[10-Q] GRAN TIERRA ENERGY INC. Quarterly Earnings Report

Rhea-AI Filing Summary

Gran Tierra Energy (GTE) reported a Q3 2025 net loss of $19.95 million, reversing from a $1.13 million profit a year ago, as higher costs and interest expense offset steady sales. Oil, natural gas and NGL sales were $149.3 million, down 1% year over year, with pricing headwinds partly offset by higher volumes.

Production expanded with the i3 Energy assets and exploration success in Ecuador. NAR production averaged 35,962 BOEPD (up 38% year over year), though temporarily impacted by an Ecuador landslide and Moqueta field repairs; NAR sales volumes rose 47% to 37,353 BOEPD. Operating expenses increased to $68.4 million, reflecting Canada integration and Ecuador ramp-up. Adjusted EBITDA was $69.0 million, while funds flow from operations was $41.7 million.

Liquidity and capital structure shifted: cash and cash equivalents were $49.1 million, nine‑month operating cash flow was $156.1 million, and capital expenditures totaled $218.2 million. Long‑term debt stood at $761.8 million, including $735.8 million of 9.50% Senior Notes due 2029. Subsequent to quarter end, the company entered a crude oil sale and purchase agreement to receive an advance of up to $150.0 million related to Ecuador production. Shares outstanding were 35,295,753 as of October 28, 2025.

Insights

Energy credit & cash flow analyst

Q3 loss driven by cost inflation and interest; liquidity augmented by post‑quarter oil prepayment.

Gran Tierra posted a net loss as operating expenses ($68.4M) and interest expense ($25.4M) weighed against sales of $149.3M. Despite a 38% YoY lift in NAR production to 35,962 BOEPD, realized pricing softness limited revenue. Adjusted EBITDA reached $69.0M, and funds flow from operations was $41.7M.

Balance sheet shows cash of $49.1M and long‑term debt of $761.8M, dominated by $735.8M 9.50% notes due 2029. The Canada facility was expanded to C$75.0M on Oct 30, 2025, and the Colombia RBL base was revised to $60.0M on Oct 23, 2025. Subsequent oil prepayment provides up to $150.0M tied to Ecuador production, affecting near‑term liquidity.

Key dependencies include stable field operations in Colombia/Ecuador and hedging outcomes. Watch subsequent disclosures for draws/repayments under facilities and execution of the Oct 24, 2025 prepayment agreement, which will influence borrowing base dynamics and cash timing.

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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 September 30, 2025

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 October 28, 2025, 35,295,753 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 September 30, 2025

Table of contents

						Page
PART I			Financial Information
Item 1.			Financial Statements			3
Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
Item 3.			Quantitative and Qualitative Disclosures About Market Risk			50
Item 4.			Controls and Procedures			51
PART II			Other Information
Item 1.			Legal Proceedings			51
Item 1A.			Risk Factors			52
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds			52
Item 5.			Other information			52
Item 6.			Exhibits			53
SIGNATURES						54

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, including, but not limited to, our ability to successfully integrate the assets and operations of i3 Energy Plc (“i3Energy”) and realize the anticipated benefits and operating synergies expected from the 2024 acquisition of i3 Energy; certain of our operations are located in South America and unexpected problems can arise due to guerilla activity, strikes, local blockades or protests; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; other disruptions to local operations; global health events; global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and natural gas, including inflation and changes resulting from actual or anticipated tariffs and trade policies, global health crises, geopolitical events, including the ongoing conflicts in Ukraine and the Middle East, or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries and the resulting company or third-party actions in response to such changes; changes in commodity prices, including volatility or a prolonged decline in these prices relative to historical or future expected levels; the risk that current global economic and credit conditions may impact oil prices and oil consumption more than we currently predict, which could cause further modification of our strategy and capital spending program; prices and markets for oil and natural gas are unpredictable and volatile; the effect of hedges; the accuracy of productive capacity of any particular field; geographic, political and weather conditions can impact the production, transport or sale of our products; our ability to execute our business plan, which may include acquisitions and realize expected benefits from current or future initiatives; the risk that unexpected delays and difficulties in developing currently owned properties may occur; the ability to replace reserves and production and develop and manage reserves on an economically viable basis; the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates); the risk profile of planned exploration activities; the effects of drilling down-dip; the effects of waterflood and multi-stage fracture stimulation operations; the extent and effect of delivery disruptions, equipment performance and costs; actions by third parties; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; volatility or declines in the trading price of our common stock or bonds; the risk that we do not receive the anticipated benefits of government programs, including government tax refunds; our ability to access debt or equity capital markets from time to time to raise additional capital, increase liquidity, fund acquisitions or refinance debt; our ability to comply with financial covenants in our indentures and make borrowings under our credit agreement; and those factors set out in Part II, Item 1A “Risk Factors” in this Quarterly Report on Form 10-Q and Part I, Item 1A “Risk Factors” in our 2024 Annual Report on Form 10-K (the “2024 Annual Report on Form 10-K”). This information included herein is given as of the filing date of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission (“SEC”) and, except as otherwise required by the securities laws, we disclaim any obligation or undertaking to publicly release any updates or revisions to or to withdraw, any forward-looking statement contained in this Quarterly Report on Form 10-Q to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based.

GLOSSARY OF OIL AND GAS TERMS

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

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

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

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 September 30,												Nine Months Ended September 30,
			2025						2024						2025						2024
OIL, NATURAL GAS AND NGL SALES (Note 9)			$	149,254					$	151,373					$	466,784					$	474,559
EXPENSES
Operating			68,379						46,060						191,588						141,561
Transportation			4,297						3,911						13,342						14,185
Export tax			2,630						—						2,630						—
Depletion, depreciation and accretion (Note 6)			64,981						55,573						205,818						167,213
General and administrative			13,596						6,346						40,228						37,616
Transaction costs			—						1,459						—						1,459
Foreign exchange loss (gain)			284						(3,084)						7,838						(8,312)
Derivative instruments loss (gain) (Note 12)			2,066						—						(10,499)						—
Interest expense (Note 7)			25,447						19,892						73,048						56,714
			181,680						130,157						523,993						410,436
INTEREST INCOME			197						684						873						2,393
OTHER INCOME			1,003						—						1,290						—
(LOSS) INCOME BEFORE INCOME TAXES			(31,226)						21,900						(55,046)						66,516
INCOME TAX EXPENSE (RECOVERY)
Current (Note 10)			4,022						15,217						14,482						61,422
Deferred (Note 10)			(15,298)						5,550						(17,557)						(32,332)
			(11,276)						20,767						(3,075)						29,090
NET (LOSS) INCOME			$	(19,950)					$	1,133					$	(51,971)					$	37,426
OTHER COMPREHENSIVE (LOSS) INCOME
Foreign currency translation adjustment			(4,108)						—						5,666						—
NET AND COMPREHENSIVE (LOSS) INCOME			$	(24,058)					$	1,133					$	(46,305)					$	37,426
NET (LOSS) INCOME PER SHARE
- BASIC and DILUTED			$	(0.57)					$	0.04					$	(1.47)					$	1.20
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC and DILUTED (Note 8)			35,291,099						30,732,807						35,465,938						31,273,861

(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 September 30, 2025						As at December 31, 2024
ASSETS
Current Assets
Cash and cash equivalents (Note 13)			$	49,089					$	103,379
Accounts receivable			32,919						35,480
Inventory			37,542						43,116
Taxes receivable (Note 5)			31,162						18,095
Other current assets (Note 12 and 13)			15,939						11,201
Total Current Assets			166,651						211,271
Oil and Gas Properties
Proved			1,284,859						1,260,578
Unproved			124,471						119,520
Total Oil and Gas Properties			1,409,330						1,380,098
Other capital assets			31,107						43,033
Total Property, Plant and Equipment (Note 6)			1,440,437						1,423,131
Other Long-Term Assets
Deferred tax assets			37,574						11,718
Taxes receivable long-term (Note 5)			1,841						1,629
Other long-term assets (Note 12 and 13)			9,306						7,038
Total Other Long-Term Assets			48,721						20,385
Total Assets			$	1,655,809					$	1,654,787
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities			$	293,576					$	273,103
Current portion of long-term debt (Note 7 and 12)			—						24,807
Taxes payable (Note 5)			9,127						13,970
Equity compensation award liability (Note 8)			6,656						10,568
Total Current Liabilities			309,359						322,448
Long-Term Liabilities
Long-term debt (Note 7 and 12)			761,829						722,123
Deferred tax liabilities			83,180						64,114
Asset retirement obligation			113,501						105,936
Equity compensation award liability (Note 8)			11,499						17,456
Other long-term liabilities			10,484						9,142
Total Long-Term Liabilities			980,493						918,771
Contingencies (Note 11)
Shareholders' Equity
Common Stock (35,295,753 and 36,460,141 issued shares and 35,295,753 and 35,972,193 outstanding shares of Common Stock as at September 30, 2025 and December 31, 2024, respectively, par value $0.001 per share), (Note 8)			9,939						9,940
Additional paid-in capital			1,268,873						1,273,343
Treasury Stock (Note 8)			—						(3,165)
Accumulated other comprehensive loss			(1,070)						(6,736)
Deficit			(911,785)						(859,814)
Total Shareholders’ Equity			365,957						413,568
Total Liabilities and Shareholders’ Equity			$	1,655,809					$	1,654,787

(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)

			Nine Months Ended September 30,
			2025						2024
Operating Activities
Net (loss) income			$	(51,971)					$	37,426
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 6)			205,818						167,213
Deferred tax recovery (Note 10)			(17,557)						(32,332)
Stock-based compensation expense (Note 8)			172						6,376
Amortization of debt issuance costs (Note 7)			12,184						9,175
Unrealized foreign exchange loss (gain)			2,936						(7,670)
Unrealized derivative instruments gain			(964)						—
Cash settlement of asset retirement obligation			(4,746)						(262)
Non-cash lease expenses			4,648						4,164
Lease payments			(4,686)						(3,540)
Other loss			355						—
Net change in assets and liabilities from operating activities (Note 13)			9,867						32,164
Net cash provided by operating activities			156,056						212,714
Investing Activities
Additions to property, plant and equipment (Note 6 and 13)			(218,155)						(163,823)
Proceeds from disposition of property, plant and equipment (Note 6)			7,500						—
Net cash used in investing activities			(210,655)						(163,823)
Financing Activities
Proceeds from issuance of Senior Notes, net of issuance costs (Note 7)			—						222,528
Proceeds from long-term debt, net of issuance costs (Note 7)			48,921						—
Repayment of long-term debt (Note 7)			(7,743)						—
Repayment of Senior Notes (Note 7)			(24,828)						(36,364)
Purchase of Senior Notes (Note 7)			(1,712)						—
Re-purchase of shares of Common Stock (Note 8)			(3,466)						(12,144)
Proceeds from exercise of stock options			40						367
Lease payments			(8,473)						(9,422)
Net cash provided by financing activities			2,739						164,965
Foreign exchange (loss) gain on cash, cash equivalents and restricted cash and cash equivalents			(1,299)						986
Net (decrease) increase in cash, cash equivalents and restricted cash and cash equivalents			(53,159)						214,842
Cash and cash equivalents and restricted cash and cash equivalents, beginning of period (Note 13)			111,337						71,038
Cash and cash equivalents and restricted cash and cash equivalents, end of period (Note 13)			$	58,178					$	285,880
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 September 30,												Nine Months Ended September 30,
			2025						2024						2025						2024
Share Capital
Balance, beginning of period			$	9,939					$	9,935					$	9,940					$	9,936
Cancellation of shares of Common Stock (Note 8)			—						(1)						(1)						(2)
Balance, end of period			$	9,939					$	9,934					$	9,939					$	9,934
Additional Paid-in Capital
Balance, beginning of period			$	1,268,654					$	1,237,844					$	1,273,343					$	1,249,651
Exercise of stock options			18						—						40						367
Stock-based compensation (Note 8)			201						2,312						2,119						2,883
Modification of stock options (Note 8)			—						—						—						(4,057)
Cancellation of shares of Common Stock (Note 8)			—						(3,617)						(6,629)						(12,305)
Balance, end of period			$	1,268,873					$	1,236,539					$	1,268,873					$	1,236,539
Treasury Stock
Balance, beginning of period			$	—					$	(141)					$	(3,165)					$	(163)
Re-purchase of shares of Common Stock (Note 8)			—						(3,477)						(3,465)						(12,144)
Cancellation of shares of Common Stock (Note 8)			—						3,618						6,630						12,307
Balance, end of period			$	—					$	—					$	—					$	—
Accumulated and other comprehensive income (loss)
Balance, beginning of period			$	3,038					$	—					$	(6,736)					$	—
Other comprehensive (loss) income			(4,108)						—						5,666						—
Balance, end of period			$	(1,070)					$	—					$	(1,070)					$	—
Deficit
Balance, beginning of period			$	(891,835)					$	(826,737)					$	(859,814)					$	(863,030)
Net (loss) income			(19,950)						1,133						(51,971)						37,426
Balance, end of period			$	(911,785)					$	(825,604)					$	(911,785)					$	(825,604)
Total Shareholders’ Equity			$	365,957					$	420,869					$	365,957					$	420,869

(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, 2024, included in the Company’s 2024 Annual Report on Form 10-K.

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

Recently Issued Accounting Pronouncements

In November 2024 and January 2025, FASB issued ASU 2024-03 and ASU 2025-01, “Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures”. The amendments in ASU 2024-03 require disclosure, in the notes to financial statements, of specified information about certain costs and expenses recognized as part of oil-and natural gas-producing activities included in each relevant expense caption on the face of statement of operations. In addition, this ASU requires the presentation of specific expense captions of comprehensive income on the face of the statements of operations. ASU 2025-01 clarifies the effective date of ASU 2024-03 to be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods within annual periods beginning after December 15, 2027. The Company is currently assessing the impact of that update will have on its financial statements.

In July 2025, the 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 will be 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 is currently assessing the impact of that update will have on its financial statements.

Recently Adopted Accounting Pronouncements

In December 2023, FASB issued ASU 2023-09, “Improvements to Income Tax Disclosures”. ASU 2023-09 enhances the income tax disclosures to enable investors to better understand an entity’s exposure to potential changes in jurisdictional tax legislation and associated risks and opportunities, income tax information that effects cash flow forecasts and potential opportunities to increase future cash flows. This ASU is effective for annual reporting periods beginning after December 15, 2024 and should be applied prospectively, with retrospective application permitted. The Company adopted ASU 2023-09 effective January 1, 2025. The implementation of this update does not impact quarterly income tax disclosures and is not expected to have material impact on annual income tax disclosures.

3. Business Combination

On October 31, 2024, the Company acquired all of the issued and outstanding common shares of i3 Energy Plc (“i3 Energy”), subsequently renamed as Gran Tierra UK Limited (“Gran Tierra UK”) for $204.5 million, consisting of cash consideration of $161.8 million, cash dividend of $4.0 million, cash settlement of stock options of $2.0 million and 5,808,925 shares of the Company’s Common Stock, the fair value of which was determined to be $36.7 million based on the closing price of the

7

Company’s shares on the acquisition date. The acquisition was accounted for as a business combination using the acquisition method with Gran Tierra being the acquirer, whereby the assets acquired and liabilities assumed were recognized at their fair values as at the i3 Energy acquisition date, and the results of i3 Energy were included with those of Gran Tierra from that date. Fair value estimates were made based on significant unobservable (Level 3) inputs and based on the best information available at the time.

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

Management is continuing to review and assess information to accurately determine the acquisition date fair value of the proved oil and natural gas properties and deferred tax assets and liabilities acquired. As at September 30, 2025, there were no changes to initial measurement of fair value of the proved oil and natural gas properties and deferred tax assets and liabilities acquired.

Pro Forma Results (unaudited)

Pro forma for the three and nine months ended September 30, 2024 are shown below, as if the i3 Energy acquisition had occurred on January 1, 2024. Pro forma results are not indicative of actual results or future performance:

			Three Months Ended September 30,						Nine Months Ended September 30,
(Unaudited, thousands of U.S. Dollars)			2024						2024
Oil, natural gas and NGL sales			$	180,598					$	580,099
Net income			$	3,852					$	50,911

4. Segment and Geographic Reporting

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

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

			Three Months Ended September 30, 2025
(Thousands of U.S. Dollars)			Colombia			Ecuador			Canada			Other			Total
Oil, natural gas and NGL sales			$	101,999		$	20,605		$	26,650		$	—		$	149,254
Operating expenses			44,819			9,157			14,403			—			68,379
Transportation expenses			2,902			1,070			325			—			4,297
Segmented earnings			$	54,278		$	10,378		$	11,922		$	—		$	76,578
Export tax															2,630
DD&A expenses															64,981
General and administrative expenses															13,596
Foreign exchange loss															284
Derivative instruments loss															2,066
Interest expense															25,447
Non-segmented expenses															109,004

8

Interest income															197
Other income															1,003
Loss before income taxes															(31,226)
Income tax expense															(11,276)
Net loss															$	(19,950)
Segment capital expenditures			$	50,323		$	10,546		$	3,250		$	65		$	64,184

			Nine Months Ended September 30, 2025
(Thousands of U.S. Dollars)			Colombia			Ecuador			Canada			Other			Total
Oil, natural gas and NGL sales			$	329,339		$	50,123		$	87,322		$	—		$	466,784
Operating expenses			126,005			21,352			44,231			—			191,588
Transportation expenses			9,848			2,604			890			—			13,342
Segmented earnings			$	193,486		$	26,167		$	42,201		$	—		$	261,854
Export tax															2,630
DD&A expenses															205,818
General and administrative expenses															40,228
Foreign exchange loss															7,838
Derivative instruments gain															(10,499)
Interest expense															73,048
Non-segmented expenses															319,063
Interest income															873
Other income															1,290
Loss before income taxes															(55,046)
Income tax expense															(3,075)
Net loss															$	(51,971)
Segment capital expenditures			$	110,741		$	56,133		$	50,786		$	495		$	218,155

9

			Three Months Ended September 30, 2024
(Thousands of U.S. Dollars)			Colombia			Ecuador			Canada			Other			Total
Oil, natural gas and NGL sales			$	143,128		$	8,245		$	—		$	—		$	151,373
Operating expenses			42,250			3,810			—			—			46,060
Transportation expenses			3,445			466			—			—			3,911
Segmented earnings			$	97,433		$	3,969		$	—		$	—		$	101,402
DD&A expenses															55,573
General and administrative expenses															6,346
Transaction costs															1,459
Foreign exchange gain															(3,084)
Interest expense															19,892
Non-segmented expenses															80,186
Interest income															684
Income before income taxes															21,900
Income tax expense															20,767
Net income															$	1,133
Segment capital expenditures			$	54,124		$	(4,430)		$	—		$	85		$	49,779

			Nine Months Ended September 30, 2024
(Thousands of U.S. Dollars)			Colombia			Ecuador			Canada			Other			Total
Oil, natural gas and NGL sales			$	456,172		$	18,387		$	—		$	—		$	474,559
Operating expenses			132,643			8,918			—			—			141,561
Transportation expenses			13,187			998			—			—			14,185
Segmented earnings			$	310,342		$	8,471		$	—		$	—		$	318,813
DD&A expenses															167,213
General and administrative expenses															37,616
Transaction costs															1,459
Foreign exchange gain															(8,312)
Interest expense															56,714
Non-segmented expenses															254,690
Interest income															2,393
Income before income taxes															66,516
Income tax expense															29,090
Net income															$	37,426
Segment capital expenditures			$	119,000		$	44,271		$	—		$	552		$	163,823

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			As at September 30, 2025
(Thousands of U.S. Dollars)			Colombia			Ecuador			Canada			Other			Total
Property, plant and equipment			$	996,434		$	168,179		$	267,590		$	8,234		$	1,440,437
All other assets			121,405			13,093			24,095			56,779			215,372
Total Assets			$	1,117,839		$	181,272		$	291,685		$	65,013		$	1,655,809
			As at December 31, 2024
(Thousands of U.S. Dollars)			Colombia			Ecuador			Canada			Other			Total
Property, plant and equipment			$	1,022,808		$	143,034		$	247,512		$	9,777		$	1,423,131
All other assets			99,100			27,942			62,541			42,073			231,656
Total Assets			$	1,121,908		$	170,976		$	310,053		$	51,850		$	1,654,787

5. Taxes Receivable and Payable

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

(Thousands of U.S. Dollars)			As at September 30, 2025						As at December 31, 2024
Taxes Receivable
Current
VAT Receivable			$	1,376					$	657
Income Tax Receivable			29,786						17,438
			$	31,162					$	18,095
Long-Term
Income Tax Receivable			$	1,841					$	1,629
Taxes Payable
Current
VAT Payable			$	(3,173)					$	(7,640)
Income Tax Payable			(5,954)						(6,330)
			$	(9,127)					$	(13,970)
Total Net Taxes Receivable			$	23,876					$	5,754

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

(Thousands of U.S. Dollars)			VAT Receivable/(Payable)(1)						Income Tax Receivable						Total Net Taxes Receivable
Balance, as at December 31, 2024			$	(6,983)					$	12,737					$	5,754
Collected through direct government refunds			(734)						(256)						(990)
Collected through sales contracts			(70,572)						—						(70,572)
Taxes paid			76,120						4,031						80,151
Withholding taxes paid			—						19,934						19,934
Current tax expense			—						(14,482)						(14,482)
Foreign exchange gain			372						3,709						4,081
Balance, as at September 30, 2025			$	(1,797)					$	25,673					$	23,876

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

6. Property, Plant and Equipment

11

(Thousands of U.S. Dollars)			As at September 30, 2025						As at December 31, 2024
Oil and natural gas properties
Proved			$	5,508,751					$	5,298,085
Unproved			124,471						119,520
			5,633,222						5,417,605
Other (1)			63,137						97,795
			5,696,359						5,515,400
Accumulated depletion, depreciation and impairment			(4,255,922)						(4,092,269)
			$	1,440,437					$	1,423,131

(1) The “other” category includes right-of-use assets for operating and finance leases of $50.7 million, which had a net book value of $21.2 million as at September 30, 2025 (December 31, 2024 - $70.1 million, which had a net book value of $35.1 million).

During the three months ended September 30, 2025, the Company entered into one operating lease contract related to a motor vehicle and one finance lease contract related to power generation equipment and capitalized $0.1 million and $1.4 million, respectively, right-of-use assets in relation to these contracts. The Company also derecognized a lease related to power generation following an early termination by reducing net book value of right-of-use asset of $9.8 million and lease liability of $10.2 million.

During the nine months ended September 30, 2025, the Company entered into one operating lease contract related to a motor vehicle and two finance lease contracts related to power generation equipment and capitalized $0.1 million and $8.0 million, respectively, right-of-use assets in relation to these contracts.

On September 8, 2025, the Company, through its wholly owned subsidiary, Gran Tierra UK Limited, a United Kingdom limited company, closed the sale agreement for its wholly owned subsidiary, Gran Tierra North Sea Limited (“GTNSL”) for total consideration of $7.5 million. The disposal of GTNSL did not result in any gain or loss on disposition.

For the three and nine months ended September 30, 2025 and 2024, the Company had no ceiling test impairment losses. The Company used a 12-month unweighted average of the first-day-of the month prices prior to the ending date of the period ended September 30, 2025 as follows: Brent Crude $71.61 per boe, Edmonton Light Crude of C$89.65 per boe, Alberta AECO spot price of C$1.70 per “MMBtu” Edmonton Propane C$34.71 per boe, Edmonton Butane C$43.07 per boe and Edmonton Condensate C$93.35, and for the nine months ended September 30, 2024 Brent Crude of $82.10 per boe.

On July 31, 2025, the Company, through its indirect wholly owned subsidiaries, Gran Tierra Energy Ecuador 1 GmbH and Gran Tierra Energy Ecuador 2 GmbH, entered into definitive agreements to acquire all of GeoPark Ecuador S.A.’s and Frontera Energy Colombia Corp Sucursal Ecuador’s interests in the Perico and Espejo Blocks (the “Blocks”) and their associated Consortiums (the “Consortiums”). The aggregate purchase price for the Blocks and Consortiums is $15.5 million, subject to customary working capital adjustments as of the effective date of January 1, 2025. The agreement includes an additional contingent consideration of $1.5 million, payable upon the Perico Block achieving cumulative gross production of two million barrels starting from January 1, 2025. The acquisitions are expected to close upon satisfaction of customary closing conditions, including the receipt of regulatory approvals for closing and operations takeover from the Ministry of Energy of Ecuador. Closing is anticipated no earlier than the fourth quarter of 2025.

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7. Debt and Debt Issuance Costs

The Company’s debt as at September 30, 2025, and December 31, 2024, was as follows:

(Thousands of U.S. Dollars)			As at September 30, 2025						As at December 31, 2024
Current
6.25% Senior Notes, due February 2025 (“6.25% Senior Notes”)			$	—					$	24,828
Unamortized debt issuance costs			—						(21)
			$	—					$	24,807
Long-Term
Credit Facility - Canada			$	19,934					$	—
Credit Facility - Colombia			24,500						—
7.75% Senior Notes, due May 2027 (“7.75% Senior Notes”)			24,201						24,201
9.50% Senior Notes, due October 2029 (“9.50% Senior Notes”)			735,790						737,590
Unamortized Senior Notes discount			(33,568)						(41,918)
Unamortized debt issuance costs			(16,604)						(18,075)
			754,253						701,798
Long-term lease obligation (1)			7,576						20,325
			$	761,829					$	722,123
Total Debt			$	761,829					$	746,930

(1) The current portion of the lease obligation has been included in accounts payable and accrued liabilities on the Company’s balance sheet and totaled $11.8 million as at September 30, 2025 (December 31, 2024 - $15.3 million).

Credit Facility - Canada

The Company, through its wholly owned subsidiary Gran Tierra Canada Ltd., has a revolving credit facility with National Bank of Canada dated March 22, 2024 with a borrowing base of C$100.0 million (US$71.8 million as of September 30, 2025) and the available commitment of a C$50.0 million (US$35.9 million as of September 30, 2025) revolving credit facility comprised of C$35.0 million (US$25.1 million as of September 30, 2025) syndicated facility and C$15.0 million (US$10.8 million as of September 30, 2025) 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. As of September 30, 2025, the outstanding balance under the facility was C$27.7 million (US$19.9 million) and the weighted-average interest rate on borrowings during the three and nine months ended September 30, 2025 was 6.64% and 6.48% respectively. On July 22, 2025, the borrowing base was redetermined by National Bank of Canada at C$100.0 million, of which available commitment is C$50.0 million.

On October 30, 2025, the existing revolving credit facility was amended to increase available commitment amount from C$50.0 million (US$35.9 million as of September 30, 2025) to C$75.0 million (US$53.9 million as of September 30, 2025) and extend the term to a two-year maturing October 30, 2027. The borrowing base was maintained at C$100.0 million.

13

Credit Facility - Colombia

On April 16, 2025, the Company, through its wholly owned subsidiary, Gran Tierra Energy Colombia GmbH, a Swiss limited liability company, entered into a $75.0 million reserve-based lending facility (the “RBL Facility”). Any loans incurred under the reserve-based landing facility will mature on April 16, 2028. The availability of borrowings under the RBL Facility is subject to an annual borrowing base determination which will occur on or before May 1 of each year. The RBL Facility will bear interest at a rate per annum equal to, at Company’s option, either (a) a customary base rate (subject to a floor of 1.00%) plus an applicable margin of 4.5% or (b) a term secured overnight finance rate (“SOFR”) reference rate plus an applicable margin of 4.5%. Interest on base rate borrowings is payable quarterly in arrears and interest on term SOFR borrowings accrues in respect of interest periods of three or six months, at the election of the Company, and is payable on the last day of such interest period. The facility also includes a commitment fee of 1.58% per annum on undrawn amounts.

On October 23, 2025, the existing RBL facility was amended (“ the Amended RBL Facility”) to reduce the borrowing base to $60.0 million and revised certain related terms, including provisions governing borrowings, hedging obligations, and borrowing base redetermination. Under the terms of Amended RBL Facility, the Company is required to repay any amounts outstanding in excess of $20.0 million upon funding the oil prepayment agreement (Note 14) and the lender may initiate a redetermination of the borrowing base if advances requested by the Company are in excess of $20.0 million.

As of September 30, 2025 the outstanding balance under the RBL Facility was $24.5 million. For the three and nine months ended September 30, 2025, the weighted-average interest rate on borrowings was 9.05% and 8.79%, respectively.

Under the terms of the RBL Facility, the Company is required to maintain compliance with the following financial covenants:

i.consolidated net debt to consolidated adjusted EBITDA ratio that may not exceed 3.00 to 1.00, and

ii.consolidated interest coverage ratio that may not be less than 2.50 to 1.00

The Company was in compliance with all applicable covenants related to the RBL facility as of September 30, 2025.

Senior Notes

During the nine months ended September 30, 2025, the Company paid at maturity the remaining principal of $24.8 million of 6.25% Senior Notes due in February 2025 for cash consideration of $25.6 million, including interest payable of $0.8 million.

During the nine months ended September 30, 2025, the Company also purchased $1.8 million of outstanding 9.50% Senior Notes for cash consideration of $1.7 million resulting in a $0.1 million loss on purchase, which included the write-off of deferred financing fees of $0.1 million.

The principal amount of 9.50% Senior Notes is to be repaid as follows: (i) October 15, 2026, 25% of the principal amount; (ii) October 15, 2027 5% of the principal amount; (iii) October 15, 2028, 30% of the principal amount; and (iv) October 15, 2029, the remainder of the principal amount.

At September 30, 2025, we had $24.2 million aggregate principal amount of outstanding 7.75% Senior Notes due 2027, and $735.8 million aggregate principal amount of outstanding 9.50% Senior Notes due 2029.

As at September 30, 2025, the Company was in compliance with all applicable covenants related to the Senior Notes.

Leases

During the three months ended September 30, 2025, the Company entered into one operating lease of $0.1 million and one finance lease of $1.4 million. The operating lease has a term of three years and a discount rate of 10.9%. The finance lease has a term of one year term and a discount rate of 9.6%.

During the nine months ended September 30, 2025, the Company entered into one operating lease of $0.1 million and two finance leases of $8.0 million. The operating lease has a term of three years and a discount rate of 10.9%. The finance leases have a lease term ranging from one to two years and a weighted average discount rate of 9.6%.

14

Interest Expense

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

			Three Months Ended September 30,									Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025			2024
Contractual interest and other financing expenses			$	21,178		$	16,783					$	60,864		$	47,539
Amortization of debt issuance costs			4,269			3,109						12,184			9,175
			$	25,447		$	19,892					$	73,048		$	56,714

8. Share Capital

			Shares of Common Stock
Shares issued at December 31, 2024			36,460,141
Treasury shares			(487,948)
Shares issued and outstanding at December 31, 2024			35,972,193
Shares issued on option exercise			16,364
Shares re-purchased and cancelled			(692,804)
Shares issued and outstanding at September 30, 2025			35,295,753

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

During the three and nine months ended September 30, 2025, the Company re-purchased nil and 692,804 shares at a weighted average price of nil and $5.00 per share (three and nine months ended September 30, 2024 - 371,130 and 1,662,110 shares under the 2023 program at a weighted average price of $9.37 and $7.31 per share), respectively. As of September 30, 2025, the Company cancelled 487,948 shares held as treasury shares at December 31, 2024, and cancelled 692,804 shares re-purchased during the nine months ended September 30, 2025. During the period from November 6, 2024 to October 29, 2025, the Company has re-purchased 1,180,752 shares out of a maximum of 3,545,872 under the 2024 Program.

Equity Compensation Awards

The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), restricted share units (“RSUs”) and stock option activity for the nine months ended September 30, 2025:

			PSUs			DSUs			RSUs			Stock Options
			Number of Outstanding Share Units			Number of Outstanding Share Units			Number of Outstanding Share Units			Number of Outstanding Stock Options			Weighted Average Exercise Price/Stock Option ($)
Balance, December 31, 2024			5,380,629			904,674			666,127			1,550,497			8.82
Granted			2,926,234			108,835			642,324			—			—
Exercised			(1,066,555)			(136,971)			(197,418)			(58,724)			2.52
Forfeited			(300,890)			—			(57,999)			(8,155)			8.86
Expired			—			—			—			(421,881)			7.94
Balance, September 30, 2025			6,939,418			876,538			1,053,034			1,061,737			9.52

15

On May 1, 2024, the Company amended the settlement terms of all outstanding stock option awards. As of this date, all outstanding stock options are to be net settled in cash resulting in a change in classification of stock options from equity to liability. On May 1, 2024, the Company recorded a liability of $4.4 million and an additional stock-based compensation costs of

$0.4 million related to the modification of the stock option plan.

As at September 30, 2025, the equity compensation award liability on the Company’s balance sheet included $1.0 million of current liability related to the Company’s outstanding stock options.

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

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

For the three and nine months ended September 30, 2025, there was $0.1 million and $0.2 million of stock-based compensation expense, respectively. For the three and nine months ended September 30, 2024, there was $3.1 million of stock-based compensation recovery and $6.4 million of stock-based compensation expense, respectively.

As at September 30, 2025, there was $10.9 million (December 31, 2024 - $21.9 million) of unrecognized compensation costs related to unvested PSUs, RSUs and stock options, which are expected to be recognized over a weighted-average period of 1.4 years. During the nine months ended September 30, 2025, the Company paid out $7.2 million for PSUs vested on December 31, 2024 (nine months ended September 30, 2024 - $10.4 million for PSUs vested on December 31, 2023).

During the three and nine months ended September 30, 2025, the Company awarded 0.1 million and 0.6 million RSU 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 September 30, 2025, in cash.

Net Income (Loss) per Share

Basic net income or loss per share is calculated by dividing net income or loss attributable to common shareholders by the weighted average number of shares of Common Stock issued and outstanding during each period.

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

Weighted Average Shares Outstanding

For the three and nine months ended September 30, 2025 and 2024, all options were excluded from the diluted loss per share calculation as the options were anti-dilutive.

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9. Revenue

			Three Months Ended September 30, 2025															Nine Months Ended September 30, 2025
			Crude Oil			Natural Gas			NGL			Total Revenue						Crude Oil			Natural Gas			NGL			Total Revenue
Colombia			$	101,999		$	—		$	—		$	101,999					$	329,339		$	—		$	—		$	329,339
Ecuador			20,605			—			—			20,605						50,123			—			—			50,123
Canada			19,273			5,818			1,559			26,650						57,027			22,774			7,521			87,322
			$	141,877		$	5,818		$	1,559		$	149,254					$	436,489		$	22,774		$	7,521		$	466,784

			Three Months Ended September 30, 2024															Nine Months Ended September 30, 2024
			Crude Oil			Natural Gas			NGL			Total Revenue						Crude Oil			Natural Gas			NGL			Total Revenue
Colombia			$	143,128		$	—		$	—		$	143,128					$	456,172		$	—		$	—		$	456,172
Ecuador			8,245			—			—			8,245						18,387			—			—			18,387
Canada			—			—			—			—						—			—			—			—
			$	151,373		$	—		$	—		$	151,373					$	474,559		$	—		$	—		$	474,559

During the three months ended September 30, 2025, the Company’s production was sold primarily to one major customer representing 66% of the total sales volumes, of which 75% was sold in Colombia, 15% in Ecuador and 10% in Canada (three months ended September 30, 2024, one major customer representing 100% of total sales volumes in Colombia and Ecuador).

During the nine months ended September 30, 2025, the Company’s production was sold primarily to one major customer representing 65% of the total sales volumes of which 79% was sold in Colombia, 11% in Ecuador and 10% in Canada (nine months ended September 30, 2024, one major customer representing 100% of total sales volumes in Colombia and Ecuador).

During the third quarter of 2025, the Company retrospectively reclassified transportation expenses against revenue, which were previously recorded separately from revenue, resulting in decrease of revenue by immaterial impact of $3.1 million and $5.5 million for the three and six months ended June 30, 2025, respectively, and $2.4 million for the three months ended March 31, 2025.

As at September 30, 2025, accounts receivable included $11.9 million of accrued sales revenue related to September 2025 production (December 31, 2024 - $13.4 million related to December 2024 production).

10. Taxes

The Company’s effective tax rate was 6% for the nine months ended September 30, 2025, compared to 44% in the comparative period of 2024.

Current income tax expense was $14.5 million for the nine months ended September 30, 2025, compared to $61.4 million in the corresponding period of 2024, primarily due to lower taxable income.

For the nine months ended September 30, 2025, the Company recognized a deferred tax recovery of $17.6 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 nine months ended September 30, 2024, the deferred income tax recovery was $32.3 million primarily as a result of the recognition of additional tax losses resulting from a tax planning.

For the nine months ended September 30, 2025, the difference between the effective tax rate of 6% and the 35% statutory tax rate was primarily due to permanent differences and valuation allowance. This was partially offset by an increase in the impact of foreign taxes.

For the nine months ended September 30, 2024, the difference between the effective tax rate of 44% and the 50% Colombian tax rate was primarily due to a decrease in the impact of foreign taxes, 2022 true-up related to tax planning and non-taxable

17

foreign exchange adjustments. These were partially offset by an increase in valuation allowance, other permanent differences, non-deductible stock-based compensation and non-deductible royalties in Colombia.

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 September 30, 2025, the Company had provided letters of credit and other credit support totaling $218.2 million (December 31, 2024 - $244.5 million) as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, the Suroriente Block, and other capital or operating requirements as well as for transportation capacity in Canada.

12. Financial Instruments and Fair Value Measurement

Financial Instruments

Financial instruments are initially recorded at fair value, defined as the price that would be received to sell an asset or paid to market participants to settle liability at the measurement date. For financial instruments carried at fair value, GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels:

•Level 1 - Inputs representing quoted market prices in active markets for identical assets and liabilities

•Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the assets and liabilities, either directly or indirectly

•Level 3 - Unobservable inputs for assets and liabilities

At September 30, 2025, the Company’s financial instruments recognized on the balance sheet consist of cash and cash equivalents, restricted cash and cash equivalents, commodity derivatives, accounts receivable, other current assets, accounts payable and accrued liabilities, long-term debt and other long-term liabilities. The Company uses appropriate valuation techniques based on the available information to measure the fair values of assets and liabilities.

Fair Value Measurement

The following table presents the Company’s fair value measurements of its financial instruments as of September 30, 2025, and December 31, 2024:

(Thousands of U.S. Dollars)			As at September 30, 2025						As at December 31, 2024
Level 1
Liabilities
6.25% Senior Notes			$	—					$	24,133
7.75% Senior Notes			20,783						21,451
9.50% Senior Notes			622,370						688,262
			$	643,153					$	733,846
Level 2
Assets
Restricted cash and cash equivalents - long-term (1)			$	9,089					$	6,816
Commodity derivatives - current (2)			1,792						712
			$	10,881					$	7,528

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Liabilities
Commodity derivatives - current (3)			$	543					$	—
Canadian and Colombian credit facilities - long-term			42,309						—
			$	42,852					$	—

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

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

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

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

Restricted Cash and Cash Equivalents - Long-Term

The fair value of long-term restricted cash and cash equivalents approximate its carrying value because interest rates are variable and reflective of market rates.

Credit Facilities and Senior Notes

Financial instruments recorded at amortized cost at September 30, 2025, were the Senior Notes and credit facilities (Note 7).

The fair value of the Canadian and Colombian credit facilities approximates their carrying value. The fair value of the Canadian and Colombian credit facilities is estimated based on the amount the Company would have to pay a third party to assume the debt, including the credit spread for the difference between the issue rate and the period-end market rate. The credit spread is the Company’s default or repayment risk.

At September 30, 2025, the carrying amounts of the 7.75% Senior Notes and 9.50% Senior Notes were $24.1 million and $687.9 million, respectively, which represented the aggregate principal amounts less unamortized debt issuance costs and discounts, and the fair values were $20.8 million, and $622.4 million, respectively.

Derivative asset and derivative liability

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

			Three Months Ended September 30,									Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025			2024
Commodity price derivatives loss (gain)			$	2,945		$	—					$	(2,390)		$	—
Foreign currency derivatives gain			(879)			—						(8,109)			—
Derivative instruments loss (gain)			$	2,066		$	—					$	(10,499)		$	—

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 September 30, 2025, the Company had outstanding commodity price derivative positions as follows:

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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 $/bbl Weighted Average)
Call Option			October 01, 2025			December 31, 2025			250			WTI CMA			—			—			C$	95.00		—
Collar			October 01, 2025			December 31, 2025			500			WTI CMA			—			$	65.00		$	77.40		—
Collar			October 01, 2025			March 31, 2026			1,000			WTI CMA			—			$	60.00		$	70.60		—
3 Way			January 01, 2026			December 31, 2026			500			WTI CMA			C$	60.00		C$	70.00		C$	107.00		C$	1.90
3 Way			April 01, 2026			September 30, 2026			500			WTI CMA			C$	65.00		C$	75.00		C$	100.40		—
Collar			April 01, 2026			September 30, 2026			500			WTI CMA			—			$	75.00		$	91.95		—
Collar			October 01, 2025			December 31, 2025			5,000			Brent			—			$	63.00		$	76.80		—
Put Option			October 01, 2025			December 31, 2025			3,000			Brent			$	—		$	66.17		$	—		$	3.09
3 Way			October 01, 2025			December 31, 2025			2,000			Brent			$	52.50		$	60.00		$	75.55		$	—
Collar			October 01, 2025			March 31, 2026			1,000			Brent			$	—		$	60.00		$	76.25		$	—
3 Way			October 01, 2025			March 31, 2026			2,000			Brent			$	52.50		$	65.00		$	74.94		$	—
Put Option			October 01, 2025			June 30, 2026			2,000			Brent			$	—		$	65.00		$	—		$	4.00
3 Way			October 01, 2025			June 30, 2026			1,500			Brent			$	50.00		$	61.67		$	76.42		$	—
Collar			January 01, 2026			March 31, 2026			1,000			Brent			$	—		$	60.00		$	74.50		$	—
3 Way			January 01, 2026			June 30, 2026			2,000			Brent			$	50.00		$	60.00		$	74.75		$	—
Collar			January 01, 2026			June 30, 2026			1,000			Brent			$	—		$	60.00		$	76.75		$	—
3 Way			January 01, 2026			September 30, 2026			1,000			Brent			$	50.00		$	60.00		$	75.50		$	—
3 Way			January 01, 2026			December 31, 2026			2,000			Brent			$	50.00		$	60.00		$	73.63		$	—

Natural Gas

Type of Instrument

Start Period

End Period

Volume, GJs/d

Reference

Sold Swap (C$/GJ, Weighted Average)

Purchased Put (C$/GJ, Weighted Average)

Sold Call (C$/GJ, Weighted Average)

Swap

October 01, 2025

December 31, 2025

22,500

Aeco 5A

$

3.13

—

—

Swap

April 01, 2026

October 31, 2026

10,000

Aeco 5A

$

2.70

—

—

Power

Type of Instrument

Start Period

End Period

Volume, MWh/d

Reference

Sold Swap (C$/MWh, Weighted Average)

Purchased Put (C$/MWh, Weighted Average)

Sold Call (C$/MWh, Weighted Average)

Swap

October 01, 2025

December 31, 2025

72

AESO

$

49.75

$

—

$

—

Subsequent to the period ended September 30, 2025, the company entered into the following commodity price derivative positions as follows:

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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)
Put Option			January 01, 2026			December 31, 2026			500			Brent			$	—		$	60.00		$	—		$	4.30
3 Way			January 01, 2026			December 31, 2026			2,000			Brent			$	50.00		$	60.00		$	75.51		$	—

Natural Gas

Type of Instrument

Start Period

End Period

Volume, GJs/d

Reference

Sold Swap (C$/GJ, Weighted Average)

Purchased Put (C$/GJ, Weighted Average)

Sold Call (C$/GJ, Weighted Average)

Swap

January 01, 2026

October 31, 2026

10,000

Aeco 5A

$

2.83

$

—

$

—

Foreign Exchange Risk

The Company is exposed to foreign exchange risk in relation to its Colombian and Canadian operations predominantly in operating expenses. To mitigate exposure to fluctuations in foreign exchange, the Company may enter into foreign currency exchange derivatives. During the three months ended September 30, 2025, the Company settled $80 million nominal USD$ (COP$323,600 million) in outstanding foreign currency derivatives for a gain of $6 million (COP$30,800 million) and as at September 30, 2025 had no outstanding foreign currency derivative positions.

As at September 30, 2025, the Company had no outstanding foreign currency exchange derivative positions outstanding.

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 September 30,									As at December 31,
(Thousands of U.S. Dollars)			2025			2024						2024			2023
Cash and cash equivalents			$	49,089		$	277,645					$	103,379		$	62,146
Restricted cash and cash equivalents - current (1)			—			1,142						1,142			1,142
Restricted cash and cash equivalents - long-term (2)			9,089			7,093						6,816			7,750
			$	58,178		$	285,880					$	111,337		$	71,038

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

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

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

			Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025						2024
Accounts receivable and other long-term assets			$	2,798					$	(1,531)
Prepaid Equity Forward			—						6,218
Prepaids and inventory			(2,206)						(3,984)
Accounts payable and accrued liabilities, and other long-term liabilities			23,621						10,442
Taxes receivable and payable			(14,346)						21,019
Net changes in assets and liabilities from operating activities			$	9,867					$	32,164

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

			Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025						2024
Additions to property, plant and equipment			$	(203,237)					$	(169,525)
(Decrease) increase in accounts payable and accrued liabilities			(15,408)						6,627
Decrease (increase) in accounts receivable			490						(925)
Net cash additions to property, plant and equipment			$	(218,155)					$	(163,823)

The Company revised the presentation of cash flows associated with additions to property, plant and equipment within net cash used in investing activities in the Consolidated Statements of Cash Flows for the nine months ended September 30, 2024. Additions to property, plant and equipment as previously reported of $169.5 million were presented on an accrual basis before the related decrease in cash outflow due to impact of changes in non-cash investing working capital of $5.7 million. The cash outflow associated with additions to property, plant and equipment has been re-casted in accordance with the direct method. There was no change in amount to the Company’s previously reported net cash used in investing activities

The following table provides additional supplemental cash flow disclosures:

			Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025						2024
Cash paid for income taxes			$	4,031					$	20,665
Cash paid for withholding taxes			$	19,934					$	27,878
Cash paid for interest			$	37,589					$	30,073
Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period			$	46,365					$	53,117

14. Subsequent Events

On October 24, 2025, the Company, through its wholly owned subsidiary, Gran Tierra Energy Colombia GmbH, entered into crude oil sale and purchase agreement where the Company will receive an advance of up to $150.0 million related to Ecuador production. An additional advance of $50.0 million is available to the Company, at the sole discretion of the lender and subject to completion of certain conditions.

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

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

Financial and Operational Highlights

Key Highlights for the third quarter of 2025

•Net loss for the third quarter of 2025 was $20.0 million or $(0.57) per share basic and diluted, compared to a net income of $1.1 million or $0.04 per share basic and diluted for the third quarter of 2024 and a net loss of $12.7 million for the prior quarter.

•Loss before income taxes for the third quarter of 2025 was $31.2 million, compared to income before income taxes of $21.9 million for the third quarter of 2024 and loss before income taxes of $8.1 million for the prior quarter.

•Brent oil price averaged $68.17 per bbl during the third quarter of 2025, a decrease of 13% from the comparable period in 2024, and a 2% increase from the prior quarter. Castilla, Vasconia and Oriente differentials averaged $4.88, $1.88 and $7.20 per bbl during the third quarter of 2025, a decrease of 45%, 63% and 21% from the comparable period of 2024, and an increase of 3% and 10% for Castilla and Vasconia differentials offset by a decrease of 1% for Oriente differential from the prior quarter, respectively.

•Adjusted EBITDA(2) was $69.0 million for the third quarter of 2025, a decrease from $92.8 million in the third quarter of 2024, and a decrease from $77.0 million in the prior quarter.

•Funds flow from operations(2) decreased to $41.7 million compared to $60.3 million in the third quarter of 2024, and decreased from $53.9 million in the prior quarter.

•During the third quarter of 2025, there were no share re-purchases. For the period from November 6, 2024 to October 29, 2025, we re-purchased a total of 1.2 million shares or 3% of the outstanding shares as of September 30, 2025.

•NAR production for the third quarter of 2025 increased by 38% to 35,962 BOEPD, compared to 25,988 BOEPD in the third quarter of 2024 due to the production from Canadian operations acquired on October 31, 2024 and successful exploration well drilling results in Ecuador, and decreased by 10% from 39,800 BOEPD in the prior quarter as a result of a landslide in Ecuador that required the shut in of all Ecuador production for several weeks and trunk line repairs at the Moqueta field which resulted in the field being shut in for the quarter. Current production from October 1, 2025 to October 29, 2025 is approximately 45,200 BOEPD.

•NAR sales volumes for the third quarter of 2025 increased by 47% to 37,353 BOEPD, compared to 25,464 BOEPD in the third quarter of 2024 and decreased by 3% from 38,331 BOEPD in the prior quarter.

•Oil, natural gas and NGL sales for the third quarter of 2025 decreased by 1% to $149.3 million, compared to the third quarter of 2024, primarily due to lower oil prices partially offset by an increase in sales volumes. Oil, natural gas and NGL sales were comparable with the prior quarter.

•On per boe basis, operating expenses increased 1% compared to the corresponding period of 2024 and increased 24% from the prior quarter. Operating expenses increased by 48% to $68.4 million when compared to the third quarter of 2024, primarily as a result of new Canadian operations and ramp-up of operations in Ecuador. Operating expenses increased by 22% from $55.9 million in the prior quarter primarily as a result of higher workover activities and lifting costs attributed to inventory fluctuation in Ecuador due to the timing of sales.

•Transportation expenses increased by 10% when compared to the third quarter of 2024 primarily due to 47% higher sales volumes attributed to new Canadian operations and higher sales volumes in Ecuador, partially offset by lower volumes transported in Colombia. Transportation expenses decreased by 4% compared to the prior quarter primarily as a result of lower sales volumes transported from Acordionero field in Colombia.

•Gross profit decreased 70% to $14.7 million compared to $48.8 million in the third quarter of 2024 and 36% from $23.1 million in the prior quarter.

•Operating Netback(2) decreased to $76.6 million compared to $101.4 million in the third quarter of 2024 and $89.0 million in the prior quarter.

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•Quality and transportation discounts for the third quarter of 2025 increased to $24.74 per boe compared to $14.10 per boe in the third quarter of 2024, primarily as a result of the change in production mix with the acquisition of Canadian operations, and $23.89 per boe in the prior quarter as a result of higher Castilla and Vasconia differentials.

•General and administrative (“G&A”) expenses before stock-based compensation for the third quarter of 2025 increased to $13.5 million compared to $9.5 million in the third quarter of 2024, due to the addition of the new Canadian operations, and decreased from $14.5 million in the prior quarter due to lower business development costs.

•Capital expenditures for the third quarter of 2025 were $57.3 million compared to $52.9 million in the third quarter of 2024 and $51.2 million in the prior quarter. This increase in capital expenditure activity is in line with the Company’s budgeted capital spend for 2025.

•The temporary excise tax levied on oil sales was introduced by the Colombian government under a state of emergency declared in 2025. The tax applies to the first sale or export of crude oil at a rate of 1% starting from February 2025 and is scheduled to remain in force until December 2025. All temporary taxes enacted under the state of emergency are currently under review by the Constitutional Court, the ruling of which could potentially invalidate these measures

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(Thousands of U.S. Dollars, unless otherwise indicated)			Three Months Ended September 30,												Three Months Ended June 30,						Nine Months Ended September 30,
			2025			2024			% Change						2025						2025			2024			% Change
Average Daily Volumes (BOEPD)
Consolidated
Working Interest (“WI”) Production Before Royalties			42,685			32,764			30						47,196						45,495			32,595			40
Royalties			(6,723)			(6,776)			(1)						(7,396)						(7,396)			(6,650)			11
Production NAR			35,962			25,988			38						39,800						38,099			25,945			47
Decrease (increase) in Inventory			1,391			(524)			365						(1,469)						132			(367)			136
Sales(1)			37,353			25,464			47						38,331						38,231			25,578			49
Net (Loss) Income			$	(19,950)		$	1,133		(1,861)						$	(12,741)					$	(51,971)		$	37,426		(239)
Gross Profit			$	14,670		$	48,803		(70)						$	23,061					$	65,568		$	160,457		(59)
Operating Netback
Gross Profit			$	14,670		$	48,803		(70)						$	23,061					$	65,568		$	160,457		(59)
Depletion and Accretion			61,908			52,599			18						65,947						196,286			158,356			24
Operating Netback(2)			$	76,578		$	101,402		(24)						$	89,008					$	261,854		$	318,813		(18)
G&A Expenses before Stock-Based Compensation			$	13,453		$	9,491		42						$	14,460					$	40,056		$	31,240		28
G&A Stock-Based Compensation Expense (Recovery)			143			(3,145)			105						546						172			6,376			(97)
G&A Expenses, including Stock-Based Compensation			$	13,596		$	6,346		114						$	15,006					$	40,228		$	37,616		7
Adjusted EBITDA(2)			$	69,034		$	92,794		(26)						$	76,987					$	231,183		$	290,590		(20)
Funds Flow from Operations(2)			$	41,685		$	60,338		(31)						$	53,906					$	150,935		$	180,812		(17)
Capital Expenditures			$	57,340		$	52,921		8						$	51,170					$	203,237		$	169,525		20

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

(2) Non-GAAP measures.

Gross profit is derived from oil, natural gas and NGL sales, net of direct production costs including operating expenses, transportation, and depletion, depreciation, and accretion (“DD&A”). Gross profit does not include 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 that do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to oil sales, net income (loss) or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Disclosure of each non-GAAP financial measure is preceded by the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.

Operating netback, as presented, is defined as 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

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our principal business activities prior to the consideration of other income and expenses. A reconciliation from oil sales to operating netback is provided in the table below.

Colombia			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025						2025			2024
Gross Profit			$	10,237		$	47,553					$	19,628					$	56,550		$	158,877
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)			44,041			49,880						47,897						136,936			151,465
Operating netback (non-GAAP)			$	54,278		$	97,433					$	67,525					$	193,486		$	310,342

(*) Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $47.0 million and $52.8 million, less depreciation of administrative assets of $3.0 million and $2.9 million, respectively. For the nine months ended September 30, 2025 and 2024 of $146.1 million and $160.1 million, less depreciation of administrative assets of $9.2 million and $8.7 million, respectively. For the prior quarter, calculated as DD&A expenses of $50.5 million, less depreciation of administrative assets of $2.6 million.

Ecuador			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025						2025			2024
Gross Profit			$	859		$	1,250					$	(418)					$	1,801		$	1,580
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)			9,519			2,719						4,350						24,366			6,891
Operating netback (non-GAAP)			$	10,378		$	3,969					$	3,932					$	26,167		$	8,471

(*) Same as DD&A expenses for the three months ended September 30, 2025 and 2024 and the prior quarter.

Canada			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025						2025			2024
Gross Profit			$	3,574		$	—					$	3,851					$	7,217		$	—
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)			8,348			—						13,700						34,984			—
Operating netback (non-GAAP)			$	11,922		$	—					$	17,551					$	42,201		$	—

(*) Same as DD&A expenses for the three months ended September 30, 2025 and 2024and the prior quarter.

Total Consolidated			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025						2025			2024
Gross Profit			$	14,670		$	48,803					$	23,061					$	65,568		$	160,457
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)			61,908			52,599						65,947						196,286			158,356
Operating netback (non-GAAP)			$	76,578		$	101,402					$	89,008					$	261,854		$	318,813

(*) Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $65.0 million and $55.6 million, less depreciation of administrative assets of $3.1 million and $3.0 million, respectively. For the nine months ended September 30, 2025 and 2024 of $205.8 million and $167.2 million, less depreciation of administrative assets of $9.5 million and $8.9 million, respectively. For the prior quarter, calculated as DD&A expenses of $68.6 million, less depreciation of administrative assets of $2.7 million.

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

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			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025						2025			2024
Net (loss) income			$	(19,950)		$	1,133					$	(12,741)					$	(51,971)		$	37,426
Adjustments to reconcile net loss to EBITDA and Adjusted EBITDA
DD&A expenses			64,981			55,573						68,635						205,818			167,213
Interest expense			25,447			19,892						24,366						73,048			56,714
Income tax expense (recovery)			(11,276)			20,767						4,648						(3,075)			29,090
EBITDA (non-GAAP)			$	59,202		$	97,365					$	84,908					$	223,820		$	290,443
Non-cash lease expense			1,187			1,370						1,725						4,648			4,164
Lease payments			(1,574)			(1,171)						(1,545)						(4,686)			(3,540)
Foreign exchange loss (gain)			284			(3,084)						3,716						7,838			(8,312)
Stock-based compensation expense (recovery)			143			(3,145)						546						172			6,376
Transaction costs			—			1,459						—						—			1,459
Other loss			265			—						38						355			—
Unrealized derivative instruments loss (gain)			9,527			—						(12,401)						(964)			—
Adjusted EBITDA (non-GAAP)			$	69,034		$	92,794					$	76,987					$	231,183		$	290,590

Funds flow from operations, as presented, is defined as net (loss) income adjusted for DD&A expenses, deferred income tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, unrealized derivative instruments loss or gain and other loss. 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 September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025						2025			2024
Net (loss) income			$	(19,950)		$	1,133					$	(12,741)					$	(51,971)		$	37,426
Adjustments to reconcile net loss to funds flow from operations
DD&A expenses			64,981			55,573						68,635						205,818			167,213
Deferred income tax (recovery) expense			(15,298)			5,550						2,453						(17,557)			(32,332)
Stock-based compensation expense (recovery)			143			(3,145)						546						172			6,376
Amortization of debt issuance costs			4,269			3,109						4,082						12,184			9,175
Non-cash lease expense			1,187			1,370						1,725						4,648			4,164
Lease payments			(1,574)			(1,171)						(1,545)						(4,686)			(3,540)
Unrealized foreign exchange loss (gain)			(1,865)			(2,081)						3,114						2,936			(7,670)
Unrealized derivative instruments loss (gain)			9,527			—						(12,401)						(964)			—
Other loss			265			—						38						355			—
Funds flow from operations (non-GAAP)			$	41,685		$	60,338					$	53,906					$	150,935		$	180,812

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Additional Operational Results

			Three Months Ended September 30,												Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024			% Change						2025						2025			2024			% Change
Oil, natural gas and NGL sales			$	149,254		$	151,373		(1)						$	149,357					$	466,784		$	474,559		(2)
Operating expenses			68,379			46,060			48						55,855						191,588			141,561			35
Transportation expenses			4,297			3,911			10						4,494						13,342			14,185			(6)
Operating netback (1)			76,578			101,402			(24)						89,008						261,854			318,813			(18)
Export tax			2,630			—			100						—						2,630			—			100
DD&A expenses			64,981			55,573			17						68,635						205,818			167,213			23
Derivative instruments loss (gain)			2,066			—			100						(14,032)						(10,499)			—			100
G&A expenses before stock-based compensation			13,453			9,491			42						14,460						40,056			31,240			28
G&A stock-based compensation expense (recovery)			143			(3,145)			105						546						172			6,376			(97)
Foreign exchange (gain) loss			284			(3,084)			(109)						3,716						7,838			(8,312)			(194)
Other income			(1,003)			—			100						(339)						(1,290)			—			100
Interest expense			25,447			19,892			28						24,366						73,048			56,714			29
Transaction costs			—			1,459			(100)						—						—			1,459			(100)
			108,001			80,186			35						97,352						317,773			254,690			25
Interest income			197			684			(71)						251						873			2,393			(64)
Income (loss) before income taxes			(31,226)			21,900			(243)						(8,093)						(55,046)			66,516			(183)
Current income tax expense			4,022			15,217			(74)						2,195						14,482			61,422			(76)
Deferred income tax (recovery) expense			(15,298)			5,550			(376)						2,453						(17,557)			(32,332)			46
			(11,276)			20,767			154						4,648						(3,075)			29,090			(111)
Net (loss) income			$	(19,950)		$	1,133		(1,861)						$	(12,741)					$	(51,971)		$	37,426		239
Sales Volumes (NAR)
Total sales volumes, BOEPD			37,353			25,464			47						38,331						38,231			25,578			49
Brent Price per bbl			$	68.17		$	78.71		(13)						$	66.71					$	69.91		$	81.82		(15)
WTI Price per bbl			$	65.07		$	75.28		(14)						$	63.81					$	66.74		$	77.71		(14)
AECO Price C$ per GJ			0.60			0.65			(8)						1.60						1.42			1.38			3
Consolidated Results of Operations per boe Sales Volumes NAR

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Oil, natural gas and NGL sales			$	43.43		$	64.61		(33)						$	42.82					$	44.72		$	67.71		(34)
Operating expenses			19.90			19.66			1						16.01						18.36			20.20			(9)
Transportation expenses			1.25			1.67			(25)						1.29						1.28			2.02			(37)
Operating netback (1)			22.28			43.28			(49)						25.52						25.08			45.49			12
Export tax			0.77			—			100						—						0.25			—			100
DD&A expenses			18.91			23.72			(20)						19.68						19.72			23.86			(17)
Derivative instruments loss (gain)			0.60			—			(100)						(4.02)						(1.01)			—			100
G&A expenses before stock-based compensation			3.91			4.05			(3)						4.15						3.84			4.46			(14)
G&A stock-based compensation expense (recovery)			0.04			(1.34)			(103)						0.16						0.02			0.91			(98)
Foreign exchange (gain) loss			0.08			(1.32)			106						1.07						0.75			(1.19)			163
Other income			(0.29)			—			(100)						(0.10)						(0.12)			—			(100)
Transaction costs			—			0.62			(100)						—						—			0.21			(100)
Interest expense			7.40			8.49			(13)						6.99						7.00			8.09			(14)
			31.42			34.22			(8)						27.93						30.45			36.34			(16)
Interest income			0.06			0.29			(80)						0.07						0.08			0.34			(77)
Income (loss) before income taxes			(9.08)			9.35			(197)						(2.34)						(5.29)			9.49			(156)
Current income tax expense			1.17			6.50			(82)						0.63						1.39			8.76			(84)
Deferred income tax (recovery) expense			(4.45)			2.37			(288)						0.70						(1.68)			(4.61)			64
			(3.28)			8.87			(137)						1.33						(0.29)			4.15			(107)
Net (loss) income			$	(5.80)		$	0.48		(1,308)						$	(3.67)					$	(5.00)		$	5.34		(194)

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

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

			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
Average Daily Volumes (BOEPD) - Colombia			2025			2024						2025						2025			2024
WI production before royalties			22,701			29,328						25,108						24,476			30,530
Royalties			(3,481)			(5,511)						(3,845)						(3,912)			(5,879)
Production NAR			19,220			23,817						21,263						20,564			24,651
Decrease (increase) in inventory			337			326						111						26			(12)
Sales			19,557			24,143						21,374						20,590			24,639
Royalties, % of working interest production before royalties			15		%	19		%				15		%				16		%	19		%
			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
Average Daily Volumes (BOEPD) - Ecuador			2025			2024						2025						2025			2024
WI production before royalties			3,872			3,436						4,592						4,166			2,065
Royalties			(1,273)			(1,265)						(1,364)						(1,353)			(771)
Production NAR			2,599			2,171						3,228						2,813			1,294
Decrease (increase) in inventory			1,054			(850)						(1,579)						106			(356)
Sales			3,653			1,321						1,649						2,919			938
Royalties, % of working interest production before royalties			33		%	37		%				30		%				32		%	37		%
			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
Average Daily Volumes (BOEPD) - Canada			2025			2024						2025						2025			2024
WI production before royalties			16,112			—						17,496						16,853			—
Royalties			(1,969)			—						(2,187)						(2,131)			—
Production NAR			14,143			—						15,309						14,722			—
Sales			14,143			—						15,309						14,722			—
Royalties, % of working interest production before royalties			12		%	—		%				13		%				13		%	—		%
			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
Average Daily Volumes (BOEPD) - Total Company			2025			2024						2025						2025			2024
WI production before royalties			42,685			32,764						47,196						45,495			32,595
Royalties			(6,723)			(6,776)						(7,396)						(7,396)			(6,650)
Production NAR			35,962			25,988						39,800						38,099			25,945
Decrease (increase) in inventory			1,391			(524)						(1,469)						132			(367)
Sales			37,353			25,464						38,331						38,231			25,578
Royalties, % of working interest production before royalties			16		%	21		%				16		%				16		%	20		%

30

Oil, natural gas and NGL production NAR for the three and nine months ended September 30, 2025, increased by 38% and 47%, to 35,962 BOEPD and 38,099 BOEPD, respectively, compared to the corresponding periods of 2024 due to the production from the Canadian operations acquired on October 31, 2024 and successful exploration well drilling results in Ecuador. Oil, natural gas and NGL production NAR decreased by 10% compared to the prior quarter primarily due to a landslide in Ecuador that required the shut in of all Ecuador production for several weeks and trunk line repairs at the Moqueta field which resulted in the field being shut in for the quarter. Current production from October 1, 2025 to October 29, 2025 is approximately 45,200 boepd.

Royalties as a percentage of production for the three and nine months ended September 30, 2025 decreased by 5% and 4%, respectively, compared to the corresponding periods of 2024 as a result of a decrease in benchmark oil prices due to the price sensitive royalty regime in Colombia and Ecuador, and lower royalties for Canadian operations. Royalties as a percentage of production were comparable to the prior quarter.

31

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

Commodity prices:

Colombia and Ecuador

32

Brent - For the three and nine months ended September 30, 2025, Brent decreased 13% and 15% from the comparable periods of 2024, and increased 2% from the prior quarter. For the three months ended September 30, 2025, Castilla, Vasconia and Oriente differentials per boe decreased to $4.88, $1.88 and $7.20 compared to $8.83, $5.07 and $9.15 in the corresponding period of 2024. For the nine months ended September 30, 2025, Castilla, Vasconia and Oriente differentials per boe decreased to $4.98, $1.95 and $7.37 from $8.62, $4.70 and $8.52 in the corresponding period of 2024.

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

Canada

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

WTI - For the three months ended September 30, 2025, WTI increased 2% from the prior quarter. For the three months ended September 30, 2025, 25% of NAR production in Canada was oil, compared with 26% in the prior quarter.

NGLs - For the three months ended September 30, 2025, the weighted average NGL price received was 9% of WTI, consistent with the prior quarter. For the three months ended September 30, 2025, 21% of NAR production in Canada was NGLs, compared to 24% in the prior quarter.

AECO - For the three months ended September 30, 2025, AECO price decreased 63% from the prior quarter. For the three months ended September 30, 2025, 54% of NAR production in Canada was natural gas, compared to 50% in the prior quarter.

Oil, natural gas and NGL sales for the three months ended September 30, 2025, decreased by 1% to $149.3 million compared to the corresponding period of 2024, due to 13% decrease in Brent price and 19% lower sales volumes in Colombia partially offset by 47% increase in sales volumes, attributed to sales from Canadian operations acquired on October 31, 2024 and sales from positive exploration drilling in Ecuador. Oil, natural gas and NGL sales for the nine months ended September 30, 2025, decreased by 2% to $466.8 million compared to the corresponding period of 2024 due to 15% decrease in Brent price and 16% decrease in sales volumes in Colombia, partially offset by a 49% increase in sales volumes attributed to sales from Canadian operations and new exploration wells in Ecuador.

Oil, natural gas and NGL sales were comparable with the prior quarter

33

During the three months ended September 30, 2025, we retrospectively reclassified transportation expenses against revenue, which were previously recorded separately from revenue, resulting in a decrease of revenue by immaterial impact of $3.1 million and $5.5 million for the three and six months ended June 30, 2025, respectively, and $2.4 million for the three months ended March 31, 2025.

The following table shows the effect of changes in realized price and sale volumes on our oil sales for the three and nine months ended September 30, 2025, compared to the prior quarter and the corresponding periods of 2024:

(Thousands of U.S. Dollars)			Three Months Ended September 30, 2025, Compared with Three Months Ended June 30, 2025						Three Months Ended September 30, 2025, Compared with Three Months Ended September 30, 2024						Nine Months Ended September 30, 2025, Compared with Nine Months Ended September 30, 2024
Oil, natural gas and NGL sales for the comparative period			$	149,357					$	151,373					$	474,559
Realized sales price increase (decrease) effect			2,099						(15,375)						(144,810)
Sales volumes (decrease) increase effect			(2,202)						(13,394)						49,713
Oil, natural gas and NGL sales - Canada Operations			—						26,650						87,322
Oil, natural gas and NGL sales for the three and nine months ended September 30, 2025			$	149,254					$	149,254					$	466,784

Gross Profit

34

			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars) Colombia			2025			2024						2025						2025			2024
Revenue			$	101,999		$	143,128					$	109,692					$	329,339		$	456,172
Operating expenses			44,819			42,250						38,432						126,005			132,643
Transportation expenses			2,902			3,445						3,735						9,848			13,187
Depletion and accretion(*)			44,041			49,880						47,897						136,936			151,465
Gross profit			$	10,237		$	47,553					$	19,628					$	56,550		$	158,877

(*)Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $47.0 million and $52.8 million, less depreciation of administrative assets of $2.9 million and $2.9 million, respectively. For the nine months ended September 30, 2025 and 2024 of $146.1 million and $160.1 million, less depreciation of administrative assets of $9.2 million and $8.7 million, respectively. For the prior quarter, calculated as DD&A expenses of $50.5 million, less depreciation of administrative assets of $2.6 million.

			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(U.S. Dollars per boe Sales NAR ) Colombia			2025			2024						2025						2025			2024
Revenue			$	56.69		$	64.44					$	56.40					$	58.59		$	67.57
Operating expenses			24.91			19.02						19.76						22.42			19.65
Transportation expenses			1.61			1.55						1.92						1.75			1.95
Depletion and accretion			24.48			22.46						24.63						24.36			22.44
Gross profit			$	5.69		$	21.41					$	10.09					$	10.06		$	23.53

			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars) Ecuador			2025			2024						2025						2025			2024
Revenue			$	20,605		$	8,245					$	8,495					$	50,123		$	18,387
Operating expenses			9,157			3,810						4,122						21,352			8,918
Transportation expenses			1,070			466						441						2,604			998
Depletion and accretion(*)			9,519			2,719						4,350						24,366			6,891
Gross profit (loss)			$	859		$	1,250					$	(418)					$	1,801		$	1,580

(*) Same as DD&A expenses for the three months ended September 30, 2025 and 2024 and the prior quarter.

			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(U.S. Dollars per boe Sales NAR ) Ecuador			2025			2024						2025						2025			2024
Revenue			$	61.30		$	67.83					$	56.64					$	62.92		$	71.47
Operating expenses			27.24			31.35						27.48						26.80			34.67
Transportation expenses			3.18			3.83						2.94						3.27			3.88
Depletion and accretion			28.32			22.37						29.00						30.59			26.79
Gross profit (loss)			$	2.56		$	10.28					$	(2.78)					$	2.26		$	6.13

35

			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars) Canada			2025			2024						2025						2025			2024
Revenue			$	26,650		$	—					$	31,170					$	87,322		$	—
Operating expenses			14,403			—						13,301						44,231			—
Transportation expenses			325			—						318						890			—
Depletion and accretion(*)			8,348			—						13,700						34,984			—
Gross profit			$	3,574		$	—					$	3,851					$	7,217		$	—

(*) Same as DD&A expenses for the three months ended September 30, 2025 and 2024 and the prior quarter.

			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(U.S. Dollars per boe Sales NAR ) Canada			2025			2024						2025						2025			2024
Revenue			$	20.48		$	—					$	22.37					$	21.73		$	—
Operating expenses			11.07			—						9.55						11.00			—
Transportation expenses			0.25			—						0.23						0.22			—
Depletion and accretion			6.42			—						9.83						8.70			—
Gross profit			$	2.74		$	—					$	2.76					$	1.81		$	—

			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars) Total Company			2025			2024						2025						2025			2024
Revenue			$	149,254		$	151,373					$	149,357					$	466,784		$	474,559
Operating expenses			68,379			46,060						55,855						191,588			141,561
Transportation expenses			4,297			3,911						4,494						13,342			14,185
Depletion and accretion(*)			61,908			52,599						65,947						196,286			158,356
Gross profit			$	14,670		$	48,803					$	23,061					$	65,568		$	160,457

(*)Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $64.981 million and $55.6 million, less depreciation of administrative assets of $3.1 million and $3.0 million, respectively. For the nine months ended September 30, 2025 and 2024 of $205.8 million and $167.2 million, less depreciation of administrative assets of $9.5 million and $8.9 million, respectively. For the prior quarter, calculated as DD&A expenses of $68.6 million, less depreciation of administrative assets of $2.7 million.

			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(U.S. Dollars per boe Sales NAR ) Total Company			2025			2024						2025						2025			2024
Revenue			$	43.43		$	64.61					$	42.82					$	44.72		$	67.71
Operating expenses			19.90			19.66						16.01						18.36			20.20
Transportation expenses			1.25			1.67						1.29						1.28			2.02
Depletion and accretion			18.01			22.45						18.91						18.81			22.60
Gross profit			$	4.27		$	20.83					$	6.61					$	6.27		$	22.89

Operating Netback

36

Colombia			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025						2025			2024
Oil, natural gas and NGL sales			$	101,999		$	143,128					$	109,692					$	329,339		$	456,172
Transportation expenses			(2,902)			(3,445)						(3,735)						(9,848)			(13,187)
			99,097			139,683						105,957						319,491			442,985
Operating expenses			(44,819)			(42,250)						(38,432)						(126,005)			(132,643)
Operating netback(1)			$	54,278		$	97,433					$	67,525					$	193,486		$	310,342
(U.S. Dollars Per boe Sales Volumes NAR)
Brent			$	68.17		$	78.71					$	66.71					$	69.91		$	81.82
Quality and transportation discounts			(11.48)			(14.27)						(10.31)						(11.32)			(14.25)
Average realized price			56.69			64.44						56.40						58.59			67.57
Transportation expenses			(1.61)			(1.55)						(1.92)						(1.75)			(1.95)
Average realized price net of transportation expenses			55.08			62.89						54.48						56.84			65.62
Operating expenses			(24.91)			(19.02)						(19.76)						(22.42)			(19.65)
Operating netback(1)			$	30.17		$	43.87					$	34.72					$	34.42		$	45.97

Ecuador			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025						2025			2024
Oil, natural gas and NGL sales			$	20,605		$	8,245					$	8,495					$	50,123		$	18,387
Transportation expenses			(1,070)			(466)						(441)						(2,604)			(998)
			19,535			7,779						8,054						47,519			17,389
Operating expenses			(9,157)			(3,810)						(4,122)						(21,352)			(8,918)
Operating netback(1)			$	10,378		$	3,969					$	3,932					$	26,167		$	8,471
(U.S. Dollars Per boe Sales Volumes NAR)
Brent			$	68.17		$	78.71					$	66.71					$	69.91		$	81.82
Quality and transportation discounts			(6.87)			(10.88)						(10.07)						(6.99)			(10.35)
Average realized price			61.30			67.83						56.64						62.92			71.47
Transportation expenses			(3.18)			(3.83)						(2.94)						(3.27)			(3.88)
Average realized price net of transportation expenses			58.11			64.00						53.70						59.65			67.59
Operating expenses			(27.24)			(31.35)						(27.48)						(26.80)			(34.67)
Operating netback(1)			$	30.87		$	32.65					$	26.21					$	32.85		$	32.92

37

Canada			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025						2025			2024
Oil, natural gas and NGL sales			$	26,650		$	—					$	31,170					$	87,322		$	—
Transportation expenses			(325)			—						(318)						(890)			—
			26,325			—						30,852						86,432			—
Operating expenses			(14,403)			—						(13,301)						(44,231)			—
Operating netback(1)			$	11,922		$	—					$	17,551					$	42,201		$	—
(U.S. Dollars Per boe Sales Volumes NAR)
WTI Price per bbl			$	65.07		$	75.28					$	63.81					$	66.74		$	77.71
AECO Price C$ per GJ			0.60			0.65						1.60						1.42			1.38
Average realized price			20.48			—						22.37						21.73			—
Transportation expenses			(0.25)			—						(0.23)						(0.22)			—
Average realized price net of transportation expenses			20.23			—						22.14						21.51			—
Operating expenses			(11.07)			—						(9.55)						(11.00)			—
Operating netback(1)			$	9.16		$	—					$	12.59					$	10.51		$	—

Total Company			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025						2025			2024
Oil, natural gas and NGL sales			$	149,254		$	151,373					$	149,357					$	466,784		$	474,559
Transportation expenses			(4,297)			(3,911)						(4,494)						(13,342)			(14,185)
			144,957			147,462						144,863						453,442			460,374
Operating expenses			(68,379)			(46,060)						(55,855)						(191,588)			(141,561)
Operating netback(1)			$	76,578		$	101,402					$	89,008					$	261,854		$	318,813
(U.S. Dollars Per boe Sales Volumes NAR)
Brent			$	68.17		$	78.71					$	66.71					$	69.91		$	81.82
Quality and transportation discounts			(24.74)			(14.10)						(23.89)						(25.19)			(14.11)
Average realized price			43.43			64.61						42.82						44.72			67.71
Transportation expenses			(1.25)			(1.67)						(1.29)						(1.28)			(2.02)
Average realized price net of transportation expenses			42.18			62.94						41.53						43.44			65.69
Operating expenses			(19.90)			(19.66)						(16.01)						(18.36)			(20.20)
Operating netback(1)			$	22.28		$	43.28					$	25.52					$	25.08		$	45.49

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

38

39

Operating expenses for the three months ended September 30, 2025, increased to $68.4 million or by $0.24 per boe to $19.90 compared to the corresponding period of 2024, due to new Canadian operations and ramp-up of operations in Ecuador.

Operating expenses for the nine months ended September 30, 2025, increased to $191.6 million compared to the corresponding period of 2024 for the same reason mentioned above. On a per boe basis, operating expenses decreased by $1.84 to $18.36 compared to the corresponding period of 2024, primarily due higher sales volumes in Ecuador and sales from new Canadian operations.

Compared to the prior quarter, operating expenses increased from $55.9 million or by $3.89 from $16.01 per boe due to higher workover activities and lifting costs associated with inventory fluctuation in Ecuador due to the timing of sales.

40

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 nine months ended September 30, 2025 and 2024, and the prior quarter:

			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
			2025			2024						2025						2025			2024
Volume transported through pipeline			47		%	5		%				44		%				46		%	4		%
Volume sold at wellhead			24		%	46		%				25		%				29		%	47		%
Volume transported via truck to sales point			29		%	49		%				31		%				25		%	49		%
			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 September 30, 2025, increased by 10% to $4.3 million or by $0.42 to $1.25 per boe, compared to the corresponding period of 2024, due to the new Canadian operations, higher sales volumes transported in Ecuador partially offset by lower sales volumes transported in Colombia.

Transportation expenses for the nine months ended September 30, 2025, decreased by 6% to $13.3 million or by $0.74 to $1.28 per boe, compared to the corresponding period of 2024, due to lower sales volumes transported in Colombia partially offset by sales volumes from a new Canada operations and the higher sales volumes transported in Ecuador.

Transportation expenses decreased by 4% or $0.04 per boe from $4.5 million or $1.29 per boe in the prior quarter due to lower sales volumes transported from Acordionero field in Colombia.

DD&A Expenses

41

			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
			2025			2024						2025						2025			2024
DD&A Expenses, thousands of U.S. Dollars			$	64,981		$	55,573					$	68,635					$	205,818		$	167,213
DD&A Expenses, U.S. Dollars per boe			$	18.91		$	23.72					$	19.68					$	19.72		$	23.86

			Three Months Ended September 30, 2025									Three Months Ended September 30, 2024
			DD&A expenses, thousands of U.S. Dollars						DD&A expenses, U.S. Dollars Per Boe						DD&A expenses, thousands of U.S. Dollars						DD&A expenses, U.S. Dollars Per Boe
Colombia			$	46,986					$	26.11					$	52,772					$	23.76
Ecuador			9,520						28.32						2,721						22.39
Canada			8,353						6.42						—						—
Corporate			122						—						80						—
			$	64,981					$	18.91					$	55,573					$	23.72

			Nine Months Ended September 30, 2025									Nine Months Ended September 30, 2024
			DD&A expenses, thousands of U.S. Dollars						DD&A expenses, U.S. Dollars Per Boe						DD&A expenses, thousands of U.S. Dollars						DD&A expenses, U.S. Dollars Per Boe
Colombia			$	146,091					$	25.99					$	160,131					$	23.72
Ecuador			24,369						30.59						6,896						26.81
Canada			34,999						8.71						—						—
Corporate			359						—						186						—
			$	205,818					$	19.72					$	167,213					$	23.86

DD&A expenses for the three and nine months ended September 30, 2025, increased by 17% and 23% due to higher costs in the depletable base for Ecuador and the new Canadian operations, compared to the corresponding periods of 2024.

On a per boe basis, DD&A expenses for the three and nine months ended September 30, 2025 decreased by $4.81 and $4.14 due to higher NAR sales volumes primarily attributed to the new Canadian operations.

DD&A expenses decreased by 5% from $68.6 million when compared to the prior quarter due to lower production rates. On a per boe basis, DD&A expenses decreased by $0.77 due to higher production in Ecuador.

42

G&A Expenses

			Three Months Ended September 30,												Three Months Ended June 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024			% Change						2025						2025			2024			% Change
G&A Expenses before Stock-Based Compensation			$	13,453		$	9,491		42						$	14,460					$	40,056		$	31,240		28
G&A Stock-Based Compensation Expense (Recovery)			143			(3,145)			(105)						546						172			6,376			(97)
G&A Expenses, including Stock-Based Compensation			$	13,596		$	6,346		114						$	15,006					$	40,228		$	37,616		7
(U.S. Dollars Per boe Sales Volumes NAR)
G&A Expenses before Stock-Based Compensation			$	3.91		$	4.05		(3)						$	4.15					$	3.84		$	4.46		(14)
G&A Stock-Based Compensation Expense (Recovery)			0.04			(1.34)			(103)						0.16						0.02			0.91			(98)
G&A Expenses, including Stock-Based Compensation			$	3.95		$	2.71		46						$	4.31					$	3.86		$	5.37		(28)

G&A expenses before stock-based compensation on a per boe basis for the three months ended September 30, 2025 decreased by $0.14 or 3% compared to the corresponding period of 2024 due to higher sales volumes mainly driven by the addition of the new Canadian operations. Total G&A expenses before stock-based compensation increased by 42% compared to the corresponding period of 2024, primarily due to the addition of the new Canadian operations and higher business development and consulting cost related to optimization projects.

G&A expenses before stock-based compensation on a per boe basis for the nine months ended September 30, 2025, decreased by $0.62 or 14% compared to the corresponding period of 2024 due to higher sales volumes mainly driven by the addition of the new Canadian operations. Total G&A expenses before stock-based compensation increased by 28% compared to the corresponding period of 2024, primarily due to the addition of the new Canadian operations.

Compared to the prior quarter, G&A expenses before stock-based compensation decreased by 7% or $0.24 per boe due to lower business development cost.

G&A expenses after stock-based compensation for the three and nine months ended September 30, 2025, increased by 114% and 7% or $1.25 and decreased $1.52 per boe compared to the corresponding periods of 2024, due to higher stock-based compensation attributed to a higher share price during the current periods and the addition of the new Canadian operations.

Compared to the prior quarter, G&A expenses after stock-based compensation decreased by 9% or $0.34 per boe due to a recovery from a lower share price.

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Foreign Exchange Gains and Losses

For the three and nine months ended September 30, 2025, we had a $0.3 million loss and $7.8 million loss on foreign exchange compared to a $3.1 million gain and $8.3 million gain on foreign exchange in the corresponding periods of 2024 and a $3.7 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.

The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the three and nine months ended September 30, 2025 and 2024 and the prior quarter:

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			Three Months Ended September 30,									Three Months Ended June 30,						Nine Months Ended September 30,
			2025			2024						2025						2025			2024
Change in the U.S. dollar against the Colombian peso			weakened by			comparable						weakened by						weakened by			strengthened by
			4%			—%						3%						12%			9%
Change in the U.S. dollar against the Canadian dollar			strengthened by			weakened by						weakened by						weakened by			strengthened by
			2%			1%						5%						3%			2%

Income Tax Expense

			Three Months Ended September 30,									Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024						2025			2024
(Loss) Income before income tax			$	(31,226)		$	21,900					$	(55,046)		$	66,516
Current income tax expense			$	4,022		$	15,217					$	14,482		$	61,422
Deferred income tax (recovery) expense			(15,298)			5,550						(17,557)			(32,332)
Income tax expense (recovery) expense			$	(11,276)		$	20,767					$	(3,075)		$	29,090
Effective tax rate			36		%	95		%				6		%	44		%

Current income tax expense was $14.5 million for the nine months ended September 30, 2025, compared to $61.4 million in the corresponding period of 2024, primarily due to lower taxable income.

The deferred tax for the nine months ended September 30, 2025, was a recovery of $17.6 million mainly due to an increase in deductible temporary differences arising from tax losses generated during the period. These were partially offset by higher tax depreciation relative to accounting depreciation.

For the nine months ended September 30, 2024, the deferred income tax was a recovery of $32.3 million, primarily as a result of the recognition of additional tax losses resulting from a tax planning strategy.

For the nine months ended September 30, 2025, the difference between the effective tax rate of negative 6% and the 35% statutory tax rate was primarily due to permanent differences and valuation allowance. This was partially offset by an increase in the impact of foreign taxes.

For the nine months ended September 30, 2024, the difference between the effective tax rate of 44% and the 50% Colombian tax rate was primarily due to a lower impact of foreign taxes, 2022 true-up related to tax planning strategy and non-taxable foreign exchange adjustments. These were partially offset by an increase in valuation allowance, other permanent differences, non-deductible stock-based compensation and non-deductible royalties in Colombia.

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

(Thousands of U.S. Dollars)			Three Months Ended September 30, 2025, Compared with Three Months Ended June 30, 2025			% change			Three Months Ended September 30, 2025, Compared with Three Months Ended September 30, 2024			% change			Nine Months Ended September 30, 2025 Compared with Nine Months Ended September 30, 2024			% change
Net (loss) income for the comparative period			$	(12,741)					$	1,133					$	37,426
Increase (decrease) due to:
Sales price			2,099						(15,375)						(144,810)
Sales volumes			(2,202)						(13,394)						49,713

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Oil, natural gas and NGL sales - Canada Operations			—						26,650						87,322
Expenses:
Operating			(12,524)						(22,319)						(50,027)
Transportation			197						(386)						843
Export tax			(2,630)						(2,630)						(2,630)
Cash G&A			1,007						(3,962)						(8,816)
Net lease payments			(567)						(586)						(662)
Interest, excluding amortization of deferred financing fees			(894)						(4,395)						(13,325)
Realized foreign exchange			(1,547)						(3,152)						(5,544)
Other cash income			891						1,268						1,645
Cash settlement on derivative instruments			5,830						7,461						9,535
Transaction costs			—						1,459						1,459
Current taxes			(1,827)						11,195						46,940
Interest income			(54)						(487)						(1,520)
Net change in funds flow from operations(1) from comparative period			(12,221)						(18,653)						(29,877)
Expenses:
Depletion, depreciation and accretion			3,654						(9,408)						(38,605)
Deferred tax			17,751						20,848						(14,775)
Amortization of deferred financing fees			(187)						(1,160)						(3,009)
Stock-based compensation			403						(3,288)						6,204
Derivative instruments gain or loss, net of settlements on derivative instruments			(21,928)						(9,527)						964
Unrealized foreign exchange			4,979						(216)						(10,606)
Other gain			(227)						(265)						(355)
Net lease payments			567						586						662
Net change in net loss			(7,209)						(21,083)						(89,397)
Net loss for the current period			$	(19,950)		(57)%			$	(19,950)		1,861%			$	(51,971)		239%

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

Capital expenditures during the three months ended September 30, 2025, were $57.3 million.

(Millions of U.S. Dollars)			Colombia			Ecuador			Canada			Total
Exploration:
Drilling and Completions			$	7.7		$	9.2		$	—		$	16.9
Civil Works			0.2			2.3			—			2.5
Other			3.2			3			—			6.2
Total Exploration			$	11.1		$	14.5		$	—		$	25.6
Development:
Drilling and Completions			$	9.4		$	0.1		$	7.2		$	16.7
Facilities			6.5			—			—			6.5
Civil Works			0.4			—			1.6			2.0
Other			5.0			1.1			0.4			6.5
Total Development			$	21.3		$	1.2		$	9.2		$	31.7
Total Company			$	32.4		$	15.7		$	9.2		$	57.3

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During the three months ended September 30, 2025, we drilled the following wells:

			Number of wells (Gross)			Number of wells (Net)
Exploration - Ecuador			1			1
Exploration - Colombia			1			1
Development - Canada			1			0.5
Total Company			3			2.5

During the three months ended September 30, 2025, we spud one exploration well in Ecuador and one in Colombia. As of September 30, 2025, the exploration well drilled in Ecuador was in-progress and in Colombia was a dry well. We also spud one development well in Canada which was in-progress as of September 30, 2025.

Liquidity and Capital Resources 

			As at
(Thousands of U.S. Dollars)			September 30, 2025						% Change						December 31, 2024
Cash and Cash Equivalents			$	49,089					(53)						$	103,379
Canada and Colombia Credit Facilities			$	42,309					(100)						$	—
6.25% Senior Notes due 2025			$	—					(100)						$	24,828
7.75% Senior Notes due 2027			$	24,201					—						$	24,201
9.50% Senior Notes due 2029			$	735,790					—						$	737,590

We believe that our capital resources, including cash on hand, cash generated from operations and available borrowings under our credit facilities and prepayment structure, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for the next 12 months, including the repayment of 25% of the principal amount of 9.50% Senior Notes due October 15, 2026, given the current oil price trends and production levels. Beyond the next 12 months, the Company may require the support of its lenders to renew existing lending arrangements and may also access to 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.

On October 24, 2025, we, through our wholly owned subsidiary, Gran Tierra Energy Colombia GmbH, entered into crude oil sale and purchase agreement where we will receive an advance of up to $150.0 million related to Ecuador production. An additional advance of $50.0 million is available to the Company, at the sole discretion of the lender and subject to completion of certain conditions.

Credit Facility - Canada

We, through our wholly owned subsidiary Gran Tierra Canada Ltd., have a revolving credit facility with National Bank of Canada dated March 22, 2024 with a borrowing base of C$100.0 million (US$71.8 million as of September 30, 2025) and the available commitment of a C$50.0 million (US$35.9 million as of September 30, 2025) revolving credit facility comprised of C$35.0 million (US$25.1 million as of September 30, 2025) syndicated facility and C$15.0 million (US$10.8 million as of September 30, 2025) 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,

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the margin or standby fee, as applicable is based on Net Debt to EBITDA ratio of Gran Tierra Canada Ltd. As of September 30, 2025, the outstanding balance under the facility was US$19.9 million (C$30.0 million) and the weighted-average interest rate on borrowings for the three and nine months ended September 30, 2025 was 6.64% and 6.48%, respectively. On July 22, 2025, the borrowing base was redetermined by National Bank of Canada at C$100.0 million, of which available commitment is C$50.0 million.

On October 30, 2025, the existing revolving credit facility was amended to increase available commitment amount from C$50.0 million (US$35.9 million as of September 30, 2025) to C$75.0 million (US$53.9 million as of September 30, 2025) and extend the term to a two-year maturing October 30, 2027. The borrowing base was maintained at C$100.0 million.

Credit Facility - Colombia

On April 16, 2025, we, through our wholly owned subsidiary, Gran Tierra Energy Colombia GmbH, a Swiss limited liability company, entered into a $75.0 million reserve-based lending facility. Any loans incurred under the new facility will mature on April 16, 2028 and will bear interest at a rate per annum equal to, at our option, either (a) a customary base rate (subject to a floor of 1.00%) plus an applicable margin of 4.50% or (b) a term SOFR reference rate plus an applicable margin of 4.50%. Interest on base rate borrowings is payable quarterly in arrears and interest on term SOFR borrowings accrues in respect of interest periods of three or six months, at the election of the Company, and is payable on the last day of such interest period.

On October 23, 2025, the existing RBL facility was amended (“ the Amended RBL Facility”) to reduce the borrowing base to $60.0 million and revised certain related terms, including provisions governing borrowings, hedging obligations, and borrowing base redetermination. Under the terms of Amended RBL Facility, we are required to repay any amounts outstanding in excess of $20.0 million upon funding the oil prepayment agreement and the lender may initiate a redetermination of the borrowing base if advances requested by us are in excess of $20.0 million.

As of September 30, 2025 the outstanding balance under the RBL Facility was $24.5 million. For the three and nine months ended September 30, 2025, the weighted-average interest rate on borrowings was 9.05% and 8.79%, respectively.

Under the terms of the facility, we are required to maintain compliance with the following financial covenants:

i.consolidated net debt to consolidated adjusted EBITDA ratio that may not exceed 3.00 to 1.00, and

ii.consolidated interest coverage ratio that may not be less than 2.50 to 1.00

Senior Notes

At September 30, 2025, we had $24.2 million aggregate principal amount of outstanding 7.75% Senior Notes due 2027, and $735.8 million aggregate principal amount of outstanding 9.50% Senior Notes due 2029.

During the nine months ended September 30, 2025, we paid at maturity the remaining principal of $24.8 million of 6.25% Senior Notes due in February 2025 for cash consideration of $25.6 million, including interest payable of $0.8 million.

The principal amount of 9.50% Senior Notes is to be repaid as follows: (i) October 15, 2026, 25% of the principal amount; (ii) October 15, 2027 5% of the principal amount; (iii) October 15, 2028, 30% of the principal amount; and (iv) October 15, 2029, the remainder of the principal amount.

We were in compliance with all applicable covenants related to credit facilities and Senior Notes as of September 30, 2025.

Share Repurchase Program, NCIB

During the three and nine months ended September 30, 2025, we re-purchased nil and 692,804 shares under the 2024 Program at a weighted average price of nil and $5.00 per share (three and nine months ended September 30, 2024 - 371,130 and 1,662,110 shares under the 2023 program at a weighted average price of $9.37 and $7.31 per share). Under the 2024 Program, we were able to re-purchase at prevailing market prices up to 3,545,872 shares of Common Stock, representing approximately 10% of the public float as of October 31, 2024. We cancelled 487,948 held as treasury shares as at December 31, 2024 and cancelled 10,000 shares re-purchased during the nine months ended September 30, 2025. During the period from November 6, 2024 to October 29, 2025, we have re-purchased 1,180,752 shares under the 2024 Program.

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Acquisitions and Dispositions

On September 8, 2025, we, through our wholly owned subsidiary, Gran Tierra UK Limited, a United Kingdom limited company, closed the sale agreement for its wholly owned subsidiary, Gran Tierra North Sea Limited (“GTNSL”) to NEO Energy for total consideration of $7.5 million. The deferred income tax asset balance of $7.5 million has been applied against total consideration and resulted in zero gain or loss on sale.

On July 31, 2025, we, through our indirect wholly owned subsidiaries, Gran Tierra Energy Ecuador 1 GmbH and Gran Tierra Energy Ecuador 2 GmbH, have entered into definitive agreements to acquire all of GeoPark Ecuador S.A.’s and Frontera Energy Colombia Corp Sucursal Ecuador’s interests in the Perico and Espejo Blocks (the “Blocks”) and their associated Consortiums (the “Consortiums”).

The aggregate purchase price for the Blocks and Consortiums is $15.5 million, subject to customary working capital adjustments as of the effective date of January 1, 2025. The agreement includes an additional contingent consideration of $1.5 million, payable upon the Perico Block achieving cumulative gross production of two million barrels starting from January 1, 2025. The acquisitions are expected to close upon satisfaction of customary closing conditions, including the receipt of regulatory approvals for closing and operations takeover from the Ministry of Energy of Ecuador. Closing is anticipated no earlier than the fourth quarter of 2025.

Cash Flows

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

			Nine Months Ended September 30,
(Thousands of U.S. Dollars)			2025			2024
Sources of cash and cash equivalents:
Net (loss) income			$	(51,971)		$	37,426
Adjustments to reconcile net loss to Adjusted EBITDA(1) and funds flow from operations(1)
DD&A expenses			205,818			167,213
Interest expense			73,048			56,714
Income tax expense			(3,075)			29,090
Non-cash lease expenses			4,648			4,164
Lease payments			(4,686)			(3,540)
Foreign exchange loss (gain)			7,838			(8,312)
Stock-based compensation expense			172			6,376
Financial instruments loss			(964)			—
Transaction costs			—			1,459
Other loss			355			—
Adjusted EBITDA(1)			231,183			290,590
Current income tax expense			(14,482)			(61,422)
Contractual interest and other financing expenses			(60,864)			(47,539)
Transaction costs			—			(1,459)
Realized foreign exchange (loss) gain			(4,902)			642
Funds flow from operations(1)			150,935			180,812
Proceeds from issuance of Senior Notes, net of issuance costs			—			222,528
Proceeds from exercise of stock options			40			367
Proceeds from disposition of property, plant and equipment			7,500			—
Proceeds from debt, net of issuance costs			48,921			—
Foreign exchange gain on cash and cash equivalents and restricted cash and cash equivalents			—			986
Net changes in assets and liabilities from operating activities			9,867			32,164

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			217,263			436,857
Uses of cash and cash equivalents:
Additions to property, plant and equipment			(218,155)			(163,823)
Repayment of long-term debt			(7,743)			—
Purchase of Senior Notes			(1,712)			—
Repayment of Senior Notes			(24,828)			(36,364)
Re-purchase of shares of Common Stock			(3,466)			(12,144)
Settlement of asset retirement obligations			(4,746)			(262)
Lease payments			(8,473)			(9,422)
Foreign exchange loss on cash, and cash equivalents and restricted cash and cash equivalents			(1,299)			—
			(270,422)			(222,015)
Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents			$	(53,159)		$	214,842

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

One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices. Sales volume changes, costs related to operations and debt transactions also impact cash flows. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes. During the three months ended September 30, 2025, funds flow from operations decreased by 31% compared to the corresponding period of 2024, due to a decrease in Brent price, higher operating expenses and higher transportation cost partially offset by higher sales volumes, lower differentials and lower current income tax expense. Funds flow from operations for the nine months ended September 30, 2025, decreased by 17% compared to the corresponding period of 2024, primarily due to decrease in Brent price, higher operating expenses, higher interest expense partially offset by higher sales volumes, lower differentials and lower current income tax expense.

Critical Accounting Policies and Estimates

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our principal market risk relates to oil, natural gas and NGL prices which are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Our revenues are from oil sales at Brent or Edmonton Light pricing and for gas at AECO pricing and adjusted for quality. As at September 30, 2025, the Company had 1,782 and 562 weighted average bopd crude volumes hedged up to December 31, 2026, in Colombia and Canada, respectively, as well as 22,500 weighted average GJ/day natural gas volumes hedged for Q4 2025 and 10,000 weighted average GJ/day natural gas volumes hedged for second and third quarters of 2026. The Company entered into an additional 10,000 weighted average GJ/day natural gas derivative from January 01, 2026 up to October 31, 2026 as well as 2,500 weighted average bopd crude volumes from January 01, 2026 up to December 31, 2026, subsequent to the quarter-end, to manage the variability of cash flows associated with the forecasted sale of our 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 82% of our revenues are related to the U.S. dollar price of Brent with the remainder related to Canadian dollar price of WTI oil or AECO gas. In Colombia and Ecuador, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures is in U.S. dollars or is based on U.S. dollar prices. The majority of income and value added taxes and G&A expenses in all locations are in local

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

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

During the three months ended September 30, 2025, the Company crystallized $80 million nominal USD$ (COP$323,600 million) in outstanding foreign currency derivatives for a gain of $6 million (COP$30,800 million) and as at September 30, 2025 had no outstanding foreign currency derivative positions.

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 Canadian revolving credit facility and Colombian reserve-based lending (“RBL”) facility, which bear floating rates of interest. As of September 30, 2025 our outstanding balance under the revolving credit facility was US$19.9 million (C$30.0 million) and $24.5 million under the RBL facility (December 31, 2024 - nil).

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 September 30, 2025.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2025, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

On October 31, 2024, the Company completed the acquisition of i3 Energy Plc (“i3 Energy”), a publicly traded oil and gas company that was listed on the TSX venture exchange. i3 Energy’s operations have been included in the consolidated financial statements of Gran Tierra since October 31, 2024. However, Gran Tierra has not yet completed its assessment of the disclosure controls and procedures, and internal controls over financial reporting previously used by i3 Energy, and integrate them with those of Gran Tierra. As a result, the certifying officers have limited the scope of their design of disclosure controls and procedures and internal controls over financial reporting to exclude controls, policies and procedures of i3 Energy (as permitted by applicable securities laws in U.S.). Gran Tierra has a program in place to complete its assessment of the controls, policies and procedures of the acquired operations by October 31, 2025. During the nine months ended September 30, 2025, the assets previously held by i3 Energy, contributed $87.3 million (representing 19%) of total Company’s oil, natural gas and NGL revenue and as at September 30, 2025, there were $291.7 million of total assets associated with acquired entity.

PART II - Other Information

Item 1. Legal Proceedings

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

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Item 1A. Risk Factors

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

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

Issuer Purchases of Equity Securities

			(a) Total Number of Shares Purchased			(b) Average Price Paid per Share (1)			(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs			(d) Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs (2)
July 1-31, 2025						$	—		—			2,365,120
August 1-31, 2025						—			—			2,365,120
September 1-30, 2025			—			$	—		—			2,365,120
Total			—			$	—		—			2,365,120

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

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

Item 5. Other Information

During the three months ended September 30, 2025, no director or Section 16 officer adopted or terminated any Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements (in each case, as defined in Item 408(a) of Regulation S-K).

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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†			Second Amended and Restated Credit Agreement, dated as of October 30, 2025, between Gran Tierra Canada LTD., as borrower, the lenders party thereto, and National Bank of Canada, as administrative agent, and National Bank Financial Markets, as lead arranger.†						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 September 30, 2025, formatted in Inline XBRL (included within the Exhibit 101 attachments).

† Certain confidential information contained in this agreement has been omitted because it is both (i) not material and (ii) the

type of information that the Company treats as private or confidential.

53

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: October 30, 2025						/s/ Gary S. Guidry
						By: Gary S. Guidry
						President and Chief Executive Officer
						(Principal Executive Officer)

Date: October 30, 2025						/s/ Ryan Ellson
						By: Ryan Ellson
						Executive Vice President and Chief Financial Officer
						(Principal Financial and Accounting Officer)

54

FAQ

What were Gran Tierra (GTE) Q3 2025 sales and earnings?

Sales were $149.3 million and net loss was $19.95 million.

How did GTE’s production and sales volumes change in Q3 2025?

NAR production averaged 35,962 BOEPD (up 38% YoY) and NAR sales volumes were 37,353 BOEPD (up 47% YoY).

What is GTE’s debt position as of September 30, 2025?

Long‑term debt was $761.8 million, including $735.8 million of 9.50% Senior Notes due 2029.

What were operating cash flow and capital expenditures year to date?

For the nine months, operating cash flow was $156.1 million and capital expenditures were $218.2 million.

Did GTE enter any financing or liquidity arrangements after quarter end?

Yes. On October 24, 2025, it entered an oil sale and purchase agreement for an advance of up to $150.0 million related to Ecuador production.

How many GTE shares were outstanding?

There were 35,295,753 shares outstanding as of October 28, 2025.

Were credit facilities changed around quarter end?

Yes. The Canada facility commitment increased to C$75.0 million on October 30, 2025; the Colombia RBL base was revised to $60.0 million on October 23, 2025.