GRAN TIERRA ENERGY INC.
For the period ended Sep 30, 2026. Filed Nov 6, 2026.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Sep 30, 2026 · Filed Nov 6, 2026
GTE$9.42+0.3%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2026-06-30; filed 2026-08-05.
0001273441-26-000028
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-09-30; filed 2026-11-06.
0001273441-26-000039
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 138 previous paragraphs and 141 current paragraphs.
53 unchanged; 63 reworded; 25 added; 21 removed; 1 previous and 0 current paragraphs rearranged.
Tables are not compared: 47 previous and 45 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (25)
Current report
•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
Current report
•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
Current report
•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
Current report
•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
Current report
•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
Current report
•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
Current report
•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
Current report
(*)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.
Current report
(*)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.
Current report
Castilla, Vasconia and Oriente differentials per bbl increased from $9.71, $1.42 and $2.01 in the prior quarter.
Current report
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.
Current report
(*)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.
Current report
(*)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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
During the three months ended September 30, 2026, we did not drill any wells in Colombia, Ecuador or Canada.
Current report
Sale of Colombia and Ecuador Business
Current report
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.
Current report
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.
Current report
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.
Current report
Subsequent to September 30, 2026, we obtained the shareholders’ approval for the sale of the Divested Business.
Current report
Exploration, Development and Production Sharing Agreement (“EDPSA”)
Current report
Subsequent to the period ended September 30, 2026, the Company entered into the following commodity price derivative positions:
Removed paragraphs (21)
Previous report
•Adjusted EBITDA(2) was $85.1 million for the second quarter of 2026, an increase from $77.0 million in the second quarter of 2025, and $73.9 million in the prior quarter
Previous report
•Funds flow from operations(2)increased to $60.3 million compared to $53.9 million in the second quarter of 2025, and $42.8 million in the prior quarter
Previous report
•Operating expenses decreased by 7% and 22% to $51.6 million when compared to the second quarter of 2025 and the prior quarter, respectively, primarily due to lower workover activities, reduced field personnel costs, lower oil treatment and testing service costs, as well as inventory fluctuations resulting from inventory accumulation at the end of the current quarter. On a per boe basis, operating expenses increased by $1.67 to $17.61 when compared to the second quarter of 2025 due to lower sales volumes and decreased by $0.64 from $18.25 in the prior quarter primarily due to inventory fluctuations resulting from inventory accumulation at the end of the current quarter
Previous report
•Transportation expenses decreased by 13% when compared to the second quarter of 2025 and decreased by 26% from the prior quarter primarily due to lower sales volumes transported in Colombia and Canada
Previous report
•Operating netback(2)was $131.7 million compared to $89.3 million in the second quarter of 2025 and $100.6 million in the prior quarter
Previous report
•During the second quarter, we satisfied all outstanding conditions precedent to and received regulatory approval for a strategic partnership with Ecopetrol S.A., earning a 49% working interest in the Tisquirama Block in Colombia. Additionally, we completed all capital commitments related to Suroriente Block.
Previous report
(*)Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $43.5 million and $50.5 million less depreciation of administrative assets of $5.5 million and $2.6 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $89.9 million and $99.1 million, less depreciation of administrative assets of $11.2 million and $6.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $46.4 million, less depreciation of administrative assets of $5.7 million.
Previous report
(*)Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $62.3 million and $68.6 million less depreciation of administrative assets of $6.1 million and $2.7 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $132.2 million and $140.8 million less depreciation of administrative assets of $12.0 million and $6.5 million, respectively. For the prior quarter, calculated as DD&A expenses of $69.9 million, less depreciation of administrative assets of $6.0 million.
Previous report
Castilla differential per bbl was comparable to the prior quarter and Vasconia and Oriente differentials per bbl decreased from $5.91 and $8.17 in the prior quarter.
Previous report
Compared to the prior quarter, oil, natural gas and NGL sales increased by 9%, primarily due to a 23% increase in Brent price and lower quality and transportation discounts in Colombia and premium in Ecuador, partially offset by a 20% decrease in sales volumes. During three months ended June 30, 2026, there was only one lifting in Ecuador compared to two in the prior quarter.
Previous report
(*)Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $43.5 million and $50.5 million less depreciation of administrative assets of $5.5 million and $2.6 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $89.9 million and $99.1 million less depreciation of administrative assets of $11.2 million and $6.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $46.4 million, less depreciation of administrative assets of $5.7 million.
Previous report
(*)Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $62.3 million and $68.6 million less depreciation of administrative assets of $6.1 million and $2.7 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $132.2 million and $140.8 million less depreciation of administrative assets of $12.0 million and $6.5 million, respectively. For the prior quarter, calculated as DD&A expenses of $69.9 million, less depreciation of administrative assets of $6.0 million.
Previous report
Transportation expenses for the three months ended June 30, 2026, decreased by 13% to $3.9 million, compared to the corresponding period of 2025, due to lower sales volumes transported in Colombia and Canada and increased by $0.04 per boe due to lower sales volumes. Transportation expenses for the six months ended June 30, 2026, increased by 2% or $0.12 per boe due to higher volumes transported via pipeline which had a higher cost per boe.
Previous report
Transportation expenses decreased by 26% or $0.13 per boe from $5.3 million or $1.46 per boe in the prior quarter due to lower sales volumes transported during the current quarter.
Previous report
G&A expenses after stock-based compensation for the three months ended June 30, 2026, decreased by 36% or $0.97 per boe compared to the corresponding period of 2025 due to lower share price resulting in stock-based compensation recovery. G&A expenses after stock-based compensation for the six months ended June 30, 2026, increased by 70% or $3.04 per boe compared to the corresponding period of 2025, due to higher stock-based compensation cost attributed to a higher share price during the current period.
Previous report
During the three months ended June 30, 2026, we drilled the following wells:
Previous report
During the three months ended June 30, 2026, we spud one development well in Cohembi field in Colombia which was producing as of June 30, 2026.
Previous report
Assets exchange transaction
Previous report
During the three months ended June 30, 2026, we completed an asset exchange transaction in which we transferred a 30% WI in certain oil and natural gas rights, wells, and tangible assets located in the Marten Hills area, in exchange for oil and natural gas rights, wells, and tangible assets in the Seal/Dawson area, WI ranging from 35% to 100%. In connection with this transaction, we received cash consideration of C$0.8 million (US$0.6 million).
Previous report
Production sharing agreement (“PSA”)
Previous report
(1)At the June 30, 2026 foreign exchange rate.
Reworded paragraphs (63)
Previous wording
Key Highlights for the second quarter of 2026
Current wording
Key Highlights for the third quarter of 2026
Previous wording
•Net income for the second quarter of 2026 was $24.9 million or $0.70 per share basic and diluted, compared to a net loss of $12.7 million or $(0.36) per share basic and diluted for the second quarter of 2025 and a net loss of $119.2 million or $(3.38) per share for the prior quarter.
Current wording
•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.
Previous wording
•Income before income taxes for the second quarter of 2026 was $45.3 million, compared to loss before income taxes of $8.1 million for the second quarter of 2025 and loss before income taxes of $145.8 million for the prior quarter
Current wording
•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
Previous wording
•Brent oil price averaged $96.68 per bbl during the quarter, an increase of 45% from the comparative period of 2025, and an increase of 23% from the prior quarter. Castilla, Vasconia and Oriente differentials averaged$9.71, $1.42 and $2.01 per bbl during the quarter, an increase of 105% for Castilla and a decrease of 17% and 72% for Vasconia and Oriente differentials from the comparable period of 2025. Castilla differential was comparable to the prior quarter and Vasconia and Oriente differentials decreased by 76% and 75% from the prior quarter, respectively
Current wording
•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
Previous wording
•NAR production for the second quarter of 2026 decreased by 20% to 31,990 BOEPD, compared to 39,800 BOEPD in the second quarter of 2025, and decreased by 15% from 37,741 BOEPD in the prior quarter primarily due to lower production in Colombia, higher in-kind royalties driven by higher oil prices and asset sales in Canada
Current wording
•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
Previous wording
•NAR sales volumes for the second quarter of 2026 decreased by 16% to 32,166 BOEPD, compared to 38,331 BOEPD in the second quarter of 2025 and decreased by 20% from 40,267 BOEPD in the prior quarter
Current wording
•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
Previous wording
•Oil, natural gas and NGL sales for the second quarter of 2026 increased by 25% to $187.2 million, compared to the second quarter of 2025, due to increase in benchmark oil prices, offset by lower sales volumes in Colombia and Canada and higher quality and transportation discounts in Colombia associated with using alternative transportation routes for Putumayo production as the Colombia and Ecuador border remained closed. Oil, natural gas and NGL sales increased by 9% from $172.1 million in the prior quarter due to higher benchmark oil prices and lower quality and transportation discounts in Colombia and premium in Ecuador, partially offset by lower sales volumes
Current wording
•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
Previous wording
•Gross profit increased to $75.5 million compared to $23.3 million in the second quarter of 2025 and $36.7 million in the prior quarter
Current wording
•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
Previous wording
•Quality and transportation discounts per boe in South America were $10.47, an increase from $10.29 in the second quarter of 2025 due to higher transportation discounts in Colombia. Quality and transportation discounts in Colombia were affected by using alternative transportation route for Putumayo production as a result of closure of Ecuador and Colombia border which was significantly more expensive and resulted in approximately $5.9 million for the current quarter. Quality and transportation discounts in South America decreased from $19.04 per boe in the prior quarter primarily a result of decrease in Vasconia and Oriente differentials, offset by higher transportation discounts
Current wording
•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
Previous wording
•Quality and transportation discounts for oil per boe in Canada for the second quarter of 2026 decreased to $2.24 compared to $8.22 in the second quarter of 2025 and $9.70 in the prior quarter due to lower pipeline tariffs in the current quarter resulting from a change in product mix associated with asset sales
Current wording
•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
Previous wording
•General and administrative (“G&A”) expenses before stock-based compensation for the second quarter of 2026 decreased to $13.2 million compared to $14.1 million in the second quarter of 2025 and $15.1 million in the prior quarter due to lower consulting, information technology costs and lower salaries associated with headcount optimization
Current wording
•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
Previous wording
•Capital expenditures for the second quarter of 2026 were $54.3 million compared to $51.2 million in the second quarter of 2025 and $45.4 million in the prior quarter
Current wording
•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
Previous wording
(*)Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $10.3 million and $4.4 million less depreciation of administrative assets of $0.6 million and nil, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $26.3 million and $14.8 million less depreciation of administrative assets of $0.7 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $16.0 million, less depreciation of administrative assets of $0.1 million.
Current wording
(*)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.
Previous wording
(*)Same as DD&A expenses for the three months ended June 30, 2026 and 2025, six months ended June 30, 2026 and 2025, and the prior quarter (the depreciation of administrative assets had a de minimus amount for all reported periods).
Current wording
(*)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).
Previous wording
EBITDA, as presented, is defined as net income (loss) adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense, and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for severance expense, non-cash lease expense, lease payments, foreign exchange gains or losses, stock-based compensation expense or recovery, other non-cash gains or losses and unrealized derivative instruments gains or losses. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is a useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income (loss) to EBITDA and adjusted EBITDA is as follows:
Current wording
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:
Previous wording
Funds flow from operations, as presented, is defined as net income (loss) adjusted for DD&A expenses, deferred income tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, Senior Notes exchange fees, non-cash interest, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, unrealized derivative instruments gains or losses and other non-cash gains or losses. Management uses this financial measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net loss to funds flow from operations is as follows:
Current wording
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:
Previous wording
Oil, natural gas and NGL production NAR for the three and six months ended June 30, 2026, decreased by 20% and 11% to 31,990 BOEPD and 34,850 BOEPD, respectively, compared to the corresponding periods of 2025 due to lower production in Colombia, higher in-kind royalties driven by higher oil prices and the sale of Simonette area in Canada at the end of prior quarter, partially offset by higher than anticipated production results from Conejo-1 well in Charapa Block and additional production from Perico Block in Ecuador acquired in December 2025. Oil, natural gas and NGL production NAR decreased by 15% compared to the prior quarter primarily due to the sale of the Simonette area in Canada and lower production in the Acordionero and Cohembi fields in Colombia as a result of failure of artificial lift systems.
Current wording
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.
Previous wording
Royalties as a percentage of production for the three and six months ended June 30, 2026 increased to 23% and 20%, respectively, compared to the corresponding periods of 2025 and the prior quarter as a result of higher benchmark oil prices and the price sensitive royalty regime in Colombia and Ecuador.
Current wording
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.
Previous wording
Brent -For the three and six months ended June 30, 2026, Brent increased 45% and 24% from the corresponding periods of 2025 and increased 23% from the prior quarter.
Current wording
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.
Previous wording
For the three months ended June 30, 2026, Castilla differential per bbl increased to $9.71 from $4.73 in the corresponding period of 2025. Vasconia and Oriente differentials per bbl decreased to $1.42 and $2.01 compared to $1.71 and $7.26, respectively, in the corresponding period of 2025.
Current wording
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.
Previous wording
For the six months ended June 30, 2026, Castilla and Vasconia differentials per bbl increased to $9.69 and $3.65 from $5.04 and $1.99, respectively, in the corresponding period of 2025. Oriente differential per bbl decreased to $5.07 from $7.45 in the corresponding period of 2025.
Current wording
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.
Previous wording
The differentials for South America fluctuate based on regional supply and demand of heavy crude, shipping costs, pipeline disruptions and geopolitical and trading policies.
Current wording
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.
Previous wording
During the three and six months ended June 30, 2026 and 2025, 100% of sales from South America was priced against Brent.
Current wording
During the three and nine months ended September 30, 2026 and 2025, 100% of sales from South America was priced against Brent.
Previous wording
WTI -For the three and six months ended June 30, 2026, WTI increased by 45% and 22% from the corresponding periods of 2025 and increased 27% from the prior quarter. During the three and six months ended June 30, 2026, 22% and 23% of NAR production in Canada was oil, compared to 26% and 23% for the corresponding periods of 2025 and 25% in the prior quarter, respectively.
Current wording
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.
Previous wording
NGLs - For the three and six months ended June 30, 2026, the weighted average NGL price received was 7% and 12% of WTI compared to 11% and 12% of WTI in the corresponding periods of 2025, respectively, and 10% of WTI in the prior quarter. During the three and six months ended June 30, 2026, NGLs production in Canada was 27% in each reporting period, and comparable to the corresponding periods of 2025 and the prior quarter.
Current wording
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.
Previous wording
AECO - For the three and six months ended June 30, 2026, AECO price decreased by 3% and 5% from the corresponding periods of 2025 and decreased 19% from the prior quarter. During the three and six months ended June 30, 2026, 52% and 50% of production in Canada was natural gas, compared to 50% and 51%, in the corresponding periods of 2025, respectively, and 49% in the prior quarter.
Current wording
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.
Previous wording
Oil, natural gas and NGL salesfor the three and six months ended June 30, 2026, increased by 25% and 13% to $187.2 million and $359.2 million compared to the corresponding periods of 2025, primarily due to increases of 45% and 24% in Brent price, partially offset by 16% and 6% lower sales volumes in Colombia and Canada and higher quality and transportation discounts in Colombia. Quality and transportation discounts in Colombia were affected by using alternative transportation route for Putumayo production as Colombia and Ecuador border remained closed. The alternative transportation route was significantly more expensive and resulted in approximately $5.9 million and $10.0 million for the three and six months ended June 30, 2026.
Current wording
Oil, natural gas and NGL salesfor 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.
Previous wording
The following table shows the effect of changes in realized price and sale volumes on our oil, natural gas and NGL sales for the three and six months ended June 30, 2026, compared to the prior quarter and the corresponding periods of 2025:
Current wording
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:
Previous wording
(*)Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $10.3 million and $4.4 million less depreciation of administrative assets of $0.6 million and nil, respectively. For the six months ended June 30, 2026 and 2025. DD&A expenses of $26.3 million and $14.8 million less depreciation of administrative assets of $0.7 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $16.0 million, less depreciation of administrative assets of $0.1 million.
Current wording
(*)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.
Previous wording
(*)Same as DD&A expenses for the three months ended June 30, 2026 and 2025, six months ended June 30, 2026 and 2025, and the prior quarter (the depreciation of administrative assets had a de minimus amount for all reported periods).
Current wording
(*)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).
Previous wording
Operating expenses for the three and six months ended June 30, 2026, decreased by 7% and 4% to $51.6 million and $117.7 million, respectively, compared to the corresponding periods of 2025. The decrease was primarily due to lower workover activities, reduced field personnel costs, lower oil treatment and testing service costs, as well as inventory fluctuations resulting from inventory accumulation at the end of the current quarter.
Current wording
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.
Previous wording
Operating expenses for the three and six months ended June 30, 2026, on a per boe basis, increased by $1.67 and $0.44 to $17.61 and $17.97, respectively, compared to the corresponding periods of 2025, primarily due to lower sales volumes during current periods, partially offset by $0.18 and $0.68 per boe lower workover activities and inventory fluctuations, respectively.
Current wording
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.
Previous wording
Compared to the prior quarter, operating expenses decreased by 22% from $66.1 million or by$0.64 from $18.25 on a per boe basis primarily due to inventory fluctuations resulting from inventory accumulation at the end of the current quarter, partially offset by$0.34 per boe higher workover activities.
Current wording
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.
Previous wording
We have options to sell our oil through multiple pipelines and various trucking routes. Each option has varying effects on realized sales price and transportation expenses. The following table shows the percentage of oil, natural gas and NGL volumes we sold in Canada, Colombia and Ecuador using each option for the three and six months ended June 30, 2026 and 2025, and the prior quarter:
Current wording
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:
Previous wording
DD&A expenses for the three and six months ended June 30, 2026, decreased by 9% and 6%, respectively, due to lower costs in the depletable base for Canadian operations as a result of Simonette and Lodgepole areas disposition and higher proved reserves across reportable segments compared to the corresponding periods of 2025. On a per boe basis, DD&A expenses for the three and six months ended June 30, 2026, increased by $1.61 and $0.06, respectively, due to the lower sales volumes in the current periods.
Current wording
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.
Previous wording
For the three and six months ended June 30, 2026 and 2025, we had no ceiling test impairment losses. We used a 12-month unweighted average of the first-day-of-the-month prices prior to the ending date of the period ended June 30, 2026 as follows: Brent Crude $78.55 per bbl, Edmonton Light Crude of C$98.28 per bbl, Alberta AECO spot price of C$1.55 per MMBtu, Edmonton Propane C$32.84 per boe, Edmonton Butane C$41.70 per boe and Edmonton Condensate C$100.06 per boe (June 30, 2025: Brent Crude of $73.60 per bbl, Edmonton Light Crude of C$91.55 per bbl, Alberta AECO spot price of C$1.69 per MMBtu Edmonton Propane C$33.82 per boe, Edmonton Butane C$47.11 per boe and Edmonton Condensate C$95.75 per boe).
Current wording
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).
Previous wording
G&A expenses before stock-based compensation for the three months ended June 30, 2026, decreased by 6% to $13.2 million compared to the corresponding period of 2025, primarily due to lower consulting and information technology costs during the current period. G&A expenses before stock-based compensation for the six months ended June 30, 2026, increased by 9% to $28.4 million, compared to the corresponding period of 2025, primarily due to higher costs associated with project optimization.
Current wording
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.
Previous wording
On a per boe basis, G&A expenses before stock-based compensation for the three and six months ended June 30, 2026 increased by $0.47 and $0.61 to $4.52 and $4.33, compared to the corresponding period of 2025 primarily due to 16% and 6% lower sales volumes, respectively.
Current wording
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.
Previous wording
Compared to the prior quarter, G&A expenses before stock-based compensation decreased by 13% due to lower consulting, information technology costs and lower salaries associated with headcount optimization. On a per boe basis, G&A expenses before stock-based compensation increased by $0.34 compared to the prior quarter due to 20% decrease in sales volumes.
Current wording
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.
Previous wording
Compared to the prior quarter, G&A expenses after stock-based compensation decreased by 73% or $6.37 per boe due to lower share price resulting in stock-based compensation recovery.
Current wording
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.
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Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
DD&A expenses decreased by 11% from $69.9 million and increased by $2.01 on a per boe basis when compared to the prior quarter for the same reason mentioned above.