Gran Tierra Energy Q3 net loss widens to $42.4M
Shareholder approval for the Colombia and Ecuador sale followed quarter-end, but closing still depends on remaining consents, regulatory approvals and customary conditions.
Sentiment and the balance of points
Rhea-AI Sentiment reads the wording of the document, how positive or negative its language is on a 1 to 5 scale. The balance of points shown with the takes weighs what the document actually discloses, so the two can disagree, for example when a trial that missed its main goal is described in upbeat language.
Form Type
10-Q
Rhea-AI Filing Summary
Gran Tierra Energy Inc. (GTE) reported third-quarter 2026 oil, natural gas and NGL sales of $168.3 million, up 13% from a year earlier, while its net loss widened to $42.4 million from $20.0 million. Higher benchmark oil prices lifted sales, partly offset by lower sales volumes and higher Colombia transportation and quality discounts.
Production NAR fell 13% to 31,390 BOEPD. Adjusted EBITDA was $68.1 million versus $69.0 million, and funds flow from operations was $31.6 million versus $41.7 million. Net cash provided by operating activities for the first nine months was $256.706 million, compared with $156.056 million in 2025.
The company agreed to sell its Colombia and Ecuador oil business for approximately $1.33 billion, subject to adjustment, and expects approximately $315.0 million in net cash proceeds after assumed liabilities, adjustments, debt redemption and transaction costs. Shareholders approved the sale after September 30; closing remains subject to creditor and prepayment-buyer consents, regulatory approvals and other customary conditions.
2 points · 0 major0 major · 1 point
How this balance works
Rhea-AI gives every point it takes from this document a weight. Minor counts 1, Moderate 3 and Major 9, so one Major point outweighs several Minor ones. The bar adds up the weights on each side, and when neither side holds more than 65% of the total the balance reads Mixed.
It reads the document as published, with the same rules for every company, and it does not look at what the market expected or at how the stock traded, so a point can be objectively good on a day the stock falls.
Rhea-AI Sentiment measures something else, the tone of the wording.
Positive
- Moderate pointOil, natural gas and NGL sales rose 13% to $168.3 million in Q3 2026.
- Moderate pointNine-month operating cash flow was $256.706 million, compared with $156.056 million in 2025.
Negative
- Moderate pointQ3 net loss was $42.4 million, versus $20.0 million in the prior-year quarter.
Filing Explained
Although shareholders have approved the Colombia/Ecuador sale, it remains unclosed; the company’s expected
Key Figures
Oil, natural gas and NGL sales: $168.3 million
Net loss: $42.4 million
Production NAR: 31,390 BOEPD
+5 more
8 metrics
Oil, natural gas and NGL sales
$168.3 million
Three months ended September 30, 2026
Net loss
$42.4 million
Three months ended September 30, 2026
Production NAR
31,390 BOEPD
Third quarter 2026
Adjusted EBITDA
$68.1 million
Third quarter 2026
Funds flow from operations
$31.6 million
Third quarter 2026
Net cash provided by operating activities
$256.706 million
Nine months ended September 30, 2026
Sale consideration
Approximately $1.33 billion
Colombia and Ecuador oil business sale; subject to adjustment
Expected net cash proceeds
Approximately $315.0 million
Colombia and Ecuador oil business sale
Key Terms
Production NAR, Net Cash Proceeds, Prepayment Agreement, Asset Coverage Ratio, +1 more
5 terms
Production NAR technical
"Production NAR for the third quarter of 2026 decreased by 13%"
Net Cash Proceeds financial
"expects to receive net cash proceeds of approximately $315.0 million"
The actual cash a company receives from a financing or sale after subtracting direct transaction costs such as bank and legal fees, commissions, taxes and other closing expenses. Think of it like selling a house and keeping what’s left after paying the realtor and closing costs — it’s the money that truly lands in the company’s account. Investors watch net cash proceeds because they determine how much cash is available for growth, paying down debt, dividends or share buybacks and therefore affect financial strength and valuation.
Prepayment Agreement financial
"amended its existing prepayment agreement with Trafigura"
Asset Coverage Ratio financial
"Asset Coverage Ratio of at least 150%"
Asset coverage ratio measures how much of a company’s debt or preferred claims could be paid off using its tangible assets if the business had to be sold. It’s a safety check for investors and creditors, showing the size of the asset “cushion” available to meet obligations; a higher ratio means more protection, like having enough savings and sellable belongings to cover outstanding bills, while a low ratio signals greater risk of loss.
Debt Service Coverage Ratio financial
"Debt Service Coverage Ratio of at least 200%"
Debt service coverage ratio measures how many times a company's available cash flow can pay its scheduled debt payments (interest plus principal). Think of it like checking how many months of take-home pay it would take to cover your mortgage and loan bills; a higher number means a bigger cushion against missed payments. Investors use it to gauge credit risk, the likelihood of default, and whether a company can afford dividends or new borrowing.
FAQ
AI-generated questions and answers. How Rhea-AI works. Not financial advice.
How did GTE's third-quarter 2026 results compare with last year?
GTE recorded oil, natural gas and NGL sales of $168.3 million and a $42.4 million net loss in the three months ended September 30, 2026, compared with $149.254 million in sales and a $19.950 million net loss in the prior-year quarter.
How much cash does GTE expect from the Colombia and Ecuador sale?
The sale agreement states approximately $1.33 billion in total consideration and expected net cash proceeds of approximately $315.0 million, subject to adjustment. Shareholders approved the sale after September 30, 2026; completion remains subject to creditor and prepayment-buyer consents, regulatory approvals in Colombia and Ecuador, and customary closing conditions.
AI-generated analysis. How Rhea-AI works. Not financial advice.
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, 2026
or
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||||||
For the transition period from __________ to __________
Commission file number 001-34018
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | ||||||||||||||||
| (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 | ||||||
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).
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 | ☐ | ☒ | |||||||||
| 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 30, 2026, 35,381,811 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, 2026
Table of contents
| Page | ||||||||
| PART I | Financial Information | |||||||
| Item 1. | Financial Statements | 2 | ||||||
| Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 22 | ||||||
| Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 54 | ||||||
| Item 4. | Controls and Procedures | 55 | ||||||
| PART II | Other Information | |||||||
| Item 1. | Legal Proceedings | 56 | ||||||
| Item 1A. | Risk Factors | 56 | ||||||
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 58 | ||||||
| Item 5. | Other Information | 58 | ||||||
| Item 6. | Exhibits | 59 | ||||||
| SIGNATURES | 60 | |||||||
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: the risk that the Sale (as
1
defined herein) may not be completed on the anticipated terms or timeline, or at all, including as a result of a failure to obtain the requisite consent of the prepayment buyers under the Prepayment Agreement (as defined herein), or the required regulatory approvals, or a failure to satisfy other conditions precedent; the risk that the amount of cash actually received by the Company differs from the amounts disclosed in this Quarterly Report on Form 10-Q, which remain estimates and are subject to customary closing and working capital adjustments, transaction costs and other items determined at or following closing; the risk that the anticipated benefits of the Sale are not realized; the possibility that the Sale is terminated; the effect of the announcement or pendency of the Sale on the Company’s business, relationships and securities; certain of our operations are located in South America and the Company is pursuing activities in other international jurisdictions, including Azerbaijan, and unexpected problems can arise due to guerrilla activity, strikes, local blockades or protests; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; other disruptions to local operations; global health events; global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and natural gas, including inflation and changes resulting from actual or anticipated tariffs and trade policies, global health crises, geopolitical events, including the ongoing conflicts in Ukraine, the Middle East and Venezuela, or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC, and other producing countries and the resulting company or third-party actions in response to such changes; changes in commodity prices, including volatility or a prolonged decline in these prices relative to historical or future expected levels; the risk that current global economic and credit conditions may impact oil prices and oil consumption more than we currently predict which could cause further modification of our strategy and capital spending program; prices and markets for oil and natural gas are unpredictable and volatile; the effect of hedges; the accuracy of productive capacity of any particular field; geographic, political and weather conditions can impact the production, transport or sale of our products; our ability to execute our business plan, which may include acquisitions and dispositions, and realize expected benefits from current or future initiatives; such as the expected effectiveness of the exploration and development production sharing agreement (“EDPSA”) in Azerbaijan and the timing and execution of the related exploration program; the risk that unexpected delays and difficulties in developing currently owned properties may occur; the ability to replace reserves and production and develop and manage reserves on an economically viable basis; the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates); the risk profile of planned exploration activities; the effects of drilling down-dip; the effects of waterflood and multi-stage fracture stimulation operations; the extent and effect of delivery disruptions, equipment performance and costs; actions by third parties; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; volatility or declines in the trading price of our common stock or bonds; the risk that we do not receive the anticipated benefits of government programs, including government tax refunds; our ability to access debt or equity capital markets from time to time to raise additional capital, increase liquidity, fund acquisitions or refinance debt; our ability to comply with financial covenants in our indentures and make borrowings under our credit agreement; and those factors set out in Part II, Item 1A “Risk Factors” in this Quarterly Report on Form 10-Q and Part I, Item 1A “Risk Factors” in our 2025 Annual Report on Form 10-K (the “2025 Annual Report on Form 10-K”). This information included herein is given as of the filing date of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission (“SEC”) and, except as otherwise required by the securities laws, we disclaim any obligation or undertaking to publicly release any updates or revisions to or to withdraw, any forward-looking statement contained in this Quarterly Report on Form 10-Q to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based.
GLOSSARY OF OIL AND GAS TERMS
In this document, the abbreviations set forth below have the following meanings:
| bbl | barrel | BOEPD | barrels of oil equivalent per day | ||||||||
| BOPD | barrels of oil per day | NGL | natural gas liquids | ||||||||
| NAR | net after royalty | boe | barrels of oil equivalent | ||||||||
Sales volumes represent production NAR adjusted for inventory changes. Our oil and gas reserves are reported as NAR. Our production is also reported NAR, except as otherwise specifically noted as “working interest production before royalties”.
PART I - Financial Information
Item 1. Financial Statements
2
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, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| $ | $ | $ | $ | ||||||||||||||||||||
| EXPENSES | |||||||||||||||||||||||
| Operating | |||||||||||||||||||||||
| Transportation | |||||||||||||||||||||||
| Other taxes | |||||||||||||||||||||||
Depletion, depreciation and accretion (Note 5) | |||||||||||||||||||||||
| General and administrative | |||||||||||||||||||||||
| Severance | |||||||||||||||||||||||
Transaction costs (Note 5) | |||||||||||||||||||||||
| Foreign exchange loss | |||||||||||||||||||||||
Derivative instruments loss (gain) (Note 12) | ( | ||||||||||||||||||||||
Interest expense (Note 6) | |||||||||||||||||||||||
| INTEREST INCOME | |||||||||||||||||||||||
OTHER INCOME (Note 6) | |||||||||||||||||||||||
| LOSS BEFORE INCOME TAXES | ( | ( | ( | ( | |||||||||||||||||||
| INCOME TAX (RECOVERY) EXPENSE | |||||||||||||||||||||||
Current (Note 10) | |||||||||||||||||||||||
Deferred (Note 10) | ( | ( | ( | ( | |||||||||||||||||||
| ( | ( | ( | ( | ||||||||||||||||||||
| NET LOSS | $ | ( | $ | ( | $ | ( | $ | ( | |||||||||||||||
| OTHER COMPREHENSIVE LOSS | |||||||||||||||||||||||
| Foreign currency translation adjustment | ( | ( | |||||||||||||||||||||
| COMPREHENSIVE LOSS | $ | ( | $ | ( | $ | ( | $ | ( | |||||||||||||||
| NET LOSS PER SHARE | |||||||||||||||||||||||
| - BASIC and DILUTED | $ | ( | $ | ( | $ | ( | $ | ( | |||||||||||||||
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC and DILUTED (Note 8) | |||||||||||||||||||||||
(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, 2026 | As at December 31, 2025 | ||||||||||
| ASSETS | |||||||||||
| Current Assets | |||||||||||
Cash and cash equivalents (Note 13) | $ | $ | |||||||||
| Accounts receivable | |||||||||||
| Inventory | |||||||||||
Taxes receivable (Note 4) | |||||||||||
Derivatives (Note 12) | |||||||||||
| Prepaid expenses | |||||||||||
| Total Current Assets | |||||||||||
| Oil and Gas Properties | |||||||||||
| Proved | |||||||||||
| Unproved | |||||||||||
| Total Oil and Gas Properties | |||||||||||
| Other capital assets | |||||||||||
Total Property, Plant and Equipment (Note 5) | |||||||||||
| Other Long-Term Assets | |||||||||||
| Deferred tax assets | |||||||||||
Taxes receivable long-term (Note 4) | |||||||||||
Other long-term assets (Notes 12 and 13) | |||||||||||
| Total Other Long-Term Assets | |||||||||||
| Total Assets | $ | $ | |||||||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | |||||||||||
| Current Liabilities | |||||||||||
Accounts payable, accrued liabilities and other (Notes 6 and 7) | $ | $ | |||||||||
Current portion of long-term debt (Notes 6 and 12) | |||||||||||
Taxes payable (Note 4) | |||||||||||
Derivatives (Note 12) | |||||||||||
Equity compensation award liability (Note 8) | |||||||||||
| Total Current Liabilities | |||||||||||
| Long-Term Liabilities | |||||||||||
Long-term debt (Notes 6 and 12) | |||||||||||
Customer advance (Note 7) | |||||||||||
| Deferred tax liabilities | |||||||||||
| Asset retirement obligation | |||||||||||
Equity compensation award liability (Note 8) | |||||||||||
Other long-term liabilities (Note 4) | |||||||||||
| Total Long-Term Liabilities | |||||||||||
Contingencies (Note 11) | |||||||||||
| Shareholders’ Equity | |||||||||||
Common Stock ( | |||||||||||
| Additional paid-in capital | |||||||||||
| Accumulated other comprehensive (loss) income | ( | ||||||||||
| Deficit | ( | ( | |||||||||
| Total Shareholders’ Equity | |||||||||||
| Total Liabilities and Shareholders’ Equity | $ | $ | |||||||||
(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, | |||||||||||
| 2026 | 2025 | ||||||||||
| Operating Activities | |||||||||||
| Net loss | $ | ( | $ | ( | |||||||
| Adjustments to reconcile net loss to net cash provided by operating activities: | |||||||||||
Depletion, depreciation and accretion (Note 5) | |||||||||||
Deferred tax recovery (Note 10) | ( | ( | |||||||||
Stock-based compensation expense (Note 8) | |||||||||||
Amortization of debt issuance costs (Note 6) | |||||||||||
| Unrealized foreign exchange (gain) loss | ( | ||||||||||
Other (gain) loss (Note 6) | ( | ||||||||||
Unrealized derivative instruments loss (gain) (Note 12) | ( | ||||||||||
| Cash settlement of asset retirement obligation | ( | ( | |||||||||
| Non-cash interest expense | |||||||||||
| Non-cash lease expenses | |||||||||||
| Lease payments | ( | ( | |||||||||
Net change in assets and liabilities from operating activities (Note 13) | |||||||||||
| Net cash provided by operating activities | |||||||||||
| Investing Activities | |||||||||||
Additions to property, plant and equipment (Notes 5 and 13) | ( | ( | |||||||||
Proceeds on disposition of property, plant and equipment (Note 5) | |||||||||||
| Proceeds from asset exchange | |||||||||||
Deposit on sale of oil business in Colombia and Ecuador (Note 5) | |||||||||||
| Net cash used in investing activities | ( | ( | |||||||||
| Financing Activities | |||||||||||
Proceeds from long-term debt, net of issuance costs (Note 6) | |||||||||||
Repayment of long-term debt (Note 6) | ( | ( | |||||||||
Re-purchase of Senior Notes (Note 6) | ( | ( | |||||||||
Repayment of Senior Notes (Note 6) | ( | ( | |||||||||
Re-purchase of shares of Common Stock (Note 8) | ( | ||||||||||
| Proceeds from exercise of stock options | |||||||||||
| Lease payments | ( | ( | |||||||||
| Net cash (used in) provided by financing activities | ( | ||||||||||
| Foreign exchange gain (loss) on cash, cash equivalents and restricted cash and cash equivalents | ( | ||||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents | ( | ||||||||||
Cash and cash equivalents and restricted cash and cash equivalents, beginning of period (Note 13) | |||||||||||
Cash and cash equivalents and restricted cash and cash equivalents, end of period (Note 13) | $ | $ | |||||||||
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, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Share Capital | |||||||||||||||||||||||
| Balance, beginning of period | $ | $ | $ | $ | |||||||||||||||||||
Cancellation of shares of Common Stock (Note 8) | ( | ||||||||||||||||||||||
| Balance, end of period | $ | $ | $ | $ | |||||||||||||||||||
| Additional Paid-in Capital | |||||||||||||||||||||||
| Balance, beginning of period | $ | $ | $ | $ | |||||||||||||||||||
| Exercise of stock options | |||||||||||||||||||||||
Stock-based compensation (Note 8) | |||||||||||||||||||||||
Cancellation of shares of Common Stock (Note 8) | ( | ||||||||||||||||||||||
| Balance, end of period | $ | $ | $ | $ | |||||||||||||||||||
| Treasury Stock | |||||||||||||||||||||||
| Balance, beginning of period | $ | $ | $ | $ | ( | ||||||||||||||||||
Re-purchase of shares of Common Stock (Note 8) | ( | ||||||||||||||||||||||
Cancellation of shares of Common Stock (Note 8) | |||||||||||||||||||||||
| Balance, end of period | $ | $ | $ | $ | |||||||||||||||||||
| Accumulated other comprehensive income (loss) | |||||||||||||||||||||||
| Balance, beginning of period | $ | ( | $ | $ | $ | ( | |||||||||||||||||
| Other comprehensive income (loss) | ( | ( | |||||||||||||||||||||
| Balance, end of period | $ | ( | $ | ( | $ | ( | $ | ( | |||||||||||||||
| Deficit | |||||||||||||||||||||||
| Balance, beginning of period | $ | ( | $ | ( | $ | ( | $ | ( | |||||||||||||||
| Net loss | ( | ( | ( | ( | |||||||||||||||||||
| Balance, end of period | $ | ( | $ | ( | $ | ( | $ | ( | |||||||||||||||
| Total Shareholders’ Equity | $ | $ | $ | $ | |||||||||||||||||||
(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
2. Significant Accounting Policies
The note disclosure requirements of annual audited consolidated financial statements provide additional disclosures required for interim unaudited condensed consolidated financial statements. Accordingly, these interim unaudited condensed consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2025, included in the Company’s 2025 Annual Report on Form 10-K.
The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements, which are included in the Company’s 2025 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial statements. The Company has evaluated all subsequent events to the date these interim unaudited condensed consolidated financial statements were issued.
Recently Adopted Accounting Pronouncements
In July 2025, FASB issued ASU 2025-05 “Financial Instruments - Credit Losses: Amendments to the Measurement of Credit Losses on Certain Financial Assets”. This ASU provides a practical expedient for estimating expected credit losses on certain short-term receivables and contract assets arising from revenue transactions within the scope of ASC 606. Under the practical expedient, all entities may elect to assume that current conditions as of the balance sheet date would not change for the remaining life of the asset when developing reasonable and supportable forecasts. The ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2025, early adoption is permitted for both interim and annual reporting periods. The Company adopted this ASU effective January 1, 2026. The implementation of this update did not have a material impact on its balance sheet, statement of operations or financial statements disclosures.
Recently Issued Accounting Pronouncements
In May 2026, the FASB issued ASU 2026-02, Environmental Credits and Environmental Credit Obligations, which establishes guidance on the recognition, measurement, and disclosure of environmental credits and related obligations. The ASU requires entities to recognize qualifying environmental credits as assets measured at cost and to record environmental credit obligations as emissions occur, measured based on the carrying amount of credits held and the fair value of any additional credits required for settlement. The ASU is effective for annual reporting periods beginning after December 15, 2027, including interim periods within those years, with early adoption permitted. The Company is currently assessing the impact this update will have on its financial statements.
In November 2024, the FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses, which requires public business entities to provide additional disclosures disaggregating certain expense captions into specified natural expense categories, including employee compensation, depreciation, depletion and amortization related to oil and gas producing activities. The guidance is effective for annual periods beginning after December 15, 2026 and interim periods within annual periods beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating the impact of the guidance on its financial statement disclosures.
3. Segment and Geographic Reporting
The Company is primarily engaged in the exploration and production of oil and natural gas. The Company reports segmented information based on internal management reporting used by our Chief Operating Decision Makers (“CODM”), which are the Company’s Chief Executive Officer, Chief Financial Officer, Chief Operating Officer and Vice Presidents across various business functions. CODM allocates resources and assesses performance of each reportable segment based on segmented
7
earnings. The Company determined three reportable segments based on the geographic organization: Colombia, Ecuador and Canada. The “Other” category represents the Company’s corporate and the start-up of Azerbaijan activities.
The following tables present information on the Company’s reportable segments and other activities:
| Three Months Ended September 30, 2026 | |||||||||||||||||
| (Thousands of U.S. Dollars) | Colombia | Ecuador | Canada | Other | Total | ||||||||||||
| Oil, natural gas and NGL sales | $ | $ | $ | $ | $ | ||||||||||||
| Operating expenses | |||||||||||||||||
| Transportation expenses | |||||||||||||||||
| Segmented earnings | $ | $ | $ | $ | $ | ||||||||||||
| Other taxes | |||||||||||||||||
Depletion, depreciation and accretion (“DD&A”) expenses | |||||||||||||||||
| General and administrative expenses | |||||||||||||||||
| Transaction costs | |||||||||||||||||
| Foreign exchange loss | |||||||||||||||||
| Derivative instruments loss | |||||||||||||||||
| Interest expense | |||||||||||||||||
| Non-segmented expenses | |||||||||||||||||
| Other income | |||||||||||||||||
| Interest income | |||||||||||||||||
| Loss before income taxes | ( | ||||||||||||||||
| Income tax recovery | ( | ||||||||||||||||
| Net loss | $ | ( | |||||||||||||||
| Segment capital expenditures | $ | $ | $ | $ | $ | ||||||||||||
| Nine Months Ended September 30, 2026 | |||||||||||||||||
| (Thousands of U.S. Dollars) | Colombia | Ecuador | Canada | Other | Total | ||||||||||||
| Oil, natural gas and NGL sales | $ | $ | $ | $ | $ | ||||||||||||
| Operating expenses | |||||||||||||||||
| Transportation expenses | |||||||||||||||||
| Segmented earnings | $ | $ | $ | $ | $ | ||||||||||||
| Other taxes | |||||||||||||||||
Depletion, depreciation and accretion (“DD&A”) expenses | |||||||||||||||||
| General and administrative expenses | |||||||||||||||||
| Severance | |||||||||||||||||
| Transaction costs | |||||||||||||||||
| Foreign exchange loss | |||||||||||||||||
| Derivative instruments loss | |||||||||||||||||
| Interest expense | |||||||||||||||||
| Non-segmented expenses | |||||||||||||||||
8
| Other income | |||||||||||||||||
| Interest income | |||||||||||||||||
| Loss before income taxes | ( | ||||||||||||||||
| Income tax recovery | ( | ||||||||||||||||
| Net loss | $ | ( | |||||||||||||||
| Segment capital expenditures | $ | $ | $ | $ | $ | ||||||||||||
| Three Months Ended September 30, 2025 | |||||||||||||||||
| (Thousands of U.S. Dollars) | Colombia | Ecuador | Canada | Other | Total | ||||||||||||
| Oil, natural gas and NGL sales | $ | $ | $ | $ | $ | ||||||||||||
| Operating expenses | |||||||||||||||||
| Transportation expenses | |||||||||||||||||
| Segmented earnings | $ | $ | $ | $ | $ | ||||||||||||
| Other taxes | |||||||||||||||||
Depletion, depreciation and accretion (“DD&A”) expenses | |||||||||||||||||
| General and administrative expenses | |||||||||||||||||
| Foreign exchange loss | |||||||||||||||||
| Derivative instruments loss | |||||||||||||||||
| Interest expense | |||||||||||||||||
| Non-segmented expenses | |||||||||||||||||
| Other income | |||||||||||||||||
| Interest income | |||||||||||||||||
| Loss before income taxes | ( | ||||||||||||||||
| Income tax recovery | ( | ||||||||||||||||
| Net loss | $ | ( | |||||||||||||||
| Segment capital expenditures | $ | $ | $ | $ | $ | ||||||||||||
| Nine Months Ended September 30, 2025 | |||||||||||||||||
| (Thousands of U.S. Dollars) | Colombia | Ecuador | Canada | Other | Total | ||||||||||||
| Oil, natural gas and NGL sales | $ | $ | $ | $ | $ | ||||||||||||
| Operating expenses | |||||||||||||||||
| Transportation expenses | |||||||||||||||||
| Segmented earnings | $ | $ | $ | $ | $ | ||||||||||||
| Other taxes | |||||||||||||||||
Depletion, depreciation and accretion (“DD&A”) expenses | |||||||||||||||||
| General and administrative expenses | |||||||||||||||||
| Foreign exchange loss | |||||||||||||||||
| Derivative instruments gain | ( | ||||||||||||||||
| Interest expense | |||||||||||||||||
9
| Non-segmented expenses | |||||||||||||||||
| Other income | |||||||||||||||||
| Interest income | |||||||||||||||||
| Loss before income taxes | ( | ||||||||||||||||
| Income tax recovery | ( | ||||||||||||||||
| Net loss | $ | ( | |||||||||||||||
| Segment capital expenditures | $ | $ | $ | $ | $ | ||||||||||||
| As at September 30, 2026 | |||||||||||||||||
| (Thousands of U.S. Dollars) | Colombia | Ecuador | Canada | Other | Total | ||||||||||||
| Property, plant and equipment | $ | $ | $ | $ | $ | ||||||||||||
| All other assets | |||||||||||||||||
| Total Assets | $ | $ | $ | $ | $ | ||||||||||||
| As at December 31, 2025 | |||||||||||||||||
| (Thousands of U.S. Dollars) | Colombia | Ecuador | Canada | Other | Total | ||||||||||||
| Property, plant and equipment | $ | $ | $ | $ | $ | ||||||||||||
| All other assets | |||||||||||||||||
| Total Assets | $ | $ | $ | $ | $ | ||||||||||||
4. Taxes Receivable and Payable
The table below shows the breakdown 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, 2026 | As at December 31, 2025 | |||||||||
Taxes Receivable | |||||||||||
| Current | |||||||||||
VAT Receivable | $ | $ | |||||||||
| Income Tax Receivable | |||||||||||
| $ | $ | ||||||||||
| Long-Term | |||||||||||
Income Tax Receivable | $ | $ | |||||||||
Taxes Payable | |||||||||||
Current | |||||||||||
VAT Payable | $ | ( | $ | ( | |||||||
| Income Tax Payable | ( | ( | |||||||||
| $ | ( | $ | ( | ||||||||
| Long-Term | |||||||||||
Income Tax Payable(1) | $ | ( | $ | ||||||||
| Total Net Taxes Receivable | $ | $ | |||||||||
(1) Included in other long-term liabilities on the Company’s condensed consolidated balance sheet.
10
The following table shows the movement of VAT and income tax receivables and payables for the period:
| (Thousands of U.S. Dollars) | VAT Receivable/(Payable)(1) | Income Tax Receivable | Total Net Taxes Receivable | ||||||||||||||
Balance, as at December 31, 2025 | $ | ( | $ | $ | |||||||||||||
Collected through direct government refunds | ( | ( | ( | ||||||||||||||
Collected through sales contracts | ( | ( | |||||||||||||||
| Taxes paid | |||||||||||||||||
Withholding taxes paid | |||||||||||||||||
Current tax expense | ( | ( | |||||||||||||||
| Foreign exchange gain | |||||||||||||||||
Balance, as at September 30, 2026 | $ | ( | $ | $ | |||||||||||||
(1) VAT is paid on certain goods and services and collected on sales in Colombia at a rate of 19%.
5. Property, Plant and Equipment
| (Thousands of U.S. Dollars) | As at September 30, 2026 | As at December 31, 2025 | |||||||||
| Oil and natural gas properties | |||||||||||
| Proved | $ | $ | |||||||||
| Unproved | |||||||||||
Other (1) | |||||||||||
| Accumulated depletion, depreciation and impairment | ( | ( | |||||||||
| $ | $ | ||||||||||
(1) The “other” category includes right-of-use assets for operating and finance leases of $107.4 million, which had a net book value of $52.7 million as at September 30, 2026 (December 31, 2025 - $65.0 million, which had a net book value of $30.8 million).
During the three and nine months ended September 30, 2026, the Company entered into one and five new finance leases related to power generation equipment agreements in Ecuador and Colombia and recognized right-of-use assets of $17.5 million and $38.5 million, respectively, related to these agreements. During the nine months ended September 30, 2026, the Company entered into one new operating office lease agreement in Colombia and recognized a right-of-use asset of $4.0 million related to this agreement.
For the three and nine months ended September 30, 2026 and 2025, the Company had no 83.30 per bbl, Edmonton Light Crude of C$102.70 per bbl, Alberta AECO spot price of C$2.01 per MMBtu, Edmonton Propane of C$28.54 per boe, Edmonton Butane of C$42.84 per boe and Edmonton Condensate of C$103.71 per boe (September 30, 2025 as follows: Brent Crude of $71.61 per bbl, Edmonton Light Crude of C$89.65 per bbl, Alberta AECO spot price of C$1.70 per MMBtu, Edmonton Propane of C$34.71 per boe, Edmonton Butane of C$43.07 per boe and Edmonton Condensate of C$93.35 per boe).
On August 5, 2026, the Company entered into a definitive share sale agreement (the “Share Purchase Agreement”) to sell its oil business in Colombia and Ecuador (“Divested Business”) to a Paris-listed international oil and natural gas exploration and production company (“Purchaser”) on the terms and conditions set out in the Share Purchase Agreement (the “Sale”). The Divested Business comprises all of the Company’s assets in Colombia and Ecuador. The transaction has an economic effective date of March 31, 2026. Total consideration for the Sale is approximately $1.33 billion, subject to adjustment, which includes the Purchaser’s assumption of the Company’s 9.75 % Senior Notes due 2031, its 9.50 % Senior Notes due 2029, and the prepayment facility under the Company’s prepayment agreement (the “Prepayment Agreement”). After the assumption of substantially all liabilities, customary closing and working capital adjustments, the Company’s redemption of its 7.75 % Senior Notes due 2027 (the “2027 Notes”), and transaction costs, the Company expects to receive net cash proceeds of approximately $315.0 million (the “Net Cash Proceeds”). Of this amount, approximately $250.0 million is payable in cash, of which $50.0 million was received as a deposit during the three months ended September 30, 2026, which was recorded in accounts payable and accrued liabilities on the Company’s condensed consolidated balance sheet and will be credited against the purchase price,
11
with the balance due on closing. The remaining $65.0 million is payable 364 days after closing under an unsecured note issued by the Divested Business. Completion of the Sale is subject to the approval of the Company’s shareholders, receipt of the requisite consents from certain creditors and from the prepayment buyers under the Prepayment Agreement, customary regulatory approvals in Colombia and Ecuador, and the satisfaction of other customary closing conditions. On September 22, 2026, the Company entered into a supplemental indenture to the indenture governing 9.75 % Senior Notes due 2031, following receipt of the consents from bond holders of a majority in aggregate principal amount of those notes, which amends the indenture to permit the sale of the Divested Business, with the amendments becoming operative upon closing of the Sale.
For the three and nine months ended September 30, 2026, the Company incurred $4.9 5 % per annum, within five days of termination, unless the termination results from the Purchaser’s default, in which case the Company is entitled to retain the deposit and accrued interest. In addition, if the agreement is terminated following a change in the Board’s recommendation to shareholders, a failure by the Company to file its proxy statement or hold its shareholder meeting within the required timeframes, or the Company’s acceptance of a superior proposal, the Company must pay the Purchaser a termination fee of $50.0 million within ten days of termination.
As at September 30, 2026, the Company assessed whether the assets and liabilities subject to the Share Purchase Agreement met the criteria to be classified as held for sale under GAAP. The Company concluded that the held for sale criteria were not met as at that date because the Sale remained subject to shareholders’ approval, a substantive condition. Accordingly, the assets and liabilities of the Divested Business continue to be classified as held and used.
Subsequent to September 30, 2026, the Company obtained the shareholders’ approval for the sale of the Divested Business.
On June 23, 2026, the Company completed a disposition of 54 % WI and associated title rights in the Lodgepole area in Canada effective January 1, 2026, for a total cash consideration of C$12.8 million (US$9.3 million). As part of the disposition, the Company derecognized the asset retirement obligation attributed to the Lodgepole area totaling C$17.5 million (US$12.8 million) on an undiscounted basis and C$9.0 million (US$6.6 million) on a discounted basis. No gain or loss was recognized in the statement of operations as the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.
On March 10, 2026, the Company completed the disposition of the entire WI and associated title rights in the Simonette Montney area in Canada effective January 1, 2026, for total cash consideration of C$66.3 million (US$48.6 million). No gain or loss was recognized in the statement of operations as the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.
On March 17, 2026, the Company entered into a strategic partnership with Ecopetrol S.A. to earn, subject to regulatory approvals and conditions precedent, a 49 % WI in the Tisquirama Block in Colombia. Under the terms of the agreement, the Company has committed to fund approximately $47.1 million of a $92.4 million gross capital program over 40 months, including a minimum Phase 1 investment of $15.0 million. Upon completion of Phase 1, the Company will be entitled to 49 % of production and is expected to assume operatorship. On May 27, 2026, the Company satisfied all outstanding conditions precedent to the partnership agreement and received regulatory approval.
12
6. Debt and Debt Issuance Costs
The Company’s debt as at September 30, 2026, and December 31, 2025, was as follows:
| (Thousands of U.S. Dollars) | As at September 30, 2026 | As at December 31, 2025 | |||||||||
| Current | |||||||||||
| $ | $ | ||||||||||
| Unamortized Senior Notes discount | ( | ( | |||||||||
| Unamortized debt issuance costs | ( | ( | |||||||||
| $ | $ | ||||||||||
| Long-Term | |||||||||||
| $ | $ | ||||||||||
| Unamortized Senior Notes discount | ( | ( | |||||||||
Unamortized debt issuance costs (1) | ( | ( | |||||||||
| $ | $ | ||||||||||
| Total Debt | $ | $ | |||||||||
(1) Includes $0.1 million of deferred financing fees related to Canadian revolving credit facility as at September 30, 2026 (December 31, 2025 - $1.8 million related to Canadian revolving and Colombian credit facilities).
(2) The current portion of the lease obligation was included in accounts payable and accrued liabilities on the Company’s condensed consolidated balance sheet and totaled $31.7 million as at September 30, 2026 (December 31, 2025 - $17.0 million).
Senior Notes
| (Thousands of U.S. Dollars) | 9.50% Senior Notes | 9.75% Senior Notes | |||||||||
Senior Notes, December 31, 2025 | $ | $ | |||||||||
Principal exchanged for | ( | ||||||||||
| Early participation principal payment | ( | ||||||||||
| Rounding adjustment on exchange | ( | ||||||||||
| Purchased in the open market | ( | ||||||||||
Senior Notes principal, September 30, 2026 | $ | $ | |||||||||
During the nine months ended September 30, 2026, the Company issued $503.6 million in aggregate principal amount of its 9.75 % Senior Secured Amortizing Notes due 2031 (the “9.75 % Senior Notes”), and paid $125.0 million in cash consideration in exchange for $628.7 million aggregate principal amount of its 9.50 % Senior Notes. The exchange was accounted for as a debt modification.
The 9.75 % Senior Notes will mature on April 15, 2031, unless earlier redeemed or re-purchased. Subject to adjustment for required minimum denominations, the principal amount of 9.75 % Senior Notes will be amortized over three installments as follows: (i) October 15, 2029 - 15 % of the principal amount; (ii) October 15, 2030 - 15 % of the principal amount; (iii) April 15, 2031 - the remainder of the principal amount. On or before December 31, 2026 (“the Offer Date”), the Company is required to offer to purchase up to $30.0 million aggregate principal amount of the 9.75 % Senior Notes (“the Offer Amount”). The Offer Amount will be reduced by the aggregate principal amount of any 9.75 % Senior Notes redeemed or re-purchased by the Company in the open market transactions before the Offer Date.
13
During the nine months ended September 30, 2026, the Company re-purchased $24.2 million of 9.75 % Senior Notes for cash consideration of $21.6 million resulting in a $1.3 million gain on purchase, which included the write-off of deferred financing fees of $1.4 million.
At any time, prior to April 15, 2028, the Company may redeem up to 35 % of the aggregate principal amount of 9.75 % Senior Notes at a redemption price equal to 109.75 % of the principal amount. Additionally, the Company may redeem all or a portion of the 9.75 % Senior Notes on or after 2028 at the following redemption prices: 2028 - 104.875 %; 2029 - 102.438 %; 2030 and thereafter - 100 %.
Under the terms of the 9.75 % Senior Notes agreement, the Company is required to maintain compliance with the following financial covenants:
i.consolidated interest coverage ratio of not less than 2.50 ; and
ii.consolidated net debt (total debt excluding deferred financing fees less cash equivalents) to consolidated adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”) of not more than 3.00 .
As at September 30, 2026, the Company was in compliance with all applicable covenants related to Senior Notes.
Upon closing of the Sale of the Divested Business as described in Note 5, the Purchaser will assume all of the Company’s obligations under the indenture that governs the 9.75 % Senior Notes and the indenture that governs the 9.50 % Senior Notes. On September 22, 2026, the Company entered into a supplemental indenture to the indenture governing the 9.75 % Senior Notes, following receipt of the consents from bond holders of a majority in aggregate principal amount of those notes, which amends the indenture to permit the sale of the Divested Business, with the amendments becoming operative upon closing of the Sale.
Credit facility
On May 12, 2026, the Company, through its wholly owned subsidiary Gran Tierra Canada Ltd., amended its revolving credit facility with National Bank of Canada. As part of the amendment, the borrowing base has decreased to C$75.0 million (US$52.8 million). The available commitment under the revolving credit facility remained unchanged at C$75.0 million (US$52.8 million), comprised of a C$60.0 million (US$42.2 million) syndicated facility and C$15.0 million (US$10.6 million) of operating facility. The amounts drawn down under the revolving credit facility can either be in Canadian or U.S. dollars and bear interest rates equal to either the Canadian prime rate or U.S. Base Rate plus a margin ranging from 2.00 % to 4.00 % per annum or for CORRA loans and SOFR loans plus a margin ranging from 3.00 % to 5.00 % per annum. Undrawn amounts under the revolving credit facility bear a standby fee ranging from 0.75 % to 1.25 % per annum. In each case, the margin or standby fee, as applicable is based on Net Debt to EBITDA ratio of Gran Tierra Canada Ltd. The revolving credit facility matures on October 30, 2027. During the three months ended September 30, 2026, the Company drew C$15.3 million (US$10.9 million) under its revolving credit facility which was fully repaid by September 30, 2026. As of September 30, 2026, the revolving credit facility remained undrawn.
Leases
During the three and nine months ended September 30, 2026, the Company entered into one and five finance leases of $17.5 million and $38.5 million, respectively. The new finance leases have lease terms ranging from to three years and a weighted average discount rate of 9.6 %.
During the nine months ended September 30, 2026, the Company entered into one operating lease of $4.0 million which had a five-year term and a discount rate of 9.1 %.
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) | 2026 | 2025 | 2026 | 2025 | |||||||||||||
| Contractual interest and other financing expenses | $ | $ | $ | $ | |||||||||||||
| Amortization of debt issuance costs | |||||||||||||||||
| $ | $ | $ | $ | ||||||||||||||
14
7. Prepayment agreement
During the nine months ended September 30, 2026, the Company amended its existing prepayment agreement with Trafigura. The amended agreement provides for total prepayments of up to $350.0 million, including $325.0 million available immediately and an additional $25.0 million available at Trafigura’s sole discretion and includes both Ecuadorian and Colombian crude oil production. The term of the amended prepayment agreement is 48 months.
Amounts drawn on this prepayment agreement are to be repaid through future oil deliveries. Shortfalls in crude oil deliveries in any given repayment period can be delivered during the next repayment period within three calendar months or paid in cash thereafter. Amounts under the prepayment facility are subject to interest based on SOFR risk-free rate plus a margin of 4.45 % per annum. Under the terms of the prepayment agreement, the Company can repay the outstanding balance of the advance payment at any time without penalty. The Company was granted a grace period for re-payment of the principal amount drawn under the prepayment agreement with first re-payment starting April 2026.
Pursuant to the amended and restated prepayment agreement, proceeds from the new advance are required to be used exclusively to finance the re-purchase or exchange of Senior Notes and to pay fees and expenses associated with the amended agreement.
The Company is required to maintain compliance with the following financial covenants related to amounts drawn under the prepayment agreement semi-annually, calculated on March 31 and September 30 of each year:
i.Asset Coverage Ratio of at least 150 %, calculated using the net present value of the consolidated future cash flows of certain wholly owned subsidiaries of the Company that sell crude oil, projected through the final maturity date and discounted at 10 % over the outstanding principal and the interest payable amount on the prepayment agreement at each reporting period. The net present value of the consolidated future cash flows of the Company is required to be based on 90 % of the prevailing ICE Brent forward strip.
ii.Debt Service Coverage Ratio of at least 200 %, calculated using the estimated crude oil to be delivered by the Company from any relevant time up to the final maturity date based on 80 % of the prevailing ICE Brent forward strip and adjusted for quality differential and transportation discount over the outstanding principal amount under the prepayment agreement.
As at September 30, 2026, there was $281.4 million outstanding (December 31, 2025 - $150.0 million) on the oil prepayment agreement. Of this amount, $88.9 million (December 31, 2025 - $34.1 million) was classified as a current portion and included in accounts payable and accrued liabilities on the Company’s condensed consolidated balance sheet.
| (Thousands of U.S. Dollars) | |||||
Outstanding balance on oil prepayment, December 31, 2025 | $ | ||||
| Prepayment advances | |||||
| Repayments | ( | ||||
Outstanding balance on oil prepayment, September 30, 2026 | $ | ||||
During the three and nine months ended September 30, 2026, the Company drew $8.5 million and $175.0 million on oil prepayment and re-paid $14.8 million and $43.6 million, respectively, of the outstanding principal on oil prepayment via crude oil deliveries.
As of September 30, 2026, the Company was in compliance with all applicable covenants under the prepayment agreement.
15
8. Share Capital
| Shares of Common Stock | |||||
Shares issued and outstanding at December 31, 2025 | |||||
| Shares issued on option exercise | |||||
Shares issued and outstanding at September 30, 2026 | |||||
As at September 30, 2026, the Company had a share re-purchase program (the “2025 Program”) through the facilities of the Toronto Stock Exchange (“TSX”), the NYSE American or alternative programs in Canada or the United States, if eligible. Under the 2025 Program, the Company is able to purchase up to 2,925,720 shares of Common Stock, par value of $0.001 10 % of the public float as of October 31, 2025, at prevailing market prices at the time of purchase. The 2025 Program will continue for one year and expire on November 5, 2026, or earlier if the 10 % maximum is reached.
During the three and nine months ended September 30, 2026, the Company did not nil and 692,804 shares re-purchased under the 2024 program at a weighted average price of nil and $5.00 per share, respectively).
Equity Compensation Awards
The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), restricted share units (“RSUs”) and stock option activity for the nine months ended September 30, 2026:
| PSUs | DSUs | RSUs | Stock Options | ||||||||||||||
| Number of Outstanding Share Units | Number of Outstanding Share Units | Number of Outstanding Share Units | Number of Outstanding Stock Options | Weighted Average Exercise Price/Stock Option ($) | |||||||||||||
| Balance, December 31, 2025 | |||||||||||||||||
| Granted | |||||||||||||||||
| Exercised | ( | ( | ( | ( | |||||||||||||
| Forfeited | ( | ( | ( | ||||||||||||||
| Expired | ( | ||||||||||||||||
Balance, September 30, 2026 | |||||||||||||||||
As at September 30, 2026, the equity compensation award liability on the Company’s balance sheet included $1.7 million of current liability related to the Company’s outstanding stock options (December 31, 2025 - $0.6 million).
For the three and nine months ended September 30, 2026, there was $30.5 million and $46.4 million of stock-based compensation expense (three and nine months ended September 30, 2025, $0.1 million and $0.2 million of stock-based compensation expense), respectively.
As at September 30, 2026, there was $58.7 million (December 31, 2025 - $15.4 million) of unrecognized compensation costs related to unvested PSUs, RSUs and stock options, which are expected to be recognized over a weighted-average period of 1.8 years. During the nine months ended September 30, 2026, the Company paid out $6.0 million for PSUs which vested on December 31, 2025 (nine months ended September 30, 2025 - $7.2 million for PSUs which vested on December 31, 2024).
During the three and nine months ended September 30, 2026, the Company awarded 479 and 1,049,365 of RSUs to employees pursuant to the existing 2007 Equity Incentive Plan, respectively. Under the 2007 Equity Incentive Plan, RSUs will vest one-third each year over a three-year
16
Net 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, 2026 and 2025, all options were excluded from the diluted loss per share calculation as the options were anti-dilutive.
9. Revenue
| Three Months Ended September 30, 2026 | Nine Months Ended September 30, 2026 | ||||||||||||||||||||||||||||
Crude Oil | Natural Gas | NGL | Total Revenue | Crude Oil | Natural Gas | NGL | Total Revenue | ||||||||||||||||||||||
Colombia | |||||||||||||||||||||||||||||
Ecuador | |||||||||||||||||||||||||||||
Canada | |||||||||||||||||||||||||||||
| $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||
| 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 | |||||||||||||||||||||||||||||
Ecuador | |||||||||||||||||||||||||||||
Canada | |||||||||||||||||||||||||||||
| $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||
During the three and nine months ended September 30, 2026, the Company’s production was sold primarily to one major customer, representing 70 % and 71 % of the total Company’s sales volumes (three and nine months ended September 30, 2025 - one major customer, representing 66 % and 65 % of the total Company’s sales volumes), respectively, reported in each of the reportable segments.
10. Taxes
The Company’s effective tax rate was 19 % for the nine months ended September 30, 2026, compared to 6 % in the corresponding period of 2025.
Current income tax expense was $19.5 million for the nine months ended September 30, 2026, compared to $14.5 million in the corresponding period of 2025, primarily due to higher taxable income.
For the nine months ended September 30, 2026, the Company recognized a deferred tax recovery of $51.2 million, primarily attributable to an increase in deductible temporary differences arising from tax losses generated during the period, unrealized hedging losses and accruals. This recovery was partially offset by temporary differences related to accelerated tax depreciation in excess of accounting depreciation.
17
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, 2026, the difference between the effective tax rate of 19 % and the 21 % statutory tax rate was primarily due to an increase in the non-deductible foreign translation adjustments and other non-deductible expenses. This was partially offset by an increase in the impact of foreign taxes and the 2025 true-up (recovery).
For the nine months ended September 30, 2025, the difference between the effective tax rate of 6 % and the 21 % statutory tax rate was primarily due to increase in the non-deductible foreign translation adjustments, other permanent differences and valuation allowance. This was partially offset by an increase in the impact of foreign taxes.
11. Contingencies
Legal Proceedings
The Company has several lawsuits and claims pending. The outcome of the lawsuits and disputes cannot be predicted with certainty; the Company believes the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows. The Company records costs as they are incurred or become probable and determinable.
Letters of Credit and Other Credit Support
At September 30, 2026, the Company had provided letters of credit and other credit support totaling $160.0 million, of which $0.5 million related to transportation capacity in Canada with the remainder as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, other capital or operating requirements (December 31, 2025 - $209.0 million). During the three months ended September 30, 2026, the Company released $39.1 million of letters of credit related to Suroriente Block due to completion of all capital commitments.
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 transfer a liability in an orderly transaction between market participants 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, 2026, the Company’s financial instruments recognized on the balance sheet consist of cash and cash equivalents, accounts receivable, derivatives, other long-term assets, accounts payable and accrued liabilities, current portion of long-term debt, long-term debt and other long-term liabilities. The Company uses appropriate valuation techniques based on the available information to measure the fair values of assets and liabilities.
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Fair Value Measurement
The following table presents the Company’s fair value measurements of its financial instruments as of September 30, 2026, and December 31, 2025:
| (Thousands of U.S. Dollars) | As at September 30, 2026 | As at December 31, 2025 | |||||||||
| Level 1 | |||||||||||
| Liabilities | |||||||||||
| $ | $ | ||||||||||
| $ | $ | ||||||||||
| Level 2 | |||||||||||
| Assets | |||||||||||
Restricted cash and cash equivalents - long-term (1) | $ | $ | |||||||||
| Commodity derivatives - current | |||||||||||
| $ | $ | ||||||||||
| Liabilities | |||||||||||
| Commodity derivatives - current | $ | $ | |||||||||
(1) The long-term portion of restricted cash and cash equivalents is included in the other long-term assets on the Company’s condensed consolidated balance sheet.
The fair values of cash and cash equivalents, current restricted cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate their carrying amounts due to the short-term maturity of these instruments.
Restricted Cash and Cash Equivalents - Long-Term
The fair value of long-term restricted cash and cash equivalents approximates its carrying value because interest rates are variable and reflective of market rates.
Senior Notes
Financial instruments recorded at amortized cost at September 30, 2026, were the Senior Notes (Note 6).
At September 30, 2026, the carrying amounts of the 7.75 % Senior Notes, 9.50 % Senior Notes and 9.75 % Senior Notes were $24.1 million, $84.5 million and $454.3 million, respectively, which represented the aggregate principal amounts less unamortized debt issuance costs and discounts, and the fair values were $23.7 million, $89.1 million and $495.7 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.
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| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||
| Commodity price derivative loss (gain) | $ | $ | $ | $ | ( | ||||||||||||
| Foreign currency derivative gain | ( | ( | ( | ( | |||||||||||||
| Derivative instruments loss (gain) | $ | $ | $ | $ | ( | ||||||||||||
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, 2026, the Company had outstanding commodity price derivative positions in Canada and Colombia as follows:
| Oil | ||||||||||||||||||||||||||
| Type of Instrument | Start Period | End Period | Volume bbl/d | Reference | Sold Put (C$/bbl or $/bbl Weighted Average) | Purchased Put (C$/bbl or $/bbl Weighted Average) | Sold Call (C$/bbl or $/bbl Weighted Average) | Premium (C$/bbl or $/bbl Weighted Average) | ||||||||||||||||||
| Collar | 10/01/26 | 12/31/26 | WTI CMA | C$ | C$ | |||||||||||||||||||||
| Put Option | 10/01/26 | 12/31/26 | Brent | |||||||||||||||||||||||
| Three Way | 10/01/26 | 12/31/26 | WTI CMA | C$ | C$ | C$ | C$ | |||||||||||||||||||
| Put Spread | 10/01/26 | 12/31/26 | Brent | |||||||||||||||||||||||
| Three Way | 10/01/26 | 12/31/26 | Brent | |||||||||||||||||||||||
| Three Way | 01/01/27 | 03/31/27 | Brent | |||||||||||||||||||||||
| Natural Gas | |||||||||||||||||||||||||||||
| Type of Instrument | Start Period | End Period | Volume, GJ/day | Reference | Sold Swap (C$/GJ, Weighted Average) | Purchased Put (C$/GJ, Weighted Average) | Sold Call (C$/GJ, Weighted Average) | ||||||||||||||||||||||
| Swap | 10/01/26 | 12/31/26 | Aeco 5A | C$ | — | — | |||||||||||||||||||||||
Subsequent to the period ended September 30, 2026, the Company entered into the following commodity price derivative positions:
| Oil | ||||||||||||||||||||||||||
| Type of Instrument | Start Period | End Period | Volume bbl/d | Reference | Sold Put ($/bbl Weighted Average) | Purchased Put ($/bbl Weighted Average) | Sold Call ($/bbl Weighted Average) | Premium ($/bbl Weighted Average) | ||||||||||||||||||
| Three Way | 01/01/2027 | 03/31/27 | Brent | — | ||||||||||||||||||||||
Foreign Exchange Risk
The Company is exposed to foreign exchange risk arising from Colombian and Canadian operations predominantly related to operating and transportation costs. Revenue and general and administrative expenses associated with the Company’s Canadian operations are also subject to foreign currency fluctuations. To mitigate exposure to fluctuations in foreign exchange, the Company may enter into foreign currency exchange derivatives.
As at September 30, 2026, the Company had no outstanding foreign currency exchange derivative positions.
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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) | 2026 | 2025 | 2025 | 2024 | |||||||||||||
| Cash and cash equivalents | $ | $ | $ | $ | |||||||||||||
| Restricted cash and cash equivalents - current | |||||||||||||||||
Restricted cash and cash equivalents - long-term (1) | |||||||||||||||||
| $ | $ | $ | $ | ||||||||||||||
(1) Included in other long-term assets on the Company’s condensed consolidated balance sheet.
Net changes in assets and liabilities from operating activities were as follows:
| Nine Months Ended September 30, | |||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | |||||||||
| Accounts receivable and other long-term assets | $ | ( | $ | ||||||||
| Derivatives | |||||||||||
Prepaids and inventory | ( | ||||||||||
| Oil prepayment | |||||||||||
Accounts payable and accrued liabilities, and other long-term liabilities | |||||||||||
| Taxes receivable and payable | ( | ||||||||||
| Net changes in assets and liabilities from operating activities | $ | $ | |||||||||
Net changes in working capital from investing activities were as follows:
| Nine Months Ended September 30, | |||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | |||||||||
| Additions to property, plant and equipment | $ | ( | $ | ( | |||||||
| Decrease in accounts payable and accrued liabilities | ( | ( | |||||||||
| (Increase) decrease in accounts receivable | ( | ||||||||||
Net cash additions to property, plant and equipment | $ | ( | $ | ( | |||||||
The following table provides additional supplemental cash flow disclosures:
| Nine Months Ended September 30, | |||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | |||||||||
| Cash paid for income taxes | $ | $ | |||||||||
| Cash paid for withholding taxes | $ | $ | |||||||||
| Cash paid for interest | $ | $ | |||||||||
| Non-cash investing activities: | |||||||||||
| Net liabilities related to property, plant and equipment, end of period | $ | $ | |||||||||
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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 2025 Annual Report on Form 10-K. Please see the cautionary language at the beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements and the risk factors described in Part II, Item 1A “Risk Factors” of this Quarterly Report on Form 10-Q, as well as Part I, Item 1A “Risk Factors” in our 2025 Annual Report on Form 10-K.
Financial and Operational Highlights
Key Highlights for the third quarter of 2026
•Net loss for the third quarter of 2026 was $42.4 million or $(1.20) per share basic and diluted, compared to a net loss of $20.0 million or $(0.57) per share basic and diluted for the third quarter of 2025 and net income of $24.9 million or $0.70 per share basic and diluted for the prior quarter.
•Loss before income taxes for the third quarter of 2026 was $68.0 million, compared to loss before income taxes of $31.2 million for the third quarter of 2025 and income before income taxes of $45.3 million for the prior quarter
•Brent oil price averaged $91.29 per bbl during the quarter, an increase of 34% from the comparative period of 2025, and a decrease of 6% from the prior quarter. Castilla, Vasconia and Oriente differentials averaged $13.73, $6.68 and $10.32 per bbl during the quarter, an increase of 181%, 255% and 43%, respectively, from the comparable period of 2025. Castilla, Vasconia and Oriente differentials increased by 41%, 370% and 413% from the prior quarter, respectively
•Adjusted EBITDA(2) was $68.1 million for the third quarter of 2026, a decrease from $69.0 million in the third quarter of 2025, and $85.1 million in the prior quarter
•Funds flow from operations(2) decreased to $31.6 million compared to $41.7 million in the third quarter of 2025, and $60.3 million in the prior quarter
•NAR production for the third quarter of 2026 decreased by 13% to 31,390 BOEPD, compared to 35,962 BOEPD in the third quarter of 2025, primarily due to lower production in Colombia, higher in-kind royalties Ecuador driven by higher oil prices and asset sales in Canada and decreased by 2% from 31,990 BOEPD in the prior quarter primarily due to sale of the Lodgepole area in Canada and lower production in Colombia, partially offset by lower in-kind royalties in Ecuador
•NAR sales volumes for the third quarter of 2026 decreased by 12% to 32,724 BOEPD, compared to 37,353 BOEPD in the third quarter of 2025 and increased by 2% from 32,166 BOEPD in the prior quarter
•Oil, natural gas and NGL sales for the third quarter of 2026 increased by 13% to $168.3 million, compared to the third quarter of 2025, due to increase in benchmark oil prices, partially offset by lower sales volumes in Colombia and Canada and higher quality and transportation discounts in Colombia associated with using alternative transportation routes for Putumayo production as the Colombia and Ecuador border remained closed. Oil, natural gas and NGL sales decreased by 10% from $187.2 million in the prior quarter due to lower benchmark oil prices, higher quality and transportation discounts in Colombia and a shift from premium to a discount in Ecuador, partially offset by higher sales volumes
•Operating expenses for the third quarter of 2026 decreased by 6% to $64.2 million when compared to the third quarter of 2025 primarily due to lower workover activities, reduced field personnel costs and lower equipment maintenance. Operating expenses increased by 24% from $51.6 million in the prior quarter due to higher workover activities and higher lifting costs associated with inventory fluctuations resulting from sale of inventory accumulated at the end of prior quarter
•On a per boe basis, operating expenses increased by $1.48 to $21.32 when compared to the third quarter of 2025 due to lower sales volumes and increased by $3.71 from $17.61 in the prior quarter due to higher workover activities and higher lifting costs associated with inventory fluctuations resulting from sale of inventory accumulated at the end of prior quarter
•Transportation expenses increased by 29% when compared to the third quarter of 2025 and increased by 42% from the prior quarter primarily due to higher volumes transported via pipeline which had higher costs per boe
•Gross profit increased to $40.9 million compared to $14.9 million in the third quarter of 2025 and decreased from $75.5 million in the prior quarter
22
•Operating netback(2) was $98.6 million compared to $76.8 million in the third quarter of 2025 and $131.7 million in the prior quarter
•Quality and transportation discounts per boe in South America were $18.09, an increase from $10.76 in the third quarter of 2025. Quality and transportation discounts in Colombia were affected by using an alternative transportation route for Putumayo production as the Colombia and Ecuador border remained closed, which was significantly more expensive and resulted in additional discounts of approximately $3.7 million for the current quarter. Quality and transportation discounts in South America increased from $10.47 per boe in the prior quarter primarily as a result of higher differentials
•Quality and transportation discounts for oil per boe in Canada for the third quarter of 2026 decreased to $6.11 compared to $6.38 in the third quarter of 2025 and increased from $2.24 in the prior quarter due to higher pipeline tariffs in the current quarter resulting from a change in product mix associated with asset sales
•General and administrative (“G&A”) expenses before stock-based compensation for the third quarter of 2026 decreased to $11.8 million compared to $13.2 million in the third quarter of 2025 and $13.2 million in the prior quarter due to lower consulting and legal expenses, lower costs associated with project optimization and lower salaries associated with headcount optimization when compared to the prior quarter
•Capital expenditures for the third quarter of 2026 were $30.7 million compared to $57.3 million in the third quarter of 2025 and $54.3 million in the prior quarter
•During the three months ended September 30, 2026, we entered into a definitive share sale agreement to sell our Colombia and Ecuador oil business for a total approximate consideration of $1.33 billion, subject to adjustment, including the assumption of our 2029 and 2031 Senior Notes and the Prepayment Agreement facility, with expected net cash proceeds of approximately $315.0 million. Subsequent to September 30, 2026, we obtained shareholders’ approval for the sale, and closing remains subject to remaining consents, regulatory approvals and other customary conditions
23
| (Thousands of U.S. Dollars, unless otherwise indicated) | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||
| 2026 | 2025 | % Change | 2026 | 2026 | 2025 | % Change | |||||||||||||||||||||||
| Average Daily Volumes (BOEPD) | |||||||||||||||||||||||||||||
| Consolidated | |||||||||||||||||||||||||||||
| Working Interest (“WI”) Production Before Royalties | 39,904 | 42,685 | (7) | 41,501 | 42,280 | 45,495 | (7) | ||||||||||||||||||||||
| Royalties | (8,514) | (6,723) | 27 | (9,511) | (8,596) | (7,396) | 16 | ||||||||||||||||||||||
| Production NAR | 31,390 | 35,962 | (13) | 31,990 | 33,684 | 38,099 | (12) | ||||||||||||||||||||||
| Decrease in Inventory | 1,334 | 1,391 | (4) | 176 | 1,341 | 132 | 916 | ||||||||||||||||||||||
Sales(1) | 32,724 | 37,353 | (12) | 32,166 | 35,025 | 38,231 | (8) | ||||||||||||||||||||||
| Net (Loss) Income | $ | (42,415) | $ | (19,950) | (113) | $ | 24,861 | $ | (136,726) | $ | (51,971) | (163) | |||||||||||||||||
| Operating Netback | |||||||||||||||||||||||||||||
| Gross Profit | $ | 40,872 | $ | 14,879 | 175 | $ | 75,460 | $ | 153,029 | $ | 66,293 | 131 | |||||||||||||||||
| Depletion and Accretion | 57,706 | 61,908 | (7) | 56,253 | 177,867 | 196,286 | (9) | ||||||||||||||||||||||
Operating Netback(2) | $ | 98,578 | $ | 76,787 | 28 | $ | 131,713 | $ | 330,896 | $ | 262,579 | 26 | |||||||||||||||||
| G&A Expenses before Stock-Based Compensation | $ | 11,814 | $ | 13,246 | (11) | $ | 13,219 | $ | 40,182 | $ | 39,306 | 2 | |||||||||||||||||
| G&A Stock-Based Compensation Expense (Recovery) | 30,465 | 143 | 21,204 | (3,757) | 46,384 | 172 | 26,867 | ||||||||||||||||||||||
| G&A Expenses, including Stock-Based Compensation | $ | 42,279 | $ | 13,389 | 216 | $ | 9,462 | $ | 86,566 | $ | 39,478 | 119 | |||||||||||||||||
Adjusted EBITDA(2) | $ | 68,096 | $ | 69,034 | (1) | $ | 85,071 | $ | 227,102 | $ | 231,183 | (2) | |||||||||||||||||
Funds Flow from Operations(2) | $ | 31,640 | $ | 41,685 | (24) | $ | 60,289 | $ | 134,752 | $ | 150,935 | (11) | |||||||||||||||||
| Capital Expenditures (before changes in working capital) | $ | 30,660 | $ | 57,340 | (47) | $ | 54,309 | $ | 130,328 | $ | 203,237 | (36) | |||||||||||||||||
(1) Sales volumes represent production NAR adjusted for inventory changes.
(2) Non-GAAP measures.
Gross profit is derived from oil, gas and NGL sales, less operating and transportation expenses, and depletion and accretion related to producing assets. Gross profit does not include depreciation of administrative assets, asset impairment, general and administrative expenses, interest, taxes or other non-operating items.
Operating netback, EBITDA, adjusted EBITDA, and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to oil sales, net income (loss) or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Disclosure of each non-GAAP financial measure is preceded by the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.
Operating netback, as presented, is defined as gross profit adjusted for depletion and accretion related to producing assets. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from gross profit to operating netback is provided in the table below.
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| Colombia | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Gross Profit | $ | 19,711 | $ | 10,446 | $ | 44,585 | $ | 88,673 | $ | 57,275 | |||||||||||||
| Adjustments to reconcile gross profit to operating netback | |||||||||||||||||||||||
| Depletion and accretion (*) | 38,356 | 44,041 | 38,072 | 117,061 | 136,936 | ||||||||||||||||||
| Operating netback (non-GAAP) | $ | 58,067 | $ | 54,487 | $ | 82,657 | $ | 205,734 | $ | 194,211 | |||||||||||||
(*) Calculated as DD&A expenses for the three months ended September 30, 2026 and 2025 of $44.7 million and $47.0 million less depreciation of administrative assets of $6.3 million and $3.0 million, respectively. For the nine months ended September 30, 2026 and 2025, DD&A expenses of $134.5 million and $146.1 million, less depreciation of administrative assets of $17.5 million and $9.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $43.5 million, less depreciation of administrative assets of $5.4 million.
| Ecuador | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Gross Profit | $ | 13,710 | $ | 859 | $ | 24,811 | $ | 44,899 | $ | 1,801 | |||||||||||||
| Adjustments to reconcile gross profit to operating netback | |||||||||||||||||||||||
| Depletion and accretion (*) | 14,104 | 9,519 | 9,775 | 39,740 | 24,366 | ||||||||||||||||||
| Operating netback (non-GAAP) | $ | 27,814 | $ | 10,378 | $ | 34,586 | $ | 84,639 | $ | 26,167 | |||||||||||||
(*) Calculated as DD&A expenses for the three months ended September 30, 2026 and 2025 of $14.3 million and $9.5 million less depreciation of administrative assets of $0.2 million and nil, respectively. For the nine months ended September 30, 2026 and 2025, DD&A expenses of $40.6 million and $24.4 million less depreciation of administrative assets of $0.9 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $10.3 million, less depreciation of administrative assets of $0.6 million.
| Canada | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Gross Profit | $ | 7,451 | $ | 3,574 | $ | 6,064 | $ | 19,457 | $ | 7,217 | |||||||||||||
| Adjustments to reconcile gross profit to operating netback | |||||||||||||||||||||||
| Depletion and accretion (*) | 5,246 | 8,348 | 8,406 | 21,066 | 34,984 | ||||||||||||||||||
| Operating netback (non-GAAP) | $ | 12,697 | $ | 11,922 | $ | 14,470 | $ | 40,523 | $ | 42,201 | |||||||||||||
(*) Same as DD&A expenses for the three months ended September 30, 2026 and 2025, nine months ended September 30, 2026 and 2025, and the prior quarter (the depreciation of administrative assets had a de minimis amount for all reported periods).
| Total Company | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Gross Profit | $ | 40,872 | $ | 14,879 | $ | 75,460 | $ | 153,029 | $ | 66,293 | |||||||||||||
| Adjustments to reconcile gross profit to operating netback | |||||||||||||||||||||||
| Depletion and accretion (*) | 57,706 | 61,908 | 56,253 | 177,867 | 196,286 | ||||||||||||||||||
| Operating netback (non-GAAP) | $ | 98,578 | $ | 76,787 | $ | 131,713 | $ | 330,896 | $ | 262,579 | |||||||||||||
(*) Calculated as DD&A expenses for the three months ended September 30, 2026 and 2025 of $64.4 million and $65.0 million less depreciation of administrative assets of $6.7 million and $3.1 million, respectively. For the nine months ended September 30, 2026 and 2025, DD&A expenses of $196.6 million and $205.8 million less depreciation of administrative assets of $18.7 million and $9.5 million, respectively. For the prior quarter, calculated as DD&A expenses of $62.3 million, less depreciation of administrative assets of $6.1 million.
EBITDA, as presented, is defined as net income or loss adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense, and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for severance, transaction costs, non-cash lease expense, lease payments, foreign exchange gains or losses, stock-based compensation expense or recovery, other non-cash gains or losses and unrealized derivative instruments gains or losses. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is useful supplemental information for investors to analyze our performance and 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) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Net (loss) income | $ | (42,415) | $ | (19,950) | $ | 24,861 | $ | (136,726) | $ | (51,971) | |||||||||||||
| Adjustments to reconcile net (loss) income to EBITDA and Adjusted EBITDA | |||||||||||||||||||||||
| DD&A expenses | 64,391 | 64,981 | 62,334 | 196,599 | 205,818 | ||||||||||||||||||
| Interest expense | 23,878 | 25,447 | 24,473 | 98,229 | 73,048 | ||||||||||||||||||
| Income tax (recovery) expense | (25,575) | (11,276) | 20,488 | (31,682) | (3,075) | ||||||||||||||||||
| EBITDA (non-GAAP) | $ | 20,279 | $ | 59,202 | $ | 132,156 | $ | 126,420 | $ | 223,820 | |||||||||||||
| Severance | — | — | 95 | 2,563 | — | ||||||||||||||||||
| Transaction costs | 4,887 | — | — | 4,887 | — | ||||||||||||||||||
| Non-cash lease expense | 1,452 | 1,187 | 1,503 | 4,423 | 4,648 | ||||||||||||||||||
| Lease payments | (1,565) | (1,574) | (1,633) | (4,885) | (4,686) | ||||||||||||||||||
| Foreign exchange loss | 2,252 | 284 | 2,603 | 6,280 | 7,838 | ||||||||||||||||||
| Stock-based compensation expense (recovery) | 30,465 | 143 | (3,757) | 46,384 | 172 | ||||||||||||||||||
| Other non-cash (gain) loss | (697) | 265 | — | (1,425) | 355 | ||||||||||||||||||
| Unrealized derivative instruments loss (gain) | 11,023 | 9,527 | (45,896) | 42,455 | (964) | ||||||||||||||||||
| Adjusted EBITDA (non-GAAP) | $ | 68,096 | $ | 69,034 | $ | 85,071 | $ | 227,102 | $ | 231,183 | |||||||||||||
Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, deferred income tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, Senior Notes exchange fees, non-cash interest, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, unrealized derivative instruments gains or losses and other non-cash gains or losses. Management uses this financial measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net (loss) income 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) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Net (loss) income | $ | (42,415) | $ | (19,950) | $ | 24,861 | $ | (136,726) | $ | (51,971) | |||||||||||||
| Adjustments to reconcile net (loss) income to funds flow from operations | |||||||||||||||||||||||
| DD&A expenses | 64,391 | 64,981 | 62,334 | 196,599 | 205,818 | ||||||||||||||||||
| Deferred income tax (recovery) expense | (30,086) | (15,298) | 11,373 | (51,158) | (17,557) | ||||||||||||||||||
| Stock-based compensation expense (recovery) | 30,465 | 143 | (3,757) | 46,384 | 172 | ||||||||||||||||||
| Amortization of debt issuance costs | 1,734 | 4,269 | 1,722 | 14,749 | 12,184 | ||||||||||||||||||
| Senior Notes exchange fees | (179) | — | 785 | 13,509 | — | ||||||||||||||||||
| Non-cash interest | 5,944 | — | 6,134 | 16,591 | — | ||||||||||||||||||
| Non-cash lease expense | 1,452 | 1,187 | 1,503 | 4,423 | 4,648 | ||||||||||||||||||
| Lease payments | (1,565) | (1,574) | (1,633) | (4,885) | (4,686) | ||||||||||||||||||
| Unrealized foreign exchange (gain) loss | (8,427) | (1,865) | 2,863 | (5,764) | 2,936 | ||||||||||||||||||
| Unrealized derivative instruments loss (gain) | 11,023 | 9,527 | (45,896) | 42,455 | (964) | ||||||||||||||||||
| Other non-cash (gain) loss | (697) | 265 | — | (1,425) | 355 | ||||||||||||||||||
| Funds flow from operations (non-GAAP) | $ | 31,640 | $ | 41,685 | $ | 60,289 | $ | 134,752 | $ | 150,935 | |||||||||||||
26
Additional Operational Results
| Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | % Change | 2026 | 2026 | 2025 | % Change | ||||||||||||||||||||||
| Oil, natural gas and NGL sales | $ | 168,306 | $ | 149,254 | 13 | $ | 187,181 | $ | 527,544 | $ | 466,784 | 13 | |||||||||||||||||
| Operating expenses | 64,186 | 68,170 | (6) | 51,561 | 181,896 | 190,863 | (5) | ||||||||||||||||||||||
| Transportation expenses | 5,542 | 4,297 | 29 | 3,907 | 14,752 | 13,342 | 11 | ||||||||||||||||||||||
Operating netback(1) | 98,578 | 76,787 | 28 | 131,713 | 330,896 | 262,579 | 26 | ||||||||||||||||||||||
| Other taxes | 1,031 | 3,046 | (66) | 1,389 | 3,461 | 4,105 | (16) | ||||||||||||||||||||||
| DD&A expenses | 64,391 | 64,981 | (1) | 62,334 | 196,599 | 205,818 | (4) | ||||||||||||||||||||||
| Derivative instruments loss (gain) | 29,228 | 2,066 | 1,315 | (11,864) | 105,774 | (10,499) | 1,107 | ||||||||||||||||||||||
| G&A expenses before stock-based compensation | 11,814 | 13,246 | (11) | 13,219 | 40,182 | 39,306 | 2 | ||||||||||||||||||||||
| G&A stock-based compensation expense (recovery) | 30,465 | 143 | 21,204 | (3,757) | 46,384 | 172 | 26,867 | ||||||||||||||||||||||
| Severance | — | — | — | 95 | 2,563 | — | 100 | ||||||||||||||||||||||
| Transaction costs | 4,887 | — | 100 | — | 4,887 | — | 100 | ||||||||||||||||||||||
| Foreign exchange loss | 2,252 | 284 | 693 | 2,603 | 6,280 | 7,838 | (20) | ||||||||||||||||||||||
| Interest expense | 23,878 | 25,447 | (6) | 24,473 | 98,229 | 73,048 | 34 | ||||||||||||||||||||||
| 167,946 | 109,213 | 54 | 88,492 | 504,359 | 319,788 | 58 | |||||||||||||||||||||||
| Other income | 840 | 1,003 | (16) | 1,625 | 3,613 | 1,290 | 180 | ||||||||||||||||||||||
| Interest income | 538 | 197 | 173 | 503 | 1,442 | 873 | 65 | ||||||||||||||||||||||
| (Loss) income before income taxes | (67,990) | (31,226) | (118) | 45,349 | (168,408) | (55,046) | (206) | ||||||||||||||||||||||
Current income tax expense | 4,511 | 4,022 | 12 | 9,115 | 19,476 | 14,482 | 34 | ||||||||||||||||||||||
| Deferred income tax (recovery) expense | (30,086) | (15,298) | (97) | 11,373 | (51,158) | (17,557) | (191) | ||||||||||||||||||||||
| Total income tax (recovery) expense | (25,575) | (11,276) | (127) | 20,488 | (31,682) | (3,075) | (930) | ||||||||||||||||||||||
| Net (loss) income | $ | (42,415) | $ | (19,950) | (113) | $ | 24,861 | $ | (136,726) | $ | (51,971) | (163) | |||||||||||||||||
| Sales Volumes (NAR) | |||||||||||||||||||||||||||||
| Total sales volumes, BOEPD | 32,724 | 37,353 | (12) | 32,166 | 35,025 | 38,231 | (8) | ||||||||||||||||||||||
| Brent Price per bbl | $ | 91.29 | $ | 68.17 | 34 | $ | 96.68 | $ | 88.86 | $ | 69.91 | 27 | |||||||||||||||||
| Castilla Differential per bbl | $ | 13.73 | $ | 4.88 | 181 | $ | 9.71 | $ | 11.07 | $ | 4.98 | 122 | |||||||||||||||||
| Vasconia Differential per bbl | $ | 6.68 | $ | 1.88 | 255 | $ | 1.42 | $ | 4.69 | $ | 1.95 | 141 | |||||||||||||||||
| Oriente Differential per bbl | $ | 10.32 | $ | 7.20 | 43 | $ | 2.01 | $ | 6.86 | $ | 7.37 | (7) | |||||||||||||||||
| WTI Price per bbl | $ | 85.68 | $ | 65.07 | 32 | $ | 92.70 | $ | 83.76 | $ | 66.74 | 26 | |||||||||||||||||
| AECO Price C$ per GJ | 1.48 | 0.60 | 147 | 1.55 | 1.65 | 1.42 | 16 | ||||||||||||||||||||||
27
| Consolidated Results of Operations per boe Sales Volumes NAR | |||||||||||||||||||||||||||||
| Oil, natural gas and NGL sales | $ | 55.90 | $ | 43.43 | 29 | $ | 63.95 | $ | 55.17 | $ | 44.72 | 23 | |||||||||||||||||
| Operating expenses | 21.32 | 19.84 | 7 | 17.61 | 19.02 | 18.29 | 4 | ||||||||||||||||||||||
| Transportation expenses | 1.84 | 1.25 | 47 | 1.33 | 1.54 | 1.28 | 20 | ||||||||||||||||||||||
Operating netback(1) | 32.74 | 22.34 | 47 | 45.01 | 34.61 | 25.15 | 38 | ||||||||||||||||||||||
| Other taxes | 0.34 | 0.89 | (62) | 0.47 | 0.36 | 0.39 | (8) | ||||||||||||||||||||||
| DD&A expenses | 21.39 | 18.91 | 13 | 21.29 | 20.56 | 19.72 | 4 | ||||||||||||||||||||||
| Derivative instruments loss (gain) | 9.71 | 0.60 | 1,518 | (4.05) | 11.06 | (1.01) | 1,195 | ||||||||||||||||||||||
| G&A expenses before stock-based compensation | 3.92 | 3.85 | 2 | 4.52 | 4.20 | 3.77 | 11 | ||||||||||||||||||||||
| G&A stock-based compensation expense (recovery) | 10.12 | 0.04 | 25,200 | (1.28) | 4.85 | 0.02 | 24,150 | ||||||||||||||||||||||
| Severance | — | — | — | 0.03 | 0.27 | — | 100 | ||||||||||||||||||||||
| Transaction costs | 1.62 | — | 100 | — | 0.51 | — | 100 | ||||||||||||||||||||||
| Foreign exchange loss | 0.75 | 0.08 | 838 | 0.89 | 0.66 | 0.75 | (12) | ||||||||||||||||||||||
| Interest expense | 7.93 | 7.40 | 7 | 8.36 | 10.27 | 7.00 | 47 | ||||||||||||||||||||||
| 55.78 | 31.77 | 76 | 30.23 | 52.75 | 30.64 | 72 | |||||||||||||||||||||||
| Other income | 0.28 | 0.29 | (3) | 0.56 | 0.38 | 0.12 | 217 | ||||||||||||||||||||||
| Interest income | 0.18 | 0.06 | 200 | 0.17 | 0.15 | 0.08 | 88 | ||||||||||||||||||||||
| (Loss) income before income taxes | (22.58) | (9.08) | (149) | 15.51 | (17.61) | (5.29) | (233) | ||||||||||||||||||||||
Current income tax expense | 1.50 | 1.17 | 28 | 3.11 | 2.04 | 1.39 | 47 | ||||||||||||||||||||||
| Deferred income tax (recovery) expense | (9.99) | (4.45) | (124) | 3.89 | (5.35) | (1.68) | (218) | ||||||||||||||||||||||
| Total income tax (recovery) expense | (8.49) | (3.28) | (159) | 7.00 | (3.31) | (0.29) | (1,041) | ||||||||||||||||||||||
| Net (loss) income | $ | (14.09) | $ | (5.80) | (143) | $ | 8.51 | $ | (14.30) | $ | (5.00) | (186) | |||||||||||||||||
(1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition of this measure.
Oil, Natural Gas and NGL Production and Sales Volumes, BOEPD
| Colombia | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| Average Daily Volumes (BOEPD) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| WI production before royalties | 19,305 | 22,701 | 19,994 | 20,199 | 24,476 | ||||||||||||||||||
| Royalties | (3,576) | (3,481) | (3,968) | (3,592) | (3,912) | ||||||||||||||||||
| Production NAR | 15,729 | 19,220 | 16,026 | 16,607 | 20,564 | ||||||||||||||||||
| Decrease (increase) in inventory | 100 | 337 | (57) | 278 | 26 | ||||||||||||||||||
| Sales | 15,829 | 19,557 | 15,969 | 16,885 | 20,590 | ||||||||||||||||||
| Royalties, % of working interest production before royalties | 19 | % | 15 | % | 20 | % | 18 | % | 16 | % | |||||||||||||
28
| Ecuador | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| Average Daily Volumes (BOEPD) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| WI production before royalties | 7,747 | 3,872 | 7,993 | 8,162 | 4,166 | ||||||||||||||||||
| Royalties | (3,206) | (1,273) | (3,788) | (3,195) | (1,353) | ||||||||||||||||||
| Production NAR | 4,541 | 2,599 | 4,205 | 4,967 | 2,813 | ||||||||||||||||||
| Decrease in inventory | 1,234 | 1,054 | 233 | 1,063 | 106 | ||||||||||||||||||
| Sales | 5,775 | 3,653 | 4,438 | 6,030 | 2,919 | ||||||||||||||||||
| Royalties, % of working interest production before royalties | 41 | % | 33 | % | 47 | % | 39 | % | 32 | % | |||||||||||||
| Canada | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| Average Daily Volumes (BOEPD) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| WI production before royalties | 12,852 | 16,112 | 13,514 | 13,919 | 16,853 | ||||||||||||||||||
| Royalties | (1,732) | (1,969) | (1,755) | (1,809) | (2,131) | ||||||||||||||||||
| Production NAR | 11,120 | 14,143 | 11,759 | 12,110 | 14,722 | ||||||||||||||||||
| Sales | 11,120 | 14,143 | 11,759 | 12,110 | 14,722 | ||||||||||||||||||
| Royalties, % of working interest production before royalties | 13 | % | 12 | % | 13 | % | 13 | % | 13 | % | |||||||||||||
| Total Company | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| Average Daily Volumes (BOEPD) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| WI production before royalties | 39,904 | 42,685 | 41,501 | 42,280 | 45,495 | ||||||||||||||||||
| Royalties | (8,514) | (6,723) | (9,511) | (8,596) | (7,396) | ||||||||||||||||||
| Production NAR | 31,390 | 35,962 | 31,990 | 33,684 | 38,099 | ||||||||||||||||||
| Decrease in inventory | 1,334 | 1,391 | 176 | 1,341 | 132 | ||||||||||||||||||
| Sales | 32,724 | 37,353 | 32,166 | 35,025 | 38,231 | ||||||||||||||||||
| Royalties, % of working interest production before royalties | 21 | % | 16 | % | 23 | % | 20 | % | 16 | % | |||||||||||||
Oil, natural gas and NGL production NAR for the three and nine months ended September 30, 2026, decreased by 13% and 12% to 31,390 BOEPD and 33,684 BOEPD, respectively, compared to the corresponding periods of 2025 due to lower production in Colombia, higher in-kind royalties primarily in Ecuador, driven by higher oil prices and the sale of the Simonette and Lodgepole areas in Canada, partially offset by higher than anticipated production results of wells in Charapa and Chanangue Blocks and additional production from Perico Block in Ecuador acquired in December 2025. Oil, natural gas and NGL production NAR decreased by 2% compared to the prior quarter due to sale of the Lodgepole area in Canada and lower production in Colombia, partially offset by lower in-kind royalties in Ecuador.
Royalties, as a percentage of production for the three and nine months ended September 30, 2026 increased to 21% and 20%, respectively, compared to the corresponding periods of 2025, as a result of higher benchmark oil prices and the price sensitive royalty regime in Colombia and Ecuador. Royalties, as a percentage of production decreased from 23% in the prior quarter as a result of lower benchmark oil prices in the current quarter.
29
30
The Midas Block includes the Acordionero field, the Suroriente Block includes the Cohembi field, and the Chaza Block includes the Costayaco and Moqueta fields. Ecuador includes the Charapa, Iguana, Chanangue and Perico Blocks. Canada includes several areas in the Western Canadian Sedimentary Basin with the majority of production in Alberta, Canada.
Commodity prices:
Colombia and Ecuador
Brent - For the three and nine months ended September 30, 2026, Brent increased 34% and 27% from the corresponding periods of 2025 and decreased 6% from the prior quarter.
For the three months ended September 30, 2026, Castilla, Vasconia and Oriente differentials per bbl increased to $13.73, $6.68 and $10.32 from $4.88, $1.88 and $7.20, respectively, in the corresponding period of 2025.
For the nine months ended September 30, 2026, Castilla and Vasconia differentials per bbl increased to $11.07 and $4.69 from $4.98 and $1.95, respectively, in the corresponding period of 2025. Oriente differential per bbl decreased to $6.86 from $7.37 in the corresponding period of 2025.
Castilla, Vasconia and Oriente differentials per bbl increased from $9.71, $1.42 and $2.01 in the prior quarter.
Differentials fluctuate based on regional supply and demand of heavy crude, shipping costs, pipeline disruptions and geopolitical and trading policies. Differentials widened significantly in the third quarter primarily because of increased imports of Venezuelan crude displacing Colombian production and significantly higher shipping costs as a result of the ongoing conflict in the Middle East.
During the three and nine months ended September 30, 2026 and 2025, 100% of sales from South America was priced against Brent.
31
Canada
WTI - For the three and nine months ended September 30, 2026, WTI increased by 32% and 26% from the corresponding periods of 2025 and decreased 8% from the prior quarter. During the three and nine months ended September 30, 2026, 20% and 22% of NAR production in Canada was oil, compared to 25% and 24% for the corresponding periods of 2025 and 21% in the prior quarter, respectively.
NGLs - For the three and nine months ended September 30, 2026, the weighted average NGL price received was 8% and 10% of WTI compared to 9% and 12% of WTI in the corresponding periods of 2025, and 7% of WTI in the prior quarter, respectively. During the three and nine months ended September 30, 2026, NGLs production in Canada was 29% and 27%, compared to 21% and 24% in the corresponding periods of 2025 and 27% in the prior quarter, respectively.
AECO - For the three and nine months ended September 30, 2026, AECO price increased by 147% and 16% from the corresponding periods of 2025 and decreased 5% from the prior quarter, respectively. During the three and nine months ended September 30, 2026, 51% of production in Canada was natural gas in each respective quarter, compared to 54% and 52%, in the corresponding periods of 2025, and 52% in the prior quarter, respectively.
Oil, natural gas and NGL sales for the three and nine months ended September 30, 2026, increased by 13% to $168.3 million and $527.5 million, respectively, compared to the corresponding periods of 2025, primarily due to 34% and 27% increase in Brent price, partially offset by 12% and 8% lower sales volumes in Colombia and Canada and higher quality and transportation discounts in Colombia. Quality and transportation discounts in Colombia were affected by using alternative transportation route for Putumayo production as the Colombia and Ecuador border remained closed. The alternative transportation route was significantly more expensive and resulted in additional discounts of approximately $3.7 million and $13.6 million, respectively, for the three and nine months ended September 30, 2026.
Compared to the prior quarter, oil, natural gas and NGL sales decreased by 10%, primarily due to a 6% decrease in Brent price, higher quality and transportation discounts in Colombia and a shift from a premium to a discount in Ecuador, partially offset by 2% higher sales volumes.
32
The following table shows the effect of changes in realized price and sales volumes on our oil, natural gas and NGL sales for the three and nine months ended September 30, 2026, compared to the prior quarter and the corresponding periods of 2025:
| (Thousands of U.S. Dollars) | Three Months Ended September 30, 2026, Compared with Three Months Ended September 30, 2025 | Three Months Ended September 30, 2026, Compared with Three Months Ended June 30, 2026 | Nine Months Ended September 30, 2026, Compared with Nine Months Ended September 30, 2025 | ||||||||||||||
| Oil, natural gas and NGL sales for the comparative period | $ | 149,254 | $ | 187,181 | $ | 466,784 | |||||||||||
| Realized sales price increase (decrease) effect | 37,553 | (24,211) | 99,895 | ||||||||||||||
| Sales volumes (decrease) increase effect | (18,501) | 5,336 | (39,135) | ||||||||||||||
Oil, natural gas and NGL sales for the three and nine months ended September 30, 2026 | $ | 168,306 | $ | 168,306 | $ | 527,544 | |||||||||||
Gross Profit
| Colombia | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Revenue | $ | 103,358 | $ | 101,999 | $ | 118,136 | $ | 323,818 | $ | 329,339 | |||||||||||||
| Operating expenses | 42,370 | 44,610 | 33,152 | 110,564 | 125,280 | ||||||||||||||||||
| Transportation expenses | 2,921 | 2,902 | 2,327 | 7,520 | 9,848 | ||||||||||||||||||
Depletion and accretion(*) | 38,356 | 44,041 | 38,072 | 117,061 | 136,936 | ||||||||||||||||||
| Gross profit | $ | 19,711 | $ | 10,446 | $ | 44,585 | $ | 88,673 | $ | 57,275 | |||||||||||||
(*) Calculated as DD&A expenses for the three months ended September 30, 2026 and 2025 of $44.7 million and $47.0 million less depreciation of administrative assets of $6.3 million and $3.0 million, respectively. For the nine months ended September 30, 2026 and 2025, DD&A expenses of $134.5
33
million and $146.1 million, less depreciation of administrative assets of $17.5 million and $9.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $43.5 million, less depreciation of administrative assets of $5.4 million.
| Colombia | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (U.S. Dollars per boe Sales Volumes NAR ) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Revenue | $ | 70.97 | $ | 56.69 | $ | 81.29 | $ | 70.25 | $ | 58.59 | |||||||||||||
| Operating expenses | 29.09 | 24.79 | 22.81 | 23.99 | 22.29 | ||||||||||||||||||
| Transportation expenses | 2.01 | 1.61 | 1.60 | 1.63 | 1.75 | ||||||||||||||||||
| Depletion and accretion | 26.34 | 24.48 | 26.20 | 25.40 | 24.36 | ||||||||||||||||||
| Gross profit | $ | 13.53 | $ | 5.81 | $ | 30.68 | $ | 19.23 | $ | 10.19 | |||||||||||||
| Ecuador | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Revenue | $ | 42,134 | $ | 20,605 | $ | 41,964 | $ | 124,843 | $ | 50,123 | |||||||||||||
| Operating expenses | 11,985 | 9,157 | 6,196 | 34,133 | 21,352 | ||||||||||||||||||
| Transportation expenses | 2,335 | 1,070 | 1,182 | 6,071 | 2,604 | ||||||||||||||||||
Depletion and accretion(*) | 14,104 | 9,519 | 9,775 | 39,740 | 24,366 | ||||||||||||||||||
| Gross profit | $ | 13,710 | $ | 859 | $ | 24,811 | $ | 44,899 | $ | 1,801 | |||||||||||||
(*) Calculated as DD&A expenses for the three months ended September 30, 2026 and 2025 of $14.3 million and $9.5 million less depreciation of administrative assets of $0.2 million and nil, respectively. For the nine months ended September 30, 2026 and 2025, DD&A expenses of $40.6 million and $24.4 million less depreciation of administrative assets of $0.9 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $10.3 million, less depreciation of administrative assets of $0.6 million.
| Ecuador | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (U.S. Dollars per boe Sales Volumes NAR ) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Revenue | $ | 79.30 | $ | 61.30 | $ | 103.90 | $ | 75.83 | $ | 62.92 | |||||||||||||
| Operating expenses | 22.56 | 27.24 | 15.34 | 20.73 | 26.80 | ||||||||||||||||||
| Transportation expenses | 4.39 | 3.18 | 2.93 | 3.69 | 3.27 | ||||||||||||||||||
| Depletion and accretion | 26.55 | 28.32 | 24.20 | 24.14 | 30.59 | ||||||||||||||||||
| Gross profit | $ | 25.80 | $ | 2.56 | $ | 61.43 | $ | 27.27 | $ | 2.26 | |||||||||||||
| Canada | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Revenue | $ | 22,814 | $ | 26,650 | $ | 27,081 | $ | 78,883 | $ | 87,322 | |||||||||||||
| Operating expenses | 9,831 | 14,403 | 12,213 | 37,199 | 44,231 | ||||||||||||||||||
| Transportation expenses | 286 | 325 | 398 | 1,161 | 890 | ||||||||||||||||||
Depletion and accretion(*) | 5,246 | 8,348 | 8,406 | 21,066 | 34,984 | ||||||||||||||||||
| Gross profit | $ | 7,451 | $ | 3,574 | $ | 6,064 | $ | 19,457 | $ | 7,217 | |||||||||||||
34
| Canada | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (U.S. Dollars per boe Sales Volumes NAR ) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Revenue | $ | 22.30 | $ | 20.48 | $ | 25.31 | $ | 23.86 | $ | 21.73 | |||||||||||||
| Operating expenses | 9.61 | 11.07 | 11.41 | 11.25 | 11.00 | ||||||||||||||||||
| Transportation expenses | 0.28 | 0.25 | 0.37 | 0.35 | 0.22 | ||||||||||||||||||
| Depletion and accretion | 5.13 | 6.42 | 7.86 | 6.37 | 8.70 | ||||||||||||||||||
| Gross profit | $ | 7.28 | $ | 2.74 | $ | 5.67 | $ | 5.89 | $ | 1.81 | |||||||||||||
| Total Company | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Revenue | $ | 168,306 | $ | 149,254 | $ | 187,181 | $ | 527,544 | $ | 466,784 | |||||||||||||
| Operating expenses | 64,186 | 68,170 | 51,561 | 181,896 | 190,863 | ||||||||||||||||||
| Transportation expenses | 5,542 | 4,297 | 3,907 | 14,752 | 13,342 | ||||||||||||||||||
Depletion and accretion(*) | 57,706 | 61,908 | 56,253 | 177,867 | 196,286 | ||||||||||||||||||
| Gross profit | $ | 40,872 | $ | 14,879 | $ | 75,460 | $ | 153,029 | $ | 66,293 | |||||||||||||
(*) Calculated as DD&A expenses for the three months ended September 30, 2026 and 2025 of $64.4 million and $65.0 million less depreciation of administrative assets of $6.7 million and $3.1 million, respectively. For the nine months ended September 30, 2026 and 2025, DD&A expenses of $196.6 million and $205.8 million less depreciation of administrative assets of $18.7 million and $9.5 million, respectively. For the prior quarter, calculated as DD&A expenses of $62.3 million, less depreciation of administrative assets of $6.1 million.
| Total Company | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (U.S. Dollars per boe Sales Volumes NAR ) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Revenue | $ | 55.90 | $ | 43.43 | $ | 63.95 | $ | 55.17 | $ | 44.72 | |||||||||||||
| Operating expenses | 21.32 | 19.84 | 17.61 | 19.02 | 18.29 | ||||||||||||||||||
| Transportation expenses | 1.84 | 1.25 | 1.33 | 1.54 | 1.28 | ||||||||||||||||||
| Depletion and accretion | 19.17 | 18.01 | 19.22 | 18.60 | 18.81 | ||||||||||||||||||
| Gross profit | $ | 13.57 | $ | 4.33 | $ | 25.79 | $ | 16.01 | $ | 6.34 | |||||||||||||
35
Operating Netback
| Colombia | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Oil, natural gas and NGL sales | $ | 103,358 | $ | 101,999 | $ | 118,136 | $ | 323,818 | $ | 329,339 | |||||||||||||
Transportation expenses | (2,921) | (2,902) | (2,327) | (7,520) | (9,848) | ||||||||||||||||||
| 100,437 | 99,097 | 115,809 | 316,298 | 319,491 | |||||||||||||||||||
Operating expenses | (42,370) | (44,610) | (33,152) | (110,564) | (125,280) | ||||||||||||||||||
Operating netback(1) | $ | 58,067 | $ | 54,487 | $ | 82,657 | $ | 205,734 | $ | 194,211 | |||||||||||||
| (U.S. Dollars Per boe Sales Volumes NAR) | |||||||||||||||||||||||
| Brent | $ | 91.29 | $ | 68.17 | $ | 96.68 | $ | 88.86 | $ | 69.91 | |||||||||||||
Quality and transportation discounts | (20.32) | (11.48) | (15.39) | (18.61) | (11.32) | ||||||||||||||||||
Average realized price | 70.97 | 56.69 | 81.29 | 70.25 | 58.59 | ||||||||||||||||||
| Transportation expenses | (2.01) | (1.61) | (1.60) | (1.63) | (1.75) | ||||||||||||||||||
Average realized price net of transportation expenses | 68.96 | 55.08 | 79.69 | 68.62 | 56.84 | ||||||||||||||||||
| Operating expenses | (29.09) | (24.79) | (22.81) | (23.99) | (22.29) | ||||||||||||||||||
Operating netback(1) | $ | 39.87 | $ | 30.29 | $ | 56.88 | $ | 44.63 | $ | 34.55 | |||||||||||||
| Ecuador | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Oil, natural gas and NGL sales | $ | 42,134 | $ | 20,605 | $ | 41,964 | $ | 124,843 | $ | 50,123 | |||||||||||||
Transportation expenses | (2,335) | (1,070) | (1,182) | (6,071) | (2,604) | ||||||||||||||||||
| 39,799 | 19,535 | 40,782 | 118,772 | 47,519 | |||||||||||||||||||
Operating expenses | (11,985) | (9,157) | (6,196) | (34,133) | (21,352) | ||||||||||||||||||
Operating netback(1) | $ | 27,814 | $ | 10,378 | $ | 34,586 | $ | 84,639 | $ | 26,167 | |||||||||||||
| (U.S. Dollars Per boe Sales Volumes NAR) | |||||||||||||||||||||||
| Brent (M-1 Pricing) | $ | 85.43 | $ | 68.89 | $ | 101.89 | $ | 84.26 | $ | 70.53 | |||||||||||||
| Quality and transportation (discounts) premium | (6.13) | (7.59) | 2.01 | (8.43) | (7.61) | ||||||||||||||||||
Average realized price | 79.30 | 61.30 | 103.90 | 75.83 | 62.92 | ||||||||||||||||||
| Transportation expenses | (4.39) | (3.18) | (2.93) | (3.69) | (3.27) | ||||||||||||||||||
Average realized price net of transportation expenses | 74.91 | 58.12 | 100.97 | 72.14 | 59.65 | ||||||||||||||||||
| Operating expenses | (22.56) | (27.24) | (15.34) | (20.73) | (26.80) | ||||||||||||||||||
Operating netback(1) | $ | 52.35 | $ | 30.88 | $ | 85.63 | $ | 51.41 | $ | 32.85 | |||||||||||||
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| Canada | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Oil, natural gas and NGL sales | $ | 22,814 | $ | 26,650 | $ | 27,081 | $ | 78,883 | $ | 87,322 | |||||||||||||
Transportation expenses | (286) | (325) | (398) | (1,161) | (890) | ||||||||||||||||||
| 22,528 | 26,325 | 26,683 | 77,722 | 86,432 | |||||||||||||||||||
Operating expenses | (9,831) | (14,403) | (12,213) | (37,199) | (44,231) | ||||||||||||||||||
Operating netback(1) | $ | 12,697 | $ | 11,922 | $ | 14,470 | $ | 40,523 | $ | 42,201 | |||||||||||||
| (U.S. Dollars Per boe Sales Volumes NAR) | |||||||||||||||||||||||
| WTI Price per bbl | $ | 85.68 | $ | 65.07 | $ | 92.70 | $ | 83.76 | $ | 66.74 | |||||||||||||
| AECO Price C$ per GJ | 1.48 | 0.60 | 1.55 | 1.65 | 1.42 | ||||||||||||||||||
Average realized price | 22.30 | 20.48 | 25.31 | 23.86 | 21.73 | ||||||||||||||||||
| Transportation expenses | (0.28) | (0.25) | (0.37) | (0.35) | (0.22) | ||||||||||||||||||
Average realized price net of transportation expenses | 22.02 | 20.23 | 24.94 | 23.51 | 21.51 | ||||||||||||||||||
| Operating expenses | (9.61) | (11.07) | (11.41) | (11.25) | (11.00) | ||||||||||||||||||
Operating netback(1) | $ | 12.41 | $ | 9.16 | $ | 13.53 | $ | 12.26 | $ | 10.51 | |||||||||||||
| Total Company | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Oil, natural gas and NGL sales | $ | 168,306 | $ | 149,254 | $ | 187,181 | $ | 527,544 | $ | 466,784 | |||||||||||||
Transportation expenses | (5,542) | (4,297) | (3,907) | (14,752) | (13,342) | ||||||||||||||||||
| 162,764 | 144,957 | 183,274 | 512,792 | 453,442 | |||||||||||||||||||
Operating expenses | (64,186) | (68,170) | (51,561) | (181,896) | (190,863) | ||||||||||||||||||
Operating netback(1) | $ | 98,578 | $ | 76,787 | $ | 131,713 | $ | 330,896 | $ | 262,579 | |||||||||||||
| (U.S. Dollars Per boe Sales Volumes NAR) | |||||||||||||||||||||||
Average realized price | $ | 55.90 | $ | 43.43 | $ | 63.95 | $ | 55.17 | $ | 44.72 | |||||||||||||
Transportation expenses | (1.84) | (1.25) | (1.33) | (1.54) | (1.28) | ||||||||||||||||||
Average realized price net of transportation expenses | 54.06 | 42.18 | 62.62 | 53.63 | 43.44 | ||||||||||||||||||
Operating expenses | (21.32) | (19.84) | (17.61) | (19.02) | (18.29) | ||||||||||||||||||
Operating netback(1) | $ | 32.74 | $ | 22.34 | $ | 45.01 | $ | 34.61 | $ | 25.15 | |||||||||||||
(1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition and reconciliation of this measure.
37
38
Operating expenses for the three and nine months ended September 30, 2026, decreased by 6% and 5% to $64.2 million and $181.9 million, respectively, compared to the corresponding periods of 2025. The decrease was primarily due to lower workover activities, reduced field personnel costs and lower equipment maintenance.
Operating expenses on a per boe basis, for the three and nine months ended September 30, 2026, increased by $1.48 and $0.73 to $21.32 and $19.02, respectively, compared to the corresponding periods of 2025, primarily due to lower sales volumes during current periods, partially offset by $0.30 and $0.57 per boe lower workover activities, reduced field personnel costs, lower equipment maintenance and inventory fluctuations, respectively.
39
Compared to the prior quarter, operating expenses increased by 24% from $51.6 million or by $3.71 from $17.61 on a per boe basis primarily due to $0.80 per boe higher workover activities and $2.91 per boe higher lifting costs associated with inventory fluctuations resulting from sale of inventory accumulated at the end of prior quarter.
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, 2026 and 2025, and the prior quarter:
| Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | |||||||||||||||||||||
| 2026 | 2025 | 2026 | 2026 | 2025 | |||||||||||||||||||
| Volume transported through pipeline | 52 | % | 47 | % | 50 | % | 52 | % | 46 | % | |||||||||||||
| Volume sold at wellhead | 23 | % | 24 | % | 26 | % | 24 | % | 29 | % | |||||||||||||
| Volume transported via truck to sales point | 25 | % | 29 | % | 24 | % | 24 | % | 25 | % | |||||||||||||
| 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 and nine months ended September 30, 2026, increased by 29% and 11% to $5.5 million and $14.8 million compared to the corresponding periods of 2025, due to higher volumes transported via pipeline which had higher costs per boe. On a per boe basis, transportation expenses for the three and nine months ended September 30, 2026 increased by $0.59 and $0.26 for the same reason mentioned above.
Transportation expenses increased by 42% or $0.51 per boe from $3.9 million or $1.33 per boe in the prior quarter due to higher volumes transported through pipeline which had higher costs per boe.
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Colombia | Three Months Ended September 30, 2026, Compared with Three Months Ended September 30, 2025 | Three Months Ended September 30, 2026, Compared with Three Months Ended June 30, 2026 | Nine Months Ended September 30, 2026, Compared with Nine Months Ended September 30, 2025 | ||||||||||||||
| (U.S. Dollars per boe Sales Volumes NAR) | |||||||||||||||||
| Average Brent price | $ | 91.29 | $ | 91.29 | $ | 88.86 | |||||||||||
| Average realized price, net of transportation expenses for the comparative period | $ | 55.08 | $ | 79.69 | $ | 56.84 | |||||||||||
| Increase (decrease) in benchmark oil prices | 23.12 | (5.39) | 18.95 | ||||||||||||||
| Increase in quality and transportation discounts | (8.84) | (4.93) | (7.29) | ||||||||||||||
| (Increase) decrease in transportation expense | (0.40) | (0.41) | 0.12 | ||||||||||||||
| Average realized price, net of transportation expenses for the period | $ | 68.96 | $ | 68.96 | $ | 68.62 | |||||||||||
| Average realized price, net of transportation expenses as a % of Brent | 76 | % | 76 | % | 77 | % | |||||||||||
| Ecuador | Three Months Ended September 30, 2026, Compared with Three Months Ended September 30, 2025 | Three Months Ended September 30, 2026, Compared with Three Months Ended June 30, 2026 | Nine Months Ended September 30, 2026, Compared with Nine Months Ended September 30, 2025 | ||||||||||||||
| (U.S. Dollars per boe Sales Volumes NAR) | |||||||||||||||||
Average Brent price (M-1 Pricing)(*) | $ | 85.43 | $ | 85.43 | $ | 84.26 | |||||||||||
| Average realized price, net of transportation expenses for the comparative period | $ | 58.12 | $ | 100.97 | $ | 59.65 | |||||||||||
| Increase (decrease) in benchmark prices | 16.54 | (16.46) | 13.73 | ||||||||||||||
| Decrease (increase) in quality and transportation discounts | 1.46 | (8.14) | (0.82) | ||||||||||||||
| Increase in transportation expense | (1.21) | (1.46) | (0.42) | ||||||||||||||
| Average realized price, net of transportation expenses for the period | $ | 74.91 | $ | 74.91 | $ | 72.14 | |||||||||||
| Average realized price, net of transportation expenses as a % of Brent | 88 | % | 88 | % | 86 | % | |||||||||||
(*)The sales price in Ecuador is the average Brent price less discounts for the month prior to lifting (M-1).
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| Canada | Three Months Ended September 30, 2026, Compared with Three Months Ended September 30, 2025 | Three Months Ended September 30, 2026, Compared with Three Months Ended June 30, 2026 | Nine Months Ended September 30, 2026, Compared with Nine Months Ended September 30, 2025 | ||||||||||||||
| (U.S. Dollars per boe Sales Volumes NAR) | |||||||||||||||||
| Average WTI price | $ | 85.68 | $ | 85.68 | $ | 83.76 | |||||||||||
| Average AECO price | $ | 1.48 | $ | 1.48 | $ | 1.65 | |||||||||||
| Average realized price, net of transportation expenses for the comparative period | $ | 20.23 | $ | 24.94 | $ | 21.51 | |||||||||||
| Increase (decrease) in benchmark prices | 20.61 | (7.02) | 17.02 | ||||||||||||||
| (Increase) decrease in quality and transportation discounts | (18.79) | 4.01 | (14.89) | ||||||||||||||
| (Increase) decrease in transportation expense | (0.03) | 0.09 | (0.13) | ||||||||||||||
| Average realized price, net of transportation expenses for the period | $ | 22.02 | $ | 22.02 | $ | 23.51 | |||||||||||
| Average realized price, net of transportation expenses as a % of WTI | 26 | % | 26 | % | 28 | % | |||||||||||
| Total Company | Three Months Ended September 30, 2026, Compared with Three Months Ended September 30, 2025 | Three Months Ended September 30, 2026, Compared with Three Months Ended June 30, 2026 | Nine Months Ended September 30, 2026, Compared with Nine Months Ended September 30, 2025 | ||||||||||||||
| (U.S. Dollars per boe Sales Volumes NAR) | |||||||||||||||||
| Average Brent price | $ | 91.29 | $ | 91.29 | $ | 88.86 | |||||||||||
| Average realized price, net of transportation expenses for the comparative period | $ | 42.18 | $ | 62.62 | $ | 43.44 | |||||||||||
| Increase (decrease) in benchmark prices | 23.12 | (5.39) | 18.95 | ||||||||||||||
| Increase in quality and transportation discounts | (10.65) | (2.66) | (8.50) | ||||||||||||||
| Increase in transportation expense | (0.59) | (0.51) | (0.26) | ||||||||||||||
| Average realized price, net of transportation expenses for the period | $ | 54.06 | $ | 54.06 | $ | 53.63 | |||||||||||
| Average realized price, net of transportation expenses as a % of Brent | 59 | % | 59 | % | 60 | % | |||||||||||
DD&A Expenses
| Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | |||||||||||||||||||||
| 2026 | 2025 | 2026 | 2026 | 2025 | |||||||||||||||||||
| DD&A Expenses, thousands of U.S. Dollars | $ | 64,391 | $ | 64,981 | $ | 62,334 | $ | 196,599 | $ | 205,818 | |||||||||||||
| DD&A Expenses, U.S. Dollars per boe | 21.39 | 18.91 | 21.29 | 20.56 | 19.72 | ||||||||||||||||||
42
| Three Months Ended September 30, 2026 | Three Months Ended June 30, 2026 | Nine Months Ended September 30, 2026 | ||||||||||||||||||||||||
| DD&A expenses, thousands of U.S. Dollars | DD&A expenses, U.S. Dollars Per Boe | DD&A expenses, thousands of U.S. Dollars | DD&A expenses, U.S. Dollars Per Boe | DD&A expenses, thousands of U.S. Dollars | DD&A expenses, U.S. Dollars Per Boe | |||||||||||||||||||||
| Colombia | $ | 44,679 | $ | 30.68 | $ | 43,479 | $ | 29.92 | $ | 134,536 | $ | 29.19 | ||||||||||||||
| Ecuador | 14,349 | 27.01 | 10,334 | 25.59 | 40,647 | 24.69 | ||||||||||||||||||||
| Canada | 5,251 | 5.13 | 8,411 | 7.86 | 21,081 | 6.38 | ||||||||||||||||||||
| Corporate | 112 | — | 110 | — | 335 | — | ||||||||||||||||||||
| $ | 64,391 | $ | 21.39 | $ | 62,334 | $ | 21.29 | $ | 196,599 | $ | 20.56 | |||||||||||||||
| Three Months Ended September 30, 2025 | Three Months Ended June 30, 2025 | Nine Months Ended September 30, 2025 | ||||||||||||||||||||||||
| DD&A expenses, thousands of U.S. Dollars | DD&A expenses, U.S. Dollars Per Boe | DD&A expenses, thousands of U.S. Dollars | DD&A expenses, U.S. Dollars Per Boe | DD&A expenses, thousands of U.S. Dollars | DD&A expenses, U.S. Dollars Per Boe | |||||||||||||||||||||
| Colombia | $ | 46,986 | $ | 26.11 | $ | 50,454 | $ | 25.94 | $ | 146,091 | $ | 25.99 | ||||||||||||||
| Ecuador | 9,520 | 28.32 | 4,351 | 29.01 | 24,369 | 30.59 | ||||||||||||||||||||
| Canada | 8,353 | 6.42 | 13,705 | 9.84 | 34,999 | 8.71 | ||||||||||||||||||||
| Corporate | 122 | — | 125 | — | 359 | — | ||||||||||||||||||||
| $ | 64,981 | $ | 18.91 | $ | 68,635 | $ | 19.68 | $ | 205,818 | $ | 19.72 | |||||||||||||||
DD&A expenses for the three and nine months ended September 30, 2026, decreased by 1% and 4%, respectively, due to lower costs in the depletable base for Canadian operations as a result of Simonette Montney and Lodgepole dispositions and higher proved reserves across reportable segments compared to the corresponding periods of 2025. On a per boe basis, DD&A expenses for the three and nine months ended September 30, 2026, increased by $2.48 and $0.84, respectively, due to the lower sales volumes in the current periods.
DD&A expenses increased by 3% from $62.3 million and increased by $0.10 on a per boe basis when compared to the prior quarter due to inventory fluctuations in Ecuador, partially offset by lower costs in the depletable base in Canada due to asset sales.
Asset Impairment
For the three and nine months ended September 30, 2026 and 2025, we had no ceiling test impairment losses. We used a 12-month unweighted average of the first-day-of-the-month prices prior to the ending date of the period ended September 30, 2026 as follows: Brent Crude of $83.30 per bbl, Edmonton Light Crude of C$102.70 per bbl, Alberta AECO spot price of C$2.01 per MMBtu, Edmonton Propane of C$28.54 per boe, Edmonton Butane of C$42.84 per boe and Edmonton Condensate of C$103.71 per boe (September 30, 2025: Brent Crude of $71.61 per bbl, Edmonton Light Crude of C$89.65 per bbl, Alberta AECO spot price of C$1.70 per MMBtu, Edmonton Propane of C$34.71 per boe, Edmonton Butane of C$43.07 per boe and Edmonton Condensate of C$93.35 per boe).
43
G&A Expenses
| Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | % Change | 2026 | 2026 | 2025 | % Change | ||||||||||||||||||||||
| G&A Expenses before Stock-Based Compensation | $ | 11,814 | $ | 13,246 | (11) | $ | 13,219 | $ | 40,182 | $ | 39,306 | 2 | |||||||||||||||||
| G&A Stock-Based Compensation Expense (Recovery) | 30,465 | 143 | 21,204 | (3,757) | 46,384 | 172 | 26,867 | ||||||||||||||||||||||
| G&A Expenses, including Stock-Based Compensation | $ | 42,279 | $ | 13,389 | 216 | $ | 9,462 | $ | 86,566 | $ | 39,478 | 119 | |||||||||||||||||
| (U.S. Dollars Per boe Sales Volumes NAR) | |||||||||||||||||||||||||||||
| G&A Expenses before Stock-Based Compensation | $ | 3.92 | $ | 3.85 | 2 | $ | 4.52 | $ | 4.20 | $ | 3.77 | 11 | |||||||||||||||||
| G&A Stock-Based Compensation Expense (Recovery) | 10.12 | 0.04 | 25,200 | (1.28) | 4.85 | 0.02 | 24,150 | ||||||||||||||||||||||
| G&A Expenses, including Stock-Based Compensation | $ | 14.04 | $ | 3.89 | 261 | $ | 3.24 | $ | 9.05 | $ | 3.79 | 139 | |||||||||||||||||
G&A expenses before stock-based compensation for the three months ended September 30, 2026, decreased by 11% to $11.8 million compared to the corresponding period of 2025, primarily due to lower consulting and legal expenses and lower costs associated with project optimization during the current period. G&A expenses before stock-based compensation for the nine months ended September 30, 2026, increased by 2% to $40.2 million, compared to the corresponding period of 2025, primarily due to higher bank fees and information technology costs.
On a per boe basis, G&A expenses before stock-based compensation for the three and nine months ended September 30, 2026 increased by $0.07 and $0.43 to $3.92 and $4.20, compared to the corresponding periods of 2025 primarily due to 12% and 8% lower sales volumes, respectively.
Compared to the prior quarter, G&A expenses before stock-based compensation decreased by 11% from $13.2 million due to lower salaries associated with headcount optimization and lower costs associated with project optimization. On a per boe basis, G&A expenses before stock-based compensation decreased by $0.60 compared to the prior quarter for the same reason mentioned above.
G&A expenses after stock-based compensation for the three and nine months ended September 30, 2026, increased by 216% and 119% or $10.15 and $5.26 per boe, respectively, compared to the corresponding periods of 2025 due to higher stock-based compensation expense associated with higher share price during current periods.
Compared to the prior quarter, G&A expenses after stock-based compensation increased by 347% or $10.80 per boe due to higher share price resulting in higher stock-based compensation expense.
44
Severance Expenses
For the three and nine months ended September 30, 2026, severance expenses related to headcount optimization were nil and $2.6 million, compared to nil for each of the corresponding periods of 2025 and $0.1 million for the prior quarter, respectively.
Foreign Exchange Gains and Losses
For the three and nine months ended September 30, 2026, we had foreign exchange losses of $2.3 million and $6.3 million, compared to $0.3 million and $7.8 million losses on foreign exchange in the corresponding periods of 2025, respectively, and a $2.6 million loss on foreign exchange in the prior quarter. Accounts payable, taxes receivable and payable and deferred income taxes are considered monetary items and require translation from local currencies to U.S. dollar functional currency at each balance sheet date. This translation was the primary source of the foreign exchange gains and losses in the periods.
45
The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the three and nine months ended September 30, 2026 and 2025 and the prior quarter:
| Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | |||||||||||||||||||||
| 2026 | 2025 | 2026 | 2026 | 2025 | |||||||||||||||||||
| Change in the U.S. dollar against the Colombian peso | weakened by | weakened by | weakened by | weakened by | weakened by | ||||||||||||||||||
| 3% | 4% | 6% | 11% | 12% | |||||||||||||||||||
| Change in the U.S. dollar against the Canadian dollar | comparable | strengthened by | strengthened by | strengthened by | weakened by | ||||||||||||||||||
| —% | 2% | 2% | 4% | 3% | |||||||||||||||||||
Financial Instruments Gains or Losses
The following table presents the nature of our financial instruments gains or losses for the three and nine months ended September 30, 2026 and 2025, and the prior quarter:
| Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | |||||||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2026 | 2025 | ||||||||||||||||||
| Commodity price derivative loss (gain) | $ | 33,733 | $ | 2,945 | $ | (9,266) | $ | 113,085 | $ | (2,390) | |||||||||||||
| Foreign currency derivative gain | (4,505) | (879) | (2,598) | (7,311) | (8,109) | ||||||||||||||||||
| Derivative instruments loss (gain) | $ | 29,228 | $ | 2,066 | $ | (11,864) | $ | 105,774 | $ | (10,499) | |||||||||||||
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Income Tax Expense
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||
| Loss before income tax | $ | (67,990) | $ | (31,226) | $ | (168,408) | $ | (55,046) | |||||||||
| Current income tax expense | $ | 4,511 | $ | 4,022 | $ | 19,476 | $ | 14,482 | |||||||||
| Deferred income tax recovery | (30,086) | (15,298) | (51,158) | (17,557) | |||||||||||||
| Income tax recovery | $ | (25,575) | $ | (11,276) | $ | (31,682) | $ | (3,075) | |||||||||
| Effective tax rate | 38 | % | 36 | % | 19 | % | 6 | % | |||||||||
Current income tax expense was $19.5 million for the nine months ended September 30, 2026, compared to $14.5 million in the corresponding period of 2025, primarily due to higher taxable income.
The deferred tax for the nine months ended September 30, 2026, was a recovery of $51.2 million mainly due to an increase in deductible temporary differences arising from tax losses generated during the period, unrealized hedging losses and accruals. These were partially offset by higher tax depreciation relative to accounting depreciation.
The deferred income tax for the 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 temporary differences related to accelerated tax depreciation in excess of accounting depreciation.
For the nine months ended September 30, 2026, the difference between the effective tax rate of 19% and the 21% statutory tax rate was primarily due to an increase in the non-deductible foreign translation adjustments and other non-deductible expenses. This was partially offset by an increase in the impact of foreign taxes and the 2025 true-up (recovery).
For the nine months ended September 30, 2025, the difference between the effective tax rate of 6% and the 21% statutory tax rate was primarily due to increase in the non-deductible foreign translation adjustments, other permanent differences and valuation allowance. This was partially offset by an increase in the impact of foreign taxes.
Net (Loss) Income and Funds Flow from Operations (a Non-GAAP Measure)
| (Thousands of U.S. Dollars) | Three Months Ended September 30, 2026, Compared with Three Months Ended June 30, 2026 | % change | Three Months Ended September 30, 2026, Compared with Three Months Ended September 30, 2025 | % change | Nine Months Ended September 30, 2026 Compared with Nine Months Ended September 30, 2025 | % change | ||||||||||||||
| Net income (loss) for the comparative period | $ | 24,861 | $ | (19,950) | $ | (51,971) | ||||||||||||||
| Increase (decrease) due to: | ||||||||||||||||||||
| Sales price | (24,211) | 37,553 | 99,895 | |||||||||||||||||
| Sales volumes | 5,336 | (18,501) | (39,135) | |||||||||||||||||
| Expenses: | ||||||||||||||||||||
| Cash operating expenses | (12,625) | 3,984 | 8,967 | |||||||||||||||||
| Transportation | (1,635) | (1,245) | (1,410) | |||||||||||||||||
| Other taxes | 358 | 2,015 | 644 | |||||||||||||||||
| Cash G&A, excluding stock-based compensation expense | 1,405 | 1,432 | (876) | |||||||||||||||||
| Net lease payments | 17 | 274 | (424) | |||||||||||||||||
| Severance | 95 | — | (2,563) | |||||||||||||||||
| Transaction costs | (4,887) | (4,887) | (4,887) | |||||||||||||||||
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| Interest, excluding amortization of deferred financing fees | (547) | 4,799 | 7,484 | |||||||||||||||||
| Realized foreign exchange loss | (10,939) | (8,530) | (7,142) | |||||||||||||||||
| Other (loss) income | (1,482) | (1,125) | 543 | |||||||||||||||||
Cash settlement on derivative instruments | 15,827 | (25,666) | (72,854) | |||||||||||||||||
| Current taxes | 4,604 | (489) | (4,994) | |||||||||||||||||
| Interest income | 35 | 341 | 569 | |||||||||||||||||
Net change in funds flow from operations(1) from comparative period | (28,649) | (10,045) | (16,183) | |||||||||||||||||
| Expenses: | ||||||||||||||||||||
| Depletion, depreciation and accretion | (2,057) | 590 | 9,219 | |||||||||||||||||
| Deferred tax | 41,459 | 14,788 | 33,601 | |||||||||||||||||
| Amortization of debt issuance costs | (12) | 2,535 | (2,565) | |||||||||||||||||
| Stock-based compensation | (34,222) | (30,322) | (46,212) | |||||||||||||||||
| Senior Notes exchange fees | 964 | 179 | (13,509) | |||||||||||||||||
| Non-cash interest | 190 | (5,944) | (16,591) | |||||||||||||||||
| Financial instruments loss, net of financial instruments settlements | (56,919) | (1,496) | (43,419) | |||||||||||||||||
| Unrealized foreign exchange gain | 11,290 | 6,562 | 8,700 | |||||||||||||||||
| Other non-cash gain | 697 | 962 | 1,780 | |||||||||||||||||
| Net lease payments | (17) | (274) | 424 | |||||||||||||||||
| Net change in net income (loss) | (67,276) | (22,465) | (84,755) | |||||||||||||||||
| Net loss for the current period | $ | (42,415) | (271)% | $ | (42,415) | (113)% | $ | (136,726) | (163)% | |||||||||||
(1) Funds flow from operations is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in "Financial and Operational Highlights" for a definition and reconciliation of this measure.
Capital expenditures during the three months ended September 30, 2026, were $30.7 million.
| (Millions of U.S. Dollars) | Colombia | Ecuador | Canada | All other | Total | ||||||||||||
| Exploration | $ | 1.7 | $ | 0.1 | $ | — | $ | 0.4 | $ | 2.2 | |||||||
| Development | 23.1 | 4.7 | 0.7 | — | 28.5 | ||||||||||||
| Total Company | $ | 24.8 | $ | 4.8 | $ | 0.7 | $ | 0.4 | $ | 30.7 | |||||||
During the three months ended September 30, 2026, we did not drill any wells in Colombia, Ecuador or Canada.
Liquidity and Capital Resources
| As at | |||||||||||||||||
| (Thousands of U.S. Dollars) | September 30, 2026 | % Change | December 31, 2025 | ||||||||||||||
| Cash and Cash Equivalents | $ | 141,077 | 70 | $ | 82,931 | ||||||||||||
| 7.75% Senior Notes due 2027 | $ | 24,201 | — | $ | 24,201 | ||||||||||||
| 9.50% Senior Notes due 2029 | $ | 87,639 | (88) | $ | 716,340 | ||||||||||||
| 9.75% Senior Notes due 2031 | $ | 479,353 | 100 | $ | — | ||||||||||||
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We believe that our capital resources, including cash on hand and cash generated from operations will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for the next 12 months, given the current oil price trends and production levels. We may also access capital markets to pursue financing, including for the re-purchase of common stock or the repayment of debt in the future. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us with the flexibility to respond to both internal growth opportunities and those available through acquisitions. We intend to pursue growth opportunities and acquisitions from time to time, which may require significant capital to be located in basins or countries beyond our current operations, involve joint ventures, or be sizable compared to our current assets and operations.
Senior Notes
During the nine months ended September 30, 2026, we issued $503.6 million in aggregate principal amount of our 9.75% Senior Secured Amortizing Notes due 2031 (the “9.75% Senior Notes”), and paid $125.0 million in cash consideration in exchange for $628.7 million aggregate principal amount of our 9.50% Senior Secured Amortizing Notes due 2029 (the “9.50% Senior Notes”). The exchange was accounted for as a debt modification.
The 9.75% Senior Notes will mature on April 15, 2031, unless earlier redeemed or re-purchased. The principal amount of 9.75% Senior Notes is to be repaid as follows: (i) October 15, 2029 - 15% of the principal amount; (ii) October 15, 2030 - 15% of the principal amount; (iii) April 15, 2031 - the remainder of the principal amount. On or before December 31, 2026 (“the Offer Date”), we are required to offer to purchase up to $30.0 million aggregate principal amount of the 9.75% Senior Notes (“the Offer Amount”). The Offer Amount will be reduced by the aggregate principal amount of any 9.75% Senior Notes redeemed or re-purchased by us in the open market transactions before the Offer Date.
During the nine months ended September 30, 2026, we re-purchased $24.2 million of 9.75% Senior Notes for cash consideration of $21.6 million resulting in a $1.3 million gain on purchase, which included the write-off of deferred financing fees of $1.4 million.
At any time, prior to April 15, 2028, we may redeem up to 35% of the aggregate principal amount of 9.75% Senior Notes at a redemption price equal to 109.75% of the principal amount. Additionally, we may redeem all or a portion of the 9.75% Senior Notes on or after 2028 at the following redemption prices: 2028 - 104.875%; 2029 - 102.438%; 2030 and thereafter - 100%.
Under the terms of the 9.75% Senior Notes agreement, we are required to maintain compliance with the following financial covenants:
i.consolidated interest coverage ratio of not less than 2.50; and
ii.consolidated net debt (total debt excluding deferred financing fees less cash equivalents) to consolidated adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”) of not more than 3.00.
As at September 30, 2026, we were in compliance with all applicable covenants related to Senior Notes.
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Credit Facility
On May 12, 2026, we, through our wholly owned subsidiary Gran Tierra Canada Ltd., amended our revolving credit facility with National Bank of Canada. As part of the amendment, the borrowing base has decreased to C$75.0 million (US$52.8 million). The available commitment under the revolving credit facility remained unchanged at C$75.0 million (US$52.8 million), comprised of C$60.0 million (US$42.2 million) syndicated facility and C$15.0 million (US$10.6 million) of operating facility. The drawn down amounts under the revolving credit facility can either be in Canadian or U.S. dollars and bear interest rates equal to either the Canadian prime rate or U.S. Base Rate plus a margin ranging from 2.00% to 4.00% per annum or for CORRA loans and SOFR loans plus a margin ranging from 3.00% to 5.00% per annum. Undrawn amounts under the revolving credit facility bear standby fee ranging from 0.75% to 1.25% per annum. In each case, the margin or standby fee, as applicable is based on Net Debt to EBITDA ratio of Gran Tierra Canada Ltd. The revolving credit facility matures on October 30, 2027. During the three months ended September 30, 2026, we drew C$15.3 million (US$10.9 million) under our revolving credit facility which was fully repaid by September 30, 2026. As of September 30, 2026, the revolving credit facility remained undrawn.
Prepayment agreements
During the nine months ended September 30, 2026, we amended our existing prepayment agreement with Trafigura, entering into a new oil prepayment agreement that covers both our Ecuadorian and Colombian oil production. The amended agreement provides for total prepayments of up to $350.0 million, including $325.0 million available immediately and an additional $25.0 million available at Trafigura’s sole discretion. The term of the amended prepayment agreement is 48 months.
Amounts drawn on this prepayment agreement are to be repaid through future oil deliveries. Shortfalls in crude oil deliveries in any given repayment period can be delivered during the next repayment period within three calendar months or paid in cash thereafter. Amounts under the prepayment facility are subject to interest based on SOFR risk-free rate plus a margin of 4.45% per annum. Under the terms of the prepayment agreement, we can repay the outstanding balance of the advance payment at any time without penalty. We were granted a grace period for re-payment of the principal amount drawn under the prepayment agreement with first re-payment starting April 2026.
Pursuant to the amended and restated prepayment agreement, proceeds from the new advance are required to be used exclusively to finance the repurchase or exchange of Senior Notes and to pay fees and expenses associated with the amended agreement.
We are required to maintain compliance with the following financial covenants related to amounts drawn under the prepayment agreement semi-annually, calculated on March 31 and September 30 of each year:
i.Asset Coverage Ratio of at least 150%, calculated using the net present value of the consolidated future cash flows of certain wholly owned subsidiaries of the Company that sell crude oil, projected through the final maturity date and discounted at 10% over the outstanding principal and the interest payable amount on the prepayment agreement at each reporting period. The net present value of the consolidated future cash flows of the Company is required to be based on 90% of the prevailing ICE Brent forward strip.
ii.Debt Service Coverage Ratio of at least 200%, calculated using the estimated crude oil to be delivered by the Company from any relevant time up to the final maturity date based on 80% of the prevailing ICE Brent forward strip and adjusted for quality differential and transportation discount over the outstanding principal amount under the prepayment agreement.
During the three and nine months ended September 30, 2026, we drew $8.5 million and $175.0 million on oil prepayment and re-paid $14.8 million and $43.6 million, respectively, of the outstanding principal on oil prepayment via crude oil deliveries.
As at September 30, 2026, there was $281.4 million outstanding (December 31, 2025 - $150.0 million) on the oil prepayment agreement. Of this amount, $88.9 million (December 31, 2025 - $34.1 million) was classified as a current portion and included in accounts payable and accrued liabilities on our condensed consolidated balance sheet.
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Sale of Colombia and Ecuador Business
During the three months ended September 30, 2026, we entered into a definitive share sale agreement (the ”Share Purchase Agreement”) to sell our oil business in Colombia and Ecuador (“Divested Business”) to a Paris-listed international oil and natural gas exploration and production company (“Purchaser”) on the terms and conditions set out in the Share Purchase Agreement (the “Sale”). The Divested Business comprises all of our assets in Colombia and Ecuador. The transaction has an economic effective date of March 31, 2026. Total consideration for the Sale is approximately $1.33 billion, subject to adjustment, which includes the Purchaser’s assumption of our 9.75% Senior Notes due 2031, our 9.50% Senior Notes due 2029, and the prepayment facility under our prepayment agreement (the “Prepayment Agreement”). After the assumption of substantially all liabilities, customary closing and working capital adjustments, our redemption of our 7.75% Senior Notes due 2027 (the “2027 Notes”), and transaction costs, we expect to receive net cash proceeds of approximately $315.0 million (the “Net Cash Proceeds”). Of this amount, approximately $250.0 million is payable in cash, of which $50.0 million was received as a deposit during the three months ended September 30, 2026, which was recorded in accounts payable and accrued liabilities on our condensed consolidated balance sheet and will be credited against the purchase price, with the balance due on closing. The remaining $65.0 million is payable 364 days after closing under an unsecured note issued by the Divested Business. Completion of the Sale is subject to the approval of our shareholders, receipt of the requisite consents from certain creditors and from the prepayment buyers under the Prepayment Agreement, customary regulatory approvals in Colombia and Ecuador, and the satisfaction of other customary closing conditions.
On September 22, 2026, we entered into a supplemental indenture to the indenture governing 9.75% Senior Notes due 2031, following receipt of the consents from bond holders of a majority in aggregate principal amount of those notes, which amends the indenture to permit the sale of Divested Business, with the amendments becoming operative upon closing of the Sale. For the three and nine months ended September 30, 2026, we incurred $4.9 million in transaction costs related to the Share Purchase Agreement. In the event the agreement is terminated, we must repay the deposit in full, together with interest accrued at 5% per annum, within five days of termination, unless the termination results from the Purchaser’s default, in which case we are entitled to retain the deposit and accrued interest. In addition, if the agreement is terminated following a change in the Board’s recommendation to shareholders, a failure by us to file our proxy statement or hold our shareholder meeting within the required timeframes, or our acceptance of a superior proposal, we must pay the Purchaser a termination fee of $50.0 million within ten days of termination.
As at September 30, 2026, we assessed whether the assets and liabilities subject to the Share Purchase Agreement met the criteria to be classified as held for sale under GAAP. We concluded that the held for sale criteria were not met as at that date because the Sale remained subject to shareholders’ approval, a substantive condition. Accordingly, the assets and liabilities of the Divested Business continue to be classified as held and used.
Subsequent to September 30, 2026, we obtained the shareholders’ approval for the sale of the Divested Business.
Disposition of Lodgepole area
During the nine months ended September 30, 2026, we completed a disposition of 54% WI and associated title rights in the Lodgepole area in Canada effective January 1, 2026, for a total cash consideration of C$12.8 million (US$9.3 million). As part of the disposition, we derecognized the asset retirement obligation attributed to Lodgepole area totaling C$17.5 million (US$12.8 million) on an undiscounted basis and C$9.0 million (US$6.6 million) on a discounted basis. No gain or loss was recognized in the statement of operations as the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.
Disposition of Simonette area
During the nine months ended September 30, 2026, we disposed of the entire working interest and associated title rights in the Simonette Montney area in Canada effective January 1, 2026, for total cash consideration of C$66.3 million (US$48.6 million). No gain or loss was recognized in the statement of operations because the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.
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Partnership with Ecopetrol S.A.
During the nine months ended September 30, 2026, we entered into a strategic partnership with Ecopetrol S.A. to earn, subject to regulatory approvals and conditions precedent, a 49% WI in the Tisquirama Block in Colombia. Under the terms of the agreement, we have committed to fund approximately $47.1 million of a $92.4 million gross capital program over 40 months, including a minimum Phase 1 investment of $15.0 million. Upon completion of Phase 1, we will be entitled to 49% of production and are expected to assume operatorship. On May 27, 2026, we satisfied all outstanding conditions precedent to the partnership agreement and received regulatory approval.
Exploration, Development and Production Sharing Agreement (“EDPSA”)
During the nine months ended September 30, 2026, we, through our wholly owned subsidiary, Gran Tierra Energy (Azerbaijan) GmbH, entered into a EDPSA with the State Oil Company of Azerbaijan Republic (“SOCAR”), providing for a 65% participating interest to us and a 35% participating interest to SOCAR. The PSA provides for a five-year exploration phase and, in the event of a commercial crude oil discovery, a 25-year development phase, with minimum work commitments during the exploration period to be completed within 36 months. These commitments include, among others, the acquisition of 250 square kilometers of 3D seismic data, the drilling of two exploration wells, and the conduct of geological and environmental impact studies. We have the right to relinquish the entire contract area during the exploration phase upon fulfillment of our exploration commitments, subject to 90 days’ prior notice to SOCAR.
Derivative positions
As at September 30, 2026, we had outstanding commodity price derivative positions as follows:
| Oil | ||||||||||||||||||||||||||
| Type of Instrument | Start Period | End Period | Volume bbl/d | Reference | Sold Put (C$/bbl or $/bbl Weighted Average) | Purchased Put (C$/bbl or $/bbl Weighted Average) | Sold Call (C$/bbl or $/bbl Weighted Average) | Premium (C$/bbl or $/bbl Weighted Average) | ||||||||||||||||||
| Collar | 10/01/26 | 12/31/26 | 500 | WTI CMA | — | C$ | 70.00 | C$ | 92.47 | — | ||||||||||||||||
| Put Option | 10/01/26 | 12/31/26 | 500 | Brent | — | 60.00 | — | 4.30 | ||||||||||||||||||
| Three Way | 10/01/26 | 12/31/26 | 500 | WTI CMA | C$ | 60.00 | C$ | 70.00 | C$ | 107.00 | C$ | 1.90 | ||||||||||||||
| Put Spread | 10/01/26 | 12/31/26 | 5,000 | Brent | 45.00 | 55.00 | — | 21.64 | ||||||||||||||||||
| Three Way | 10/01/26 | 12/31/26 | 9,000 | Brent | 50.33 | 60.33 | 72.49 | — | ||||||||||||||||||
| Three Way | 01/01/27 | 03/31/27 | 3,000 | Brent | 58.33 | 71.67 | 89.55 | — | ||||||||||||||||||
| Natural Gas | ||||||||||||||||||||||||||||||||||||||
| Type of Instrument | Start Period | End Period | Volume, GJ/day | Reference | Sold Swap (C$/GJ, Weighted Average) | Purchased Put (C$/GJ, Weighted Average) | Sold Call (C$/GJ, Weighted Average) | |||||||||||||||||||||||||||||||
| Swap | 10/01/26 | 12/31/26 | 6,739 | Aeco 5A | C$ | 2.71 | — | — | ||||||||||||||||||||||||||||||
Subsequent to the period ended September 30, 2026, the Company entered into the following commodity price derivative positions:
| Oil | ||||||||||||||||||||||||||
| Type of Instrument | Start Period | End Period | Volume bbl/d | Reference | Sold Put ($/bbl Weighted Average) | Purchased Put ($/bbl Weighted Average) | Sold Call ($/bbl Weighted Average) | Premium ($/bbl Weighted Average) | ||||||||||||||||||
| Three Way | 01/01/2027 | 03/31/27 | 5,000 | Brent | 80.00 | 95.00 | 111.00 | — | ||||||||||||||||||
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As at September 30, 2026, we had no outstanding foreign currency exchange derivative positions.
Cash Flows
The following table presents our primary sources and uses of cash and cash equivalents and restricted cash and cash equivalents for the periods presented:
| Nine Months Ended September 30, | ||||||||
| (Thousands of U.S. Dollars) | 2026 | 2025 | ||||||
| Sources of cash and cash equivalents: | ||||||||
| Net loss | $ | (136,726) | $ | (51,971) | ||||
Adjustments to reconcile net loss to Adjusted EBITDA(1) and funds flow from operations(1) | ||||||||
| DD&A expenses | 196,599 | 205,818 | ||||||
| Transaction costs | 4,887 | — | ||||||
| Interest expense | 98,229 | 73,048 | ||||||
| Severance | 2,563 | — | ||||||
| Income tax recovery | (31,682) | (3,075) | ||||||
| Non-cash lease expenses | 4,423 | 4,648 | ||||||
| Lease payments | (4,885) | (4,686) | ||||||
| Foreign exchange loss | 6,280 | 7,838 | ||||||
| Stock-based compensation expense | 46,384 | 172 | ||||||
| Financial instruments loss (gain) | 42,455 | (964) | ||||||
| Other (gain) loss | (1,425) | 355 | ||||||
Adjusted EBITDA(1) | 227,102 | 231,183 | ||||||
| Transaction costs | (4,887) | — | ||||||
| Current income tax expense | (19,476) | (14,482) | ||||||
| Contractual interest and other financing expenses (net of non-cash interest and Senior Notes exchange fees) | (53,380) | (60,864) | ||||||
| Realized foreign exchange loss | (12,044) | (4,902) | ||||||
| Severance | (2,563) | — | ||||||
Funds flow from operations(1) | 134,752 | 150,935 | ||||||
| Proceeds from debt, net of issuance costs | 10,895 | 48,921 | ||||||
| Proceeds from exercise of stock options | 759 | 40 | ||||||
| Proceeds from disposition of property, plant and equipment | 57,944 | 7,500 | ||||||
| Deposit on sale of oil business in Colombia and Ecuador | 50,000 | — | ||||||
| Proceeds from assets exchange | 583 | — | ||||||
| Net changes in assets and liabilities from operating activities | 138,518 | 9,867 | ||||||
| Foreign exchange gain on cash, and cash equivalents and restricted cash and cash equivalents | 2,815 | — | ||||||
| 396,266 | 217,263 | |||||||
| Uses of cash and cash equivalents: | ||||||||
| Additions to property, plant and equipment | (148,110) | (218,155) | ||||||
| Repayment of long-term debt | (10,870) | (7,743) | ||||||
| Re-purchase of Senior Notes | (21,569) | (1,712) | ||||||
| Senior Notes exchange fees | (13,509) | — | ||||||
| Repayment of Senior Notes | (125,000) | (24,828) | ||||||
Re-purchase of shares of Common Stock | — | (3,466) | ||||||
| Settlement of asset retirement obligations | (3,055) | (4,746) | ||||||
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| Lease payments | (15,904) | (8,473) | ||||||
| Foreign exchange loss on cash, and cash equivalents and restricted cash and cash equivalents | — | (1,299) | ||||||
| (338,017) | (270,422) | |||||||
| Net increase (decrease) in cash and cash equivalents and restricted cash and cash equivalents | $ | 58,249 | $ | (53,159) | ||||
(1) Adjusted EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition and reconciliation of this measure.
One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices. Sales volume changes, costs related to operations and debt transactions also impact cash flows. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes. During the three and nine months ended September 30, 2026, funds flow from operations decreased by 24% and 11%, respectively, compared to the corresponding periods of 2025, due to lower sales volumes, higher quality and transportation discounts, higher cash settlements on derivative instruments and higher realized foreign exchange loss, partially offset by an increase in benchmark oil prices and lower operating expenses.
Critical Accounting Policies and Estimates
Our critical accounting policies and estimates are disclosed in Item 7 of our 2025 Annual Report on Form 10-K and have not changed materially since the filing of that document.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity price risk
Our principal market risk relates to oil, natural gas and NGL prices which are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Our revenues are from oil sales at Brent, or Edmonton Light pricing and for gas at AECO pricing and adjusted for quality. As at September 30, 2026, we have entered into commodity price derivative contracts to manage the variability in cash flows associated with the forecasted sale of our oil production, reduce commodity price risk and provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending.
Foreign currency risk
Foreign currency risk is a factor for our Company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. Our reporting currency is U.S. dollars and 86% of our revenues are related to the U.S. dollar price of Brent with the remainder related to Canadian dollar price of WTI oil or AECO gas. In Colombia and Ecuador, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures is in U.S. dollars or is based on U.S. dollar prices. The majority of our operating costs, income taxes, VAT, and G&A expenses in all locations are in local currency. In Canada, we receive 100% of our revenue in Canadian dollars and the majority of our capital and operating expenditures are in Canadian dollars or are based on Canadian dollar prices.
We may enter into foreign currency derivative contracts to manage the variability in cash flows associated with our forecasted Colombian peso denominated costs. As at September 30, 2026, we had no outstanding foreign currency exchange derivative positions.
Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our accounts payable, taxes receivable and payable and deferred tax assets and liabilities in Colombia are denominated in the local currency of the Colombian foreign operations which are our monetary assets. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency.
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our revolving Canadian credit facility and our oil prepayment agreement which bear floating rates of interest. As of September 30, 2026, the revolving credit facility remained undrawn and $281.4 million was outstanding under the oil prepayment agreement.
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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 13a-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, 2026.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2026, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
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PART II - Other Information
Item 1. Legal Proceedings
See Note 11 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference, for any material developments with respect to matters previously reported in our Annual Report on Form 10-K for the year ended December 31, 2025, and any material matters that have arisen since the filing of such report.
Item 1A. Risk Factors
There are numerous factors that affect our business and results of operations, many of which are beyond our control. In addition to information set forth in this Quarterly Report on Form 10-Q, including in Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, you should carefully read and consider the following risk factors, as well as the factors set out in Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2025. These risk factors could materially affect our business, financial condition and results of operations. The unprecedented nature of ongoing conflicts in several parts of the world, along with volatility in the worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks.
The Sale is subject to certain completion conditions and may not be completed as anticipated, or at all
The completion of the Sale is subject to a number of conditions, certain of which are outside of control of Gran Tierra and Purchaser, including certain regulatory approvals in Colombia and Ecuador. A substantial delay in obtaining the required regulatory approvals, or the imposition of unfavorable terms or conditions in connection with any such regulatory approvals, could delay completion and may adversely affect our business, financial condition or results of operations. There is no certainty, nor can we provide any assurance, that these conditions will be satisfied or, if satisfied, when they will be satisfied.
Each of Gran Tierra and Purchaser has the right to terminate the Share Purchase Agreement in certain circumstances. Accordingly, there is no certainty, nor can we provide any assurance, that the Share Purchase Agreement will not be terminated by either us or Purchaser before the completion of the Sale. For instance, Purchaser has the right, in certain circumstances, to terminate the Share Purchase Agreement following delivery of a notice regarding the occurrence of a material adverse change. There is no assurance that a material adverse change or material adverse effect or other termination event will not occur before completion, in which case we or Purchaser could elect to terminate the Share Purchase Agreement and the Sale would not proceed.
If, for any reason, the Sale is not completed or is materially delayed, there may be ongoing or additional uncertainty regarding us and our business, operations and assets, including with respect to our business segments not subject to the Sale (the “Retained Business”) and the retention of key personnel. If the Sale is not completed, there can be no assurance that another purchaser for the Divested Business will emerge or propose a transaction on terms acceptable to us. In addition, certain costs related to the Sale, such as legal, accounting and financial advisor fees, must be paid by us even if the Sale is not completed. Any of the foregoing circumstances or events may adversely affect the market price of our Common Stock.
The Sale and the other transactions contemplated by the Share Purchase Agreement, whether or not completed, may adversely affect the Retained Business.
Transactions such as the Sale are often subject to lawsuits by stockholders. It is possible that our stockholders or other stakeholders will commence or seek to commence litigation against Gran Tierra or our board of directors. Such litigation could result in substantial costs and divert management’s attention from other business concerns, which could adversely affect the Retained Business.
The Sale is dependent upon the satisfaction of various conditions, and as a result its completion is subject to uncertainty. In response to this uncertainty, our customers, suppliers, joint venture partners and other counterparties may delay or defer decisions concerning Gran Tierra and both our current and anticipated ongoing business, and may instead, where applicable, enter into material contracts or business arrangements with our competitors who are not faced with such uncertainty. Any change, delay or deferral of those decisions by our customers, suppliers, joint venture partners and other counterparties could negatively impact the business, operations and prospects of Gran Tierra, regardless of whether the Sale is ultimately completed. In addition, our ability to execute on our business strategies for the Retained Business depends on the retention and recruitment of qualified executives and other professionals. We rely upon the services of our current executive and senior management
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teams. The market for qualified executives, senior managers and other employees has become very competitive. As a result of the Sale, we may experience higher employee turnover and finding qualified replacements may be more difficult. Current and prospective employees of Gran Tierra may experience uncertainty about their future roles with Gran Tierra and its affiliates until completion of the Sale, which may adversely affect our ability to attract or retain key employees during the period until the Sale is completed and thereafter. The loss of the services of members of our executive and/or senior management teams or our inability to hire and retain other talented personnel could delay or prevent us from succeeding in executing our strategies for the Retained Business, which could negatively impact the Retained Business. Further, while the completion of the Sale is pending, we may be unable to attract and retain key personnel and our management’s focus and attention and employee resources may be diverted from operational matters.
If we fail to complete the Sale, our business and financial performance may be adversely affected
If the Sale is not completed, we may have difficulty recouping the costs incurred in connection with negotiating the Sale. Our directors, executive officers and other employees will have expended extensive time and effort and will have experienced significant distractions from their work during the pendency of the Sale, and we will have incurred significant third-party transaction costs, in each case, without any commensurate benefit, which may have a material and adverse effect on our stock price and results of operations.
Furthermore, if the Sale is not completed, the announcement of the termination of the Share Purchase Agreement may adversely affect our relationships with our customers, business partners, and employees, which could have a material adverse impact on our ability to effectively operate our business and could have further adverse effects on our business and results of operations and the trading price of our Common Stock.
If we fail to complete the Sale, there may not be any other offer from potential acquirers that the board of directors determines to be attractive
If we fail to complete the Sale, our board of directors, in discharging its fiduciary obligations to our stockholders, may evaluate other strategic alternatives including, but not limited to, continuing to operate the Divested Business for the foreseeable future or an alternative transaction relating to the Divested Business. An alternative transaction, if available, may yield lower consideration or value than the Sale, be on less favorable terms and conditions than those contained in the Share Purchase Agreement and involve significant delay. Any future sale of substantially all of Gran Tierra’s property and assets within the meaning of Section 271 of the DGCL and related case law or other similar transaction may be subject to further stockholder approval, and there is no guarantee that Gran Tierra would be able to obtain such stockholder approval in favor of any such sale or other transaction. If the Divested Business is not sold, there can be no assurance that we will realize value at least equivalent to the proceeds of the Sale from the operation of the Divested Business over time, or any value; nor can we predict the timeline for realizing value, if any, from the Divested Business in the absence of the Sale.
The Share Purchase Agreement exposes Gran Tierra to certain contingent liabilities following completion of the Sale
Under the Share Purchase Agreement, we agreed to indemnify Purchaser and its affiliates against losses arising out of specified matters, including pre-Completion corporate income tax assessments and audits, a specified ongoing Colombian tax proceeding, and a specified environmental proceeding. We will also indemnify Purchaser and the acquired entities for taxes arising from a pre-signing internal reorganization of one of our subsidiaries into the Divested Business and losses arising from indirect-transfer tax exposure and related successor-liability claims triggered by the transaction; these tax indemnities are not subject to the general liability limitations and will survive completion of the Sale until the applicable statute of limitations plus six months.
Significant indemnification claims by Purchaser or its affiliates under these provisions could result in material cash outflows by Gran Tierra following completion of the Sale and could have a material adverse effect on our financial condition, results of operations, cash flows and ability to redeploy the proceeds of the Sale as contemplated.
Following completion of the Sale, Gran Tierra’s business will be significantly different, less diversified and more concentrated
Completion of the Sale will result in a significant reduction of Gran Tierra’s current cash-generating business and assets. Following completion of the Sale, Gran Tierra will no longer operate or have any interests in Colombia or Ecuador, which currently represent a substantial portion of Gran Tierra’s revenues, production and operations. Gran Tierra’s remaining business will consist of its interests in Canada and Azerbaijan, and Gran Tierra will be significantly more reliant on the results of the Retained Business, will be less geographically and asset-diversified than prior to the Sale, and will be exposed to different
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business, regulatory, operational, fiscal and commodity-mix risks than those to which Gran Tierra was exposed prior to the Sale. The risks attributable to Gran Tierra’s remaining business and operations, and the significance of those risks, will be significantly different than prior to the Sale, and the risk factors relating to the Retained Business that are set forth or incorporated by reference in this Quarterly Report and in our Annual Report on Form 10-K and subsequent Quarterly Reports on Form 10-Q, may be magnified due to the reduced size, scope and diversity of Gran Tierra’s business following the Sale.
The amount and use of net proceeds from the Sale is uncertain
The amount of net proceeds ultimately available to Gran Tierra from the Sale is uncertain and will depend on a number of factors. These include the final purchase price after the adjustments contemplated by the Share Purchase Agreement. Net proceeds will also be affected by Gran Tierra’s transaction expenses (including legal, accounting and financial advisor fees), transaction-related taxes and tax indemnity exposure retained by Gran Tierra under the Share Purchase Agreement. The nature, timing and use of the net proceeds will be determined by the board of directors in its discretion.
The market price and trading volume of our Common Stock may materially decrease or experience increased volatility
The market price and trading volume of our Common Stock may materially decrease or experience increased volatility as a result of a variety of factors relating to the Sale, whether or not it is completed, and the Retained Business, including announcements of new developments pertaining to the Sale or Gran Tierra’s ongoing business and operations, the manner in which the net proceeds from the Sale are ultimately used, fluctuations in Gran Tierra’s operating results, failure to meet analysts’ expectations, public announcements made with respect to the Sale or Gran Tierra’s business, changes in the reserves, production or financial profile of the Retained Business, changes in commodity prices or general market conditions of the worldwide economy, and any determination by the board of directors to modify or discontinue Gran Tierra’s existing capital return practices in light of the reduced size of the business. There can be no assurance that the market price of our Common Stock will not materially decrease or experience significant fluctuations in the future, whether or not the Sale is completed, including fluctuations that are unrelated to the Sale and Gran Tierra’s performance. Furthermore, our Common Stock is listed on the NYSE American, the TSX and the London Stock Exchange (“LSE”) and the trading prices of our Common Stock on these three exchanges may at times differ due to a variety of factors, including factors related to the Sale. Any decrease in the price of our Common Stock on one of these exchanges could cause a decrease in the trading price of our Common Stock on another. Investors could seek to sell or buy our Common Stock to take advantage of any price differences between the markets through a practice referred to as arbitrage. Any arbitrage activity could create unexpected volatility in the trading prices on one exchange and our Common Stock available for trading on the other exchanges.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
| (a) Total Number of Shares Purchased | (b) Average Price Paid per Share | (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | (d) Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs (1) | |||||||||||
| July 1-31, 2026 | — | — | — | 2,925,720 | ||||||||||
| August 1-31, 2026 | — | — | — | 2,925,720 | ||||||||||
| September 1-30, 2026 | — | — | — | 2,925,720 | ||||||||||
| Total | — | — | — | 2,925,720 | ||||||||||
Item 5. Other Information
During the three months ended September 30, 2026, no director or Section 16 officer adopted terminated
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Item 6. Exhibits
| Exhibit No. | Description | Reference | |||||||||
| 2.1*+ | Share Sale and Purchase Agreement dated August 5, 2026 by and between Gran Tierra Energy, Inc., Gran Tierra Energy International Holdings GmbH, Établissements Maurel & Prom S.A., and Maurel & Prom Andina | Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K/A, filed with the SEC on August 10, 2026 (SEC File No. 001-34018). | |||||||||
| 3.1 | Certificate of Incorporation. | Incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018). | |||||||||
| 3.2 | Certificate of Amendment to Certificate of Incorporation of Gran Tierra Energy Inc., effective May 5, 2023 | Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, filed with the SEC on May 5, 2023 (SEC File No. 001-34018). | |||||||||
| 3.3 | Bylaws of Gran Tierra Energy Inc. | Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018). | |||||||||
| 3.4 | Amendment No.1 to Bylaws of Gran Tierra Energy Inc. | Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the SEC on August 4, 2021 (SEC File No. 001-34018). | |||||||||
| 31.1 | Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | Filed herewith. | |||||||||
| 31.2 | Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | Filed herewith. | |||||||||
| 32.1 | Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | Furnished herewith. | |||||||||
101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH Inline XBRL Taxonomy Extension Schema Document
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document
104.The cover page from Gran Tierra Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2026, formatted in Inline XBRL (included within the Exhibit 101 attachments).
* Certain schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. We will furnish the omitted schedules to
the Securities Exchange Commission upon request by it.
+ Portions of this exhibit have been omitted pursuant to Item 601(b)(2)(ii).
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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: November 5, 2026 | /s/ Gary S. Guidry | |||||||
| By: Gary S. Guidry | ||||||||
| President and Chief Executive Officer | ||||||||
| (Principal Executive Officer) | ||||||||
Date: November 5, 2026 | /s/ Ryan Ellson | |||||||
| By: Ryan Ellson | ||||||||
| Executive Vice President and Chief Financial Officer | ||||||||
| (Principal Financial and Accounting Officer) | ||||||||
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