,971

	As at June 30, 2026
(Thousands of U.S. Dollars)	Colombia		Ecuador		Canada		Other		Total
Property, plant and equipment	$	954,619	$	167,553	$	108,272	$	6,498	$	1,236,942
All other assets	164,168		83,069		42,518		37,398		327,153
Total Assets	$	1,118,787	$	250,622	$	150,790	$	43,896	$	1,564,095
	As at December 31, 2025
(Thousands of U.S. Dollars)	Colombia		Ecuador		Canada		Other		Total
Property, plant and equipment	$	935,351	$	176,003	$	185,226	$	7,840	$	1,304,420
All other assets	150,524		55,313		39,093		36,729		281,659
Total Assets	$	1,085,875	$	231,316	$	224,319	$	44,569	$	1,586,079

4. 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 June 30, 2026		As at December 31, 2025
Taxes Receivable
Current
VAT Receivable	$	1,153	$	1,394
Income Tax Receivable	13,885		25,719
	$	15,038	$	27,113
Long-Term
Income Tax Receivable	$	10,227	$	1,912
Taxes Payable
Current
VAT Payable	$	(4,709)	$	(5,189)
Income Tax Payable	(10,400)		(6,717)
	$	(15,109)	$	(11,906)
Long-Term
Income Tax Payable(1)	$	(2,062)	$	—
Total Net Taxes Receivable	$	8,094	$	17,119

(1) Included into other long-term liabilities on the Company’s condensed consolidated balance sheet.

10

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, 2025	$	(3,795)	$	20,914	$	17,119
Collected through direct government refunds	(49)		(15,746)		(15,795)
Collected through sales contracts	(51,817)		—		(51,817)
Taxes paid	52,069		7,995		60,064
Withholding taxes paid	688		12,889		13,577
Current tax expense	—		(14,965)		(14,965)
Foreign exchange (loss) gain	(652)		563		(89)
Balance, as at June 30, 2026	$	(3,556)	$	11,650	$	8,094

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

5. Property, Plant and Equipment

(Thousands of U.S. Dollars)	As at June 30, 2026		As at December 31, 2025
Oil and natural gas properties
Proved	$	5,613,178	$	5,587,422
Unproved	108,769		108,339
	5,721,947		5,695,761
Other (1)	105,948		78,780
	5,827,895		5,774,541
Accumulated depletion, depreciation and impairment	(4,590,953)		(4,470,121)
	$	1,236,942	$	1,304,420

(1) The “other” category includes right-of-use assets for operating and finance leases of $90.0 million, which had a net book value of $42.9 million as at June 30, 2026 (December 31, 2025 - $65.0 million, which had a net book value of $30.8 million).

During the three and six months ended June 30, 2026, the Company entered into three and four new finance leases related to power generation agreements in Ecuador and Colombia and recognized right-of-use assets of $5.3 million and $21.0 million, respectively, related to these agreements. During the six months ended June 30, 2026, the Company entered into one new operating office lease agreement in Colombia and recognized right-of-use asset of $4.0 million related to this agreement.

For the three and six months ended June 30, 2026 and 2025, 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 June 30, 2026 as follows: Brent Crude $78.55 per bbl, Edmonton Light Crude of C$98.28 per bbl, Alberta AECO spot price of C$1.55 per MMBtu, Edmonton Propane C$32.84 per boe, Edmonton Butane C$41.70 per boe and Edmonton Condensate C$100.06 per boe (June 30, 2025 as follows: Brent Crude of $73.60 per bbl, Edmonton Light Crude of C$91.55 per bbl, Alberta AECO spot price of C$1.69 per MMBtu, Edmonton Propane C$33.82 per boe, Edmonton Butane C$47.11 per boe and Edmonton Condensate C$95.75 per boe).

On June 30, 2026, the Company completed an asset exchange transaction in which it transferred a 30% working interest ("WI") in certain oil and natural gas rights, wells, and tangible assets located in the Marten Hills area, in exchange for oil and natural gas rights, wells, and tangible assets in the Seal/Dawson area, WI ranging from 35% to 100%. In connection with this transaction, the Company received cash consideration of C$0.8 million (US$0.6 million).

On June 23, 2026, the Company completed a disposition of 54% WI and associated title rights in the Lodgepole area in Canada effective January 1, 2026, for a total cash consideration of C$12.8 million (US$9.3 million). As part of disposition, the Company derecognized asset retirement obligation attributed to Lodgepole area totaling C$17.5 million (US$12.8 million) on an undiscounted basis and C$9.0 million (US$6.6 million) on a discounted basis. No gain or loss was recognized in the statement of operations as the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.

On March 10, 2026, the Company completed the disposition of the entire WI and associated title rights in the Simonette Montney area in Canada effective January 1, 2026, for total cash consideration of C$66.3 million (US$48.6 million). No gain

11

or loss was recognized in the statement of operations as the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.

On March 17, 2026, the Company entered into a strategic partnership with Ecopetrol S.A. to earn, subject to regulatory approvals and conditions precedent, a 49% WI in the Tisquirama Block in Colombia. Under the terms of the agreement, the Company has committed to fund approximately $47.1 million of a $92.4 million gross capital program over 40 months, including a minimum Phase 1 investment of $15.0 million. Upon completion of Phase 1, the Company will be entitled to 49% of production and is expected to assume operatorship. On May 27, 2026, the Company satisfied all outstanding conditions precedent to the partnership agreement and received regulatory approval.

6. Debt and Debt Issuance Costs

The Company’s debt as at June 30, 2026, and December 31, 2025, was as follows:

(Thousands of U.S. Dollars)	As at June 30, 2026		As at December 31, 2025
Current
7.75% Senior Notes	$	24,201	$	—
9.50% Senior Notes	21,910		21,910
Unamortized Senior Notes discount	(247)		(496)
Unamortized debt issuance costs	(147)		(202)
	$	45,717	$	21,212
Long-Term
7.75% Senior Notes, due May 2027 (“7.75% Senior Notes”)	$	—	$	24,201
9.50% Senior Notes, due October 2029 (“9.50% Senior Notes”)	65,729		694,430
9.75% Senior Notes, due April 2031 (“9.75% Senior Notes”)	494,353		—
Unamortized Senior Notes discount	(21,343)		(29,365)
Unamortized debt issuance costs (1)	(9,233)		(14,458)
	529,506		674,808
Long-term lease obligation (2)	22,306		11,713
	$	551,812	$	686,521
Total Debt	$	597,529	$	707,733

(1) Includes $0.1 million of deferred financing fees related to Canadian revolving credit facility as at June 30, 2026 (December 31, 2025 - $1.8 million related to Canadian revolving and Colombian credit facilities).

(2) The current portion of the lease obligation was included in accounts payable and accrued liabilities on the Company’s condensed consolidated balance sheet and totaled $25.2 million as at June 30, 2026 (December 31, 2025 - $17.0 million).

Senior Notes

(Thousands of U.S. Dollars)	9.50% Senior Notes		9.75% Senior Notes
Senior Notes, December 31, 2025	$	716,340	$	—
Principal exchanged for 9.75% Senior Notes	(628,701)		628,701
Early participation principal payment	—		(125,000)
Rounding adjustment on exchange	—		(131)
Purchased in the open market	—		(9,217)
Senior Notes principal, June 30, 2026	$	87,639	$	494,353

During the six months ended June 30, 2026, the Company issued $503.6 million in aggregate principal amount of its 9.75% Senior Secured Amortizing Notes due 2031 (the “9.75% Senior Notes”), and paid $125.0 million in cash consideration in

12

exchange for $628.7 million aggregate principal amount of its 9.50% Senior Notes. The exchange was accounted for as a debt modification.

The 9.75% Senior Notes will mature on April 15, 2031, unless earlier redeemed or re-purchased. Subject to adjustment for required minimum denominations, the principal amount of 9.75% Senior Notes will be amortized over three installments as follows: (i) October 15, 2029 - 15% of the principal amount; (ii) October 15, 2030 - 15% of the principal amount; (iii) April 15, 2031 - the remainder of the principal amount. On or before December 31, 2026 (“the Offer Date”), the Company is required to offer to purchase up to $30.0 million aggregate principal amount of the 9.75% Senior Notes (“the Offer Amount”). The Offer Amount will be reduced by the aggregate principal amount of any 9.75% Senior Notes redeemed or re-purchased by the Company in the open market transactions before the Offer Date.

During the six months ended June 30, 2026, the Company re-purchased $9.2 million of 9.75% Senior Notes for cash consideration of $8.1 million resulting in a $0.6 million gain on purchase, which included the write-off of deferred financing fees of $0.5 million. Subsequent to the quarter, the Company re-purchased an additional $15.0 million of 9.75% Senior Notes for cash consideration of $13.5 million.

At any time, prior to April 15, 2028, the Company may redeem up to 35% of the aggregate principal amount of 9.75% Senior Notes at a redemption price equal to 109.75% of the principal amount. Additionally, the Company may redeem all or a portion of the 9.75% Senior Notes on or after 2028 at the following redemption prices: 2028 - 104.875%; 2029 - 102.438%; 2030 and thereafter - 100%.

Under the terms of the 9.75% Senior Notes agreement, the Company is required to maintain compliance with the following financial covenants:

i.consolidated interest coverage ratio of not less than 2.50; and

ii.consolidated net debt (total debt excluding deferred financing fees less cash equivalents) to consolidated adjusted earnings before interest, taxes and DD&A (“EBITDA”) of not more than 3.00.

As at June 30, 2026, the Company was in compliance with all applicable covenants related to Senior Notes.

Credit facility

On May 12, 2026, the Company, through its wholly owned subsidiary Gran Tierra Canada Ltd., amended its revolving credit facility with National Bank of Canada. As part of the amendment, the borrowing base has decreased to C$75.0 million (US$52.8 million). The available commitment under the revolving credit facility remained unchanged of a C$75.0 million (US$52.8 million), comprised of a C$60.0 million (US$42.3 million) syndicated facility and C$15.0 million (US$10.6 million) of operating facility. The amounts drawn down 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 a 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. The revolving credit facility matures on October 30, 2027. As of June 30, 2026, the revolving credit facility remained undrawn.

Leases

During the three and six months ended June 30, 2026, the Company entered into three and four finance leases of $5.3 million and $21.0 million, respectively. The new finance leases had a three-year term and a weighted average discount rate of 9.6%.

During the six months ended June 30, 2026, the Company entered into one operating lease of $4.0 million which had a five-year term and a discount rate of 9.1%.

13

Interest Expense

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

	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2025
Contractual interest and other financing expenses	$	22,751	$	20,284	$	61,336	$	39,686
Amortization of debt issuance costs	1,722		4,082		13,015		7,915
	$	24,473	$	24,366	$	74,351	$	47,601

7. Prepayment agreements

During the six months ended June 30, 2026, the Company amended its existing prepayment agreement with Trafigura. The amended agreement provides for total prepayments of up to $350.0 million, including $325.0 million available immediately and an additional $25.0 million available at Trafigura’s sole discretion and includes both Ecuadorian and Colombian crude oil production. The term of the amended prepayment agreement is 48 months.

Amounts drawn on this prepayment agreement are to be repaid through future oil deliveries. Shortfalls in crude oil deliveries in any given repayment period can be delivered during the next repayment period within three calendar months or paid in cash thereafter. Amounts under the prepayment facility are subject to interest based on SOFR risk-free rate plus a margin of 4.45% per annum. Under the terms of the prepayment agreement, the Company can repay the outstanding balance of the advance payment at any time without penalty. The Company was granted a grace period for re-payment of the principal amount drawn under the prepayment agreement with first re-payment starting April 2026.

Pursuant to the amended and restated prepayment agreement, proceeds from the new advance are required to be used exclusively to finance the re-purchase or exchange of Senior Notes and to pay fees and expenses associated with the amended agreement.

The Company is required to maintain compliance with the following financial covenants related to amounts drawn under the prepayment agreement semi-annually, calculated on March 31 and September 30 of each year:

i.Asset Coverage Ratio of at least 150%, calculated using the net present value of the consolidated future cash flows of certain wholly owned subsidiaries of the Company that sell crude oil, projected through the final maturity date and discounted at 10% over the outstanding principal and the interest payable amount on the prepayment agreement at each reporting period. The net present value of the consolidated future cash flows of the Company is required to be based on 90% of the prevailing ICE Brent forward strip.

ii.Debt Service Coverage Ratio of at least 200%, calculated using the estimated crude oil to be delivered by the Company from any relevant time up to the final maturity date based on 80% of the prevailing ICE Brent forward strip and adjusted for quality differential and transportation discount over the outstanding principal amount under the prepayment agreement.

As at June 30, 2026, there was $287.7 million outstanding (December 31, 2025 - $150.0 million) on the oil prepayment agreement. Of this amount, $86.3 million (December 31, 2025 - $34.1 million) was classified as a current portion and included in accounts payable and accrued liabilities on the Company’s condensed consolidated balance sheet.

(Thousands of U.S. Dollars)
Outstanding balance on oil prepayment, December 31, 2025	$	150,000
Prepayment advances	166,500
Repayments	(28,773)
Outstanding balance on oil prepayment, June 30, 2026	$	287,727

During the three and six months ended June 30, 2026, the Company drew nil and $166.5 million on oil prepayment and re-paid $28.8 million of the outstanding principal on oil prepayment via crude oil deliveries.

14

As of June 30, 2026, the Company was in compliance with all applicable covenants under the prepayment agreement.

8. Share Capital

	Shares of Common Stock
Shares issued and outstanding at December 31, 2025	35,298,774
Shares issued on option exercise	81,655
Shares issued and outstanding at June 30, 2026	35,380,429

As at June 30, 2026, the Company had a share re-purchase program (the “2025 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 2025 Program, the Company is able to purchase up to 2,925,720 shares of Common Stock, par value of $0.001 per share (“Common Stock”) representing 10% of the public float as of October 31, 2025, at prevailing market prices at the time of purchase. The 2025 Program will continue for one year and expire on November 5, 2026, or earlier if the 10% maximum is reached.

During the three and six months ended June 30, 2026, the Company did not re-purchase any shares under the 2025 Program (three and six months ended June 30, 2025 - 239,754 and 692,804 shares re-purchased under the 2024 program at a weighted average price of $4.38 and $5.00 per share, respectively).

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 six months ended June 30, 2026:

	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, 2025	7,595,979	876,538	1,064,824	1,043,996	9.61
Granted	4,234,770	230,482	1,048,886	—	—
Exercised	(1,491,419)	(321,660)	(330,744)	(88,051)	7.58
Forfeited	(442,596)	—	(44,805)	(7,325)	10.25
Expired	—	—	—	(373,095)	8.30
Balance, June 30, 2026	9,896,734	785,360	1,738,161	575,525	10.76

As at June 30, 2026, 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 (December 31, 2025 - $0.6 million).

For the three and six months ended June 30, 2026, there was $3.8 million of stock-based compensation recovery and $15.9 million of stock-based compensation expense, respectively. For the three and six months ended June 30, 2025, stock-based compensation expense was $0.5 million and nil, respectively.

As at June 30, 2026, there was $43.6 million (December 31, 2025 - $15.4 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 2.0 years. During the six months ended June 30, 2026, the Company paid out $6.0 million for PSUs which vested on December 31, 2025 (six months ended June 30, 2025 - $7.2 million for PSUs which vested on December 31, 2024).

During the three and six months ended June 30, 2026, the Company awarded nil and 1.0 million of RSUs to employees pursuant to the existing 2007 Equity Incentive Plan, respectively. 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 June 30, 2026, in cash.

15

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 and six months ended June 30, 2026 and 2025, all options were excluded from the diluted earnings (loss) per share calculation as the options were anti-dilutive.

9. Revenue

	Three Months Ended June 30, 2026								Six Months Ended June 30, 2026
	Crude Oil		Natural Gas		NGL		Total Revenue		Crude Oil		Natural Gas		NGL		Total Revenue
Colombia	118,136		—		—		118,136		220,460		—		—		220,460
Ecuador	41,964		—		—		41,964		82,709		—		—		82,709
Canada	21,086		4,075		1,920		27,081		39,824		11,985		4,260		56,069
	$	181,186	$	4,075	$	1,920	$	187,181	$	342,993	$	11,985	$	4,260	$	359,238

	Three Months Ended June 30, 2025								Six Months Ended June 30, 2025
	Crude Oil		Natural Gas		NGL		Total Revenue		Crude Oil		Natural Gas		NGL		Total Revenue
Colombia	109,692		—		—		109,692		227,340		—		—		227,340
Ecuador	8,495		—		—		8,495		29,518		—		—		29,518
Canada	19,647		9,180		2,343		31,170		37,755		17,058		5,859		60,672
	$	137,834	$	9,180	$	2,343	$	149,357	$	294,613	$	17,058	$	5,859	$	317,530

During the three and six months ended June 30, 2026, the Company’s production was sold primarily to one major customer, representing 69% and 71% of the total Company’s sales volumes (three and six months ended June 30, 2025 - one major customer, representing 64% and 65% of the total Company’s sales volumes), respectively, reported in each of the reportable segments.

As at June 30, 2026, accounts receivable included $10.9 million of accrued sales revenue related to June 2026 production (December 31, 2025 - $14.8 million related to December 2025 production).

10. Taxes

The Company’s effective tax rate was 6% for the six months ended June 30, 2026, compared to a negative 34% in the corresponding period of 2025.

Current income tax expense was $15.0 million for the six months ended June 30, 2026, compared to $10.5 million in the corresponding period of 2025, primarily due to higher taxable income.

For the six months ended June 30, 2026, the Company recognized a deferred tax recovery of $21.1 million, primarily attributable to an increase in deductible temporary differences arising from tax losses generated during the period, unrealized hedging losses and accruals. This recovery was partially offset by temporary differences related to accelerated tax depreciation in excess of accounting depreciation.

16

For the six months ended June 30, 2025, the deferred income tax recovery of $2.3 million was primarily attributable to an increase in deductible temporary differences arising from tax losses generated during the period. This recovery was partially offset by temporary differences related to accelerated tax depreciation in excess of accounting depreciation.

For the six months ended June 30, 2026, the difference between the effective tax rate of 6% and the 21% statutory tax rate was primarily due to an increase in the non-deductible foreign translation adjustments and other non-deductible expenses. This was partially offset by an increase in the impact of foreign taxes and the 2025 true-up (recovery).

For the six months ended June 30, 2025, the difference between the effective tax rate of negative 34% and the 21% statutory 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.

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 June 30, 2026, the Company had provided letters of credit and other credit support totaling $222.5 million, of which $39.1 million was related to capital commitments in the Suroriente Block which were completed by the end of the quarter and $0.5 million related to transportation capacity in Canada with the remainder as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, other capital or operating requirements (December 31, 2025 - $209.0 million).

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 June 30, 2026, the Company’s financial instruments recognized on the balance sheet consist of cash and cash equivalents, accounts receivable, derivatives, other long-term assets, 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.

17

Fair Value Measurement

The following table presents the Company’s fair value measurements of its financial instruments as of June 30, 2026, and December 31, 2025:

(Thousands of U.S. Dollars)	As at June 30, 2026		As at December 31, 2025
Level 1
Liabilities
7.75% Senior Notes	$	22,749	$	19,784
9.50% Senior Notes	83,257		505,020
9.75% Senior Notes	433,757		—
	$	539,763	$	524,804
Level 2
Assets
Restricted cash and cash equivalents - long-term (1)	$	11,113	$	9,735
Foreign currency derivatives - current	3,077		10,147
	$	14,190	$	19,882
Liabilities
Commodity derivatives - current	$	30,693	$	—

(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.

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.

Senior Notes

Financial instruments recorded at amortized cost at June 30, 2026, were the Senior Notes (Note 6).

At June 30, 2026, the carrying amounts of the 7.75% Senior Notes, 9.50% Senior Notes and 9.75% Senior Notes were $24.1 million, $83.9 million and $467.3 million, respectively, which represented the aggregate principal amounts less unamortized debt issuance costs and discounts, and the fair values were $22.7 million, $83.3 million and $433.8 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.

18

	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2025
Commodity price derivative (gain) loss	$	(9,266)	$	(6,802)	$	79,352	$	(5,335)
Foreign currency derivative gain	(2,598)		(7,230)		(2,806)		(7,230)
Derivative instruments (gain) loss	$	(11,864)	$	(14,032)	$	76,546	$	(12,565)

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 June 30, 2026, the Company had outstanding commodity price derivative positions in Canada and Colombia as follows:

Oil
Type of Instrument	Start Period	End Period	Volume bbl/d	Reference	Sold Put (C$/bbl or $/bbl Weighted Average)		Purchased Put (C$/bbl or $/bbl Weighted Average)		Sold Call (C$/bbl or $/bbl Weighted Average)		Premium (C$/bbl or $/bbl Weighted Average)
Collar	07/01/26	09/30/26	500	WTI CMA	—		C$	75.00	C$	91.95	—
Put Option	07/01/26	09/30/26	500	Brent	—		60.00		—		4.30
Put Spread	07/01/26	09/30/26	5,000	Brent	45.00		55.00		—		21.64
Three Way	07/01/26	09/30/26	1,000	WTI CMA	C$	62.50	C$	72.50	C$	103.70	C$	0.95
Three Way	07/01/26	09/30/26	9,000	Brent	50.89		60.89		73.23		—
Collar	10/01/26	12/31/26	500	WTI CMA	—		C$	70.00	C$	92.47	—
Put Option	10/01/26	12/31/26	500	Brent	—		60.00		—		4.30
Three Way	10/01/26	12/31/26	500	WTI CMA	C$	60.00	C$	70.00	C$	107.00	C$	1.90
Put Spread	10/01/26	12/31/26	5,000	Brent	45.00		55.00		—		21.64
Three Way	10/01/26	12/31/26	9,000	Brent	50.33		60.33		72.49		—
Three Way	01/01/27	03/31/27	3,000	Brent	58.33		71.67		89.55		—

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$/GJ, Weighted Average)
Swap	07/01/26	09/30/26	20,000	Aeco 5A	C$	2.71	—	—
Swap	10/01/26	12/31/26	6,739	Aeco 5A	C$	2.71	—	—

Foreign Exchange Risk

The Company is exposed to foreign exchange risk arising from Colombian and Canadian operations predominantly related to operating and transportation costs. Revenue and general and administrative expenses associated with the Company’s Canadian operations are also subject to foreign currency fluctuations. To mitigate exposure to fluctuations in foreign exchange, the Company may enter into foreign currency exchange derivatives.

19

As at June 30, 2026, the Company had the following outstanding foreign currency exchange 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: July 2026, to March 2027	9,000	30,996	COP	3,790	4,080
Collars: July 2026, to May 2027	32,000	110,208	COP	3,767	4,050

(1) At June 30, 2026 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 June 30,				As at December 31,
(Thousands of U.S. Dollars)	2026		2025		2025		2024
Cash and cash equivalents	$	126,728	$	61,028	$	82,931	$	103,379
Restricted cash and cash equivalents - current	—		—		—		1,142
Restricted cash and cash equivalents - long-term (1)	11,113		8,533		9,735		6,816
	$	137,841	$	69,561	$	92,666	$	111,337

(1) 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:

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025
Accounts receivable and other long-term assets	$	(394)	$	(2,038)
Derivatives	6,292		—
Prepaids and inventory	(3,541)		(11,693)
Oil prepayment	137,727		—
Accounts payable and accrued liabilities, and other long-term liabilities	(6,786)		27,387
Taxes receivable and payable	8,936		(11,954)
Net changes in assets and liabilities from operating activities	$	142,234	$	1,702

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

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025
Additions to property, plant and equipment	$	(99,668)	$	(145,897)
Decrease in accounts payable and accrued liabilities	(2,841)		(8,911)
(Increase) decrease in accounts receivable	(8)		837
Net cash additions to property, plant and equipment	$	(102,517)	$	(153,971)

20

The following table provides additional supplemental cash flow disclosures:

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025
Cash paid for income taxes	$	7,995	$	3,816
Cash paid for withholding taxes	$	13,577	$	15,654
Cash paid for interest	$	33,535	$	36,763
Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	38,842	$	53,209

21

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 2025 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 2025 Annual Report on Form 10-K.

Financial and Operational Highlights

Key Highlights for the second quarter of 2026

•Net income for the second quarter of 2026 was $24.9 million or $0.70 per share basic and diluted, compared to a net loss of $12.7 million or $(0.36) per share basic and diluted for the second quarter of 2025 and a net loss of $119.2 million or $(3.38) per share for the prior quarter.

•Income before income taxes for the second quarter of 2026 was $45.3 million, compared to loss before income taxes of $8.1 million for the second quarter of 2025 and loss before income taxes of $145.8 million for the prior quarter

•Brent oil price averaged $96.68 per bbl during the quarter, an increase of 45% from the comparative period of 2025, and an increase of 23% from the prior quarter. Castilla, Vasconia and Oriente differentials averaged $9.71, $1.42 and $2.01 per bbl during the quarter, an increase of 105% for Castilla and a decrease of 17% and 72% for Vasconia and Oriente differentials from the comparable period of 2025. Castilla differential was comparable to the prior quarter and Vasconia and Oriente differentials decreased by 76% and 75% from the prior quarter, respectively

•Adjusted EBITDA(2) was $85.1 million for the second quarter of 2026, an increase from $77.0 million in the second quarter of 2025, and $73.9 million in the prior quarter

•Funds flow from operations(2) increased to $60.3 million compared to $53.9 million in the second quarter of 2025, and $42.8 million in the prior quarter

•NAR production for the second quarter of 2026 decreased by 20% to 31,990 BOEPD, compared to 39,800 BOEPD in the second quarter of 2025, and decreased by 15% from 37,741 BOEPD in the prior quarter primarily due to lower production in Colombia, higher in-kind royalties driven by higher oil prices and asset sales in Canada

•NAR sales volumes for the second quarter of 2026 decreased by 16% to 32,166 BOEPD, compared to 38,331 BOEPD in the second quarter of 2025 and decreased by 20% from 40,267 BOEPD in the prior quarter

•Oil, natural gas and NGL sales for the second quarter of 2026 increased by 25% to $187.2 million, compared to the second quarter of 2025, due to increase in benchmark oil prices, offset by lower sales volumes in Colombia and Canada and higher quality and transportation discounts in Colombia associated with using alternative transportation routes for Putumayo production as the Colombia and Ecuador border remained closed. Oil, natural gas and NGL sales increased by 9% from $172.1 million in the prior quarter due to higher benchmark oil prices and lower quality and transportation discounts in Colombia and premium in Ecuador, partially offset by lower sales volumes

•Operating expenses decreased by 7% and 22% to $51.6 million when compared to the second quarter of 2025 and the prior quarter, respectively, primarily due to lower workover activities, reduced field personnel costs, lower oil treatment and testing service costs, as well as inventory fluctuations resulting from inventory accumulation at the end of the current quarter. On a per boe basis, operating expenses increased by $1.67 to $17.61 when compared to the second quarter of 2025 due to lower sales volumes and decreased by $0.64 from $18.25 in the prior quarter primarily due to inventory fluctuations resulting from inventory accumulation at the end of the current quarter

•Transportation expenses decreased by 13% when compared to the second quarter of 2025 and decreased by 26% from the prior quarter primarily due to lower sales volumes transported in Colombia and Canada

•Gross profit increased to $75.5 million compared to $23.3 million in the second quarter of 2025 and $36.7 million in the prior quarter

•Operating netback(2) was $131.7 million compared to $89.3 million in the second quarter of 2025 and $100.6 million in the prior quarter

•Quality and transportation discounts per boe in South America were $10.47, an increase from $10.29 in the second quarter of 2025 due to higher transportation discounts in Colombia. Quality and transportation discounts in Colombia were affected by using alternative transportation route for Putumayo production as a result of closure of Ecuador and Colombia border which was significantly more expensive and resulted in approximately $5.9 million for the current

22

quarter. Quality and transportation discounts in South America decreased from $19.04 per boe in the prior quarter primarily a result of decrease in Vasconia and Oriente differentials, offset by higher transportation discounts

•Quality and transportation discounts for oil per boe in Canada for the second quarter of 2026 decreased to $2.24 compared to $8.22 in the second quarter of 2025 and $9.70 in the prior quarter due to lower pipeline tariffs in the current quarter resulting from a change in product mix associated with asset sales

•General and administrative (“G&A”) expenses before stock-based compensation for the second quarter of 2026 decreased to $13.2 million compared to $14.1 million in the second quarter of 2025 and $15.1 million in the prior quarter due to lower consulting, information technology costs and lower salaries associated with headcount optimization

•Capital expenditures for the second quarter of 2026 were $54.3 million compared to $51.2 million in the second quarter of 2025 and $45.4 million in the prior quarter

•During the second quarter, we satisfied all outstanding conditions precedent to and received regulatory approval for a strategic partnership with Ecopetrol S.A., earning a 49% working interest in the Tisquirama Block in Colombia. Additionally, we completed all capital commitments related to Suroriente Block.

23

(Thousands of U.S. Dollars, unless otherwise indicated)	Three Months Ended June 30,					Three Months Ended March 31,		Six Months Ended June 30,
	2026		2025		% Change	2026		2026		2025		% Change
Average Daily Volumes (BOEPD)
Consolidated
Working Interest (“WI”) Production Before Royalties	41,501		47,196		(12)	45,497		43,488		46,923		(7)
Royalties	(9,511)		(7,396)		29	(7,756)		(8,638)		(7,738)		12
Production NAR	31,990		39,800		(20)	37,741		34,850		39,185		(11)
Decrease (increase) in Inventory	176		(1,469)		112	2,526		1,345		(509)		364
Sales(1)	32,166		38,331		(16)	40,267		36,195		38,676		(6)
Net Income (Loss)	$	24,861	$	(12,741)	295	$	(119,172)	$	(94,311)	$	(32,021)	(195)
Operating Netback
Gross Profit	$	75,460	$	23,313	224	$	36,697	$	112,157	$	51,414	118
Depletion and Accretion	$	56,253	$	65,948	(15)	63,908		120,161		134,379		(11)
Operating Netback(2)	$	131,713	$	89,261	48	$	100,605	$	232,318	$	185,793	25
G&A Expenses before Stock-Based Compensation	$	13,219	$	14,136	(6)	$	15,149	$	28,368	$	26,062	9
G&A Stock-Based Compensation (Recovery) Expense	(3,757)		546		(788)	19,676		15,919		29		54,793
G&A Expenses, including Stock-Based Compensation	$	9,462	$	14,682	(36)	$	34,825	$	44,287	$	26,091	70
Adjusted EBITDA(2)	$	85,071	$	76,987	11	$	73,935	$	159,006	$	162,149	(2)
Funds Flow from Operations(2)	$	60,289	$	53,906	12	$	42,823	$	103,112	$	109,250	(6)
Capital Expenditures (before changes in working capital)	$	54,309	$	51,170	6	$	45,359	$	99,668	$	145,897	(32)

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

(2) Non-GAAP measures.

Gross profit is derived from oil, gas and NGL sales, less operating and transportation expenses, and depletion and accretion related to producing assets. Gross profit does not include depreciation of administrative assets, asset impairment, general and administrative expenses, interest, taxes or other non-operating items.

Operating netback, EBITDA, adjusted EBITDA, and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to 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 gross profit adjusted for depletion and accretion related to producing assets. 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 gross profit to operating netback is provided in the table below.

24

Colombia	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Gross Profit	$	44,585	$	19,880	$	24,377	$	68,962	$	46,828
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)	38,072		47,897		40,633		78,705		92,896
Operating netback (non-GAAP)	$	82,657	$	67,777	$	65,010	$	147,667	$	139,724

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $43.5 million and $50.5 million less depreciation of administrative assets of $5.5 million and $2.6 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $89.9 million and $99.1 million, less depreciation of administrative assets of $11.2 million and $6.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $46.4 million, less depreciation of administrative assets of $5.7 million.

Ecuador	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Gross Profit (Loss)	$	24,811	$	(419)	$	6,378	$	31,189	$	942
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)	9,775		4,351		15,861		25,636		14,847
Operating netback (non-GAAP)	$	34,586	$	3,932	$	22,239	$	56,825	$	15,789

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $10.3 million and $4.4 million less depreciation of administrative assets of $0.6 million and nil, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $26.3 million and $14.8 million less depreciation of administrative assets of $0.7 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $16.0 million, less depreciation of administrative assets of $0.1 million.

Canada	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Gross Profit	$	6,064	$	3,852	$	5,942	$	12,006	$	3,644
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)	8,406		13,700		7,414		15,820		26,636
Operating netback (non-GAAP)	$	14,470	$	17,552	$	13,356	$	27,826	$	30,280

(*) Same as DD&A expenses for the three months ended June 30, 2026 and 2025, six months ended June 30, 2026 and 2025, and the prior quarter (the depreciation of administrative assets had a de minimus amount for all reported periods).

Total Consolidated	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Gross Profit	$	75,460	$	23,313	$	36,697	$	112,157	$	51,414
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)	56,253		65,948		63,908		120,161		134,379
Operating netback (non-GAAP)	$	131,713	$	89,261	$	100,605	$	232,318	$	185,793

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $62.3 million and $68.6 million less depreciation of administrative assets of $6.1 million and $2.7 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $132.2 million and $140.8 million less depreciation of administrative assets of $12.0 million and $6.5 million, respectively. For the prior quarter, calculated as DD&A expenses of $69.9 million, less depreciation of administrative assets of $6.0 million.

EBITDA, as presented, is defined as net income (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 severance expense, non-cash lease expense, lease payments, foreign exchange gains or losses, stock-based compensation expense or recovery, other non-cash gains or losses and unrealized derivative instruments gains or losses. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is a useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income (loss) to EBITDA and adjusted EBITDA is as follows:

25

	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Net income (loss)	$	24,861	$	(12,741)	$	(119,172)	$	(94,311)	$	(32,021)
Adjustments to reconcile net income (loss) to EBITDA and Adjusted EBITDA
DD&A expenses	62,334		68,635		69,874		132,208		140,837
Interest expense	24,473		24,366		49,878		74,351		47,601
Income tax expense (recovery)	20,488		4,648		(26,595)		(6,107)		8,201
EBITDA (non-GAAP)	$	132,156	$	84,908	$	(26,015)	$	106,141	$	164,618
Severance	95		—		2,468		2,563		—
Non-cash lease expense	1,503		1,725		1,468		2,971		3,461
Lease payments	(1,633)		(1,545)		(1,687)		(3,320)		(3,112)
Foreign exchange loss	2,603		3,716		1,425		4,028		7,554
Stock-based compensation (recovery) expense	(3,757)		546		19,676		15,919		29
Other non-cash loss (gain)	—		38		(728)		(728)		90
Unrealized derivative instruments (gain) loss	(45,896)		(12,401)		77,328		31,432		(10,491)
Adjusted EBITDA (non-GAAP)	$	85,071	$	76,987	$	73,935	$	159,006	$	162,149

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

	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Net income (loss)	$	24,861	$	(12,741)	$	(119,172)	$	(94,311)	$	(32,021)
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A expenses	62,334		68,635		69,874		132,208		140,837
Deferred income tax expense (recovery)	11,373		2,453		(32,445)		(21,072)		(2,259)
Stock-based compensation (recovery) expense	(3,757)		546		19,676		15,919		29
Amortization of debt issuance costs	1,722		4,082		11,293		13,015		7,915
Senior Notes exchange fees	785		—		12,903		13,688		—
Non-cash interest	6,134		—		4,513		10,647		—
Non-cash lease expense	1,503		1,725		1,468		2,971		3,461
Lease payments	(1,633)		(1,545)		(1,687)		(3,320)		(3,112)
Unrealized foreign exchange loss (gain)	2,863		3,114		(200)		2,663		4,801
Unrealized derivative instruments (gain) loss	(45,896)		(12,401)		77,328		31,432		(10,491)
Other non-cash loss (gain)	—		38		(728)		(728)		90
Funds flow from operations (non-GAAP)	$	60,289	$	53,906	$	42,823	$	103,112	$	109,250

26

Additional Operational Results

	Three Months Ended June 30,					Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		% Change	2026		2026		2025		% Change
Oil, natural gas and NGL sales	$	187,181	$	149,357	25	$	172,057	$	359,238	$	317,530	13
Operating expenses	51,561		55,602		(7)	66,149		117,710		122,692		(4)
Transportation expenses	3,907		4,494		(13)	5,303		9,210		9,045		2
Operating netback(1)	131,713		89,261		48	100,605		232,318		185,793		25
Other taxes	1,389		577		141	1,041		2,430		1,058		130
DD&A expenses	62,334		68,635		(9)	69,874		132,208		140,837		(6)
Derivative instruments (gain) loss	(11,864)		(14,032)		(15)	88,410		76,546		(12,565)		709
G&A expenses before stock-based compensation	13,219		14,136		(6)	15,149		28,368		26,062		9
G&A stock-based compensation (recovery) expense	(3,757)		546		(788)	19,676		15,919		29		54,793
Severance	95		—		100	2,468		2,563		—		100
Foreign exchange loss	2,603		3,716		(30)	1,425		4,028		7,554		(47)
Interest expense	24,473		24,366		—	49,878		74,351		47,601		56
	88,492		97,944		(10)	247,921		336,413		210,576		60
Other income	1,625		339		379	1,148		2,773		287		866
Interest income	503		251		100	401		904		676		34
Income (loss) before income taxes	45,349		(8,093)		660	(145,767)		(100,418)		(23,820)		(322)
Current income tax expense	9,115		2,195		315	5,850		14,965		10,460		43
Deferred income tax expense (recovery)	11,373		2,453		364	(32,445)		(21,072)		(2,259)		(833)
Total income tax expense (recovery)	20,488		4,648		341	(26,595)		(6,107)		8,201		(174)
Net income (loss)	$	24,861	$	(12,741)	295	$	(119,172)	$	(94,311)	$	(32,021)	(195)
Sales Volumes (NAR)
Total sales volumes, BOEPD	32,166		38,331		(16)	40,267		36,195		38,676		(6)
Brent Price per bbl	$	96.68	$	66.71	45	$	78.38	$	87.60	$	70.81	24
WTI Price per bbl	$	92.70	$	63.81	45	$	72.73	$	82.77	$	67.60	22
AECO Price C$ per GJ	1.55		1.60		(3)	1.91		1.73		1.82		(5)
Consolidated Results of Operations per boe Sales Volumes NAR
Oil, natural gas and NGL sales	$	63.95	$	42.82	49	$	47.48	$	54.84	$	45.36	21
Operating expenses	17.61		15.94		10	18.25		17.97		17.53		3

27

Transportation expenses	1.33		1.29		3	1.46		1.41		1.29		9
Operating netback(1)	45.01		25.59		76	27.77		35.46		26.54		34
Other taxes	0.47		0.17		187	0.29		0.37		0.15		147
DD&A expenses	21.29		19.68		8	19.28		20.18		20.12		—
Derivative instruments (gain) loss	(4.05)		(4.02)		(1)	24.40		11.68		(1.79)		751
G&A expenses before stock-based compensation	4.52		4.05		12	4.18		4.33		3.72		16
G&A stock-based compensation (recovery) expense	(1.28)		0.16		(918)	5.43		2.43		—		100
Severance	0.03		—		100	0.68		0.39		—		100
Foreign exchange loss	0.89		1.07		(17)	0.39		0.61		1.08		(44)
Interest expense	8.36		6.99		20	13.76		11.35		6.80		67
	30.23		28.09		8	68.41		51.35		30.08		71
Other income	0.56		0.10		471	0.32		0.42		0.04		932
Interest income	0.17		0.07		139	0.11		0.14		0.10		43
Income (loss) before income taxes	15.51		(2.33)		766	(40.21)		(15.33)		(3.40)		(351)
Current income tax expense	3.11		0.63		395	1.61		2.28		1.49		53
Deferred income tax expense (recovery)	3.89		0.70		452	(8.95)		(3.22)		(0.32)		(897)
Total income tax expense (recovery)	7.00		1.33		426	(7.34)		(0.94)		1.17		(180)
Net income (loss)	$	8.51	$	(3.66)	333	$	(32.87)	$	(14.39)	$	(4.57)	(215)

(1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to footnote 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 June 30,				Three Months Ended March 31,		Six Months Ended June 30,
Average Daily Volumes (BOEPD) - Colombia	2026		2025		2026		2026		2025
WI production before royalties	19,994		25,108		21,319		20,653		25,378
Royalties	(3,968)		(3,845)		(3,230)		(3,601)		(4,131)
Production NAR	16,026		21,263		18,089		17,052		21,247
(Increase) decrease in inventory	(57)		110		799		369		(133)
Sales	15,969		21,373		18,888		17,421		21,114
Royalties, % of working interest production before royalties	20	%	15	%	15	%	17	%	16	%

28

	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
Average Daily Volumes (BOEPD) - Ecuador	2026		2025		2026		2026		2025
WI production before royalties	7,993		4,592		8,759		8,373		4,315
Royalties	(3,788)		(1,364)		(2,584)		(3,189)		(1,394)
Production NAR	4,205		3,228		6,175		5,184		2,921
Decrease (increase) in inventory	233		(1,579)		1,727		976		(376)
Sales	4,438		1,649		7,902		6,160		2,545
Royalties, % of working interest production before royalties	47	%	30	%	30	%	38	%	32	%
	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
Average Daily Volumes (BOEPD) - Canada	2026		2025		2026		2026		2025
WI production before royalties	13,514		17,496		15,419		14,462		17,230
Royalties	(1,755)		(2,187)		(1,942)		(1,848)		(2,213)
Production NAR	11,759		15,309		13,477		12,614		15,017
Sales	11,759		15,309		13,477		12,614		15,017
Royalties, % of working interest production before royalties	13	%	13	%	13	%	13	%	13	%
	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
Average Daily Volumes (BOEPD) - Total Company	2026		2025		2026		2026		2025
WI production before royalties	41,501		47,196		45,497		43,488		46,923
Royalties	(9,511)		(7,396)		(7,756)		(8,638)		(7,738)
Production NAR	31,990		39,800		37,741		34,850		39,185
Decrease (increase) in inventory	176		(1,469)		2,526		1,345		(509)
Sales	32,166		38,331		40,267		36,195		38,676
Royalties, % of working interest production before royalties	23	%	16	%	17	%	20	%	16	%

Oil, natural gas and NGL production NAR for the three and six months ended June 30, 2026, decreased by 20% and 11% to 31,990 BOEPD and 34,850 BOEPD, respectively, compared to the corresponding periods of 2025 due to lower production in Colombia, higher in-kind royalties driven by higher oil prices and the sale of Simonette area in Canada at the end of prior quarter, partially offset by higher than anticipated production results from Conejo-1 well in Charapa Block and additional production from Perico Block in Ecuador acquired in December 2025. Oil, natural gas and NGL production NAR decreased by 15% compared to the prior quarter primarily due to the sale of the Simonette area in Canada and lower production in the Acordionero and Cohembi fields in Colombia as a result of failure of artificial lift systems.

Royalties as a percentage of production for the three and six months ended June 30, 2026 increased to 23% and 20%, respectively, compared to the corresponding periods of 2025 and the prior quarter as a result of higher benchmark oil prices and the price sensitive royalty regime in Colombia and Ecuador.

29

30

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, Iguana, Chanangue and Perico Blocks. Canada includes several areas in the Western Canadian Sedimentary Basin with the majority of production in Alberta, Canada.

Commodity prices:

Colombia and Ecuador

Brent - For the three and six months ended June 30, 2026, Brent increased 45% and 24% from the corresponding periods of 2025 and increased 23% from the prior quarter.

For the three months ended June 30, 2026, Castilla differential per bbl increased to $9.71 from $4.73 in the corresponding period of 2025. Vasconia and Oriente differentials per bbl decreased to $1.42 and $2.01 compared to $1.71 and $7.26, respectively, in the corresponding period of 2025.

For the six months ended June 30, 2026, Castilla and Vasconia differentials per bbl increased to $9.69 and $3.65 from $5.04 and $1.99, respectively, in the corresponding period of 2025. Oriente differential per bbl decreased to $5.07 from $7.45 in the corresponding period of 2025.

Castilla differential per bbl was comparable to the prior quarter and Vasconia and Oriente differentials per bbl decreased from $5.91 and $8.17 in the prior quarter.

The differentials for South America fluctuate based on regional supply and demand of heavy crude, shipping costs, pipeline disruptions and geopolitical and trading policies.

During the three and six months ended June 30, 2026 and 2025, 100% of sales from South America was priced against Brent.

31

Canada

WTI - For the three and six months ended June 30, 2026, WTI increased by 45% and 22% from the corresponding periods of 2025 and increased 27% from the prior quarter. During the three and six months ended June 30, 2026, 22% and 23% of NAR production in Canada was oil, compared to 26% and 23% for the corresponding periods of 2025 and 25% in the prior quarter, respectively.

NGLs - For the three and six months ended June 30, 2026, the weighted average NGL price received was 7% and 12% of WTI compared to 11% and 12% of WTI in the corresponding periods of 2025, respectively, and 10% of WTI in the prior quarter. During the three and six months ended June 30, 2026, NGLs production in Canada was 27% in each reporting period, and comparable to the corresponding periods of 2025 and the prior quarter.

AECO - For the three and six months ended June 30, 2026, AECO price decreased by 3% and 5% from the corresponding periods of 2025 and decreased 19% from the prior quarter. During the three and six months ended June 30, 2026, 52% and 50% of production in Canada was natural gas, compared to 50% and 51%, in the corresponding periods of 2025, respectively, and 49% in the prior quarter.

Oil, natural gas and NGL sales for the three and six months ended June 30, 2026, increased by 25% and 13% to $187.2 million and $359.2 million compared to the corresponding periods of 2025, primarily due to increases of 45% and 24% in Brent price, partially offset by 16% and 6% lower sales volumes in Colombia and Canada and higher quality and transportation discounts in Colombia. Quality and transportation discounts in Colombia were affected by using alternative transportation route for Putumayo production as Colombia and Ecuador border remained closed. The alternative transportation route was significantly more expensive and resulted in approximately $5.9 million and $10.0 million for the three and six months ended June 30, 2026.

Compared to the prior quarter, oil, natural gas and NGL sales increased by 9%, primarily due to a 23% increase in Brent price and lower quality and transportation discounts in Colombia and premium in Ecuador, partially offset by a 20% decrease in sales volumes. During three months ended June 30, 2026, there was only one lifting in Ecuador compared to two in the prior quarter.

32

The following table shows the effect of changes in realized price and sale volumes on our oil, natural gas and NGL sales for the three and six months ended June 30, 2026, compared to the prior quarter and the corresponding periods of 2025:

(Thousands of U.S. Dollars)	Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025		Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026		Six Months Ended June 30, 2026, Compared with Six Months Ended June 30, 2025
Oil, natural gas and NGL sales for the comparative period	$	149,357	$	172,057	$	317,530
Realized sales price increase effect	61,840		48,208		62,076
Sales volumes decrease effect	(24,016)		(33,084)		(20,368)
Oil, natural gas and NGL sales for the three and six months ended June 30, 2026	$	187,181	$	187,181	$	359,238

Gross Profit

Colombia	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Revenue	$	118,136	$	109,692	$	102,324	$	220,460	$	227,340
Operating expenses	33,152		38,180		35,042		68,194		80,670
Transportation expenses	2,327		3,735		2,272		4,599		6,946
Depletion and accretion(*)	38,072		47,897		40,633		78,705		92,896
Gross profit	$	44,585	$	19,880	$	24,377	$	68,962	$	46,828

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $43.5 million and $50.5 million less depreciation of administrative assets of $5.5 million and $2.6 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $89.9 million and $99.1 million

33

less depreciation of administrative assets of $11.2 million and $6.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $46.4 million, less depreciation of administrative assets of $5.7 million.

Colombia	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(U.S. Dollars per boe Sales NAR )	2026		2025		2026		2026		2025
Revenue	$	81.29	$	56.40	$	60.19	$	69.92	$	59.49
Operating expenses	22.81		19.63		20.61		21.63		21.11
Transportation expenses	1.60		1.92		1.34		1.46		1.82
Depletion and accretion	26.20		24.63		23.90		24.96		24.31
Gross profit	$	30.68	$	10.22	$	14.34	$	21.87	$	12.25

Ecuador	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Revenue	$	41,964	$	8,495	$	40,745	$	82,709	$	29,518
Operating expenses	6,196		4,122		15,952		22,148		12,195
Transportation expenses	1,182		441		2,554		3,736		1,534
Depletion and accretion(*)	9,775		4,351		15,861		25,636		14,847
Gross profit (loss)	$	24,811	$	(419)	$	6,378	$	31,189	$	942

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $10.3 million and $4.4 million less depreciation of administrative assets of $0.6 million and nil, respectively. For the six months ended June 30, 2026 and 2025. DD&A expenses of $26.3 million and $14.8 million less depreciation of administrative assets of $0.7 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $16.0 million, less depreciation of administrative assets of $0.1 million.

Ecuador	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(U.S. Dollars per boe Sales NAR )	2026		2025		2026		2026		2025
Revenue	$	103.90	$	56.64	$	57.30	$	74.18	$	64.10
Operating expenses	15.34		27.48		22.43		19.86		26.48
Transportation expenses	2.93		2.94		3.59		3.35		3.33
Depletion and accretion	24.20		29.01		22.30		22.99		32.24
Gross profit (loss)	$	61.43	$	(2.79)	$	8.98	$	27.98	$	2.05

Canada	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Revenue	$	27,081	$	31,170	$	28,988	$	56,069	$	60,672
Operating expenses	12,213		13,300		15,155		27,368		29,827
Transportation expenses	398		318		477		875		565
Depletion and accretion(*)	8,406		13,700		7,414		15,820		26,636
Gross profit	$	6,064	$	3,852	$	5,942	$	12,006	$	3,644

(*) Same as DD&A expenses for the three months ended June 30, 2026 and 2025, six months ended June 30, 2026 and 2025, and the prior quarter (the depreciation of administrative assets had a de minimus amount for all reported periods).

34

Canada	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(U.S. Dollars per boe Sales NAR )	2026		2025		2026		2026		2025
Revenue	$	25.31	$	22.37	$	23.90	$	24.56	$	22.32
Operating expenses	11.41		9.55		12.49		11.99		10.97
Transportation expenses	0.37		0.23		0.39		0.38		0.21
Depletion and accretion	7.86		9.83		6.11		6.93		9.80
Gross profit	$	5.67	$	2.76	$	4.91	$	5.26	$	1.34

Total Company	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Revenue	$	187,181	$	149,357	$	172,057	$	359,238	$	317,530
Operating expenses	51,561		55,602		66,149		117,710		122,692
Transportation expenses	3,907		4,494		5,303		9,210		9,045
Depletion and accretion(*)	56,253		65,948		63,908		120,161		134,379
Gross profit	$	75,460	$	23,313	$	36,697	$	112,157	$	51,414

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $62.3 million and $68.6 million less depreciation of administrative assets of $6.1 million and $2.7 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $132.2 million and $140.8 million less depreciation of administrative assets of $12.0 million and $6.5 million, respectively. For the prior quarter, calculated as DD&A expenses of $69.9 million, less depreciation of administrative assets of $6.0 million.

Total Company	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(U.S. Dollars per boe Sales NAR )	2026		2025		2026		2026		2025
Revenue	$	63.95	$	42.82	$	47.48	$	54.84	$	45.36
Operating expenses	17.61		15.94		18.25		17.97		17.53
Transportation expenses	1.33		1.29		1.46		1.41		1.29
Depletion and accretion	19.22		18.91		17.63		18.34		19.20
Gross profit	$	25.79	$	6.68	$	10.14	$	17.12	$	7.34

35

Operating Netback

Colombia	Three Months Ended June 30,				Three Months Ended March 31		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Oil, natural gas and NGL sales	$	118,136	$	109,692	$	102,324	$	220,460	$	227,340
Transportation expenses	(2,327)		(3,735)		(2,272)		(4,599)		(6,946)
	115,809		105,957		100,052		215,861		220,394
Operating expenses	(33,152)		(38,180)		(35,042)		(68,194)		(80,670)
Operating netback(1)	$	82,657	$	67,777	$	65,010	$	147,667	$	139,724
(U.S. Dollars Per boe Sales Volumes NAR)
Brent	$	96.68	$	66.71	$	78.38	$	87.60	$	70.81
Quality and transportation discounts	(15.39)		(10.31)		(18.19)		(17.68)		(11.32)
Average realized price	81.29		56.40		60.19		69.92		59.49
Transportation expenses	(1.60)		(1.92)		(1.34)		(1.46)		(1.82)
Average realized price net of transportation expenses	79.69		54.48		58.85		68.46		57.67
Operating expenses	(22.81)		(19.63)		(20.61)		(21.63)		(21.11)
Operating netback(1)	$	56.88	$	34.85	$	38.24	$	46.83	$	36.56

Ecuador	Three Months Ended June 30,				Three Months Ended March 31		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Oil, natural gas and NGL sales	$	41,964	$	8,495	$	40,745	$	82,709	$	29,518
Transportation expenses	(1,182)		(441)		(2,554)		(3,736)		(1,534)
	40,782		8,054		38,191		78,973		27,984
Operating expenses	(6,196)		(4,122)		(15,952)		(22,148)		(12,195)
Operating netback(1)	$	34,586	$	3,932	$	22,239	$	56,825	$	15,789
(U.S. Dollars Per boe Sales Volumes NAR)
Brent (M-1 Pricing)	$	101.89	$	66.91	$	65.12	$	83.65	$	71.36
Quality and transportation premium (discounts)	2.01		(10.27)		(7.82)		(9.47)		(7.26)
Average realized price	103.90		56.64		57.30		74.18		64.10
Transportation expenses	(2.93)		(2.94)		(3.59)		(3.35)		(3.33)
Average realized price net of transportation expenses	100.97		53.70		53.71		70.83		60.77
Operating expenses	(15.34)		(27.48)		(22.43)		(19.86)		(26.48)
Operating netback(1)	$	85.63	$	26.22	$	31.28	$	50.97	$	34.29

36

Canada	Three Months Ended June 30,				Three Months Ended March 31		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Oil, natural gas and NGL sales	$	27,081	$	31,170	$	28,988	$	56,069	$	60,672
Transportation expenses	(398)		(318)		(477)		(875)		(565)
	26,683		30,852		28,511		55,194		60,107
Operating expenses	(12,213)		(13,300)		(15,155)		(27,368)		(29,827)
Operating netback(1)	$	14,470	$	17,552	$	13,356	$	27,826	$	30,280
(U.S. Dollars Per boe Sales Volumes NAR)
WTI Price per bbl	$	92.70	$	63.81	$	72.73	$	82.77	$	67.60
AECO Price C$ per GJ	1.55		1.60		1.91		1.73		1.82
Average realized price	25.31		22.37		23.90		24.56		22.32
Transportation expenses	(0.37)		(0.23)		(0.39)		(0.38)		(0.21)
Average realized price net of transportation expenses	24.94		22.14		23.51		24.18		22.11
Operating expenses	(11.41)		(9.55)		(12.49)		(11.99)		(10.97)
Operating netback(1)	$	13.53	$	12.59	$	11.02	$	12.19	$	11.14

Total Company	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Oil, natural gas and NGL sales	$	187,181	$	149,357	$	172,057	$	359,238	$	317,530
Transportation expenses	(3,907)		(4,494)		(5,303)		(9,210)		(9,045)
	183,274		144,863		166,754		350,028		308,485
Operating expenses	(51,561)		(55,602)		(66,149)		(117,710)		(122,692)
Operating netback(1)	$	131,713	$	89,261	$	100,605	$	232,318	$	185,793
(U.S. Dollars Per boe Sales Volumes NAR)
Average realized price	$	63.95	$	42.82	47.48		$	54.84	$	45.36
Transportation expenses	(1.33)		(1.29)		(1.46)		(1.41)		(1.29)
Average realized price net of transportation expenses	62.62		41.53		46.02		53.43		44.07
Operating expenses	(17.61)		(15.94)		(18.25)		(17.97)		(17.53)
Operating netback(1)	$	45.01	$	25.59	$	27.77	$	35.46	$	26.54

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

37

38

Operating expenses for the three and six months ended June 30, 2026, decreased by 7% and 4% to $51.6 million and $117.7 million, respectively, compared to the corresponding periods of 2025. The decrease was primarily due to lower workover activities, reduced field personnel costs, lower oil treatment and testing service costs, as well as inventory fluctuations resulting from inventory accumulation at the end of the current quarter.

Operating expenses for the three and six months ended June 30, 2026, on a per boe basis, increased by $1.67 and $0.44 to $17.61 and $17.97, respectively, compared to the corresponding periods of 2025, primarily due to lower sales volumes during current periods, partially offset by $0.18 and $0.68 per boe lower workover activities and inventory fluctuations, respectively.

39

Compared to the prior quarter, operating expenses decreased by 22% from $66.1 million or by $0.64 from $18.25 on a per boe basis primarily due to inventory fluctuations resulting from inventory accumulation at the end of the current quarter, partially offset by $0.34 per boe higher workover activities.

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 and six months ended June 30, 2026 and 2025, and the prior quarter:

	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
	2026		2025		2026		2026		2025
Volume transported through pipeline	50	%	40	%	54	%	52	%	33	%
Volume sold at wellhead	26	%	40	%	24	%	25	%	31	%
Volume transported via truck to sales point	24	%	20	%	22	%	23	%	36	%
	100	%	100	%	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 June 30, 2026, decreased by 13% to $3.9 million, compared to the corresponding period of 2025, due to lower sales volumes transported in Colombia and Canada and increased by $0.04 per boe due to lower sales volumes. Transportation expenses for the six months ended June 30, 2026, increased by 2% or $0.12 per boe due to higher volumes transported via pipeline which had a higher cost per boe.

Transportation expenses decreased by 26% or $0.13 per boe from $5.3 million or $1.46 per boe in the prior quarter due to lower sales volumes transported during the current quarter.

40

Colombia	Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025			Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026			Six Months Ended June 30, 2026, Compared with Six Months Ended June 30, 2025
(U.S. Dollars per boe Sales Volumes NAR)
Average Brent price	$	96.68		$	96.68		$	87.60
Average realized price, net of transportation expenses for the comparative period	$	54.48		$	58.85		$	57.67
Increase in benchmark oil prices	29.97			18.30			16.79
(Increase) decrease in quality and transportation discounts	(5.08)			2.80			(6.36)
Decrease (increase) in transportation expense	0.32			(0.26)			0.36
Average realized price, net of transportation expenses for the period	$	79.69		$	79.69		$	68.46
Average realized price, net of transportation expenses as a % of Brent	82		%	82		%	78		%

Ecuador	Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025			Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026			Six Months Ended June 30, 2026, Compared with Six Months Ended June 30, 2025
(U.S. Dollars per boe Sales Volumes NAR)
Average Brent price (M-1 Pricing)(*)	$	101.89		$	101.89		$	83.65
Average realized price, net of transportation expenses for the comparative period	$	53.70		$	53.71		$	60.77
Increase in benchmark prices	34.98			36.77			12.29
Decrease (increase) in quality and transportation discounts	12.28			9.83			(2.21)
Decrease (increase) in transportation expense	0.01			0.66			(0.02)
Average realized price, net of transportation expenses for the period	$	100.97		$	100.97		$	70.83
Average realized price, net of transportation expenses as a % of Brent	99		%	99		%	85		%

(*)The sales price in Ecuador is the average Brent price less discounts for the month prior to lifting (M-1).

41

Canada	Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025			Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026			Six Months Ended June 30, 2026, Compared with Six Months Ended June 30, 2025
(U.S. Dollars per boe Sales Volumes NAR)
Average WTI price	$	92.70		$	92.70		$	82.77
Average AECO price	$	1.55		$	1.55		$	1.73
Average realized price, net of transportation expenses for the comparative period	$	22.14		$	23.51		$	22.11
Increase in benchmark prices	28.89			19.97			15.17
Increase in quality and transportation discounts	(25.95)			(18.56)			(12.93)
(Increase) decrease in transportation expense	(0.14)			0.02			(0.17)
Average realized price, net of transportation expenses for the period	$	24.94		$	24.94		$	24.18
Average realized price, net of transportation expenses as a % of WTI	27		%	27		%	29		%

Total Company	Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025			Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026			Six Months Ended June 30, 2026, Compared with Six Months Ended June 30, 2025
(U.S. Dollars per boe Sales Volumes NAR)
Average Brent price	$	96.68		$	96.68		$	87.60
Average realized price, net of transportation expenses for the comparative period	$	41.53		$	46.02		$	44.07
Increase in benchmark prices	29.97			18.30			16.79
Increase in quality and transportation discounts	(8.84)			(1.83)			(7.31)
(Increase) decrease in transportation expense	(0.04)			0.13			(0.12)
Average realized price, net of transportation expenses for the period	$	62.62		$	62.62		$	53.43
Average realized price, net of transportation expenses as a % of Brent	65		%	65		%	61		%

DD&A Expenses

	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
	2026		2025		2026		2026		2025
DD&A Expenses, thousands of U.S. Dollars	$	62,334	$	68,635	$	69,874	$	132,208	$	140,837
DD&A Expenses, U.S. Dollars per boe	21.29		19.68		19.28		20.18		20.12

42

	Three Months Ended June 30, 2026				Three Months Ended March 31, 2026				Six Months Ended June 30, 2026
	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	$	43,479	$	29.92	$	46,378	$	27.28	$	89,857	$	28.50
Ecuador	10,334		25.59		15,964		22.45		26,298		23.59
Canada	8,411		7.86		7,419		6.12		15,830		6.93
Corporate	110		—		113		—		223		—
	$	62,334	$	21.29	$	69,874	$	19.28	$	132,208	$	20.18

	Three Months Ended June 30, 2025				Three Months Ended March 31, 2025				Six Months Ended June 30, 2025
	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	$	50,454	$	25.94	$	48,651	$	25.92	$	99,105	$	25.93
Ecuador	4,351		29.01		10,498		33.81		14,849		32.25
Canada	13,705		9.84		12,941		9.77		26,646		9.80
Corporate	125		—		112		—		237		—
	$	68,635	$	19.68	$	72,202	$	20.56	$	140,837	$	20.12

DD&A expenses for the three and six months ended June 30, 2026, decreased by 9% and 6%, respectively, due to lower costs in the depletable base for Canadian operations as a result of Simonette and Lodgepole areas disposition and higher proved reserves across reportable segments compared to the corresponding periods of 2025. On a per boe basis, DD&A expenses for the three and six months ended June 30, 2026, increased by $1.61 and $0.06, respectively, due to the lower sales volumes in the current periods.

DD&A expenses decreased by 11% from $69.9 million and increased by $2.01 on a per boe basis when compared to the prior quarter for the same reason mentioned above.

Asset Impairment

For the three and six months ended June 30, 2026 and 2025, we had no ceiling test impairment losses. We used a 12-month unweighted average of the first-day-of-the-month prices prior to the ending date of the period ended June 30, 2026 as follows: Brent Crude $78.55 per bbl, Edmonton Light Crude of C$98.28 per bbl, Alberta AECO spot price of C$1.55 per MMBtu, Edmonton Propane C$32.84 per boe, Edmonton Butane C$41.70 per boe and Edmonton Condensate C$100.06 per boe (June 30, 2025: Brent Crude of $73.60 per bbl, Edmonton Light Crude of C$91.55 per bbl, Alberta AECO spot price of C$1.69 per MMBtu Edmonton Propane C$33.82 per boe, Edmonton Butane C$47.11 per boe and Edmonton Condensate C$95.75 per boe).

43

G&A Expenses

	Three Months Ended June 30,					Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		% Change	2026		2026		2025		% Change
G&A Expenses before Stock-Based Compensation	$	13,219	$	14,136	(6)	$	15,149	$	28,368	$	26,062	9
G&A Stock-Based Compensation (Recovery) Expense	(3,757)		546		(788)	19,676		15,919		29		54,793
G&A Expenses, including Stock-Based Compensation	$	9,462	$	14,682	(36)	$	34,825	$	44,287	$	26,091	70
(U.S. Dollars Per boe Sales Volumes NAR)
G&A Expenses before Stock-Based Compensation	$	4.52	$	4.05	12	$	4.18	$	4.33	$	3.72	16
G&A Stock-Based Compensation (Recovery) Expense	(1.28)		0.16		(918)	5.43		2.43		—		100
G&A Expenses, including Stock-Based Compensation	$	3.24	$	4.21	(23)	$	9.61	$	6.76	$	3.72	82

G&A expenses before stock-based compensation for the three months ended June 30, 2026, decreased by 6% to $13.2 million compared to the corresponding period of 2025, primarily due to lower consulting and information technology costs during the current period. G&A expenses before stock-based compensation for the six months ended June 30, 2026, increased by 9% to $28.4 million, compared to the corresponding period of 2025, primarily due to higher costs associated with project optimization.

On a per boe basis, G&A expenses before stock-based compensation for the three and six months ended June 30, 2026 increased by $0.47 and $0.61 to $4.52 and $4.33, compared to the corresponding period of 2025 primarily due to 16% and 6% lower sales volumes, respectively.

Compared to the prior quarter, G&A expenses before stock-based compensation decreased by 13% due to lower consulting, information technology costs and lower salaries associated with headcount optimization. On a per boe basis, G&A expenses before stock-based compensation increased by $0.34 compared to the prior quarter due to 20% decrease in sales volumes.

G&A expenses after stock-based compensation for the three months ended June 30, 2026, decreased by 36% or $0.97 per boe compared to the corresponding period of 2025 due to lower share price resulting in stock-based compensation recovery. G&A expenses after stock-based compensation for the six months ended June 30, 2026, increased by 70% or $3.04 per boe compared to the corresponding period of 2025, due to higher stock-based compensation cost attributed to a higher share price during the current period.

Compared to the prior quarter, G&A expenses after stock-based compensation decreased by 73% or $6.37 per boe due to lower share price resulting in stock-based compensation recovery.

44

Severance Expenses

For the three and six months ended June 30, 2026, severance expenses were $0.1 million and $2.6 million, compared to nil for each of the corresponding periods of 2025 and $2.5 million for the prior quarter, respectively, due to headcount optimization.

Foreign Exchange Gains and Losses

For the three and six months ended June 30, 2026, we had foreign exchange losses of $2.6 million and $4.0 million, compared to $3.7 million and $7.6 million losses on foreign exchange in the corresponding periods of 2025, respectively, and a $1.4 million loss 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.

45

The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the three and six months ended June 30, 2026 and 2025 and the prior quarter:

	Three Months Ended June 30,		Three Months Ended March 31,	Six Months Ended June 30,
	2026	2025	2026	2026	2025
Change in the U.S. dollar against the Colombian peso	weakened by	weakened by	weakened by	weakened by	weakened by
	6%	3%	2%	8%	8%
Change in the U.S. dollar against the Canadian dollar	strengthened by	weakened by	strengthened by	strengthened by	weakened by
	2%	5%	1%	3%	5%

Financial Instruments Gains or Losses

The following table presents the nature of our financial instruments gains or losses for the three and six months ended June 30, 2026 and 2025, and the prior quarter:

	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025		2026		2026		2025
Commodity price derivative (gain) loss	$	(9,266)	$	(6,802)	$	88,618	$	79,352	$	(5,335)
Foreign currency derivative gain	(2,598)		(7,230)		(208)		(2,806)		(7,230)
Derivative instruments (gain) loss	$	(11,864)	$	(14,032)	$	88,410	$	76,546	$	(12,565)

46

Income Tax Expense

	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026			2025			2026			2025
Income (loss) before income tax	$	45,349		$	(8,093)		$	(100,418)		$	(23,820)
Current income tax expense	$	9,115		$	2,195		$	14,965		$	10,460
Deferred income tax expense (recovery)	11,373			2,453			(21,072)			(2,259)
Income tax expense (recovery)	$	20,488		$	4,648		$	(6,107)		$	8,201
Effective tax rate	45		%	(57)		%	6		%	(34)		%

Current income tax expense was $15.0 million for the six months ended June 30, 2026, compared to $10.5 million in the corresponding period of 2025, primarily due to higher taxable income.

The deferred tax for the six months ended June 30, 2026, was a recovery of $21.1 million mainly due to an increase in deductible temporary differences arising from tax losses generated during the period, unrealized hedging losses and accruals. These were partially offset by higher tax depreciation relative to accounting depreciation.

The deferred income tax for the six months ended June 30, 2025, was a recovery of $2.3 million primarily attributable to an increase in deductible temporary differences arising from tax losses generated during the period. This recovery was partially offset by temporary differences related to accelerated tax depreciation in excess of accounting depreciation.

For the six months ended June 30, 2026, the difference between the effective tax rate of 6% and the 21% statutory tax rate was primarily due to an increase in the non-deductible foreign translation adjustments and other non-deductible expenses. This was partially offset by an increase in the impact of foreign taxes and the 2025 true-up (recovery).

For the six months ended June 30, 2025, the difference between the effective tax rate of negative 34% and the 21% statutory 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.

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

(Thousands of U.S. Dollars)	Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026		% change	Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025		% change	Six Months Ended June 30, 2026 Compared with Six Months Ended June 30, 2025		% change
Net loss for the comparative period	$	(119,172)		$	(12,741)		$	(32,021)
Increase (decrease) due to:
Sales price	48,208			61,840			62,076
Sales volumes	(33,084)			(24,016)			(20,368)
Expenses:
Cash operating expenses	14,588			4,041			4,982
Transportation	1,396			587			(165)
Other taxes	(348)			(812)			(1,372)
Cash G&A, excluding stock-based compensation expense	1,930			917			(2,306)
Net lease payments	89			(310)			(698)
Severance	2,373			(95)			(2,563)
Interest, excluding amortization of deferred financing fees	5,337			4,452			2,685
Realized foreign exchange loss	1,885			862			1,388
Other gain	1,205			1,248			1,668

47

Cash settlement on derivative instruments	(22,950)			(35,663)			(47,188)
Current taxes	(3,265)			(6,920)			(4,505)
Interest income	102			252			228
Net change in funds flow from operations(1) from comparative period	17,466			6,383			(6,138)
Expenses:
Depletion, depreciation and accretion	7,540			6,301			8,629
Asset impairment	—			—
Deferred tax	(43,818)			(8,920)			18,813
Amortization of debt issuance costs	9,571			2,360			(5,100)
Stock-based compensation	23,433			4,303			(15,890)
Senior Notes exchange fees	12,118			(785)			(13,688)
Non-cash interest	(1,621)			(6,134)			(10,647)
Financial instruments loss, net of financial instruments settlements	123,224			33,495			(41,923)
Unrealized foreign exchange (loss) gain	(3,063)			251			2,138
Other non-cash (loss) gain	(728)			38			818
Net lease payments	(89)			310			698
Net change in net loss	144,033			37,602			(62,290)
Net income (loss) for the current period	$	24,861	121%	$	24,861	295%	$	(94,311)	(195)%

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

Capital expenditures during the three months ended June 30, 2026, were $54.3 million.

(Millions of U.S. Dollars)	Colombia		Ecuador		Canada		Total
Exploration	$	2.8	$	—	$	—	$	2.8
Development	$	41.3	$	6.0	$	4.2	$	51.5
Total Company	$	44.1	$	6.0	$	4.2	$	54.3

During the three months ended June 30, 2026, we drilled the following wells:

	Number of wells (Gross)	Number of wells (Net)
Development - Colombia	1	0.5
Total Company	1	0.5

During the three months ended June 30, 2026, we spud one development well in Cohembi field in Colombia which was producing as of June 30, 2026.

48

Liquidity and Capital Resources 

	As at
(Thousands of U.S. Dollars)	June 30, 2026		% Change	December 31, 2025
Cash and Cash Equivalents	$	126,728	53	$	82,931
7.75% Senior Notes due 2027	$	24,201	—	$	24,201
9.50% Senior Notes due 2029	$	87,639	(88)	$	716,340
9.75% Senior Notes due 2031	$	494,353	100	$	—

We believe that our capital resources, including cash on hand and cash generated from operations 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.

Senior Notes

During the six months ended June 30, 2026, we issued $503.6 million in aggregate principal amount of our 9.75% Senior Secured Amortizing Notes due 2031 (the “9.75% Senior Notes”), and paid $125.0 million in cash consideration in exchange for $628.7 million aggregate principal amount of our 9.50% Senior Secured Amortizing Notes due 2029 (the “9.50% Senior Notes”). The exchange was accounted for as debt modification.

The 9.75% Senior Notes will mature on April 15, 2031, unless earlier redeemed or re-purchased. The principal amount of 9.75% Senior Notes is to be repaid as follows: (i) October 15, 2029 - 15% of the principal amount; (ii) October 15, 2030 - 15% of the principal amount; (iii) April 15, 2031 - the remainder of the principal amount. On or before December 31, 2026 (“the Offer Date”), we are required to offer to purchase up to $30.0 million aggregate principal amount of the 9.75% Senior Notes (“the Offer Amount”). The Offer Amount will be reduced by the aggregate principal amount of any 9.75% Senior Notes redeemed or re-purchased by us in the open market transactions before the Offer Date.

During the six months ended June 30, 2026, we re-purchased $9.2 million of 9.75% Senior Notes for cash consideration of $8.1 million resulting in a $0.6 million gain on purchase, which included the write-off of deferred financing fees of $0.5 million. Subsequent to the quarter, we re-purchased an additional $15.0 million of 9.75% Senior Notes for cash consideration of $13.5 million.

At any time, prior to April 15, 2028, we may redeem up to 35% of the aggregate principal amount of 9.75% Senior Notes at a redemption price equal to 109.75% of the principal amount. Additionally, we may redeem all or a portion of the 9.75% Senior Notes on or after 2028 at the following redemption prices: 2028 - 104.875%; 2029 - 102.438%; 2030 and thereafter - 100%.

Under the terms of the 9.75% Senior Notes agreement, we are required to maintain compliance with the following financial covenants:

i.consolidated interest coverage ratio of not less than 2.50; and

ii.consolidated net debt (total debt excluding deferred financing fees less cash equivalents) to consolidated adjusted earnings before interest, taxes and DD&A (“EBITDA”) of not more than 3.00.

As at June 30, 2026, we were in compliance with all applicable covenants related to Senior Notes.

49

Credit Facility

On May 12, 2026, we, through our wholly owned subsidiary Gran Tierra Canada Ltd., amended our revolving credit facility with National Bank of Canada. As part of the amendment, the borrowing base has decreased to C$75.0 million (US$52.8 million). The available commitment under the revolving credit facility remained unchanged of a C$75.0 million (US$52.8 million), comprised of C$60.0 million (US$42.3 million) syndicated facility and C$15.0 million (US$10.6 million) of operating facility. 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. The revolving credit facility matures on October 30, 2027. As of June 30, 2026, the revolving credit facility remained undrawn.

Prepayment agreements

During the six months ended June 30, 2026, we amended our existing prepayment agreement with Trafigura, entering into a new oil prepayment agreement that covers both our Ecuadorian and Colombian oil production. The amended agreement provides for total prepayments of up to $350.0 million, including $325.0 million available immediately and an additional $25.0 million available at Trafigura’s sole discretion. The term of the amended prepayment agreement is 48 months.

Amounts drawn on this prepayment agreement are to be repaid through future oil deliveries. Shortfalls in crude oil deliveries in any given repayment period can be delivered during the next repayment period within three calendar months or paid in cash thereafter. Amounts under the prepayment facility are subject to interest based on SOFR risk-free rate plus a margin of 4.45% per annum. Under the terms of the prepayment agreement, we can repay the outstanding balance of the advance payment at any time without penalty. We were granted a grace period for re-payment of the principal amount drawn under the prepayment agreement with first re-payment starting April 2026.

Pursuant to the amended and restated prepayment agreement, proceeds from the new advance are required to be used exclusively to finance the repurchase or exchange of Senior Notes and to pay fees and expenses associated with the amended agreement.

We are required to maintain compliance with the following financial covenants related to amounts drawn under the prepayment agreement semi-annually, calculated on March 31 and September 30 of each year:

i.Asset Coverage Ratio of at least 150%, calculated using the net present value of the consolidated future cash flows of certain wholly owned subsidiaries of the Company that sell crude oil, projected through the final maturity date and discounted at 10% over the outstanding principal and the interest payable amount on the prepayment agreement at each reporting period. The net present value of the consolidated future cash flows of the Company is required to be based on 90% of the prevailing ICE Brent forward strip.

ii.Debt Service Coverage Ratio of at least 200%, calculated using the estimated crude oil to be delivered by the Company from any relevant time up to the final maturity date based on 80% of the prevailing ICE Brent forward strip and adjusted for quality differential and transportation discount over the outstanding principal amount under the prepayment agreement.

During the three and six months ended June 30, 2026, we drew nil and $166.5 million on oil prepayment and re-paid $28.8 million of the outstanding principal on oil prepayment via crude oil deliveries.

As at June 30, 2026, there was $287.7 million outstanding (December 31, 2025 - $150.0 million) on the oil prepayment agreement. Of this amount, $86.3 million (December 31, 2025 - $34.1 million) was classified as a current portion and included in accounts payable and accrued liabilities on our condensed consolidated balance sheet.

Assets exchange transaction

During the three months ended June 30, 2026, we completed an asset exchange transaction in which we transferred a 30% WI in certain oil and natural gas rights, wells, and tangible assets located in the Marten Hills area, in exchange for oil and natural gas rights, wells, and tangible assets in the Seal/Dawson area, WI ranging from 35% to 100%. In connection with this transaction, we received cash consideration of C$0.8 million (US$0.6 million).

50

Disposition of Lodgepole area

During the three months ended June 30, 2026, we completed a disposition of 54% WI and associated title rights in the Lodgepole area in Canada effective January 1, 2026, for a total cash consideration of C$12.8 million (US$9.3 million). As part of disposition, we derecognized asset retirement obligation attributed to Lodgepole area totaling C$17.5 million (US$12.8 million) on an undiscounted basis and C$9.0 million (US$6.6 million) on a discounted basis. No gain or loss was recognized in the statement of operations as the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.

Disposition of Simonette area

During the six months ended June 30, 2026, we disposed of the entire working interest and associated title rights in the Simonette Montney area in Canada effective January 1, 2026, for total cash consideration of C$66.3 million (US$48.6 million). No gain or loss was recognized in the statement of operations because the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.

Partnership with Ecopetrol S.A.

During the six months ended June 30, 2026, we entered into a strategic partnership with Ecopetrol S.A. to earn, subject to regulatory approvals and conditions precedent, a 49% WI in the Tisquirama Block in Colombia. Under the terms of the agreement, we have committed to fund approximately $47.1 million of a $92.4 million gross capital program over 40 months, including a minimum Phase 1 investment of $15.0 million. Upon completion of Phase 1, we will be entitled to 49% of production and are expected to assume operatorship. On May 27, 2026, we satisfied all outstanding conditions precedent to the partnership agreement and received regulatory approval.

Production sharing agreement (“PSA”)

During the six months ended June 30, 2026, we, through our wholly owned subsidiary, Gran Tierra Energy (Azerbaijan) GmbH, entered into an exploration, development and PSA with the State Oil Company of Azerbaijan Republic (“SOCAR”), providing for a 65% participating interest to us and a 35% participating interest to SOCAR. The PSA provides for a five-year exploration phase and, in the event of a commercial crude oil discovery, a 25-year development phase, with minimum work commitments during the exploration period to be completed within 36 months. These commitments include, among others, the acquisition of 250 square kilometers of 3D seismic data, the drilling of two exploration wells, and the conduct of geological and environmental impact studies. We have the right to relinquish the entire contract area during the exploration phase upon fulfillment of our exploration commitments, subject to 90 days’ prior notice to SOCAR.

Derivative positions

As at June 30, 2026, we had outstanding commodity price derivative positions as follows:

Oil
Type of Instrument	Start Period	End Period	Volume bbl/d	Reference	Sold Put (C$/bbl or $/bbl Weighted Average)		Purchased Put (C$/bbl or $/bbl Weighted Average)		Sold Call (C$/bbl or $/bbl Weighted Average)		Premium (C$/bbl or $/bbl Weighted Average)
Collar	07/01/26	09/30/26	500	WTI CMA	—		C$	75.00	C$	91.95	—
Put Option	07/01/26	09/30/26	500	Brent	—		60.00		—		4.30
Put Spread	07/01/26	09/30/26	5,000	Brent	45.00		55.00		—		21.64
Three Way	07/01/26	09/30/26	1,000	WTI CMA	C$	62.50	C$	72.50	C$	103.70	C$	0.95
Three Way	07/01/26	09/30/26	9,000	Brent	50.89		60.89		73.23		—
Collar	10/01/26	12/31/26	500	WTI CMA	—		C$	70.00	C$	92.47	—
Put Option	10/01/26	12/31/26	500	Brent	—		60.00		—		4.30
Three Way	10/01/26	12/31/26	500	WTI CMA	C$	60.00	C$	70.00	C$	107.00	C$	1.90
Put Spread	10/01/26	12/31/26	5,000	Brent	45.00		55.00		—		21.64

51

Three Way	10/01/26	12/31/26	9,000	Brent	50.33	60.33	72.49	—
Three Way	01/01/27	03/31/27	3,000	Brent	58.33	71.67	89.55	—

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$/GJ, Weighted Average)
Swap	07/01/26	09/30/26	20,000	Aeco 5A	C$	2.71	—	—
Swap	10/01/26	12/31/26	6,739	Aeco 5A	C$	2.71	—	—

As at June 30, 2026, we had the following outstanding foreign currency exchange 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: July 2026, to March 2027	9,000	30,996	COP	3,790	4,080
Collars: July 2026, to May 2027	32,000	110,208	COP	3,767	4,050

(1) At the June 30, 2026 foreign exchange rate.

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:

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2026		2025
Sources of cash and cash equivalents:
Net loss	$	(94,311)	$	(32,021)
Adjustments to reconcile net loss to Adjusted EBITDA(1) and funds flow from operations(1)
DD&A expenses	132,208		140,837
Interest expense	74,351		47,601
Severance	2,563		—
Income tax (recovery) expense	(6,107)		8,201
Non-cash lease expenses	2,971		3,461
Lease payments	(3,320)		(3,112)
Foreign exchange loss	4,028		7,554
Stock-based compensation expense	15,919		29
Financial instruments loss (gain)	31,432		(10,491)
Other (gain) loss	(728)		90
Adjusted EBITDA(1)	159,006		162,149
Severance	(2,563)		—
Current income tax expense	(14,965)		(10,460)
Contractual interest and other financing expenses	(37,001)		(39,686)
Realized foreign exchange loss	(1,365)		(2,753)
Funds flow from operations(1)	103,112		109,250
Proceeds from debt, net of issuance costs	—		44,781
Proceeds from exercise of stock options	748		22
Proceeds from disposition of property, plant and equipment	57,944		—

52

Proceeds from assets exchange	583		—
Net changes in assets and liabilities from operating activities	142,234		1,702
	304,621		155,755
Uses of cash and cash equivalents:
Additions to property, plant and equipment	(102,517)		(153,971)
Repayment of long-term debt	—		(1,894)
Re-purchase of Senior Notes	(8,087)		(1,712)
Senior Notes exchange fees	(13,688)		—
Repayment of Senior Notes	(125,000)		(24,828)
Re-purchase of shares of Common Stock	—		(3,466)
Settlement of asset retirement obligations	(1,510)		(3,045)
Lease payments	(8,347)		(7,849)
Foreign exchange loss on cash, and cash equivalents and restricted cash and cash equivalents	(297)		(766)
	(259,446)		(197,531)
Net increase (decrease) in cash and cash equivalents and restricted cash and cash equivalents	$	45,175	$	(41,776)

(1) Adjusted EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Refer to footnote 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 June 30, 2026, funds flow from operations increased by 12% compared to the corresponding period of 2025, due to an increase in benchmark oil prices, lower operating expenses, partially offset by lower sales volumes, higher cash settlements on derivative instruments and higher current income tax expense. During the six months ended June 30, 2026, funds flow from operations decreased by 6% compared to the corresponding period of 2025, primarily due to lower sales volumes, higher cash settlements on derivative instruments and higher current income tax expense, partially offset by an increase in benchmark oil prices and lower operating expenses.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Item 7 of our 2025 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. As at June 30, 2026, we have entered into commodity price derivative contracts to manage the variability in cash flows associated with the forecasted sale of our oil production, reduce commodity price risk and provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending.

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 85% 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 our operating costs, income taxes, VAT, and G&A expenses in all locations are in

53

local currency. In Canada, we receive 100% of our revenue in Canadian dollars and the majority of our capital and operating expenditures are in Canadian dollars or are based on Canadian dollar prices.

We have entered into foreign currency derivative contracts to manage the variability in cash flows associated with our forecasted Colombian peso denominated costs.

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

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 Canadian credit facility which bears floating rates of interest. As of June 30, 2026, 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 June 30, 2026.

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 June 30, 2026, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

54

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, 2025, 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, 2025. 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	(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 (1)
April 1-30, 2026	—	—	—	2,925,720
May 1-31, 2026	—	—	—	2,925,720
June 1-30, 2026	—	—	—	2,925,720
Total	—	—	—	2,925,720

(1) On November 3, 2025, we implemented a share re-purchase program (the “2025 Program”) through the facilities of the TSX, the NYSE American or alternative programs in Canada or the United States commencing November 6, 2025 and ending on November 5, 2026. Under the 2025 Program, we are able to purchase at prevailing market prices up to 2,925,720 shares of Common Stock, representing approximately 10% of the public float as of October 31, 2025.

Item 5. Other Information

During the three months ended June 30, 2026, 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).

55

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).
10.1	First Amending Agreement to the Second Amended and Restated Credit Agreement, dated as of May 12, 2026, between Gran Tierra Canada LTD., as borrower, the lenders party thereto, and National Bank of Canada, as administrative agent.	Filed herewith.
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 June 30, 2026, formatted in Inline XBRL (included within the Exhibit 101 attachments).

56

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: August 4, 2026	/s/ Gary S. Guidry
	By: Gary S. Guidry
	President and Chief Executive Officer
	(Principal Executive Officer)

Date: August 4, 2026	/s/ Ryan Ellson
	By: Ryan Ellson
	Executive Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer)

57

EX-10.1

Exhibit 10.1

FIRST AMENDING AGREEMENT TO THE

GRAN TIERRA CANADA LTD. SECOND AMENDED AND RESTATED CREDIT AGREEMENT

DATED OCTOBER 30, 2025

THIS FIRST AMENDING AGREEMENT (the “Agreement”) is made effective as of May 12, 2026 (the “First Amendment Date”), between GRAN TIERRA CANADA LTD., as borrower, NATIONAL BANK OF CANADA, as Agent, and the Lenders party hereto.

PREAMBLE:

A.Pursuant to a second amended and restated credit agreement dated October 30, 2025 (as amended, restated, supplemented or otherwise modified to the date hereof, the “Credit Agreement”) among Gran Tierra Canada Ltd. (the “Borrower”), the lenders from time to time party thereto (collectively, the “Lenders”) and National Bank of Canada, as agent on behalf of the Lenders (the “Agent”), the Lenders agreed to provide the Borrower with the Credit Facilities.

B.The Parties wish to amend the Credit Agreement on the terms and conditions provided in this Agreement.

AGREEMENT:

NOW THEREFORE in consideration of the premises, the covenants and the agreements herein contained and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged between the Parties, the Parties agree as follows:

1.Definitions. Capitalized terms used in this Agreement will, unless otherwise defined herein, have the meanings attributed to such terms in the Credit Agreement as amended by this Agreement (the “Amended Credit Agreement”).

2.Amendment Date. The amendments set forth in Section 3 below shall each be effective on the First Amendment Date.

3.Borrowing Base Determination. Pursuant to Section 3.9(b)(i) of the Credit Agreement and effective on the First Amendment Date, the Borrowing Base is reduced to $75,000,000. For certainty, the Individual Commitment Amounts of each Lender under the Credit Agreement shall remain unchanged. The next Scheduled Borrowing Base Date is October 31, 2026.

4.Amendments. The Credit Agreement is hereby amended as follows:

(a)Section 3.9(a) of the Credit Agreement is hereby deleted in its entirety and replaced with the following:

“(a) Borrowing Base. The Borrowing Base is, as of the First Amendment Date,

$75,000,000, provided that, in any event, each Credit Facility is made available by the applicable Lenders in accordance with their then-applicable Individual Commitment Amount, as set forth in Schedule B from time-to-time.”

(b)Schedule A to the Credit Agreement is hereby amended by:

(i)adding the following thereto, in correct alphabetical order, as a new defined term:

““First Amendment Date” means May 12, 2026.”

(ii)the definition of “Specified Permitted Distributions” is hereby deleted in its entirety and replaced with the following:

““Specified Permitted Distributions” means any Distributions, provided that the Aggregate Principal Amount outstanding under the Credit Facilities both prior to and immediately after giving effect to such Distribution does not exceed 30% of the Commitment Amount.”

5.Representations and Warranties. To confirm Lenders’ understanding concerning the Loan Parties and their businesses, properties and obligations, and to induce the Agent and Lenders to enter into this Agreement, the Borrower hereby reaffirms to the Agent, and Lenders, that, as of the date hereof, its representations and warranties contained in Section 11.1 of the Amended Credit Agreement, and except to the extent such representations and warranties relate solely to an earlier date, are true and correct in all material respects and additionally represents and warrants as follows on the First Amendment Date:

(a)the execution and delivery of this Agreement and the performance by it of its obligations under this Agreement (i) have been duly authorized, (ii) do not conflict with or contravene or constitute a default or create a Lien, other than a Lien which is a Permitted Encumbrance and other than a conflict, contravention, default or a Lien which could not be reasonably be expected to have a Material Adverse Effect, under: (A) its constating documents or bylaws or any resolution of its Directors or shareholders; (B) any agreement or document to which it is a party or by which any of its property is bound; or (C) any applicable Law;

(b)this Agreement is a legal, valid and binding obligation of it, enforceable against it in accordance with its terms, except to the extent that enforceability may be limited by applicable bankruptcy, insolvency, reorganization, or similar statutes affecting the enforcement of creditors’ rights generally and by general principles of equity; and

(c)subject to the consents provided for herein, no Default or Event of Default has occurred and is continuing or would result from giving effect to this Agreement.

6.Continuing Effect. Each of the Parties acknowledges and agrees that the Amended Credit Agreement, the Loan Documents and all other documents entered into in connection therewith, will be and continue in full force and effect and are hereby confirmed and the rights and obligations of all parties thereunder will not be effected or prejudiced in any manner except as specifically provided herein The Borrower hereby further acknowledges and agrees that all Security granted by it to the Agent for its own benefit and on behalf of the Lenders and others in connection with the Credit Agreement and any other documents executed and delivered pursuant thereto or in connection therewith, including confirmations and acknowledgements thereof, continue in full force and effect, without in any way impairing or derogating from any of the mortgages, pledges, charges, assignments, security interests and covenants therein contained or thereby constituted, as continuing security for all indebtedness, liabilities and other obligations of the Borrower under the Amended Credit Agreement and each other Loan Document to which it is a party.

7.Further Assurance. The Borrower will from time to time forthwith at the Agent’s request and at the Borrower’s own cost and expense make, execute and deliver, or cause to be done, made, executed and delivered, all such further documents, financing statements, assignments, acts, matters and things which may be reasonably required by the Agent and as are consistent with the

intention of the parties as evidenced herein, with respect to all matters arising under the Amended Credit Agreement.

8.Governing Law. This Agreement will be governed by and construed in accordance with the Laws in force in the Province of Alberta from time to time.

9.Expenses. The Borrower will pay or reimburse the Agent and the Lenders, as applicable, for the reasonable out of pocket expenses, including reasonable legal fees and disbursements (on a solicitor and his own client full indemnity basis) and enforcement costs, incurred by the Agent and the Lenders, as applicable, in connection with the negotiation, preparation, execution and maintenance of the Amended Credit Agreement.

10.Counterparts. This Agreement may be executed in any number of counterparts (including by facsimile or other electronic transmission), each of which when executed and delivered will be deemed to be an original, but all of which when taken together constitutes one and the same instrument. Any party hereto may execute this Agreement by signing any counterpart. The words “execution”, “execute”, “executed”, “signed”, “signature” and words of like import in this Agreement or in or related to any document to be signed in connection with this Agreement and the transactions contemplated hereby, shall be deemed to include electronic signatures or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, in accordance with applicable Law including, without limitation, as in provided Parts 2 and 3 of the Personal Information Protection and Electronic Documents Act (Canada), the Electronic Commerce Act, 2000 (Ontario), the Electronic Transactions Act (British Columbia), the Electronic Transactions Act (Alberta), or any other similar Laws based on the Uniform Electronic Commerce Act of the Uniform Law Conference of Canada. The Agent may, in its discretion, require that any such documents and signatures executed electronically or delivered by fax or other electronic transmission be confirmed by a manually-signed original thereof (and each Party agrees to promptly provide any such required signature page); provided that the failure to request or deliver the same shall not limit the effectiveness of any document or signature executed electronically or delivered by fax or other electronic transmission.

[Signature Pages Follow]

IN WITNESS WHEREOF each of the undersigned has duly executed this Agreement as of the First Amendment Date.

GRAN TIERRA CANADA LTD.,

as Borrower

By:	/S/Ryan Ellson
	Name:    Ryan Ellson Title:    Executive Vice President & Chief Financial Office
By:	/S/Gary Guidry
	Name:    Gary Guidry Title:    President&ChiefExecutive Officer

[Signature Page to First Amending Agreement (GTE)]

NATIONAL BANK OF CANADA,

as Agent

By:	/S/Adam Lamb
	Name:    Adam Lamb Title:    Authorized Signatory
By:	/S/Chuck Warnica
	Name:    Chuck Warnica Title:    Authorized Signatory

[SignaturePageto First Amending Agreement (GTE)]

NATIONAL BANK OF CANADA,

as Lender

By:	/S/Adam Lamb
	Name:    Adam Lamb Title:    Authorized Signatory
By:	/S/Chuck Warnica
	Name:    Chuck Warnica Title:    Authorized Signatory

[SignaturePageto First Amending Agreement (GTE)]

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

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

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Gary S. Guidry, certify that:

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

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

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

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

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date: August 4, 2026	/s/ Gary S. Guidry
	By: Gary S. Guidry
	President and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

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

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Ryan Ellson, certify that:

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

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

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

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

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date: August 4, 2026	/s/ Ryan Ellson
	By: Ryan Ellson
	Executive Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer)

EX-32.1

EXHIBIT 32.1

Certification of Chief Executive Officer and Chief Financial Officer

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

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

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

The Quarterly Report on Form 10-Q for the quarter ended June 30, 2026 (the “Form 10-Q”) to which this Certification is attached as Exhibit 32.1 fully complies with the requirements of Section 13(a) or 15(d) of the Exchange Act. The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, the undersigned have set their hands hereto as of the 4th day of August, 2026.

/s/ Gary S. Guidry	/s/ Ryan Ellson
By: Gary S. Guidry	By: Ryan Ellson
President and Chief Executive Officer	Executive Vice President and Chief Financial Officer

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