Gran Tierra Energy Inc.

11/06/2026 | Press release | Distributed by Public on 11/06/2026 05:00

Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)

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
•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
(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.
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:
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
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
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 %
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.
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.
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.
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
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
(*) 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).
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
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
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.
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.
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.
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).
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
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).
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.
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.
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)
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)
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 $ -
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.
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.
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.
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 -
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)
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.
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