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The following discussion of our financial condition and results of operations should be read in conjunction with the “Financial Statements” as set out in Part I, Item 1 of this Quarterly Report on Form 10-Q, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the “Financial Statements and Supplementary Data” included in Part II, Items 7 and 8, respectively, of our 2025 Annual Report on Form 10-K. Please see the cautionary language at the beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements and the risk factors described in Part II, Item 1A “Risk Factors” of this Quarterly Report on Form 10-Q, as well as Part I, Item 1A “Risk Factors” in our 2025 Annual Report on Form 10-K. Financial and Operational Highlights Key Highlights for the second quarter of 2026 •Net income for the second quarter of 2026 was $24.9 million or $0.70 per share basic and diluted, compared to a net loss of $12.7 million or $(0.36) per share basic and diluted for the second quarter of 2025 and a net loss of $119.2 million or $(3.38) per share for the prior quarter. •Income before income taxes for the second quarter of 2026 was $45.3 million, compared to loss before income taxes of $8.1 million for the second quarter of 2025 and loss before income taxes of $145.8 million for the prior quarter •Brent oil price averaged $96.68 per bbl during the quarter, an increase of 45% from the comparative period of 2025, and an increase of 23% from the prior quarter. Castilla, Vasconia and Oriente differentials averaged $9.71, $1.42 and $2.01 per bbl during the quarter, an increase of 105% for Castilla and a decrease of 17% and 72% for Vasconia and Oriente differentials from the comparable period of 2025. Castilla differential was comparable to the prior quarter and Vasconia and Oriente differentials decreased by 76% and 75% from the prior quarter, respectively •Adjusted EBITDA(2) was $85.1 million for the second quarter of 2026, an increase from $77.0 million in the second quarter of 2025, and $73.9 million in the prior quarter •Funds flow from operations(2) increased to $60.3 million compared to $53.9 million in the second quarter of 2025, and $42.8 million in the prior quarter •NAR production for the second quarter of 2026 decreased by 20% to 31,990 BOEPD, compared to 39,800 BOEPD in the second quarter of 2025, and decreased by 15% from 37,741 BOEPD in the prior quarter primarily due to lower production in Colombia, higher in-kind royalties driven by higher oil prices and asset sales in Canada •NAR sales volumes for the second quarter of 2026 decreased by 16% to 32,166 BOEPD, compared to 38,331 BOEPD in the second quarter of 2025 and decreased by 20% from 40,267 BOEPD in the prior quarter •Oil, natural gas and NGL sales for the second quarter of 2026 increased by 25% to $187.2 million, compared to the second quarter of 2025, due to increase in benchmark oil prices, offset by lower sales volumes in Colombia and Canada and higher quality and transportation discounts in Colombia associated with using alternative transportation routes for Putumayo production as the Colombia and Ecuador border remained closed. Oil, natural gas and NGL sales increased by 9% from $172.1 million in the prior quarter due to higher benchmark oil prices and lower quality and transportation discounts in Colombia and premium in Ecuador, partially offset by lower sales volumes •Operating expenses decreased by 7% and 22% to $51.6 million when compared to the second quarter of 2025 and the prior quarter, respectively, primarily due to lower workover activities, reduced field personnel costs, lower oil treatment and testing service costs, as well as inventory fluctuations resulting from inventory accumulation at the end of the current quarter. On a per boe basis, operating expenses increased by $1.67 to $17.61 when compared to the second quarter of 2025 due to lower sales volumes and decreased by $0.64 from $18.25 in the prior quarter primarily due to inventory fluctuations resulting from inventory accumulation at the end of the current quarter •Transportation expenses decreased by 13% when compared to the second quarter of 2025 and decreased by 26% from the prior quarter primarily due to lower sales volumes transported in Colombia and Canada •Gross profit increased to $75.5 million compared to $23.3 million in the second quarter of 2025 and $36.7 million in the prior quarter •Operating netback(2) was $131.7 million compared to $89.3 million in the second quarter of 2025 and $100.6 million in the prior quarter •Quality and transportation discounts per boe in South America were $10.47, an increase from $10.29 in the second quarter of 2025 due to higher transportation discounts in Colombia. Quality and transportation discounts in Colombia were affected by using alternative transportation route for Putumayo production as a result of closure of Ecuador and Colombia border which was significantly more expensive and resulted in approximately $5.9 million for the current 22 quarter. Quality and transportation discounts in South America decreased from $19.04 per boe in the prior quarter primarily a result of decrease in Vasconia and Oriente differentials, offset by higher transportation discounts •Quality and transportation discounts for oil per boe in Canada for the second quarter of 2026 decreased to $2.24 compared to $8.22 in the second quarter of 2025 and $9.70 in the prior quarter due to lower pipeline tariffs in the current quarter resulting from a change in product mix associated with asset sales •General and administrative (“G&A”) expenses before stock-based compensation for the second quarter of 2026 decreased to $13.2 million compared to $14.1 million in the second quarter of 2025 and $15.1 million in the prior quarter due to lower consulting, information technology costs and lower salaries associated with headcount optimization •Capital expenditures for the second quarter of 2026 were $54.3 million compared to $51.2 million in the second quarter of 2025 and $45.4 million in the prior quarter •During the second quarter, we satisfied all outstanding conditions precedent to and received regulatory approval for a strategic partnership with Ecopetrol S.A., earning a 49% working interest in the Tisquirama Block in Colombia. Additionally, we completed all capital commitments related to Suroriente Block. 23 (Thousands of U.S. Dollars, unless otherwise indicated) Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, 2026 2025 % Change 2026 2026 2025 % Change Average Daily Volumes (BOEPD) Consolidated Working Interest (“WI”) Production Before Royalties 41,501 47,196 (12) 45,497 43,488 46,923 (7) Royalties (9,511) (7,396) 29 (7,756) (8,638) (7,738) 12 Production NAR 31,990 39,800 (20) 37,741 34,850 39,185 (11) Decrease (increase) in Inventory 176 (1,469) 112 2,526 1,345 (509) 364 Sales(1) 32,166 38,331 (16) 40,267 36,195 38,676 (6) Net Income (Loss) $ 24,861 $ (12,741) 295 $ (119,172) $ (94,311) $ (32,021) (195) Operating Netback Gross Profit $ 75,460 $ 23,313 224 $ 36,697 $ 112,157 $ 51,414 118 Depletion and Accretion $ 56,253 $ 65,948 (15) 63,908 120,161 134,379 (11) Operating Netback(2) $ 131,713 $ 89,261 48 $ 100,605 $ 232,318 $ 185,793 25 G&A Expenses before Stock-Based Compensation $ 13,219 $ 14,136 (6) $ 15,149 $ 28,368 $ 26,062 9 G&A Stock-Based Compensation (Recovery) Expense (3,757) 546 (788) 19,676 15,919 29 54,793 G&A Expenses, including Stock-Based Compensation $ 9,462 $ 14,682 (36) $ 34,825 $ 44,287 $ 26,091 70 Adjusted EBITDA(2) $ 85,071 $ 76,987 11 $ 73,935 $ 159,006 $ 162,149 (2) Funds Flow from Operations(2) $ 60,289 $ 53,906 12 $ 42,823 $ 103,112 $ 109,250 (6) Capital Expenditures (before changes in working capital) $ 54,309 $ 51,170 6 $ 45,359 $ 99,668 $ 145,897 (32) (1) Sales volumes represent production NAR adjusted for inventory changes. (2) Non-GAAP measures. Gross profit is derived from oil, gas and NGL sales, less operating and transportation expenses, and depletion and accretion related to producing assets. Gross profit does not include depreciation of administrative assets, asset impairment, general and administrative expenses, interest, taxes or other non-operating items. Operating netback, EBITDA, adjusted EBITDA, and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to oil sales, net income (loss) or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Disclosure of each non-GAAP financial measure is preceded by the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure. Operating netback, as presented, is defined as gross profit adjusted for depletion and accretion related to producing assets. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from gross profit to operating netback is provided in the table below. 24 Colombia Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Gross Profit $ 44,585 $ 19,880 $ 24,377 $ 68,962 $ 46,828 Adjustments to reconcile gross profit to operating netback Depletion and accretion (*) 38,072 47,897 40,633 78,705 92,896 Operating netback (non-GAAP) $ 82,657 $ 67,777 $ 65,010 $ 147,667 $ 139,724 (*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $43.5 million and $50.5 million less depreciation of administrative assets of $5.5 million and $2.6 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $89.9 million and $99.1 million, less depreciation of administrative assets of $11.2 million and $6.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $46.4 million, less depreciation of administrative assets of $5.7 million. Ecuador Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Gross Profit (Loss) $ 24,811 $ (419) $ 6,378 $ 31,189 $ 942 Adjustments to reconcile gross profit to operating netback Depletion and accretion (*) 9,775 4,351 15,861 25,636 14,847 Operating netback (non-GAAP) $ 34,586 $ 3,932 $ 22,239 $ 56,825 $ 15,789 (*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $10.3 million and $4.4 million less depreciation of administrative assets of $0.6 million and nil, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $26.3 million and $14.8 million less depreciation of administrative assets of $0.7 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $16.0 million, less depreciation of administrative assets of $0.1 million. Canada Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Gross Profit $ 6,064 $ 3,852 $ 5,942 $ 12,006 $ 3,644 Adjustments to reconcile gross profit to operating netback Depletion and accretion (*) 8,406 13,700 7,414 15,820 26,636 Operating netback (non-GAAP) $ 14,470 $ 17,552 $ 13,356 $ 27,826 $ 30,280 (*) Same as DD&A expenses for the three months ended June 30, 2026 and 2025, six months ended June 30, 2026 and 2025, and the prior quarter (the depreciation of administrative assets had a de minimus amount for all reported periods). Total Consolidated Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Gross Profit $ 75,460 $ 23,313 $ 36,697 $ 112,157 $ 51,414 Adjustments to reconcile gross profit to operating netback Depletion and accretion (*) 56,253 65,948 63,908 120,161 134,379 Operating netback (non-GAAP) $ 131,713 $ 89,261 $ 100,605 $ 232,318 $ 185,793 (*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $62.3 million and $68.6 million less depreciation of administrative assets of $6.1 million and $2.7 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $132.2 million and $140.8 million less depreciation of administrative assets of $12.0 million and $6.5 million, respectively. For the prior quarter, calculated as DD&A expenses of $69.9 million, less depreciation of administrative assets of $6.0 million. EBITDA, as presented, is defined as net income (loss) adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense, and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for severance expense, non-cash lease expense, lease payments, foreign exchange gains or losses, stock-based compensation expense or recovery, other non-cash gains or losses and unrealized derivative instruments gains or losses. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is a useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income (loss) to EBITDA and adjusted EBITDA is as follows: 25 Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Net income (loss) $ 24,861 $ (12,741) $ (119,172) $ (94,311) $ (32,021) Adjustments to reconcile net income (loss) to EBITDA and Adjusted EBITDA DD&A expenses 62,334 68,635 69,874 132,208 140,837 Interest expense 24,473 24,366 49,878 74,351 47,601 Income tax expense (recovery) 20,488 4,648 (26,595) (6,107) 8,201 EBITDA (non-GAAP) $ 132,156 $ 84,908 $ (26,015) $ 106,141 $ 164,618 Severance 95 — 2,468 2,563 — Non-cash lease expense 1,503 1,725 1,468 2,971 3,461 Lease payments (1,633) (1,545) (1,687) (3,320) (3,112) Foreign exchange loss 2,603 3,716 1,425 4,028 7,554 Stock-based compensation (recovery) expense (3,757) 546 19,676 15,919 29 Other non-cash loss (gain) — 38 (728) (728) 90 Unrealized derivative instruments (gain) loss (45,896) (12,401) 77,328 31,432 (10,491) Adjusted EBITDA (non-GAAP) $ 85,071 $ 76,987 $ 73,935 $ 159,006 $ 162,149 Funds flow from operations, as presented, is defined as net income (loss) adjusted for DD&A expenses, deferred income tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, Senior Notes exchange fees, non-cash interest, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, unrealized derivative instruments gains or losses and other non-cash gains or losses. Management uses this financial measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net loss to funds flow from operations is as follows: Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Net income (loss) $ 24,861 $ (12,741) $ (119,172) $ (94,311) $ (32,021) Adjustments to reconcile net income (loss) to funds flow from operations DD&A expenses 62,334 68,635 69,874 132,208 140,837 Deferred income tax expense (recovery) 11,373 2,453 (32,445) (21,072) (2,259) Stock-based compensation (recovery) expense (3,757) 546 19,676 15,919 29 Amortization of debt issuance costs 1,722 4,082 11,293 13,015 7,915 Senior Notes exchange fees 785 — 12,903 13,688 — Non-cash interest 6,134 — 4,513 10,647 — Non-cash lease expense 1,503 1,725 1,468 2,971 3,461 Lease payments (1,633) (1,545) (1,687) (3,320) (3,112) Unrealized foreign exchange loss (gain) 2,863 3,114 (200) 2,663 4,801 Unrealized derivative instruments (gain) loss (45,896) (12,401) 77,328 31,432 (10,491) Other non-cash loss (gain) — 38 (728) (728) 90 Funds flow from operations (non-GAAP) $ 60,289 $ 53,906 $ 42,823 $ 103,112 $ 109,250 26 Additional Operational Results Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 % Change 2026 2026 2025 % Change Oil, natural gas and NGL sales $ 187,181 $ 149,357 25 $ 172,057 $ 359,238 $ 317,530 13 Operating expenses 51,561 55,602 (7) 66,149 117,710 122,692 (4) Transportation expenses 3,907 4,494 (13) 5,303 9,210 9,045 2 Operating netback(1) 131,713 89,261 48 100,605 232,318 185,793 25 Other taxes 1,389 577 141 1,041 2,430 1,058 130 DD&A expenses 62,334 68,635 (9) 69,874 132,208 140,837 (6) Derivative instruments (gain) loss (11,864) (14,032) (15) 88,410 76,546 (12,565) 709 G&A expenses before stock-based compensation 13,219 14,136 (6) 15,149 28,368 26,062 9 G&A stock-based compensation (recovery) expense (3,757) 546 (788) 19,676 15,919 29 54,793 Severance 95 — 100 2,468 2,563 — 100 Foreign exchange loss 2,603 3,716 (30) 1,425 4,028 7,554 (47) Interest expense 24,473 24,366 — 49,878 74,351 47,601 56 88,492 97,944 (10) 247,921 336,413 210,576 60 Other income 1,625 339 379 1,148 2,773 287 866 Interest income 503 251 100 401 904 676 34 Income (loss) before income taxes 45,349 (8,093) 660 (145,767) (100,418) (23,820) (322) Current income tax expense 9,115 2,195 315 5,850 14,965 10,460 43 Deferred income tax expense (recovery) 11,373 2,453 364 (32,445) (21,072) (2,259) (833) Total income tax expense (recovery) 20,488 4,648 341 (26,595) (6,107) 8,201 (174) Net income (loss) $ 24,861 $ (12,741) 295 $ (119,172) $ (94,311) $ (32,021) (195) Sales Volumes (NAR) Total sales volumes, BOEPD 32,166 38,331 (16) 40,267 36,195 38,676 (6) Brent Price per bbl $ 96.68 $ 66.71 45 $ 78.38 $ 87.60 $ 70.81 24 WTI Price per bbl $ 92.70 $ 63.81 45 $ 72.73 $ 82.77 $ 67.60 22 AECO Price C$ per GJ 1.55 1.60 (3) 1.91 1.73 1.82 (5) Consolidated Results of Operations per boe Sales Volumes NAR Oil, natural gas and NGL sales $ 63.95 $ 42.82 49 $ 47.48 $ 54.84 $ 45.36 21 Operating expenses 17.61 15.94 10 18.25 17.97 17.53 3 27 Transportation expenses 1.33 1.29 3 1.46 1.41 1.29 9 Operating netback(1) 45.01 25.59 76 27.77 35.46 26.54 34 Other taxes 0.47 0.17 187 0.29 0.37 0.15 147 DD&A expenses 21.29 19.68 8 19.28 20.18 20.12 — Derivative instruments (gain) loss (4.05) (4.02) (1) 24.40 11.68 (1.79) 751 G&A expenses before stock-based compensation 4.52 4.05 12 4.18 4.33 3.72 16 G&A stock-based compensation (recovery) expense (1.28) 0.16 (918) 5.43 2.43 — 100 Severance 0.03 — 100 0.68 0.39 — 100 Foreign exchange loss 0.89 1.07 (17) 0.39 0.61 1.08 (44) Interest expense 8.36 6.99 20 13.76 11.35 6.80 67 30.23 28.09 8 68.41 51.35 30.08 71 Other income 0.56 0.10 471 0.32 0.42 0.04 932 Interest income 0.17 0.07 139 0.11 0.14 0.10 43 Income (loss) before income taxes 15.51 (2.33) 766 (40.21) (15.33) (3.40) (351) Current income tax expense 3.11 0.63 395 1.61 2.28 1.49 53 Deferred income tax expense (recovery) 3.89 0.70 452 (8.95) (3.22) (0.32) (897) Total income tax expense (recovery) 7.00 1.33 426 (7.34) (0.94) 1.17 (180) Net income (loss) $ 8.51 $ (3.66) 333 $ (32.87) $ (14.39) $ (4.57) (215) (1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition of this measure. Oil, Natural Gas and NGL Production and Sales Volumes, BOEPD Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, Average Daily Volumes (BOEPD) - Colombia 2026 2025 2026 2026 2025 WI production before royalties 19,994 25,108 21,319 20,653 25,378 Royalties (3,968) (3,845) (3,230) (3,601) (4,131) Production NAR 16,026 21,263 18,089 17,052 21,247 (Increase) decrease in inventory (57) 110 799 369 (133) Sales 15,969 21,373 18,888 17,421 21,114 Royalties, % of working interest production before royalties 20 % 15 % 15 % 17 % 16 % 28 Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, Average Daily Volumes (BOEPD) - Ecuador 2026 2025 2026 2026 2025 WI production before royalties 7,993 4,592 8,759 8,373 4,315 Royalties (3,788) (1,364) (2,584) (3,189) (1,394) Production NAR 4,205 3,228 6,175 5,184 2,921 Decrease (increase) in inventory 233 (1,579) 1,727 976 (376) Sales 4,438 1,649 7,902 6,160 2,545 Royalties, % of working interest production before royalties 47 % 30 % 30 % 38 % 32 % Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, Average Daily Volumes (BOEPD) - Canada 2026 2025 2026 2026 2025 WI production before royalties 13,514 17,496 15,419 14,462 17,230 Royalties (1,755) (2,187) (1,942) (1,848) (2,213) Production NAR 11,759 15,309 13,477 12,614 15,017 Sales 11,759 15,309 13,477 12,614 15,017 Royalties, % of working interest production before royalties 13 % 13 % 13 % 13 % 13 % Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, Average Daily Volumes (BOEPD) - Total Company 2026 2025 2026 2026 2025 WI production before royalties 41,501 47,196 45,497 43,488 46,923 Royalties (9,511) (7,396) (7,756) (8,638) (7,738) Production NAR 31,990 39,800 37,741 34,850 39,185 Decrease (increase) in inventory 176 (1,469) 2,526 1,345 (509) Sales 32,166 38,331 40,267 36,195 38,676 Royalties, % of working interest production before royalties 23 % 16 % 17 % 20 % 16 % Oil, natural gas and NGL production NAR for the three and six months ended June 30, 2026, decreased by 20% and 11% to 31,990 BOEPD and 34,850 BOEPD, respectively, compared to the corresponding periods of 2025 due to lower production in Colombia, higher in-kind royalties driven by higher oil prices and the sale of Simonette area in Canada at the end of prior quarter, partially offset by higher than anticipated production results from Conejo-1 well in Charapa Block and additional production from Perico Block in Ecuador acquired in December 2025. Oil, natural gas and NGL production NAR decreased by 15% compared to the prior quarter primarily due to the sale of the Simonette area in Canada and lower production in the Acordionero and Cohembi fields in Colombia as a result of failure of artificial lift systems. Royalties as a percentage of production for the three and six months ended June 30, 2026 increased to 23% and 20%, respectively, compared to the corresponding periods of 2025 and the prior quarter as a result of higher benchmark oil prices and the price sensitive royalty regime in Colombia and Ecuador. 29 30 The Midas Block includes the Acordionero field, the Suroriente Block includes the Cohembi field, and the Chaza Block includes the Costayaco and Moqueta fields. Ecuador includes the Charapa, Iguana, Chanangue and Perico Blocks. Canada includes several areas in the Western Canadian Sedimentary Basin with the majority of production in Alberta, Canada. Commodity prices: Colombia and Ecuador Brent - For the three and six months ended June 30, 2026, Brent increased 45% and 24% from the corresponding periods of 2025 and increased 23% from the prior quarter. For the three months ended June 30, 2026, Castilla differential per bbl increased to $9.71 from $4.73 in the corresponding period of 2025. Vasconia and Oriente differentials per bbl decreased to $1.42 and $2.01 compared to $1.71 and $7.26, respectively, in the corresponding period of 2025. For the six months ended June 30, 2026, Castilla and Vasconia differentials per bbl increased to $9.69 and $3.65 from $5.04 and $1.99, respectively, in the corresponding period of 2025. Oriente differential per bbl decreased to $5.07 from $7.45 in the corresponding period of 2025. Castilla differential per bbl was comparable to the prior quarter and Vasconia and Oriente differentials per bbl decreased from $5.91 and $8.17 in the prior quarter. The differentials for South America fluctuate based on regional supply and demand of heavy crude, shipping costs, pipeline disruptions and geopolitical and trading policies. During the three and six months ended June 30, 2026 and 2025, 100% of sales from South America was priced against Brent. 31 Canada WTI - For the three and six months ended June 30, 2026, WTI increased by 45% and 22% from the corresponding periods of 2025 and increased 27% from the prior quarter. During the three and six months ended June 30, 2026, 22% and 23% of NAR production in Canada was oil, compared to 26% and 23% for the corresponding periods of 2025 and 25% in the prior quarter, respectively. NGLs - For the three and six months ended June 30, 2026, the weighted average NGL price received was 7% and 12% of WTI compared to 11% and 12% of WTI in the corresponding periods of 2025, respectively, and 10% of WTI in the prior quarter. During the three and six months ended June 30, 2026, NGLs production in Canada was 27% in each reporting period, and comparable to the corresponding periods of 2025 and the prior quarter. AECO - For the three and six months ended June 30, 2026, AECO price decreased by 3% and 5% from the corresponding periods of 2025 and decreased 19% from the prior quarter. During the three and six months ended June 30, 2026, 52% and 50% of production in Canada was natural gas, compared to 50% and 51%, in the corresponding periods of 2025, respectively, and 49% in the prior quarter. Oil, natural gas and NGL sales for the three and six months ended June 30, 2026, increased by 25% and 13% to $187.2 million and $359.2 million compared to the corresponding periods of 2025, primarily due to increases of 45% and 24% in Brent price, partially offset by 16% and 6% lower sales volumes in Colombia and Canada and higher quality and transportation discounts in Colombia. Quality and transportation discounts in Colombia were affected by using alternative transportation route for Putumayo production as Colombia and Ecuador border remained closed. The alternative transportation route was significantly more expensive and resulted in approximately $5.9 million and $10.0 million for the three and six months ended June 30, 2026. Compared to the prior quarter, oil, natural gas and NGL sales increased by 9%, primarily due to a 23% increase in Brent price and lower quality and transportation discounts in Colombia and premium in Ecuador, partially offset by a 20% decrease in sales volumes. During three months ended June 30, 2026, there was only one lifting in Ecuador compared to two in the prior quarter. 32 The following table shows the effect of changes in realized price and sale volumes on our oil, natural gas and NGL sales for the three and six months ended June 30, 2026, compared to the prior quarter and the corresponding periods of 2025: (Thousands of U.S. Dollars) Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025 Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026 Six Months Ended June 30, 2026, Compared with Six Months Ended June 30, 2025 Oil, natural gas and NGL sales for the comparative period $ 149,357 $ 172,057 $ 317,530 Realized sales price increase effect 61,840 48,208 62,076 Sales volumes decrease effect (24,016) (33,084) (20,368) Oil, natural gas and NGL sales for the three and six months ended June 30, 2026 $ 187,181 $ 187,181 $ 359,238 Gross Profit Colombia Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Revenue $ 118,136 $ 109,692 $ 102,324 $ 220,460 $ 227,340 Operating expenses 33,152 38,180 35,042 68,194 80,670 Transportation expenses 2,327 3,735 2,272 4,599 6,946 Depletion and accretion(*) 38,072 47,897 40,633 78,705 92,896 Gross profit $ 44,585 $ 19,880 $ 24,377 $ 68,962 $ 46,828 (*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $43.5 million and $50.5 million less depreciation of administrative assets of $5.5 million and $2.6 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $89.9 million and $99.1 million 33 less depreciation of administrative assets of $11.2 million and $6.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $46.4 million, less depreciation of administrative assets of $5.7 million. Colombia Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (U.S. Dollars per boe Sales NAR ) 2026 2025 2026 2026 2025 Revenue $ 81.29 $ 56.40 $ 60.19 $ 69.92 $ 59.49 Operating expenses 22.81 19.63 20.61 21.63 21.11 Transportation expenses 1.60 1.92 1.34 1.46 1.82 Depletion and accretion 26.20 24.63 23.90 24.96 24.31 Gross profit $ 30.68 $ 10.22 $ 14.34 $ 21.87 $ 12.25 Ecuador Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Revenue $ 41,964 $ 8,495 $ 40,745 $ 82,709 $ 29,518 Operating expenses 6,196 4,122 15,952 22,148 12,195 Transportation expenses 1,182 441 2,554 3,736 1,534 Depletion and accretion(*) 9,775 4,351 15,861 25,636 14,847 Gross profit (loss) $ 24,811 $ (419) $ 6,378 $ 31,189 $ 942 (*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $10.3 million and $4.4 million less depreciation of administrative assets of $0.6 million and nil, respectively. For the six months ended June 30, 2026 and 2025. DD&A expenses of $26.3 million and $14.8 million less depreciation of administrative assets of $0.7 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $16.0 million, less depreciation of administrative assets of $0.1 million. Ecuador Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (U.S. Dollars per boe Sales NAR ) 2026 2025 2026 2026 2025 Revenue $ 103.90 $ 56.64 $ 57.30 $ 74.18 $ 64.10 Operating expenses 15.34 27.48 22.43 19.86 26.48 Transportation expenses 2.93 2.94 3.59 3.35 3.33 Depletion and accretion 24.20 29.01 22.30 22.99 32.24 Gross profit (loss) $ 61.43 $ (2.79) $ 8.98 $ 27.98 $ 2.05 Canada Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Revenue $ 27,081 $ 31,170 $ 28,988 $ 56,069 $ 60,672 Operating expenses 12,213 13,300 15,155 27,368 29,827 Transportation expenses 398 318 477 875 565 Depletion and accretion(*) 8,406 13,700 7,414 15,820 26,636 Gross profit $ 6,064 $ 3,852 $ 5,942 $ 12,006 $ 3,644 (*) Same as DD&A expenses for the three months ended June 30, 2026 and 2025, six months ended June 30, 2026 and 2025, and the prior quarter (the depreciation of administrative assets had a de minimus amount for all reported periods). 34 Canada Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (U.S. Dollars per boe Sales NAR ) 2026 2025 2026 2026 2025 Revenue $ 25.31 $ 22.37 $ 23.90 $ 24.56 $ 22.32 Operating expenses 11.41 9.55 12.49 11.99 10.97 Transportation expenses 0.37 0.23 0.39 0.38 0.21 Depletion and accretion 7.86 9.83 6.11 6.93 9.80 Gross profit $ 5.67 $ 2.76 $ 4.91 $ 5.26 $ 1.34 Total Company Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Revenue $ 187,181 $ 149,357 $ 172,057 $ 359,238 $ 317,530 Operating expenses 51,561 55,602 66,149 117,710 122,692 Transportation expenses 3,907 4,494 5,303 9,210 9,045 Depletion and accretion(*) 56,253 65,948 63,908 120,161 134,379 Gross profit $ 75,460 $ 23,313 $ 36,697 $ 112,157 $ 51,414 (*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $62.3 million and $68.6 million less depreciation of administrative assets of $6.1 million and $2.7 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $132.2 million and $140.8 million less depreciation of administrative assets of $12.0 million and $6.5 million, respectively. For the prior quarter, calculated as DD&A expenses of $69.9 million, less depreciation of administrative assets of $6.0 million. Total Company Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (U.S. Dollars per boe Sales NAR ) 2026 2025 2026 2026 2025 Revenue $ 63.95 $ 42.82 $ 47.48 $ 54.84 $ 45.36 Operating expenses 17.61 15.94 18.25 17.97 17.53 Transportation expenses 1.33 1.29 1.46 1.41 1.29 Depletion and accretion 19.22 18.91 17.63 18.34 19.20 Gross profit $ 25.79 $ 6.68 $ 10.14 $ 17.12 $ 7.34 35 Operating Netback Colombia Three Months Ended June 30, Three Months Ended March 31 Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Oil, natural gas and NGL sales $ 118,136 $ 109,692 $ 102,324 $ 220,460 $ 227,340 Transportation expenses (2,327) (3,735) (2,272) (4,599) (6,946) 115,809 105,957 100,052 215,861 220,394 Operating expenses (33,152) (38,180) (35,042) (68,194) (80,670) Operating netback(1) $ 82,657 $ 67,777 $ 65,010 $ 147,667 $ 139,724 (U.S. Dollars Per boe Sales Volumes NAR) Brent $ 96.68 $ 66.71 $ 78.38 $ 87.60 $ 70.81 Quality and transportation discounts (15.39) (10.31) (18.19) (17.68) (11.32) Average realized price 81.29 56.40 60.19 69.92 59.49 Transportation expenses (1.60) (1.92) (1.34) (1.46) (1.82) Average realized price net of transportation expenses 79.69 54.48 58.85 68.46 57.67 Operating expenses (22.81) (19.63) (20.61) (21.63) (21.11) Operating netback(1) $ 56.88 $ 34.85 $ 38.24 $ 46.83 $ 36.56 Ecuador Three Months Ended June 30, Three Months Ended March 31 Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Oil, natural gas and NGL sales $ 41,964 $ 8,495 $ 40,745 $ 82,709 $ 29,518 Transportation expenses (1,182) (441) (2,554) (3,736) (1,534) 40,782 8,054 38,191 78,973 27,984 Operating expenses (6,196) (4,122) (15,952) (22,148) (12,195) Operating netback(1) $ 34,586 $ 3,932 $ 22,239 $ 56,825 $ 15,789 (U.S. Dollars Per boe Sales Volumes NAR) Brent (M-1 Pricing) $ 101.89 $ 66.91 $ 65.12 $ 83.65 $ 71.36 Quality and transportation premium (discounts) 2.01 (10.27) (7.82) (9.47) (7.26) Average realized price 103.90 56.64 57.30 74.18 64.10 Transportation expenses (2.93) (2.94) (3.59) (3.35) (3.33) Average realized price net of transportation expenses 100.97 53.70 53.71 70.83 60.77 Operating expenses (15.34) (27.48) (22.43) (19.86) (26.48) Operating netback(1) $ 85.63 $ 26.22 $ 31.28 $ 50.97 $ 34.29 36 Canada Three Months Ended June 30, Three Months Ended March 31 Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Oil, natural gas and NGL sales $ 27,081 $ 31,170 $ 28,988 $ 56,069 $ 60,672 Transportation expenses (398) (318) (477) (875) (565) 26,683 30,852 28,511 55,194 60,107 Operating expenses (12,213) (13,300) (15,155) (27,368) (29,827) Operating netback(1) $ 14,470 $ 17,552 $ 13,356 $ 27,826 $ 30,280 (U.S. Dollars Per boe Sales Volumes NAR) WTI Price per bbl $ 92.70 $ 63.81 $ 72.73 $ 82.77 $ 67.60 AECO Price C$ per GJ 1.55 1.60 1.91 1.73 1.82 Average realized price 25.31 22.37 23.90 24.56 22.32 Transportation expenses (0.37) (0.23) (0.39) (0.38) (0.21) Average realized price net of transportation expenses 24.94 22.14 23.51 24.18 22.11 Operating expenses (11.41) (9.55) (12.49) (11.99) (10.97) Operating netback(1) $ 13.53 $ 12.59 $ 11.02 $ 12.19 $ 11.14 Total Company Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Oil, natural gas and NGL sales $ 187,181 $ 149,357 $ 172,057 $ 359,238 $ 317,530 Transportation expenses (3,907) (4,494) (5,303) (9,210) (9,045) 183,274 144,863 166,754 350,028 308,485 Operating expenses (51,561) (55,602) (66,149) (117,710) (122,692) Operating netback(1) $ 131,713 $ 89,261 $ 100,605 $ 232,318 $ 185,793 (U.S. Dollars Per boe Sales Volumes NAR) Average realized price $ 63.95 $ 42.82 47.48 $ 54.84 $ 45.36 Transportation expenses (1.33) (1.29) (1.46) (1.41) (1.29) Average realized price net of transportation expenses 62.62 41.53 46.02 53.43 44.07 Operating expenses (17.61) (15.94) (18.25) (17.97) (17.53) Operating netback(1) $ 45.01 $ 25.59 $ 27.77 $ 35.46 $ 26.54 (1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition and reconciliation of this measure. 37 38 Operating expenses for the three and six months ended June 30, 2026, decreased by 7% and 4% to $51.6 million and $117.7 million, respectively, compared to the corresponding periods of 2025. The decrease was primarily due to lower workover activities, reduced field personnel costs, lower oil treatment and testing service costs, as well as inventory fluctuations resulting from inventory accumulation at the end of the current quarter. Operating expenses for the three and six months ended June 30, 2026, on a per boe basis, increased by $1.67 and $0.44 to $17.61 and $17.97, respectively, compared to the corresponding periods of 2025, primarily due to lower sales volumes during current periods, partially offset by $0.18 and $0.68 per boe lower workover activities and inventory fluctuations, respectively. 39 Compared to the prior quarter, operating expenses decreased by 22% from $66.1 million or by $0.64 from $18.25 on a per boe basis primarily due to inventory fluctuations resulting from inventory accumulation at the end of the current quarter, partially offset by $0.34 per boe higher workover activities. Transportation expenses We have options to sell our oil through multiple pipelines and various trucking routes. Each option has varying effects on realized sales price and transportation expenses. The following table shows the percentage of oil, natural gas and NGL volumes we sold in Canada, Colombia and Ecuador using each option for the three and six months ended June 30, 2026 and 2025, and the prior quarter: Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, 2026 2025 2026 2026 2025 Volume transported through pipeline 50 % 40 % 54 % 52 % 33 % Volume sold at wellhead 26 % 40 % 24 % 25 % 31 % Volume transported via truck to sales point 24 % 20 % 22 % 23 % 36 % 100 % 100 % 100 % 100 % 100 % Volumes transported through pipeline or via truck receive a higher realized price but incur higher transportation expenses. Conversely, volumes sold at the wellhead have the opposite effect of a lower realized price, offset by lower transportation expenses. Transportation expenses for the three months ended June 30, 2026, decreased by 13% to $3.9 million, compared to the corresponding period of 2025, due to lower sales volumes transported in Colombia and Canada and increased by $0.04 per boe due to lower sales volumes. Transportation expenses for the six months ended June 30, 2026, increased by 2% or $0.12 per boe due to higher volumes transported via pipeline which had a higher cost per boe. Transportation expenses decreased by 26% or $0.13 per boe from $5.3 million or $1.46 per boe in the prior quarter due to lower sales volumes transported during the current quarter. 40 Colombia Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025 Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026 Six Months Ended June 30, 2026, Compared with Six Months Ended June 30, 2025 (U.S. Dollars per boe Sales Volumes NAR) Average Brent price $ 96.68 $ 96.68 $ 87.60 Average realized price, net of transportation expenses for the comparative period $ 54.48 $ 58.85 $ 57.67 Increase in benchmark oil prices 29.97 18.30 16.79 (Increase) decrease in quality and transportation discounts (5.08) 2.80 (6.36) Decrease (increase) in transportation expense 0.32 (0.26) 0.36 Average realized price, net of transportation expenses for the period $ 79.69 $ 79.69 $ 68.46 Average realized price, net of transportation expenses as a % of Brent 82 % 82 % 78 % Ecuador Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025 Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026 Six Months Ended June 30, 2026, Compared with Six Months Ended June 30, 2025 (U.S. Dollars per boe Sales Volumes NAR) Average Brent price (M-1 Pricing)(*) $ 101.89 $ 101.89 $ 83.65 Average realized price, net of transportation expenses for the comparative period $ 53.70 $ 53.71 $ 60.77 Increase in benchmark prices 34.98 36.77 12.29 Decrease (increase) in quality and transportation discounts 12.28 9.83 (2.21) Decrease (increase) in transportation expense 0.01 0.66 (0.02) Average realized price, net of transportation expenses for the period $ 100.97 $ 100.97 $ 70.83 Average realized price, net of transportation expenses as a % of Brent 99 % 99 % 85 % (*)The sales price in Ecuador is the average Brent price less discounts for the month prior to lifting (M-1). 41 Canada Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025 Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026 Six Months Ended June 30, 2026, Compared with Six Months Ended June 30, 2025 (U.S. Dollars per boe Sales Volumes NAR) Average WTI price $ 92.70 $ 92.70 $ 82.77 Average AECO price $ 1.55 $ 1.55 $ 1.73 Average realized price, net of transportation expenses for the comparative period $ 22.14 $ 23.51 $ 22.11 Increase in benchmark prices 28.89 19.97 15.17 Increase in quality and transportation discounts (25.95) (18.56) (12.93) (Increase) decrease in transportation expense (0.14) 0.02 (0.17) Average realized price, net of transportation expenses for the period $ 24.94 $ 24.94 $ 24.18 Average realized price, net of transportation expenses as a % of WTI 27 % 27 % 29 % Total Company Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025 Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026 Six Months Ended June 30, 2026, Compared with Six Months Ended June 30, 2025 (U.S. Dollars per boe Sales Volumes NAR) Average Brent price $ 96.68 $ 96.68 $ 87.60 Average realized price, net of transportation expenses for the comparative period $ 41.53 $ 46.02 $ 44.07 Increase in benchmark prices 29.97 18.30 16.79 Increase in quality and transportation discounts (8.84) (1.83) (7.31) (Increase) decrease in transportation expense (0.04) 0.13 (0.12) Average realized price, net of transportation expenses for the period $ 62.62 $ 62.62 $ 53.43 Average realized price, net of transportation expenses as a % of Brent 65 % 65 % 61 % DD&A Expenses Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, 2026 2025 2026 2026 2025 DD&A Expenses, thousands of U.S. Dollars $ 62,334 $ 68,635 $ 69,874 $ 132,208 $ 140,837 DD&A Expenses, U.S. Dollars per boe 21.29 19.68 19.28 20.18 20.12 42 Three Months Ended June 30, 2026 Three Months Ended March 31, 2026 Six Months Ended June 30, 2026 DD&A expenses, thousands of U.S. Dollars DD&A expenses, U.S. Dollars Per Boe DD&A expenses, thousands of U.S. Dollars DD&A expenses, U.S. Dollars Per Boe DD&A expenses, thousands of U.S. Dollars DD&A expenses, U.S. Dollars Per Boe Colombia $ 43,479 $ 29.92 $ 46,378 $ 27.28 $ 89,857 $ 28.50 Ecuador 10,334 25.59 15,964 22.45 26,298 23.59 Canada 8,411 7.86 7,419 6.12 15,830 6.93 Corporate 110 — 113 — 223 — $ 62,334 $ 21.29 $ 69,874 $ 19.28 $ 132,208 $ 20.18 Three Months Ended June 30, 2025 Three Months Ended March 31, 2025 Six Months Ended June 30, 2025 DD&A expenses, thousands of U.S. Dollars DD&A expenses, U.S. Dollars Per Boe DD&A expenses, thousands of U.S. Dollars DD&A expenses, U.S. Dollars Per Boe DD&A expenses, thousands of U.S. Dollars DD&A expenses, U.S. Dollars Per Boe Colombia $ 50,454 $ 25.94 $ 48,651 $ 25.92 $ 99,105 $ 25.93 Ecuador 4,351 29.01 10,498 33.81 14,849 32.25 Canada 13,705 9.84 12,941 9.77 26,646 9.80 Corporate 125 — 112 — 237 — $ 68,635 $ 19.68 $ 72,202 $ 20.56 $ 140,837 $ 20.12 DD&A expenses for the three and six months ended June 30, 2026, decreased by 9% and 6%, respectively, due to lower costs in the depletable base for Canadian operations as a result of Simonette and Lodgepole areas disposition and higher proved reserves across reportable segments compared to the corresponding periods of 2025. On a per boe basis, DD&A expenses for the three and six months ended June 30, 2026, increased by $1.61 and $0.06, respectively, due to the lower sales volumes in the current periods. DD&A expenses decreased by 11% from $69.9 million and increased by $2.01 on a per boe basis when compared to the prior quarter for the same reason mentioned above. Asset Impairment For the three and six months ended June 30, 2026 and 2025, we had no ceiling test impairment losses. We used a 12-month unweighted average of the first-day-of-the-month prices prior to the ending date of the period ended June 30, 2026 as follows: Brent Crude $78.55 per bbl, Edmonton Light Crude of C$98.28 per bbl, Alberta AECO spot price of C$1.55 per MMBtu, Edmonton Propane C$32.84 per boe, Edmonton Butane C$41.70 per boe and Edmonton Condensate C$100.06 per boe (June 30, 2025: Brent Crude of $73.60 per bbl, Edmonton Light Crude of C$91.55 per bbl, Alberta AECO spot price of C$1.69 per MMBtu Edmonton Propane C$33.82 per boe, Edmonton Butane C$47.11 per boe and Edmonton Condensate C$95.75 per boe). 43 G&A Expenses Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 % Change 2026 2026 2025 % Change G&A Expenses before Stock-Based Compensation $ 13,219 $ 14,136 (6) $ 15,149 $ 28,368 $ 26,062 9 G&A Stock-Based Compensation (Recovery) Expense (3,757) 546 (788) 19,676 15,919 29 54,793 G&A Expenses, including Stock-Based Compensation $ 9,462 $ 14,682 (36) $ 34,825 $ 44,287 $ 26,091 70 (U.S. Dollars Per boe Sales Volumes NAR) G&A Expenses before Stock-Based Compensation $ 4.52 $ 4.05 12 $ 4.18 $ 4.33 $ 3.72 16 G&A Stock-Based Compensation (Recovery) Expense (1.28) 0.16 (918) 5.43 2.43 — 100 G&A Expenses, including Stock-Based Compensation $ 3.24 $ 4.21 (23) $ 9.61 $ 6.76 $ 3.72 82 G&A expenses before stock-based compensation for the three months ended June 30, 2026, decreased by 6% to $13.2 million compared to the corresponding period of 2025, primarily due to lower consulting and information technology costs during the current period. G&A expenses before stock-based compensation for the six months ended June 30, 2026, increased by 9% to $28.4 million, compared to the corresponding period of 2025, primarily due to higher costs associated with project optimization. On a per boe basis, G&A expenses before stock-based compensation for the three and six months ended June 30, 2026 increased by $0.47 and $0.61 to $4.52 and $4.33, compared to the corresponding period of 2025 primarily due to 16% and 6% lower sales volumes, respectively. Compared to the prior quarter, G&A expenses before stock-based compensation decreased by 13% due to lower consulting, information technology costs and lower salaries associated with headcount optimization. On a per boe basis, G&A expenses before stock-based compensation increased by $0.34 compared to the prior quarter due to 20% decrease in sales volumes. G&A expenses after stock-based compensation for the three months ended June 30, 2026, decreased by 36% or $0.97 per boe compared to the corresponding period of 2025 due to lower share price resulting in stock-based compensation recovery. G&A expenses after stock-based compensation for the six months ended June 30, 2026, increased by 70% or $3.04 per boe compared to the corresponding period of 2025, due to higher stock-based compensation cost attributed to a higher share price during the current period. Compared to the prior quarter, G&A expenses after stock-based compensation decreased by 73% or $6.37 per boe due to lower share price resulting in stock-based compensation recovery. 44 Severance Expenses For the three and six months ended June 30, 2026, severance expenses were $0.1 million and $2.6 million, compared to nil for each of the corresponding periods of 2025 and $2.5 million for the prior quarter, respectively, due to headcount optimization. Foreign Exchange Gains and Losses For the three and six months ended June 30, 2026, we had foreign exchange losses of $2.6 million and $4.0 million, compared to $3.7 million and $7.6 million losses on foreign exchange in the corresponding periods of 2025, respectively, and a $1.4 million loss on foreign exchange in the prior quarter. Accounts payable, taxes receivable and payable and deferred income taxes are considered monetary items and require translation from local currencies to U.S. dollar functional currency at each balance sheet date. This translation was the primary source of the foreign exchange gains and losses in the periods. 45 The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the three and six months ended June 30, 2026 and 2025 and the prior quarter: Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, 2026 2025 2026 2026 2025 Change in the U.S. dollar against the Colombian peso weakened by weakened by weakened by weakened by weakened by 6% 3% 2% 8% 8% Change in the U.S. dollar against the Canadian dollar strengthened by weakened by strengthened by strengthened by weakened by 2% 5% 1% 3% 5% Financial Instruments Gains or Losses The following table presents the nature of our financial instruments gains or losses for the three and six months ended June 30, 2026 and 2025, and the prior quarter: Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2026 2025 Commodity price derivative (gain) loss $ (9,266) $ (6,802) $ 88,618 $ 79,352 $ (5,335) Foreign currency derivative gain (2,598) (7,230) (208) (2,806) (7,230) Derivative instruments (gain) loss $ (11,864) $ (14,032) $ 88,410 $ 76,546 $ (12,565) 46 Income Tax Expense Three Months Ended June 30, Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2025 Income (loss) before income tax $ 45,349 $ (8,093) $ (100,418) $ (23,820) Current income tax expense $ 9,115 $ 2,195 $ 14,965 $ 10,460 Deferred income tax expense (recovery) 11,373 2,453 (21,072) (2,259) Income tax expense (recovery) $ 20,488 $ 4,648 $ (6,107) $ 8,201 Effective tax rate 45 % (57) % 6 % (34) % Current income tax expense was $15.0 million for the six months ended June 30, 2026, compared to $10.5 million in the corresponding period of 2025, primarily due to higher taxable income. The deferred tax for the six months ended June 30, 2026, was a recovery of $21.1 million mainly due to an increase in deductible temporary differences arising from tax losses generated during the period, unrealized hedging losses and accruals. These were partially offset by higher tax depreciation relative to accounting depreciation. The deferred income tax for the six months ended June 30, 2025, was a recovery of $2.3 million primarily attributable to an increase in deductible temporary differences arising from tax losses generated during the period. This recovery was partially offset by temporary differences related to accelerated tax depreciation in excess of accounting depreciation. For the six months ended June 30, 2026, the difference between the effective tax rate of 6% and the 21% statutory tax rate was primarily due to an increase in the non-deductible foreign translation adjustments and other non-deductible expenses. This was partially offset by an increase in the impact of foreign taxes and the 2025 true-up (recovery). For the six months ended June 30, 2025, the difference between the effective tax rate of negative 34% and the 21% statutory tax rate was primarily due to an increase in the non-deductible foreign translation adjustments, other permanent differences and valuation allowance. This was partially offset by an increase in the impact of foreign taxes. Net (Loss) Income and Funds Flow from Operations (a Non-GAAP Measure) (Thousands of U.S. Dollars) Three Months Ended June 30, 2026, Compared with Three Months Ended March 31, 2026 % change Three Months Ended June 30, 2026, Compared with Three Months Ended June 30, 2025 % change Six Months Ended June 30, 2026 Compared with Six Months Ended June 30, 2025 % change Net loss for the comparative period $ (119,172) $ (12,741) $ (32,021) Increase (decrease) due to: Sales price 48,208 61,840 62,076 Sales volumes (33,084) (24,016) (20,368) Expenses: Cash operating expenses 14,588 4,041 4,982 Transportation 1,396 587 (165) Other taxes (348) (812) (1,372) Cash G&A, excluding stock-based compensation expense 1,930 917 (2,306) Net lease payments 89 (310) (698) Severance 2,373 (95) (2,563) Interest, excluding amortization of deferred financing fees 5,337 4,452 2,685 Realized foreign exchange loss 1,885 862 1,388 Other gain 1,205 1,248 1,668 47 Cash settlement on derivative instruments (22,950) (35,663) (47,188) Current taxes (3,265) (6,920) (4,505) Interest income 102 252 228 Net change in funds flow from operations(1) from comparative period 17,466 6,383 (6,138) Expenses: Depletion, depreciation and accretion 7,540 6,301 8,629 Asset impairment — — Deferred tax (43,818) (8,920) 18,813 Amortization of debt issuance costs 9,571 2,360 (5,100) Stock-based compensation 23,433 4,303 (15,890) Senior Notes exchange fees 12,118 (785) (13,688) Non-cash interest (1,621) (6,134) (10,647) Financial instruments loss, net of financial instruments settlements 123,224 33,495 (41,923) Unrealized foreign exchange (loss) gain (3,063) 251 2,138 Other non-cash (loss) gain (728) 38 818 Net lease payments (89) 310 698 Net change in net loss 144,033 37,602 (62,290) Net income (loss) for the current period $ 24,861 121% $ 24,861 295% $ (94,311) (195)% (1) Funds flow from operations is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in "Financial and Operational Highlights" for a definition and reconciliation of this measure. Capital expenditures during the three months ended June 30, 2026, were $54.3 million. (Millions of U.S. Dollars) Colombia Ecuador Canada Total Exploration $ 2.8 $ — $ — $ 2.8 Development $ 41.3 $ 6.0 $ 4.2 $ 51.5 Total Company $ 44.1 $ 6.0 $ 4.2 $ 54.3 During the three months ended June 30, 2026, we drilled the following wells: Number of wells (Gross) Number of wells (Net) Development - Colombia 1 0.5 Total Company 1 0.5 During the three months ended June 30, 2026, we spud one development well in Cohembi field in Colombia which was producing as of June 30, 2026. 48 Liquidity and Capital Resources As at (Thousands of U.S. Dollars) June 30, 2026 % Change December 31, 2025 Cash and Cash Equivalents $ 126,728 53 $ 82,931 7.75% Senior Notes due 2027 $ 24,201 — $ 24,201 9.50% Senior Notes due 2029 $ 87,639 (88) $ 716,340 9.75% Senior Notes due 2031 $ 494,353 100 $ — We believe that our capital resources, including cash on hand and cash generated from operations will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for the next 12 months, given the current oil price trends and production levels. We may also access capital markets to pursue financing, including for the re-purchase of common stock or the repayment of debt in the future. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us with the flexibility to respond to both internal growth opportunities and those available through acquisitions. We intend to pursue growth opportunities and acquisitions from time to time, which may require significant capital to be located in basins or countries beyond our current operations, involve joint ventures, or be sizable compared to our current assets and operations. Senior Notes During the six months ended June 30, 2026, we issued $503.6 million in aggregate principal amount of our 9.75% Senior Secured Amortizing Notes due 2031 (the “9.75% Senior Notes”), and paid $125.0 million in cash consideration in exchange for $628.7 million aggregate principal amount of our 9.50% Senior Secured Amortizing Notes due 2029 (the “9.50% Senior Notes”). The exchange was accounted for as debt modification. The 9.75% Senior Notes will mature on April 15, 2031, unless earlier redeemed or re-purchased. The principal amount of 9.75% Senior Notes is to be repaid as follows: (i) October 15, 2029 - 15% of the principal amount; (ii) October 15, 2030 - 15% of the principal amount; (iii) April 15, 2031 - the remainder of the principal amount. On or before December 31, 2026 (“the Offer Date”), we are required to offer to purchase up to $30.0 million aggregate principal amount of the 9.75% Senior Notes (“the Offer Amount”). The Offer Amount will be reduced by the aggregate principal amount of any 9.75% Senior Notes redeemed or re-purchased by us in the open market transactions before the Offer Date. During the six months ended June 30, 2026, we re-purchased $9.2 million of 9.75% Senior Notes for cash consideration of $8.1 million resulting in a $0.6 million gain on purchase, which included the write-off of deferred financing fees of $0.5 million. Subsequent to the quarter, we re-purchased an additional $15.0 million of 9.75% Senior Notes for cash consideration of $13.5 million. At any time, prior to April 15, 2028, we may redeem up to 35% of the aggregate principal amount of 9.75% Senior Notes at a redemption price equal to 109.75% of the principal amount. Additionally, we may redeem all or a portion of the 9.75% Senior Notes on or after 2028 at the following redemption prices: 2028 - 104.875%; 2029 - 102.438%; 2030 and thereafter - 100%. Under the terms of the 9.75% Senior Notes agreement, we are required to maintain compliance with the following financial covenants: i.consolidated interest coverage ratio of not less than 2.50; and ii.consolidated net debt (total debt excluding deferred financing fees less cash equivalents) to consolidated adjusted earnings before interest, taxes and DD&A (“EBITDA”) of not more than 3.00. As at June 30, 2026, we were in compliance with all applicable covenants related to Senior Notes. 49 Credit Facility On May 12, 2026, we, through our wholly owned subsidiary Gran Tierra Canada Ltd., amended our revolving credit facility with National Bank of Canada. As part of the amendment, the borrowing base has decreased to C$75.0 million (US$52.8 million). The available commitment under the revolving credit facility remained unchanged of a C$75.0 million (US$52.8 million), comprised of C$60.0 million (US$42.3 million) syndicated facility and C$15.0 million (US$10.6 million) of operating facility. The drawn down amounts under the revolving credit facility can either be in Canadian or U.S. dollars and bear interest rates equal to either the Canadian prime rate or U.S. Base Rate plus a margin ranging from 2.00% to 4.00% per annum or for CORRA loans and SOFR loans plus a margin ranging from 3.00% to 5.00% per annum. Undrawn amounts under the revolving credit facility bear standby fee ranging from 0.75% to 1.25% per annum. In each case, the margin or standby fee, as applicable is based on Net Debt to EBITDA ratio of Gran Tierra Canada Ltd. The revolving credit facility matures on October 30, 2027. As of June 30, 2026, the revolving credit facility remained undrawn. Prepayment agreements During the six months ended June 30, 2026, we amended our existing prepayment agreement with Trafigura, entering into a new oil prepayment agreement that covers both our Ecuadorian and Colombian oil production. The amended agreement provides for total prepayments of up to $350.0 million, including $325.0 million available immediately and an additional $25.0 million available at Trafigura’s sole discretion. The term of the amended prepayment agreement is 48 months. Amounts drawn on this prepayment agreement are to be repaid through future oil deliveries. Shortfalls in crude oil deliveries in any given repayment period can be delivered during the next repayment period within three calendar months or paid in cash thereafter. Amounts under the prepayment facility are subject to interest based on SOFR risk-free rate plus a margin of 4.45% per annum. Under the terms of the prepayment agreement, we can repay the outstanding balance of the advance payment at any time without penalty. We were granted a grace period for re-payment of the principal amount drawn under the prepayment agreement with first re-payment starting April 2026. Pursuant to the amended and restated prepayment agreement, proceeds from the new advance are required to be used exclusively to finance the repurchase or exchange of Senior Notes and to pay fees and expenses associated with the amended agreement. We are required to maintain compliance with the following financial covenants related to amounts drawn under the prepayment agreement semi-annually, calculated on March 31 and September 30 of each year: i.Asset Coverage Ratio of at least 150%, calculated using the net present value of the consolidated future cash flows of certain wholly owned subsidiaries of the Company that sell crude oil, projected through the final maturity date and discounted at 10% over the outstanding principal and the interest payable amount on the prepayment agreement at each reporting period. The net present value of the consolidated future cash flows of the Company is required to be based on 90% of the prevailing ICE Brent forward strip. ii.Debt Service Coverage Ratio of at least 200%, calculated using the estimated crude oil to be delivered by the Company from any relevant time up to the final maturity date based on 80% of the prevailing ICE Brent forward strip and adjusted for quality differential and transportation discount over the outstanding principal amount under the prepayment agreement. During the three and six months ended June 30, 2026, we drew nil and $166.5 million on oil prepayment and re-paid $28.8 million of the outstanding principal on oil prepayment via crude oil deliveries. As at June 30, 2026, there was $287.7 million outstanding (December 31, 2025 - $150.0 million) on the oil prepayment agreement. Of this amount, $86.3 million (December 31, 2025 - $34.1 million) was classified as a current portion and included in accounts payable and accrued liabilities on our condensed consolidated balance sheet. Assets exchange transaction During the three months ended June 30, 2026, we completed an asset exchange transaction in which we transferred a 30% WI in certain oil and natural gas rights, wells, and tangible assets located in the Marten Hills area, in exchange for oil and natural gas rights, wells, and tangible assets in the Seal/Dawson area, WI ranging from 35% to 100%. In connection with this transaction, we received cash consideration of C$0.8 million (US$0.6 million). 50 Disposition of Lodgepole area During the three months ended June 30, 2026, we completed a disposition of 54% WI and associated title rights in the Lodgepole area in Canada effective January 1, 2026, for a total cash consideration of C$12.8 million (US$9.3 million). As part of disposition, we derecognized asset retirement obligation attributed to Lodgepole area totaling C$17.5 million (US$12.8 million) on an undiscounted basis and C$9.0 million (US$6.6 million) on a discounted basis. No gain or loss was recognized in the statement of operations as the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets. Disposition of Simonette area During the six months ended June 30, 2026, we disposed of the entire working interest and associated title rights in the Simonette Montney area in Canada effective January 1, 2026, for total cash consideration of C$66.3 million (US$48.6 million). No gain or loss was recognized in the statement of operations because the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets. Partnership with Ecopetrol S.A. During the six months ended June 30, 2026, we entered into a strategic partnership with Ecopetrol S.A. to earn, subject to regulatory approvals and conditions precedent, a 49% WI in the Tisquirama Block in Colombia. Under the terms of the agreement, we have committed to fund approximately $47.1 million of a $92.4 million gross capital program over 40 months, including a minimum Phase 1 investment of $15.0 million. Upon completion of Phase 1, we will be entitled to 49% of production and are expected to assume operatorship. On May 27, 2026, we satisfied all outstanding conditions precedent to the partnership agreement and received regulatory approval. Production sharing agreement (“PSA”) During the six months ended June 30, 2026, we, through our wholly owned subsidiary, Gran Tierra Energy (Azerbaijan) GmbH, entered into an exploration, development and PSA with the State Oil Company of Azerbaijan Republic (“SOCAR”), providing for a 65% participating interest to us and a 35% participating interest to SOCAR. The PSA provides for a five-year exploration phase and, in the event of a commercial crude oil discovery, a 25-year development phase, with minimum work commitments during the exploration period to be completed within 36 months. These commitments include, among others, the acquisition of 250 square kilometers of 3D seismic data, the drilling of two exploration wells, and the conduct of geological and environmental impact studies. We have the right to relinquish the entire contract area during the exploration phase upon fulfillment of our exploration commitments, subject to 90 days’ prior notice to SOCAR. Derivative positions As at June 30, 2026, we had outstanding commodity price derivative positions as follows: Oil Type of Instrument Start Period End Period Volume bbl/d Reference Sold Put (C$/bbl or $/bbl Weighted Average) Purchased Put (C$/bbl or $/bbl Weighted Average) Sold Call (C$/bbl or $/bbl Weighted Average) Premium (C$/bbl or $/bbl Weighted Average) Collar 07/01/26 09/30/26 500 WTI CMA — C$ 75.00 C$ 91.95 — Put Option 07/01/26 09/30/26 500 Brent — 60.00 — 4.30 Put Spread 07/01/26 09/30/26 5,000 Brent 45.00 55.00 — 21.64 Three Way 07/01/26 09/30/26 1,000 WTI CMA C$ 62.50 C$ 72.50 C$ 103.70 C$ 0.95 Three Way 07/01/26 09/30/26 9,000 Brent 50.89 60.89 73.23 — Collar 10/01/26 12/31/26 500 WTI CMA — C$ 70.00 C$ 92.47 — Put Option 10/01/26 12/31/26 500 Brent — 60.00 — 4.30 Three Way 10/01/26 12/31/26 500 WTI CMA C$ 60.00 C$ 70.00 C$ 107.00 C$ 1.90 Put Spread 10/01/26 12/31/26 5,000 Brent 45.00 55.00 — 21.64 51 Three Way 10/01/26 12/31/26 9,000 Brent 50.33 60.33 72.49 — Three Way 01/01/27 03/31/27 3,000 Brent 58.33 71.67 89.55 — Natural Gas Type of Instrument Start Period End Period Volume, GJ/day Reference Sold Swap (C$/GJ, Weighted Average) Purchased Put (C$/GJ, Weighted Average) Sold Call (C$/GJ, Weighted Average) Swap 07/01/26 09/30/26 20,000 Aeco 5A C$ 2.71 — — Swap 10/01/26 12/31/26 6,739 Aeco 5A C$ 2.71 — — As at June 30, 2026, we had the following outstanding foreign currency exchange derivative positions: Period and Type of Instrument U.S. Dollars Amount Hedged (Thousands of U.S. Dollars) COP Equivalent of Amount Hedged (Millions of COP)(1) Reference Floor Price (COP, Weighted Average) Cap Price (COP, Weighted Average) Collars: July 2026, to March 2027 9,000 30,996 COP 3,790 4,080 Collars: July 2026, to May 2027 32,000 110,208 COP 3,767 4,050 (1) At the June 30, 2026 foreign exchange rate. Cash Flows The following table presents our primary sources and uses of cash and cash equivalents and restricted cash and cash equivalents for the periods presented: Six Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 Sources of cash and cash equivalents: Net loss $ (94,311) $ (32,021) Adjustments to reconcile net loss to Adjusted EBITDA(1) and funds flow from operations(1) DD&A expenses 132,208 140,837 Interest expense 74,351 47,601 Severance 2,563 — Income tax (recovery) expense (6,107) 8,201 Non-cash lease expenses 2,971 3,461 Lease payments (3,320) (3,112) Foreign exchange loss 4,028 7,554 Stock-based compensation expense 15,919 29 Financial instruments loss (gain) 31,432 (10,491) Other (gain) loss (728) 90 Adjusted EBITDA(1) 159,006 162,149 Severance (2,563) — Current income tax expense (14,965) (10,460) Contractual interest and other financing expenses (37,001) (39,686) Realized foreign exchange loss (1,365) (2,753) Funds flow from operations(1) 103,112 109,250 Proceeds from debt, net of issuance costs — 44,781 Proceeds from exercise of stock options 748 22 Proceeds from disposition of property, plant and equipment 57,944 — 52 Proceeds from assets exchange 583 — Net changes in assets and liabilities from operating activities 142,234 1,702 304,621 155,755 Uses of cash and cash equivalents: Additions to property, plant and equipment (102,517) (153,971) Repayment of long-term debt — (1,894) Re-purchase of Senior Notes (8,087) (1,712) Senior Notes exchange fees (13,688) — Repayment of Senior Notes (125,000) (24,828) Re-purchase of shares of Common Stock — (3,466) Settlement of asset retirement obligations (1,510) (3,045) Lease payments (8,347) (7,849) Foreign exchange loss on cash, and cash equivalents and restricted cash and cash equivalents (297) (766) (259,446) (197,531) Net increase (decrease) in cash and cash equivalents and restricted cash and cash equivalents $ 45,175 $ (41,776) (1) Adjusted EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition and reconciliation of this measure. One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices. Sales volume changes, costs related to operations and debt transactions also impact cash flows. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes. During the three months ended June 30, 2026, funds flow from operations increased by 12% compared to the corresponding period of 2025, due to an increase in benchmark oil prices, lower operating expenses, partially offset by lower sales volumes, higher cash settlements on derivative instruments and higher current income tax expense. During the six months ended June 30, 2026, funds flow from operations decreased by 6% compared to the corresponding period of 2025, primarily due to lower sales volumes, higher cash settlements on derivative instruments and higher current income tax expense, partially offset by an increase in benchmark oil prices and lower operating expenses. Critical Accounting Policies and Estimates Our critical accounting policies and estimates are disclosed in Item 7 of our 2025 Annual Report on Form 10-K and have not changed materially since the filing of that document.