GRAN TIERRA ENERGY INC.
For the period ended Mar 31, 2026. Filed May 8, 2026.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2026 · Filed May 8, 2026
GTE$9.42+0.3%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-09-30; filed 2025-10-31.
0001273441-25-000033
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-05-08.
0001273441-26-000015
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 117 previous paragraphs and 129 current paragraphs.
26 unchanged; 43 reworded; 58 added; 48 removed; 0 previous and 2 current paragraphs rearranged.
Tables are not compared: 37 previous and 47 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (58)
Current report
•NAR production for the first quarter of 2026 decreased by 2% to 37,741 BOEPD, compared to 38,563 BOEPD in the first quarter of 2025, and decreased by 4% from 39,464 BOEPD in the prior quarter
Current report
•Oil, natural gas and NGL sales for the first quarter of 2026 increased by 2% to $172.1 million, compared to the first quarter of 2025, due to higher sales volumes driven by selling production from the newly acquired Perico Block in Ecuador and increase in Brent price, offset by higher quality and transportation discounts in Colombia. Higher quality and transportation discounts incurred due to using alternative transportation route associated with Putumayo production which was significantly more expensive and resulted in approximately $4.1 million for the current quarter. Oil, natural gas and NGL sales increased by 32% from $129.9 million in the prior quarter due to higher oil prices, and increase in sales volumes, partially offset by higher differentials. During the first quarter, we had two liftings in Ecuador compared to one in the prior quarter. The sales price in Ecuador is the average Brent price less discounts for the month prior to lifting (M-1). During the current quarter, we sold our January 2026 production in Ecuador at the average Brent price of December 2025 and March production at the average Brent price of February 2026
Current report
•Operating expenses decreased by 1% or $0.85 per boe to $66.1 million or $18.25 per boe when compared to the first quarter of 2025, due to lower workover activities, lower power generation and field personnel costs associated with head-count optimization partially offset by inventory fluctuations due to the sale of oil inventory accumulated at the end of the previous quarter. Operating expenses increasedby 16% or by$0.98 per boefrom$57.2 million or $17.27 per boe in the prior quarter primarily a result of inventory fluctuations due to the sale of oil inventory accumulated at the end of the previous quarter partially offset by lower workover activities and lower operating costs across various categories
Current report
•Transportation expenses increased by 17% when compared to the first quarter of 2025 and increased by 44% compared to the prior quarter primarily due to higher sales volumes transported in Ecuador during the current quarter
Current report
•Gross profit increased to $36.7 million compared to $28.1 million in first quarter of 2025 and $0.9 million in the prior quarter
Current report
•Operating netback(2)was $100.6 million compared to $96.5 million in the first quarter of 2025 and $69.1 million in the prior quarter
Current report
•Quality and transportation discounts per boe in South America increased for the first quarter of 2026 to $19.04 compared to $11.58 in the first quarter of 2025 and $12.30 in the prior quarter, due to higher differentials and transportation discounts. Higher transportation discounts were incurred due to utilizing alternative transportation route associated with Putumayo production in Colombia which was significantly more expensive and resulted in approximately $4.1 million for the current quarter
Current report
•Quality and transportation discounts for oil per boe in Canada increased for the first quarter of 2026 to $9.64 compared to $7.48 in the first quarter of 2025 due to higher pipeline tariffs related to new wells drilled and decreased from $10.35 in the prior quarter
Current report
•During the first quarter, 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
Current report
•During the first quarter of 2026, we completed the disposition of our entire working interest and associated title rights in the Simonette Montney area in Canada
Current report
•During the first quarter of 2026 we entered into an exploration, development and production sharing agreement with the State Oil Company of the Republic of Azerbaijan, for the onshore Guba–Khazaryani region in Azerbaijan, expanding our international exploration portfolio
Current report
(*)Calculated as DD&A expenses for the three months ended March 31, 2026 and 2025 of $46.4 million and $48.7 million less depreciation of administrative assets of $5.7 million and $3.7 million, respectively. For the prior quarter, calculated as DD&A expenses of $53.3 million, less depreciation of administrative assets of $3.9 million.
Current report
(*)Calculated as DD&A expenses for the three months ended March 31, 2026 and 2025 of $16.0 million and $10.5 million less depreciation of administrative assets of $0.1 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $5.5 million, less depreciation of administrative assets of $0.3 million.
Current report
(*)Calculated as DD&A expenses for the three months ended March 31, 2026 and 2025 of $69.9 million and $72.2 million less depreciation of administrative assets of $6.0 million and $3.8 million, respectively. For the prior quarter, calculated as DD&A expenses of $72.5 million, less depreciation of administrative assets of $4.3 million.
Current report
(1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition of this measure.
Current report
Oil, natural gas and NGL production NAR for the three months ended March 31, 2026, decreased by 2% to 37,741 BOEPD compared to the corresponding period of 2025 due to lower production in Acordionero field in Colombia and the sale of Simonette area in Canada, 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 4% compared to the prior quarter for the same reason mentioned above.
Current report
Brent -For the three months ended March 31, 2026, Brent increased 5% from the corresponding period of 2025 and increased 24% from the prior quarter. For the three months ended March 31, 2026, Castilla, Vasconia and Oriente differentials per boe increased to $9.67, $5.91 and $8.17 compared to $5.34, $2.27 and $7.65, respectively, in the corresponding period of 2025. Additionally, the realized price for South America was effected by higher transportation discounts. Higher transportation discounts were incurred due to utilizing alternative transportation route associated with Putumayo production in Colombia which was significantly more expensive and resulted in approximately $4.1 million for the current quarter.
Current report
Oil, natural gas and NGL salesfor the three months ended March 31, 2026, increased by 2% to $172.1 million compared to the corresponding period of 2025 due to 3% higher sales volumes driven by selling production from newly acquired Perico Block in Ecuador and 5% increase in Brent price, offset by higher quality and transportation discounts in Colombia. Higher quality and transportation discounts incurred due to using alternative transportation route associated with Putumayo production which was significantly more expensive and resulted in approximately $4.1 million for the current quarter.
Current report
Compared to the prior quarter, oil, natural gas and NGL sales increased by 32%, primarily due to a 24% increase in Brent price, and a 12% increase in sales volumes as a result of higher sales volumes in Ecuador partially offset by higher differentials. During the first quarter, we had two liftings in Ecuador compared to one in prior quarter. The sales price in Ecuador is the average Brent price less discounts for the month prior to lifting (M-1). During the three months ended March 31, 2026, we sold our January 2026 production for the average Brent price of December 2025 and the March 2026 production at the average Brent price of February 2026.
Current report
(*)Calculated as DD&A expenses for the three months ended March 31, 2026 and 2025 of $46.4 million and $48.7 million less depreciation of administrative assets of $5.7 million and $3.7 million, respectively. For the prior quarter, calculated as DD&A expenses of $53.3 million, less depreciation of administrative assets of $3.9 million.
Current report
(*)Calculated as DD&A expenses for the three months ended March 31, 2026 and 2025 of $16.0 million and $10.5 million less depreciation of administrative assets of $0.1 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $5.5 million, less depreciation of administrative assets of $0.3 million.
Current report
(*)Calculated as DD&A expenses for the three months ended March 31, 2026 and 2025 of $69.9 million and $72.2 million less depreciation of administrative assets of $6.0 million and $3.8 million, respectively. For the prior quarter, calculated as DD&A expenses of $72.5 million, less depreciation of administrative assets of $4.3 million.
Current report
Operating expenses for the three months ended March 31, 2026, decreased by 1% to $66.1 million compared to the corresponding period of 2025 due to lower workover activities, lower power generation and field personnel costs associated with head count optimization partially offset by higher inventory fluctuations due to the sale of oil inventory accumulated at the end of the previous quarter.
Current report
On a per boe basis, operating expenses decreased by $0.85 to $18.25 compared to the corresponding period of 2025, primarily due to $1.14 per boe lower workover activities which were partially offset by $0.21 per boe higher lifting costs associated with inventory fluctuations.
Current report
Compared to the prior quarter, operating expenses increased by 16% from $57.2 million or by$0.98 from $17.27 on a per boe basis primarily a result of inventory fluctuations due to the sale of oil inventory accumulated at the end of the previous quarter partially offset by lower workover activities and lower operating costs across various categories.
Current report
Transportation expenses increased by 44% or $0.35 per boe from $3.7 million or $1.11 per boe in the prior quarter for the same reason mentioned above.
Current report
DD&A expenses decreased by 4% from $72.5 million or by $2.63 on a per boe basis when compared to the prior quarter for the same reason mentioned above.
Current report
Asset Impairment
Current report
For the three months ended March 31, 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 March 31, 2026 as follows: Brent Crude $67.58 per boe, Edmonton Light Crude of C$83.04 per boe, Alberta AECO spot price of C$1.99 per MMBtu Edmonton Propane C$28.38 per boe, Edmonton Butane C$36.04 per boe and Edmonton Condensate C$85.94 and for the period ended three months ended March 31, 2025 Brent Crude of $78.90 per boe, Edmonton Light Crude of C$98.11 per boe, Alberta AECO spot price of C$1.51 per MMBtu Edmonton Propane C$32.53 per boe, Edmonton Butane C$48.81 per boe and Edmonton Condensate C$101.71.
Current report
G&A expenses before stock-based compensation for the three months ended March 31, 2026, increased by 27% to $15.1 million or by $0.78 to $4.18 per boe compared to the corresponding period of 2025, primarily due to higher consulting costs attributable to optimization projects.
Current report
Severance Expenses
Current report
For the three months ended March 31, 2026, severance expenses were $2.5 million, compared to nil for the corresponding period of 2025 and the prior quarter, respectively due to headcount optimization.
Current report
Financial Instruments Gains or Losses
Current report
The following table presents the nature of our financial instruments gains or losses three months ended March 31, 2026 and 2025, and the prior quarter:
Current report
During the three months ended March 31, 2026, we spud three development wells in Colombia and three in Canada. As of March 31, 2026, two development wells drilled in Colombia were producing and one well was in-progress. The wells drilled in Canada were in Simonette area, which was disposed during the three months ended March 31, 2026.
Current report
During the three months ended March 31, 2026, we issued $503.6 million in aggregate principal amount of its 9.75% Senior Secured Amortizing Notes due 2031 (the “9.75% Senior Notes”), and paid $125.0 million in cash consideration in exchange for $628.7 million aggregate principal amount of its 9.50% Senior Secured Amortizing Notes due 2029 (the “9.50% Senior Notes”). The exchange was accounted for as debt modification.
Current report
At any time, prior to April 15, 2028, we may redeem up to 0.35 of the aggregate principal amount of 9.75% Senior Notes at a redemption price equal to 1.0975 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 - 1.04875; 2029 - 1.02438; 2030 and thereafter - 1.
Current report
ii. consolidated net debt (total debt excluding deferred financing fees debt less cash equivalents) to consolidated adjusted earnings before interest, taxes and DD&A (“EBITDA”) of not more than 3.00.
Current report
During the three months ended March 31, 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.
Current report
Credit Facility
Showing the first 40 of 58 passages. Open the source sections for the rest.
Removed paragraphs (48)
Previous report
•During the third quarter of 2025, there were no share re-purchases. For the period from November 6, 2024 to October 29, 2025, we re-purchased a total of 1.2 million shares or 3% of the outstanding shares as of September 30, 2025.
Previous report
•NAR production for the third quarter of 2025 increased by 38% to 35,962 BOEPD, compared to 25,988 BOEPD in the third quarter of 2024 due to the production from Canadian operations acquired on October 31, 2024 and successful exploration well drilling results in Ecuador, and decreased by 10% from 39,800 BOEPD in the prior quarter as a result of a landslide in Ecuador that required the shut in of all Ecuador production for several weeks and trunk line repairs at the Moqueta field which resulted in the field being shut in for the quarter. Current production from October 1, 2025 to October 29, 2025 is approximately 45,200 BOEPD.
Previous report
•Oil, natural gas and NGL sales for the third quarter of 2025 decreased by 1% to $149.3 million, compared to the third quarter of 2024, primarily due to lower oil prices partially offset by an increase in sales volumes. Oil, natural gas and NGL sales were comparable with the prior quarter.
Previous report
•On per boe basis, operating expenses increased 1% compared to the corresponding period of 2024 and increased 24% from the prior quarter. Operating expenses increased by 48% to $68.4 million when compared to the third quarter of 2024, primarily as a result of new Canadian operations and ramp-up of operations in Ecuador. Operating expenses increasedby 22% from$55.9 million in the prior quarter primarily as a result of higher workover activities and lifting costs attributed to inventory fluctuation in Ecuador due to the timing of sales.
Previous report
•Transportation expenses increased by 10% when compared to the third quarter of 2024 primarily due to 47% higher sales volumes attributed to new Canadian operations and higher sales volumes in Ecuador, partially offset by lower volumes transported in Colombia. Transportation expenses decreased by 4% compared to the prior quarter primarily as a result of lower sales volumes transported from Acordionero field in Colombia.
Previous report
•Gross profit decreased 70% to $14.7 million compared to $48.8 million in the third quarter of 2024 and 36% from $23.1 million in the prior quarter.
Previous report
•Operating Netback(2) decreased to $76.6 million compared to $101.4 million in the third quarter of 2024 and $89.0 million in the prior quarter.
Previous report
•Quality and transportation discounts for the third quarter of 2025 increased to $24.74 per boe compared to $14.10 per boe in the third quarter of 2024, primarily as a result of the change in production mix with the acquisition of Canadian operations, and $23.89 per boe in the prior quarter as a result of higher Castilla and Vasconia differentials.
Previous report
•The temporary excise tax levied on oil sales was introduced by the Colombian government under a state of emergency declared in 2025. The tax applies to the first sale or export of crude oil at a rate of 1% starting from February 2025 and is scheduled to remain in force until December 2025. All temporary taxes enacted under the state of emergency are currently under review by the Constitutional Court, the ruling of which could potentially invalidate these measures
Previous report
(*)Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $47.0 million and $52.8 million, less depreciation of administrative assets of $3.0 million and $2.9 million, respectively. For the nine months ended September 30, 2025 and 2024 of $146.1 million and $160.1 million, less depreciation of administrative assets of $9.2 million and $8.7 million, respectively. For the prior quarter, calculated as DD&A expenses of $50.5 million, less depreciation of administrative assets of $2.6 million.
Previous report
(*)Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $65.0 million and $55.6 million, less depreciation of administrative assets of $3.1 million and $3.0 million, respectively. For the nine months ended September 30, 2025 and 2024 of $205.8 million and $167.2 million, less depreciation of administrative assets of $9.5 million and $8.9 million, respectively. For the prior quarter, calculated as DD&A expenses of $68.6 million, less depreciation of administrative assets of $2.7 million.
Previous report
(1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition and a reconciliation of this measure.
Previous report
Oil, natural gas and NGL production NAR for the three and nine months ended September 30, 2025, increased by 38% and 47%, to 35,962 BOEPD and 38,099 BOEPD, respectively, compared to the corresponding periods of 2024 due to the production from the Canadian operations acquired on October 31, 2024 and successful exploration well drilling results in Ecuador. Oil, natural gas and NGL production NAR decreased by 10% compared to the prior quarter primarily due to a landslide in Ecuador that required the shut in of all Ecuador production for several weeks and trunk line repairs at the Moqueta field which resulted in the field being shut in for the quarter. Current production from October 1, 2025 to October 29, 2025 is approximately 45,200 boepd.
Previous report
Brent -For the three and nine months ended September 30, 2025, Brent decreased 13% and 15% from the comparable periods of 2024, and increased 2% from the prior quarter. For the three months ended September 30, 2025, Castilla, Vasconia and Oriente differentials per boe decreased to $4.88, $1.88 and $7.20 compared to $8.83, $5.07 and $9.15 in the corresponding period of 2024. For the nine months ended September 30, 2025, Castilla, Vasconia and Oriente differentials per boe decreased to $4.98, $1.95 and $7.37 from $8.62, $4.70 and $8.52 in the corresponding period of 2024.
Previous report
Gran Tierra entered Canada with the acquisition of i3 Energy which closed on October 31, 2024, therefore no comparative data is provided for the corresponding periods of 2024.
Previous report
Oil, natural gas and NGL salesfor the three months ended September 30, 2025, decreased by 1% to $149.3 million compared to the corresponding period of 2024, due to 13% decrease in Brent price and 19% lower sales volumes in Colombia partially offset by 47% increase in sales volumes, attributed to sales from Canadian operations acquired on October 31, 2024 and sales from positive exploration drilling in Ecuador. Oil, natural gas and NGL sales for the nine months ended September 30, 2025, decreased by 2% to $466.8 million compared to the corresponding period of 2024 due to 15% decrease in Brent price and 16% decrease in sales volumes in Colombia, partially offset by a 49% increase in sales volumes attributed to sales from Canadian operations and new exploration wells in Ecuador.
Previous report
Oil, natural gas and NGL sales were comparable with the prior quarter
Previous report
During the three months ended September 30, 2025, we retrospectively reclassified transportation expenses against revenue, which were previously recorded separately from revenue, resulting in a decrease of revenue by immaterial impact of $3.1 million and $5.5 million for the three and six months ended June 30, 2025, respectively, and $2.4 million for the three months ended March 31, 2025.
Previous report
(*)Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $47.0 million and $52.8 million, less depreciation of administrative assets of $2.9 million and $2.9 million, respectively. For the nine months ended September 30, 2025 and 2024 of $146.1 million and $160.1 million, less depreciation of administrative assets of $9.2 million and $8.7 million, respectively. For the prior quarter, calculated as DD&A expenses of $50.5 million, less depreciation of administrative assets of $2.6 million.
Previous report
(*)Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $64.981 million and $55.6 million, less depreciation of administrative assets of $3.1 million and $3.0 million, respectively. For the nine months ended September 30, 2025 and 2024 of $205.8 million and $167.2 million, less depreciation of administrative assets of $9.5 million and $8.9 million, respectively. For the prior quarter, calculated as DD&A expenses of $68.6 million, less depreciation of administrative assets of $2.7 million.
Previous report
Operating expensesfor the three months ended September 30, 2025, increased to $68.4 million or by $0.24 per boe to $19.90 compared to the corresponding period of 2024, due to new Canadian operations and ramp-up of operations in Ecuador.
Previous report
Operating expenses for the nine months ended September 30, 2025, increased to $191.6 million compared to the corresponding period of 2024 for the same reason mentioned above. On a per boe basis, operating expenses decreased by $1.84 to $18.36 compared to the corresponding period of 2024, primarily due higher sales volumes in Ecuador and sales from new Canadian operations.
Previous report
Compared to the prior quarter, operating expenses increased from $55.9 million or by $3.89 from $16.01 per boe due to higher workover activities and lifting costs associated with inventory fluctuation in Ecuador due to the timing of sales.
Previous report
Transportation expenses for the nine months ended September 30, 2025, decreased by 6% to $13.3 million or by $0.74 to $1.28 per boe, compared to the corresponding period of 2024, due to lower sales volumes transported in Colombia partially offset by sales volumes from a new Canada operations and the higher sales volumes transported in Ecuador.
Previous report
Transportation expenses decreased by 4% or $0.04 per boe from $4.5 million or $1.29 per boe in the prior quarter due to lower sales volumes transported from Acordionero field in Colombia.
Previous report
On a per boe basis, DD&A expenses for the three and nine months ended September 30, 2025 decreased by$4.81 and$4.14 due to higher NAR sales volumes primarily attributed to the new Canadian operations.
Previous report
DD&A expenses decreased by 5% from $68.6 million when compared to the prior quarter due to lower production rates. On a per boe basis, DD&A expenses decreased by $0.77 due to higher production in Ecuador.
Previous report
G&A expenses before stock-based compensation on a per boe basis for the three months ended September 30, 2025 decreased by $0.14 or 3% compared to the corresponding period of 2024 due to higher sales volumes mainly driven by the addition of the new Canadian operations. Total G&A expenses before stock-based compensation increased by 42% compared to the corresponding period of 2024, primarily due to the addition of the new Canadian operations and higher business development and consulting cost related to optimization projects.
Previous report
G&A expenses before stock-based compensation on a per boe basis for the nine months ended September 30, 2025, decreased by $0.62 or 14% compared to the corresponding period of 2024 due to higher sales volumes mainly driven by the addition of the new Canadian operations. Total G&A expenses before stock-based compensation increased by 28% compared to the corresponding period of 2024, primarily due to the addition of the new Canadian operations.
Previous report
For the nine months ended September 30, 2024, the deferred income tax was a recovery of $32.3 million, primarily as a result of the recognition of additional tax losses resulting from a tax planning strategy.
Previous report
During the three months ended September 30, 2025, we spud one exploration well in Ecuador and one in Colombia. As of September 30, 2025, the exploration well drilled in Ecuador was in-progress and in Colombia was a dry well. We also spud one development well in Canada which was in-progress as of September 30, 2025.
Previous report
On October 24, 2025, we, through our wholly owned subsidiary, Gran Tierra Energy Colombia GmbH, entered into crude oil sale and purchase agreement where we will receive an advance of up to $150.0 million related to Ecuador production. An additional advance of $50.0 million is available to the Company, at the sole discretion of the lender and subject to completion of certain conditions.
Previous report
Credit Facility - Canada
Previous report
On October 30, 2025, the existing revolving credit facility was amended to increase available commitment amount from C$50.0 million (US$35.9 million as of September 30, 2025) to C$75.0 million (US$53.9 million as of September 30, 2025) and extend the term to a two-year maturing October 30, 2027. The borrowing base was maintained at C$100.0 million.
Previous report
Credit Facility - Colombia
Previous report
On April 16, 2025, we, through our wholly owned subsidiary, Gran Tierra Energy Colombia GmbH, a Swiss limited liability company, entered into a $75.0 million reserve-based lending facility. Any loans incurred under the new facility will mature on April 16, 2028 and will bear interest at a rate per annum equal to, at our option, either (a) a customary base rate (subject to a floor of 1.00%) plus an applicable margin of 4.50% or (b) a term SOFR reference rate plus an applicable margin of 4.50%. Interest on base rate borrowings is payable quarterly in arrears and interest on term SOFR borrowings accrues in respect of interest periods of three or six months, at the election of the Company, and is payable on the last day of such interest period.
Previous report
On October 23, 2025, the existing RBL facility was amended (“ the Amended RBL Facility”) to reduce the borrowing base to$60.0 million and revised certain related terms, including provisions governing borrowings, hedging obligations, and borrowing base redetermination. Under the terms of Amended RBL Facility, we are required to repay any amounts outstanding in excess of $20.0 million upon funding the oil prepayment agreement and the lender may initiate a redetermination of the borrowing base if advances requested by us are in excess of $20.0 million.
Previous report
As of September 30, 2025 the outstanding balance under the RBL Facility was $24.5 million. For the three andnine months ended September 30, 2025, the weighted-average interest rate on borrowings was 9.05% and 8.79%, respectively.
Previous report
i. consolidated net debt to consolidated adjusted EBITDA ratio that may not exceed 3.00 to 1.00, and
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Reworded paragraphs (43)
Previous wording
Key Highlights for the third quarter of 2025
Current wording
Key Highlights for the first quarter of 2026
Previous wording
•Net loss for the third quarter of 2025 was $20.0 million or $(0.57) per share basic and diluted, compared to a net income of $1.1 million or $0.04 per share basic and diluted for the third quarter of 2024 and a net loss of $12.7 million for the prior quarter.
Current wording
•Net loss for the first quarter of 2026 was $119.2 million or $3.38 per share basic and diluted, compared to a net loss of $19.3 million or $0.54 per share basic and diluted for the first quarter of 2025 and a net loss of $141.1 million for the prior quarter. The following non-cash items were the main contributors to net loss for the first quarter of 2026: $77.3 million unrealized mark-to-market hedging loss, $19.7 million stock-based compensation remeasurement, $11.3 million amortization of deferred financing fees and $4.5 million oil prepayment interest
Previous wording
•Loss before income taxes for the third quarter of 2025 was $31.2 million, compared to income before income taxes of $21.9 million for the third quarter of 2024 and loss before income taxes of $8.1 million for the prior quarter.
Current wording
•Loss before income taxes for the first quarter of 2026 was $145.8 million, compared to loss before income taxes of $15.7 million for the first quarter of 2025 and loss before income taxes of $177.8 million for the prior quarter
Previous wording
•Brent oil price averaged $68.17 per bbl during the third quarter of 2025, a decrease of 13% from the comparable period in 2024, and a 2% increase from the prior quarter. Castilla, Vasconia and Oriente differentials averaged$4.88, $1.88 and $7.20 per bbl during the third quarter of 2025, a decrease of 45%, 63% and 21% from the comparable period of 2024, and an increase of 3% and 10% for Castilla and Vasconia differentials offset by a decrease of 1% for Oriente differential from the prior quarter, respectively.
Current wording
•Brent oil price averaged $78.38 per bbl during the quarter, an increase of 5% from the comparative period of 2025, and a 24% increase from the prior quarter. Castilla, Vasconia and Oriente differentials averaged$9.67, $5.91 and $8.17 per bbl during the quarter, an increase of 81%, 160% and 7% from the comparable period of 2025, and an increase of 49%, 73% for Castilla and Vasconia differentials and 3% decrease for Oriente differential from the prior quarter, respectively
Previous wording
•Adjusted EBITDA(2) was $69.0 million for the third quarter of 2025, a decrease from $92.8 million in the third quarter of 2024, and a decrease from $77.0 million in the prior quarter.
Current wording
•Adjusted EBITDA(2) was $73.9 million for the first quarter of 2026, a decrease from $85.2 million in the first quarter of 2025, and an increase from $52.5 million in the prior quarter
Previous wording
•Funds flow from operations(2)decreased to $41.7 million compared to $60.3 million in the third quarter of 2024, and decreased from $53.9 million in the prior quarter.
Current wording
•Funds flow from operations(2)decreased to $42.8 million compared to $55.3 million in the first quarter of 2025, and increased from $26.8 million in the prior quarter
Previous wording
•NAR sales volumes for the third quarter of 2025 increased by 47% to 37,353 BOEPD, compared to 25,464 BOEPD in the third quarter of 2024 and decreased by 3% from 38,331 BOEPD in the prior quarter.
Current wording
•NAR Sales volumes for the first quarter of 2026 increased by 3% to 40,267 BOEPD, compared to 39,024 BOEPD in the first quarter of 2025 and increased by 12% from 35,984 BOEPD in the prior quarter
Previous wording
•General and administrative (“G&A”) expenses before stock-based compensation for the third quarter of 2025 increased to $13.5 million compared to $9.5 million in the third quarter of 2024, due to the addition of the new Canadian operations, and decreased from $14.5 million in the prior quarter due to lower business development costs.
Current wording
•General and administrative (“G&A”) expenses before stock-based compensation for the first quarter of 2026 increased to $15.1 million compared to $11.9 million in the first quarter of 2025 due to higher consulting costs attributable to optimization projects and decreased from $16.8 million in the prior quarter due to headcount optimization measures implemented during the current quarter
Previous wording
•Capital expenditures for the third quarter of 2025 were $57.3 million compared to $52.9 million in the third quarter of 2024 and $51.2 million in the prior quarter. This increase in capital expenditure activity is in line with the Company’s budgeted capital spend for 2025.
Current wording
•Capital expenditures for the first quarter of 2026 were $45.4 million compared to $94.7 million in the first quarter of 2025 and $53.0 million in the prior quarter
Previous wording
Gross profit is derived from oil, natural gas and NGL sales, net of direct production costs including operating expenses, transportation, and depletion, depreciation, and accretion (“DD&A”). Gross profit does not include general and administrative expenses, interest, taxes, or other non-operating items.
Current wording
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.
Previous wording
Operating netback, EBITDA, adjusted EBITDA, and funds flow from operations are non-GAAP measures that do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to oil sales, net income (loss) or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Disclosure of each non-GAAP financial measure is preceded by the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.
Current wording
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.
Previous wording
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 oil sales to operating netback is provided in the table below.
Current wording
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.
Previous wording
(*)Same as DD&A expenses for the three months ended September 30, 2025 and 2024and the prior quarter.
Current wording
(*)Same as DD&A expenses for the three months ended March 31, 2026 and 2025 and the prior quarter.
Previous wording
EBITDA, as presented, is defined as net (loss) income adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, lease payments, foreign exchange gain or loss, stock-based compensation expense or recovery, transaction costs, other loss and unrealized derivative instruments loss or gain. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net (loss) income to EBITDA and adjusted EBITDA is as follows:
Current wording
EBITDA, as presented, is defined as net income (loss) adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense, and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for asset impairment, 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:
Previous wording
Funds flow from operations, as presented, is defined as net (loss) income adjusted for DD&A expenses, deferred income tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, unrealized derivative instruments loss or gain and other loss. Management uses this financial measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net loss to funds flow from operations is as follows:
Current wording
Funds flow from operations, as presented, is defined as net loss adjusted for DD&A expenses, asset impairment, 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 loss 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:
Previous wording
Royalties as a percentage of production for the three and nine months ended September 30, 2025 decreased by 5% and 4%, respectively, compared to the corresponding periods of 2024 as a result of a decrease in benchmark oil prices due to the price sensitive royalty regime in Colombia and Ecuador, and lower royalties for Canadian operations. Royalties as a percentage of production were comparable to the prior quarter.
Current wording
Royalties as a percentage of production for the three months ended March 31, 2026 were comparable to the corresponding period of 2025. Royalties as a percentage of production increased 2% compared to the prior quarter commensurate with the increase in benchmark oil prices and the price sensitive royalty regime in Colombia, Ecuador, and Canada.
Previous wording
The Midas Block includes the Acordionero field, the Suroriente Block includes the Cohembi field, and the Chaza Block includes the Costayaco and Moqueta fields. Ecuador includes the Charapa, Chanangue and Iguana Blocks. Canada includes several areas in the Western Canadian Sedimentary Basin with all production in Alberta, Canada.
Current wording
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.
Previous wording
During the third quarter of 2025, 100% of sales from South America were priced against Brent.
Current wording
During the three months ended March 31, 2026, 100% of sales from South America was priced against Brent.
Previous wording
WTI - For the three months ended September 30, 2025, WTI increased 2% from the prior quarter. For the three months ended September 30, 2025, 25% of NAR production in Canada was oil, compared with 26% in the prior quarter.
Current wording
WTI -For the three months ended March 31, 2026, WTI increased 2% from the corresponding period of 2025 and increased 23% from the prior quarter. During the first quarter of 2026, 25% of NAR production in Canada was oil, compared to 21% for the comparable period of 2025, and 26% for the prior quarter.
Previous wording
NGLs - For the three months ended September 30, 2025, the weighted average NGL price received was 9% of WTI, consistent with the prior quarter. For the three months ended September 30, 2025, 21% of NAR production in Canada was NGLs, compared to 24% in the prior quarter.
Current wording
NGLs - For the three months ended March 31, 2026, the weighted average NGL price received was 10% of WTI compared to 14% percent of WTI in the comparable period of 2025 and 22% percent of WTI in the prior quarter. During the first quarter of 2026, 26% of production in Canada were NGLs, compared to 27% from the comparable period of 2025 and 24% in the prior quarter.
Previous wording
AECO - For the three months ended September 30, 2025, AECO price decreased 63% from the prior quarter. For the three months ended September 30, 2025, 54% of NAR production in Canada was natural gas, compared to 50% in the prior quarter.
Current wording
AECO - For the three months ended March 31, 2026, AECO price decreased 7% and 9% from the comparable period of 2025 and from prior quarter, respectively. During the first quarter of 2026, 49% of production in Canada was natural gas, compared to 52% from the comparable period of 2025 and 50% in the prior quarter.
Previous wording
The following table shows the effect of changes in realized price and sale volumes on our oil sales for the three and nine months ended September 30, 2025, compared to the prior quarter and the corresponding periods of 2024:
Current wording
The following table shows the effect of changes in realized price and sale volumes on our oil sales for the three months ended March 31, 2026, compared to the prior quarter and the corresponding period of 2025:
Previous wording
We have options to sell our oil through multiple pipelines and various trucking routes. Each option has varying effects on realized sales price and transportation expenses. The following table shows the percentage of oil, natural gas and NGL volumes we sold in Canada, Colombia and Ecuador using each option for the three and nine months ended September 30, 2025 and 2024, and the prior quarter:
Current wording
We have options to sell our oil through multiple pipelines and various trucking routes. Each option has varying effects on realized sales price and transportation expenses. The following table shows the percentage of oil, natural gas and NGL volumes we sold in Canada, Colombia and Ecuador using each option for the three months ended March 31, 2026 and 2025, and the prior quarter:
Previous wording
Transportation expenses for the three months ended September 30, 2025, increased by 10% to $4.3 million or by $0.42 to $1.25 per boe, compared to the corresponding period of 2024, due to the new Canadian operations, higher sales volumes transported in Ecuador partially offset by lower sales volumes transported in Colombia.
Current wording
Transportation expenses for the three months ended March 31, 2026, increased by 17% to $5.3 million or $0.16 to $1.46 per boe, compared to the corresponding period of 2025, due to higher sales volumes transported in Ecuador during the current quarter.
Previous wording
DD&A expenses for the three and nine months ended September 30, 2025, increased by 17% and 23% due to higher costs in the depletable base for Ecuador and the new Canadian operations, compared to the corresponding periods of 2024.
Current wording
DD&A expenses for the three months ended March 31, 2026, decreased by 3% or by$1.28 on a per boe basis, due to lower costs in the depletable base for Canadian operations as a result of Simonette field disposition and higher proved reserves in Ecuador, compared to the corresponding period of 2025.
Previous wording
Compared to the prior quarter, G&A expenses before stock-based compensation decreased by 7% or $0.24 per boe due to lower business development cost.
Current wording
Compared to the prior quarter, G&A expenses before stock-based compensation decreased by 10% or $0.90 per boe due to headcount optimization and higher sales volumes.
Previous wording
G&A expenses after stock-based compensation for the three and nine months ended September 30, 2025, increased by 114% and 7% or $1.25 and decreased $1.52 per boe compared to the corresponding periods of 2024, due to higher stock-based compensation attributed to a higher share price during the current periods and the addition of the new Canadian operations.
Current wording
G&A expenses after stock-based compensation for the three months ended March 31, 2026, increased by 205% or $6.36 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 quarter.
Previous wording
Compared to the prior quarter, G&A expenses after stock-based compensation decreased by 9% or $0.34 per boe due to a recovery from a lower share price.
Current wording
Compared to the prior quarter, G&A expenses after stock-based compensation increased by 75% or $3.61 per boe for the same reason mentioned above.
Previous wording
For the three and nine months ended September 30, 2025, we had a $0.3 million loss and $7.8 million loss on foreign exchange compared to a $3.1 million gain and $8.3 million gain on foreign exchange in the corresponding periods of 2024 and a $3.7 million loss on foreign exchange in the prior quarter. Accounts payable, taxes receivable and payable and deferred income taxes are considered monetary items and require translation from local currencies to U.S. dollar functional currency at each balance sheet date. This translation was the primary source of the foreign exchange gains and losses in the periods.
Current wording
For the three months ended March 31, 2026, we had a $1.4 million loss on foreign exchange compared to a $3.8 million loss on foreign exchange in the corresponding period of 2025, and a $0.9 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.
Previous wording
The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the three and nine months ended September 30, 2025 and 2024 and the prior quarter:
Current wording
The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the three months ended March 31, 2026 and 2025 and the prior quarter:
Previous wording
Current income tax expense was $14.5 million for the nine months ended September 30, 2025, compared to $61.4 million in the corresponding period of 2024, primarily due to lower taxable income.
Current wording
Current income tax expense was $5.9 million for the three months ended March 31, 2026, compared to $8.3 million in the corresponding period of 2025, primarily due to lower taxable income.
Previous wording
The deferred tax for the nine months ended September 30, 2025, was a recovery of $17.6 million mainly due to an increase in deductible temporary differences arising from tax losses generated during the period. These were partially offset by higher tax depreciation relative to accounting depreciation.
Current wording
The deferred tax for the three months ended March 31, 2026, was a recovery of $32.4 million mainly due to an increase in deductible temporary differences arising from tax losses generated during the period and accruals. These were partially offset by higher tax depreciation relative to accounting depreciation.
Previous wording
For the nine months ended September 30, 2024, the difference between the effective tax rate of 44% and the 50% Colombian tax rate was primarily due to a lower impact of foreign taxes, 2022 true-up related to tax planning strategy and non-taxable foreign exchange adjustments. These were partially offset by an increase in valuation allowance, other permanent differences, non-deductible stock-based compensation and non-deductible royalties in Colombia.
Current wording
For the three months ended March 31, 2026, the difference between the effective tax rate of 18% and the 21% statutory tax rate was primarily due to an increase in the non-deductible foreign translation adjustments and other permanent differences. This was partially offset by an increase in the impact of foreign taxes.
Previous wording
For the nine months ended September 30, 2025, the difference between the effective tax rate of negative 6% and the 35% statutory tax rate was primarily due to permanent differences and valuation allowance. This was partially offset by an increase in the impact of foreign taxes.
Current wording
For the three months ended March 31, 2025, the difference between the effective tax rate of negative 23% 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.
Previous wording
Capital expenditures during the three months ended September 30, 2025, were $57.3 million.
Current wording
Capital expenditures during the three months ended March 31, 2026, were $45.4 million.
Previous wording
We believe that our capital resources, including cash on hand, cash generated from operations and available borrowings under our credit facilities and prepayment structure, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for the next 12 months, including the repayment of 25% of the principal amount of 9.50% Senior Notes due October 15, 2026, given the current oil price trends and production levels. Beyond the next 12 months, the Company may require the support of its lenders to renew existing lending arrangements and may also access to capital markets to pursue financing, including for the re-purchase of common stock or the repayment of debt in the future. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us with the flexibility to respond to both internal growth opportunities and those available through acquisitions. We intend to pursue growth opportunities and acquisitions from time to time, which may require significant capital to be located in basins or countries beyond our current operations, involve joint ventures, or be sizable compared to our current assets and operations.
Current wording
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.
Previous wording
The principal amount of 9.50% Senior Notes is to be repaid as follows: (i) October 15, 2026, 25% of the principal amount; (ii) October 15, 2027 5% of the principal amount; (iii) October 15, 2028, 30% of the principal amount; and (iv) October 15, 2029, the remainder of the principal amount.
Current wording
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. We are required to complete mandatory redemption of $30.0 million aggregate principal amount of 9.75% Senior Notes less any re-purchases in the open market during the year ended December 31, 2026.
Previous wording
Under the terms of the facility, we are required to maintain compliance with the following financial covenants:
Current wording
Under the terms of the 9.75% Senior Notes agreement, we are required to maintain compliance with the following financial covenants:
Previous wording
ii. consolidated interest coverage ratio that may not be less than 2.50 to 1.00
Current wording
i. consolidated interest coverage ratio of not less than 2.50; and
Previous wording
We were in compliance with all applicable covenants related to credit facilities and Senior Notes as of September 30, 2025.
Current wording
As at March 31, 2026, we were in compliance with all applicable covenants related to Senior Notes.
Showing the first 40 of 43 pairs. Open the source sections for the rest.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
(*)Same as DD&A expenses for the three months ended March 31, 2026 and 2025 and the prior quarter.
Current report — wording carried from elsewhere
The deferred income tax for the three months ended March 31, 2025, was a recovery of $4.7 million mainly due to the use of a higher enacted tax rate on Colombia tax losses. These were partially offset by higher tax depreciation relative to accounting depreciation.