GRAN TIERRA ENERGY INC.
For the period ended Dec 31, 2025. Filed Mar 4, 2026.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Mar 4, 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-K
Period ended 2024-12-31; filed 2025-02-24.
0001273441-25-000002
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-03-04.
0001273441-26-000010
Item 7. 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 160 previous paragraphs and 211 current paragraphs.
72 unchanged; 57 reworded; 79 added; 27 removed; 4 previous and 3 current paragraphs rearranged.
Tables are not compared: 25 previous and 41 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 (79)
Current report
•Quality and transportation discounts for oil per boe in Canada increased in 2025 to$7.90 when compared to $4.49 in 2024, primarily as a result of higher pipeline tariffs related to new wells coming on stream in Simonette and Clearwater areas
Current report
•Transportation expenses for 2025 decreased by 8% or by$0.60 per boe to$17.0 million or $1.24 per boe compared to $18.5 million or $1.84 per boe in 2024 due to the full year of Canadian operations which had lower transportation costs per boe, and a shift to lower-cost delivery points in Colombia
Current report
•Gross profit decreased by 64% to $66.4 million compared to $182.6 million in 2024 primarily as a result of higher operating and depletion and accretion costs driven by a full year of Canadian operations in 2025
Current report
•Operating netback(2) decreased to $330.9 million compared to $401.1 million in 2024
Current report
•G&A expenses before stock-based compensation increased by 37% to $56.9 million in 2025 compared to $41.4 million in 2024 as a result of the full year of G&A expenses from Canadian operations, higher business development costs, and consulting costs attributed to optimization projects
Current report
•Capital expenditures increased by $8.2 million or 3% to $256.3 million compared to $248.1 million in 2024
Current report
•During the fourth quarter of 2025, we completed the acquisition for 100% working interest of Perico and Espejo Blocks in the Oriente Basin in Ecuador for cash consideration of $8.3 million, deferred payment of $3.1 million and $1.1 million contingent consideration payable upon achieving 2.0 million barrels of crude oil production in the Perico Block
Current report
•In February 2025, the Colombian government introduced a temporary 1% excise tax on the first sale or export of crude oil pursuant to a declared state of internal emergency, effective through December 31, 2025. On October 16, 2025, the Colombian Constitutional Court upheld the validity of the emergency tax measures, including the excise tax on hydrocarbons, subject to a cap on total collections. The Court confirmed that the tax remains payable during its effective period and that any amounts collected in excess of the authorized budget must be refunded to taxpayers on a proportional basis following reporting by the Colombian tax authority. The determination of whether excess collections exist is expected to occur after the end of the tax period, once the tax authority completes its reporting of total collections. Accordingly, while we were required to comply with the tax through December 31, 2025, any potential refund would be assessed thereafter and cannot be determined at this time.
Current report
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.
Current report
(*)Calculated as DD&A expenses for the year ended December 31, 2025, 2024 and 2023 of $199.4 million, $211.2 million and $207.3 million, less depreciation of administrative assets of $13.1 million, $11.9 million and $6.5 million, respectively. For the three months ended December 31, 2025 and 2024, calculated as DD&A expenses of $53.3 million and $51.1 million, less depreciation of administrative assets of $3.9 million and $3.3 million, respectively. For the prior quarter, calculated as DD&A expenses of $47.0 million, less depreciation of administrative assets of $2.9 million.
Current report
(*)Calculated as DD&A expenses for the year ended December 31, 2025, of $29.9 million, less depreciation of administrative assets of $0.3 million and the same as DD&A expenses for the years ended December 31, 2024 and 2023. For the three months ended December 31, 2025 of $5.5 million less depreciation of administrative assets of $0.3 million and the same as DD&A expenses for the three months ended December 31, 2024, and the prior quarter.
Current report
(*)Same as DD&A expenses for the year ended December 31, 2025 and 2024, three months ended December 31, 2025 and 2024 and the prior quarter.
Current report
(*)Calculated as DD&A expenses for the year ended December 31, 2025, 2024 and 2023 of $278.4 million, $230.6 million and $215.6 million, less depreciation of administrative assets of $13.8 million, $12.2 million and $6.8 million, respectively. For the three months ended December 31, 2025 and 2024 of $72.5 million and $63.4 million, less depreciation of administrative assets of $4.3 million and $3.3 million, respectively. For the prior quarter, calculated as DD&A expenses of $65.0 million, less depreciation of administrative assets of $3.1 million.
Current report
Oil, natural gas and NGL production NAR for the year ended December 31, 2025, increased by 38% to 38,443 BOEPD compared to 27,890 BOEPD in 2024. The increase in production was a result of positive exploration well drilling in Ecuador, full-year production from the Canadian operations acquired on October 31, 2024, partially offset by lower production in the Acordionero and Costayaco fields as a result of export pipeline disruptions, and trunk line repairs in the Moqueta field which resulted in the field being shut-in during the third quarter.
Current report
Commodity prices:
Current report
Colombia and Ecuador
Current report
Brent -For the year ended December 31, 2025, Brent price decreased by 15% compared to 2024 as a result of excess global oil supply and the gradual unwinding of the previously curtailed OPEC production volumes while Castilla, Vasconia and Oriente differentials decreased to $5.36, $2.31 and $7.63 compared to $8.54, $4.78 and $8.75 in 2024 primarily as a result of decreased supply of heavier crude oil.
Current report
For the year ended December 31, 2024, Brent price decreased by 17% compared to 2023 and Castilla, Vasconia and Oriente differentials decreased to $8.54, $4.78 and $8.75 from $10.22, $5.39 and $9.91 in 2023.
Current report
During the years ended December 31, 2025, 2024 and 2023, 100% of sales from South America were oil, priced against Brent.
Current report
Canada
Current report
We entered Canada with the acquisition of i3 Energy which closed on October 31, 2024, and as a result, we only have two months of comparative data available for the corresponding period of 2024, and no comparative data available for 2023.
Current report
WTI - For the year ended December 31, 2025, WTI decreased 7% compared to the two month period of operations in 2024. For the year ended December 31, 2025, 25% of NAR production in Canada was oil, compared with 21% during the two month period of 2024.
Current report
NGLs - For the year ended December 31, 2025, the weighted average NGL price received was 11% of WTI, consistent with the two month period of 2024. For the year ended December 31, 2025, 24% of NAR production in Canada was NGLs, compared to 27% during the two month period of 2024.
Current report
AECO - For the year ended December 31, 2025, AECO price increased 2% compared to the two month period of 2024 averaging $1.56 per mcf. For the year ended December 31, 2025, 51% of NAR production in Canada was natural gas, compared to 52% during the two month period of 2024.
Current report
Oil, natural gas and NGL sales for the year ended December 31, 2025, decreased by 4% to $596.7 million compared to $621.8 million in 2024, primarily as a result of a 15% decrease in Brent price, a 15% decrease in sales volumes in Colombia, offset by higher sales volumes in Ecuador, lower differentials, and the full year of sales from Canadian operations of $115.7 million in 2025 compared to the two month period in 2024 of $19.0 million.
Current report
On a per boe basis, the average realized price for Colombia decreased by 14% to$56.54 for the year ended December 31, 2025, compared to $65.80 in 2024, primarily as a result of 15% decrease in Brent price.
Current report
On a per boe basis, the average realized price for Ecuador decreased by 11% to$61.53 for the year ended December 31, 2025, compared to $68.80 in 2024, primarily as a result of 15% decrease in Brent price and lower differentials.
Current report
On a per boe basis, the average realized price for Canada increased by 3% to$21.71 for the year ended December 31, 2025, compared to $21.14 in 2024, primarily as a result of royalties adjustments during the year, partially offset by the decrease in benchmark oil and gas prices.
Current report
On a consolidated basis, the average realized price decreased by 30% to $43.41 per boefor the year ended December 31, 2025, compared to $61.93 in 2024, reflecting the structural impact of adding Canadian operations which carry wider benchmark differentials and transportation costs.
Current report
Operating expensesfor the year ended December 31, 2025, increased by 23% to $248.7 million compared to $202.3 million in 2024 due to higher operating costs in Ecuador as a result of production ramp-up in 2025 and the full year of Canadian operations compared to only two months in the corresponding period of 2024. On a per boe basis, operating expenses decreased by 10% or by $2.06 ($1.43 lower workovers and $0.63 lower power generation) to $18.09 compared to $20.15 in the prior year as a result of higher NAR sales in Ecuador and Canada in 2025.
Current report
Transportation expenses for the year ended December 31, 2025, decreased by 8% to $17.0 million or by $0.60 to$1.24 per boe compared to $18.5 million or $1.84 per boe in 2024, as a result of full year of operations in Canada which had lower transportation costs per boe, and a shift to lower-cost delivery points in Colombia.
Current report
Gross Profit
Current report
(*)Calculated as DD&A expenses for the year ended December 31, 2025, 2024 and 2023 of $199.4 million, $211.2 million and $207.3 million, less depreciation of administrative assets of $13.1 million, $11.9 million and $6.5 million, respectively.
Current report
(*)Calculated as DD&A expenses for the year ended December 31, 2025, of $29.9 million, less depreciation of administrative assets of $0.3 million. and the same as DD&A expenses for the years ended December 31, 2024 and 2023.
Current report
(*)Same as DD&A expenses for the years ended December 31, 2025 and 2024.
Current report
(*)Calculated as DD&A expenses for the year ended December 31, 2025, 2024 and 2023 of $278.4 million, $230.6 million and $215.6 million, less depreciation of administrative assets of $13.8 million, $12.2 million and $6.8 million, respectively.
Current report
DD&A expenses for the year ended December 31, 2025, increased by 21% from 2024 due to higher production in Ecuador and full year of DD&A from Canadian operations. On a per boe basis, the DD&A decreased by $2.72 due to a higher mix of Canadian NAR sales which have a lower depletion rate.
Current report
G&A expenses before stock-based compensationfor the year ended December 31, 2025 increased 37% compared to 2024, as a result of a full year of G&A from Canadian operations, and higher business development and consulting cost related to optimization projects.
Current report
G&A expenses before stock-based compensation, on a per boe basis for the year ended December 31, 2025, was comparable with 2024.
Current report
G&A expenses before stock-based compensation, on a per boe basis, for the year ended December 31, 2024, decreased by 3% to $4.13 compared to 2023, as a result of higher NAR sales volumes during 2024.
Showing the first 40 of 79 passages. Open the source sections for the rest.
Removed paragraphs (27)
Previous report
•On October 31, 2024, we acquired oil and natural gas reserves and production operations in Canada through the acquisition of all of the issued and outstanding common shares of i3 Energy, subsequently renamed Gran Tierra UK Limited (“Gran Tierra UK”), for $204.5 million. We consolidated operating activities for the last two months of 2024 as a result of the i3 Energy acquisition
Previous report
•General and administrative (“G&A”) expenses before stock-based compensation per boe for 2024 decreased by 6% to $3.97 compared to $4.24 in 2023 dueto lower business development, consulting and legal expenses during 2024. G&A expenses before stock-based compensation were $39.9 million in 2024 compared to $40.1 million in 2023, representing a 1% decrease
Previous report
•Capital expenditures increased by$7.7 million or 3% to $234.2 million compared to 2023 due to a higher number of wells drilled in 2024 in Colombia, Ecuador and Canada.
Previous report
Oil production NAR for the year ended December 31, 2023, increased by 10% to 26,099 BOEPD compared to 23,815 BOEPD in 2022. The increase in production was a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador.
Previous report
Oil, natural gas and NGL sales for the year ended December 31, 2023, decreased by 10% to $637.0 million compared to $711.4 million in 2022, primarily as a result of a 17% decrease in Brent price and higher Vasconia and Castilla differentials partially offset by 9% higher sales volumes and lower transportation discounts in 2023. Vasconia and Castilla differentials increased to $5.39 and $10.22 per boe in 2023 from $4.99 and $9.81 per boe in 2022, respectively. During the year ended December 31, 2023, we commenced sales in Ecuador which were subject to a$9.91 per boe Oriente differential.
Previous report
On a per boe basis, average realized prices decreased by 18% to $67.26 for the year ended December 31, 2023, compared to $82.25 in 2022, primarily as a result of the decrease in benchmark oil prices, offset by higher Castilla and Vasconia differentials in 2023.
Previous report
Operating expenses for the year ended December 31, 2023, increased by 15% to $186.9 million compared to $162.4 million in 2022. On a per boe basis, despite significant inflationary pressures operating expenses increased by only 5% or $0.96 to $19.73 in 2023 compared to $18.77 in 2022, primarily as a result of $2.23 per boe higher lifting costs associated with road and pipeline maintenance, power generation attributed to higher compressed natural gas purchases, diesel tariffs and equipment rental associated with testing exploratory wells, offset by $1.27 per boe of lower workovers. As a result of an El-Niño-induced drought, power costs in 2023 increased across Colombia, which relies on hydroelectricity for more than two-thirds of its installed power capacity. In addition, operating costs increased as a result of the depreciation of U.S. dollar against the Colombian peso in 2023.
Previous report
b
Previous report
G&A expenses before stock-based compensation, on a per boe basis for the year ended December 31, 2024, decreased by 6% to $3.97 compared to 2023, for the same reason mentioned above and higher NAR sales during 2024.
Previous report
G&A expenses before stock-based compensation for the year ended December 31, 2023, increased 26% to $40.1 million compared to 2022 due to costs attributed to business development activities, higher salaries related to increased headcount in Ecuador to support ramp-up of operations and the strengthening of the Colombian peso against the U.S. dollar.
Previous report
G&A expenses after stock-based compensation for the year ended December 31, 2023, increased by 12% to $45.8 million compared to 2022 due to higher G&A expenses before stock-based compensation, partially offset by 37% decrease in stock-based compensation expense which was a result of lower share price in 2023.
Previous report
G&A expenses after stock-based compensation, on a per boe basis, for the year ended December 31, 2023, increased by 2% to $4.84 per boe compared to 2022 due to higher NAR sales in 2023.
Previous report
Foreign Exchange (Gains) Losses
Previous report
Income Tax Expense
Previous report
The difference between our effective tax rate of 43% for the year ended December 31, 2022, and the 35% Colombian statutory was primarily due to $26.6 million of hedging loss, $46.5 million of financing cost mainly related to the senior notes, and $23.1 million of stock-based compensation and G&A cost, which were incurred in jurisdictions where no tax benefit is recognized. These were partially offset by $13.2 million of non-taxable foreign exchange gain.
Previous report
The 6.25% Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The 6.25% Senior Notes matured and were settled on February 15, 2025.
Previous report
On February 6, 2024 and September 18, 2024, we issued additional $100.0 million and $150.0 million of 9.50% Senior Notes due October 2029 (the “new 9.50% Senior Notes”), and received cash proceeds of $88.0 million and $139.8 million, respectively. The new 9.50% Senior Notes have the same terms and provisions as the previously issued $487.6 million 9.50% Senior Notes except for the issue price. $100.0 million of new 9.50% Senior Notes accrue interest from October 20, 2023, the date of issuance of the previously issued 9.50% Senior Notes and $150.0 million of new 9.50% Senior Notes accrue interest from April 15, 2024, the date of the last interest payment. We received a cash payment of $2.8 million and $6.1 million related to the accrued interest of the $100.0 million and $150.0 million of new 9.50% Senior Notes, respectively. As at December 31, 2023, we had a $36.4 million balance outstanding under the Company’s credit facility. On February 6, 2024, the outstanding balance under the credit facility was fully re-paid and the credit facility was terminated.
Previous report
On August 19, 2024, the Company entered into a credit facility agreement (“Loan Facility”) with a market leader in the global commodities industry to fund the cash consideration payable to i3 Energy’s shareholders in connection with the i3 Energy acquisition and associated costs (Note 3). The Loan Facility has a borrowing base of £80.0 million (US$107.0 million) and bears interest based on a three-month secured overnight financing rate posted by the Federal Reserve Bank of New York plus a margin of 3.00% per annum for the first three months after the initial drawdown and 6.00% per annum thereafter. The Loan Facility is subject to a commitment fee equal to the higher of $0.5 million and 0.50% of the borrowing base converted to U.S. dollars using the agreed upon GBP to USD foreign exchange rate at the time of initial drawdown date. The Company paid $0.6 million of commitment fees and the Loan Facility was terminated on October 31, 2024.
Previous report
Income Taxes
Previous report
We carry on business in several countries and as a result, we are subject to income taxes in numerous jurisdictions. The determination of our income tax provision is inherently complex and we are required to interpret continually changing regulations and make certain judgments. While income tax filings are subject to audits and reassessments, we believe we have made adequate provision for all income tax obligations. However, changes in facts and circumstances as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease in our provision for income taxes.
Previous report
To assess the realization of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. This determination involves numerous judgments and assumptions and includes estimating factors such as commodity prices, production and other operating conditions. If any of those factors, assumptions or judgments change, the deferred tax asset could change, and in particular decrease in a period where we determine it is more likely than not that the asset will not be realized. Alternatively, a valuation allowance may be reversed where it is determined it is more likely not that the asset will be realized.
Previous report
Legal and Other Contingencies
Previous report
A provision for legal and other contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amount for accrual is a complex estimation process that includes the subjective judgment of management. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. Management closely monitors known and potential legal and other contingencies and periodically determines when we should record losses for these items based on information available to us.
Previous report
Stock-Based Compensation
Previous report
Our stock-based compensation cost is measured based on the fair value of the awards that are ultimately expected to vest. Fair values are determined using pricing models such as the Black-Scholes simulation stock option-pricing model and/or observable share prices. These estimates depend on certain assumptions, including volatility, risk-free interest rate, the term of the awards, the forfeiture rate and performance factors, which, by their nature, are subject to measurement uncertainty. We use historical data to estimate the expected term used in the Black-Scholes option pricing model, option exercises and employee departure behavior. Expected volatilities used in the fair value estimate are based on the historical volatility of our shares. The risk-free rate for periods within the expected term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant.
Previous report
Business Combination
Previous report
Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed in a business combination are recognized at their fair values. Any excess of the consideration paid over the fair value of the net assets acquired and liabilities assumed is recognized as a goodwill and any excess of the fair value of the net assets acquired and liabilities assumed over the consideration paid is recognized as bargain purchase gain in the consolidated statements of operations.
Reworded paragraphs (57)
Previous wording
We are a company focused on oil and gas exploration and production, with assets in Colombia, Canada and Ecuador. Our Colombian properties represented 47%, our Canadian properties represented 46% and our Ecuadorian properties represented 7% of our proved reserves NAR at December 31, 2024, and for the year ended December 31, 2024, 93% of our revenue was generated in Colombia (2023 - 97% and 2022 -100%), 3% of our revenue was generated in Canada (2023 and 2022 - nil) and 4% (2023 - 3%, 2022 - nil) of our revenue was generated in Ecuador. We are headquartered in Calgary, Alberta, Canada.
Current wording
We are a company focused on oil and gas exploration and production, with assets in Colombia, Canada and Ecuador. Our Colombian properties represented 46%, our Canadian properties represented 38%, and our Ecuadorian properties represented 16% of our proved reserves NAR at December 31, 2025, and for the year ended December 31, 2025, 70% of our revenue was generated in Colombia (2024 - 93%; 2023 -97%), 19% of our revenue was generated in Canada (2024 - 3%; 2023 - nil) and 11% (2024 - 4%; 2023 - 3%) of our revenue was generated in Ecuador. We are headquartered in Calgary, Alberta, Canada.
Previous wording
As of December 31, 2024, we had estimated proved reserves NAR of 135.0 MMBOE, an 82% increase from the prior year, of which 50% were proved developed reserves and 62% were oil.
Current wording
As of December 31, 2025, we had estimated proved reserves NAR of 111.6 MMBOE, a 17% decrease from the prior year, of which 57% were proved developed reserves and 71% were oil.
Previous wording
•Net income in 2024 was $3.2 million or $0.10 per share basic and diluted compared to a net loss of $6.3 million or $(0.19) per share basic and diluted in 2023
Current wording
•Net loss in 2025 was $193.1 million or $5.45 per share basic and diluted, which included a non-cash ceiling test impairment in Colombia and Ecuador of $136.3 million, compared to net income of $3.2 million or $0.10 per share basic and diluted in 2024
Previous wording
•Income before income taxes in 2024 was $44.6 million compared to $106.2 million in 2023
Current wording
•Loss before income taxes in 2025 was $232.9 million compared to income before income taxes of $44.6 million in 2024
Previous wording
•Adjusted EBITDA(2)in 2024 was$366.8 million compared to $399.4 million in 2023
Current wording
•Adjusted EBITDA(2)in 2025 was$283.7 million compared to $366.8 million in 2024
Previous wording
•In 2024, we re-purchased 0.5 million and 1.7 million shares of Common Stock through the 2024 and 2023 share re-purchase programs, representing about 1% and 5%, respectively, of shares outstanding as of December 31, 2024
Current wording
•In 2025, we re-purchased 0.7 million shares of Common Stock through the 2024 share re-purchase program, representing about 2% of shares outstanding as of December 31, 2025
Previous wording
•Our 2024 average production NAR was 27,890 BOEPD, an increase from 26,099 BOEPD in 2023 as a result of two-months of production from the newly acquired Canadian operations, and positive exploration drilling results in Ecuador, partially offset by lower production in the Acordionero field
Current wording
•Our 2025 average production NAR was 38,443 BOEPD, an increase from 27,890 BOEPD in 2024 as a result of positive exploration drilling results in Ecuador, full year production from the Canadian operations, partially offset by lower production in the Acordionero and Costayaco fields as a result of export pipeline disruptions and trunk line repairs at the Moqueta field which resulted in the field being shut-in during the third quarter of 2025
Previous wording
•Our 2024 oil, natural gas and NGL sales volumes NAR increased by 6% to 27,436 BOEPD compared to 25,947 BOEPD in 2023
Current wording
•Our 2025 oil, natural gas and NGL sales volumes NAR increased by 37% to 37,664 BOEPD compared to 27,436 BOEPD in 2024
Previous wording
•Oil, natural gas and natural gas liquids (“NGL”) sales for 2024 decreased by 2% to $621.8 million compared to $637.0 million in 2023, primarily as a result of a 3% decrease in Brent price, lower in sales volumes in Colombia, offset by increase in sales volumes in Ecuador, lower differentials, and the addition of natural gas and NGL into the portfolio via the Canadian acquisition in 2024
Current wording
•Oil, natural gas and NGL sales for 2025 decreased by 4% to $596.7 million compared to $621.8 million in 2024, primarily as a result of a 15% decrease in Brent price, lower sales volumes in Colombia, offset by higher sales volumes in Ecuador, lower differentials, and a full year of sales from Canadian operations
Previous wording
•In 2024, we generated net cash provided by operating activities of $239.3 million, an increase of 5% from $228.0 million in 2023
Current wording
•In 2025, we generated net cash provided by operating activities of $313.2 million, an increase of 31% from $239.3 million in 2024
Previous wording
•Operating expenses per boe for 2024 were $20.15, 2% higher compared to 2023, primarily due to higher workovers. removal of diesel subsidies and higher natural gas and electricity costs in Colombia, partially offset by lower operating costs in Ecuador as a result of production ramp-up in 2024. Total operating expenses were$202.3 million in 2024, compared to $186.9 million in 2023, representing an 8% increase as a result of two months of Canadian production
Current wording
•Operating expenses per boe for 2025 were $18.09, 10% or$2.06 per boe lower compared to 2024, primarily due to higher NAR sales volumes. Total operating expenses were$248.7 million in 2025, compared to $202.3 million in 2024, representing an 23% increase as a result of higher operating costs in Ecuador driven by a production ramp-up in 2025, and the full year of Canadian operations
Previous wording
•Quality and transportation discounts per boe increased in 2024 to $17.93 when compared to $14.90 in 2023 primarily due to higher differentials
Current wording
•Quality and transportation discounts per boe in South America decreased in 2025 to$11.04 when compared to $13.93 in 2024 due to lower Castilla, Vasconia and Oriente differentials as a result of higher demand for heavy oil.
Previous wording
Operating netback, as presented, is defined as oil, natural gas and NGL sales less operating and transportation expenses. 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, natural gas and NGL sales to operating netback is provided in the table above.
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
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 non-cash lease expense, lease payments, foreign exchange gains or losses, unrealized derivative instruments gains or losses, transaction costs, other financial instruments gains or losses, other non-cash gains or losses, and stock-based compensation expense or recovery. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is a useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income (loss) to EBITDA and adjusted EBITDA is as follows:
Current wording
EBITDA, as presented, is defined as net income (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, non-cash lease expense, lease payments, foreign exchange gains or losses, unrealized derivative instruments gains or losses, transaction costs, other non-cash gains or losses, and stock-based compensation expense. 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 income (loss) adjusted for DD&A expenses, deferred tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gains or losses, unrealized derivative instruments gains or losses, other financial 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. Free cash flow, as presented, is defined as funds flow from operations less capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income (loss) to funds flow from operations and free cash flow is as follows:
Current wording
Funds flow from operations, as presented, is defined as net income (loss) adjusted for DD&A expenses, asset impairment, deferred tax expense or recovery, stock-based compensation expense, amortization of debt issuance costs, non-cash interest, non-cash lease expense, lease payments, unrealized foreign exchange gains or losses, 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. Free cash flow, as presented, is defined as funds flow from operations less capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income (loss) to funds flow from operations and free cash flow is as follows:
Previous wording
Oil, natural gas and NGL production NAR for the year ended December 31, 2024, increased by 7% to 27,890 BOEPD compared to 26,099 BOEPD in 2023. The increase in production was a result of two months of production from the Canadian operations acquired on October 31, 2024 and positive exploration well drilling results in Ecuador, partially offset by lower production in the Acordionero field caused by downtime related to workovers.
Current wording
Oil production NAR for the year ended December 31, 2024, increased by 7% to 27,890 BOEPD compared to 26,099 BOEPD in 2023. The increase in production was a result of two months production from Canadian operations acquired on October 31, 2024 and positive exploration well drilling results in Ecuador, partially offset by lower production in the Acordionero field caused by downtime related to workovers.
Previous wording
Royalties as a percentage of production for the year ended December 31, 2024, were comparable with royalties as a percentage of production for 2023. Royalties as a percentage of production for the year ended December 31, 2023, decreased 3% compared to 2022 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia and Ecuador.
Current wording
Royalties as a percentage of production for the year ended December 31, 2025, decreased 4% compared to 2024 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia, Ecuador, and Canada. Royalties as a percentage of production for the year ended December 31, 2024, were comparable to 2023.
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 and Chanangue 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
Oil, natural gas and NGL sales for the year ended December 31, 2024, decreased by 2% to $621.8 million compared to $637.0 million in 2023, primarily as a result of a 3% decrease in Brent price and 6% decrease in sales volumes in Colombia, offset by increase in sales volumes in Ecuador, lower differentials, and two months of sales from Canadian operations of $19.0 million in 2024. Vasconia, Castilla and Oriente differentials decreased to $4.78, $8.54 and $8.75 per boe in 2024 from $5.39, $10.22 and $9.91 per boe in 2023, respectively.
Current wording
Oil, natural gas and NGL sales for the year ended December 31, 2024, decreased by 2% to $621.8 million compared to $637.0 million in 2023, primarily as a result of a 3% decrease in Brent price and 6% decrease in sales volumes in Colombia, offset by an increase in sales volumes in Ecuador, lower differentials, and two months of sales from Canadian operations of $19.0 million in 2024.
Previous wording
On a per boe basis, average realized prices decreased by 8% to $61.93 for the year ended December 31, 2024, compared to $67.26 in 2023, primarily as a result of the decrease in benchmark oil prices and the addition of natural gas and liquids to the portfolio in 2024 through the i3 Energy acquisition.
Current wording
On a per boe basis, the average realized price decreased by 8% to $61.93 for the year ended December 31, 2024, compared to $67.26 in 2023, primarily as a result of the decrease in benchmark oil prices and the addition of two months of natural gas and liquids to the portfolio in 2024 through the i3 Energy acquisition.
Previous wording
Operating expensesfor the year ended December 31, 2024, increased by 8% to $202.3 million compared to $186.9 million in 2023. On a per boe basis, operating expenses increased by only 2% or $0.42 to $20.15 compared to $19.73 in the prior year, primarily as a result of $0.48 higher workovers, removal of diesel subsidies and higher natural gas and electricity costs in Colombia, partially offset by lower operating costs in Ecuador as a result of production ramp-up in 2024.
Current wording
Operating expenses for the year ended December 31, 2024, increased by 8% to $202.3 million compared to $186.9 million in 2023. On a per boe basis, operating expenses increased by only 2% or $0.42 to $20.15 in 2024 compared to $19.73 in 2023, primarily as a result of $0.48 higher workovers, removal of diesel subsidies and higher natural gas and electricity costs in Colombia, partially offset by lower operating costs in Ecuador.
Previous wording
Colombian volumes transported through pipelines or via trucks receive a higher realized price but incur higher transportation expenses. Volumes sold at the wellhead have the opposite effect of lower realized price, offset by lower transportation expense. Volumes sold in Ecuador are transported via pipeline. We focus on maximizing operating netback(1) per boe when choosing a transportation method.
Current wording
Colombian volumes transported through pipelines or via trucks receive a higher realized price but incur higher transportation expenses. Volumes sold at the wellhead have the opposite effect of lower realized price, offset by lower transportation expense as transportation costs are netted against the sales price. Volumes sold in Ecuador and Canada are transported via pipeline and trucks. We focus on maximizing operating netback(1) per boe when choosing a transportation method.
Previous wording
Transportation expenses for the year ended December 31, 2024, increased by 27% to $18.5 million or by $0.30 to$1.84 per boe compared to $14.5 million or $1.54 per boe in 2023, as a result of higher sales volumes transported in Ecuador, two months of transporting sales volumes in Canada through pipelines, and an increase in trucking tariffs for Acordionero volumes in 2024.
Current wording
Transportation expenses for the year ended December 31, 2024, increased by 27% to $18.5 million or by $0.30 to $1.84 per boe compared to$14.5 million or $1.54 per boe in 2023, as a result of higher sales volumes transported in Ecuador, two months of transporting sales volumes in Canada through pipelines, and an increase in trucking tariffs for Acordionero volumes in 2024.
Previous wording
DD&A expenses for the year ended December 31, 2023, increased 20% or $1.92 per boe from 2022. On a per boe basis, the DD&A increase in 2023 was due to increased production and higher costs in the depletable base as a result of higher future development costs compared to 2022.
Current wording
DD&A expenses for the year ended December 31, 2024, increased by 7% or $0.21 per boe from 2023. On a per boe basis, the DD&A increase in 2024 was due to increased production relative to reserve additions in Ecuador, two months of DD&A expense from Canadian operations, and higher costs in the depletable base as a result of higher future development costs compared to 2023.
Previous wording
We follow the full cost method of accounting for our oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after-tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the unweighted arithmetic average of the first-day-of-the month Brent price for the 12-month period prior to the ending date of the period covered by the balance sheet. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. Therefore, ceiling test estimates are based on historical prices discounted at 10% per year, and it should not be assumed that estimates of future net revenues represent the fair market value of our reserves.
Current wording
For the year ended December 31, 2025, we recorded ceiling test impairment losses of $136.3 million in Canada and Colombia as a result of lower oil and natural gas prices and revised development plans primarily related to natural gas properties in Canada and reduction of capital investment in Colombia. We follow the full cost method of accounting for our oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after-tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined usingthe average price for the 12-month period prior to the ending date of the period covered by the balance sheet, calculated using unweighted arithmetic average of the first-day-of-the-month price for each month within such period. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. Therefore, ceiling test estimates are based on historical prices discounted at 10% per year and it should not be assumed that estimates of future net revenues represent the fair market value of our reserves. In accordance with GAAP, we used unweighted arithmetic average of the first-day-of-the-month prices as follows: Brent price of$69.38 per boe, Edmonton Light price of $63.21 (C$86.73) per boe, Alberta AECO spot price of $1.42 (C$1.95) per MMBtu, Edmonton Propane price of $24.05 (C$32.99) per boe, Edmonton Butane price of $27.64 (C$37.92) per boe and Edmonton Condensate price of $65.38 (C$89.70) per boe for the December 31, 2025 ceiling test calculations (December 31, 2024 - Brent price of $80.42 per boe, Edmonton Light price of $68.11 (C$98.01) per boe, Alberta AECO spot price of $1.01 (C$1.46) per MMBtu, Edmonton Propane price of $21.17 (C$30.46) per boe, Edmonton Butane price of $33.63 (C$48.39) and Edmonton Condensate price of $70.07 (C$100.83) per boe; and December 31, 2023 - Brent price of $82.51 per bbl).
Previous wording
G&A expenses before stock-based compensationfor the year ended December 31, 2024 decreased 1% as a result of lower business development, legal and consulting costs compared to 2023, offset by the addition of two months of G&A from the newly acquired Canadian operations.
Current wording
G&A expenses before stock-based compensation for the year ended December 31, 2024, increased 3% to $41.4 million as a result of higher severance costs and the addition of two months of G&A from Canadian operations acquired through the i3 acquisition, partially offset by lower business development, legal and consulting costs compared to 2023.
Previous wording
G&A expenses before stock-based compensation, on a per boe basis, for the year ended December 31, 2023, increased by 15% to $4.24 compared to 2022, for the same reason mentioned above.
Current wording
G&A expenses after stock-based compensation for the year ended December 31, 2025, increased by 17% to $60.1 million, compared to 2024 for the same reason mentioned above, partially offset by lower stock-based compensation attributable to the lower share price in 2025.
Previous wording
G&A expenses after stock-based compensation for the year ended December 31, 2024, increased by 8% to $49.6 million, compared to 2023 due to higher stock-based compensation attributable to the higher share price in 2024.
Current wording
G&A expenses after stock-based compensation for the year ended December 31, 2024, increased by 12% to $51.1 million compared to 2023 due to higher stock-based compensation attributable to the higher share price in 2024.
Previous wording
G&A expenses after stock-based compensation, on a per boe basis, for the year ended December 31, 2024, increased by 2% to $4.94 compared to 2023 due to 62% increase in stock-based compensation attributable to higher share price in 2024.
Current wording
G&A expenses after stock-based compensation, on a per boe basis, for the year ended December 31, 2024, increased by 5% to $5.10 per boe compared to 2023 due to a 62% increase in stock-based compensation attributable to higher share price in 2024.
Previous wording
For the years ended December 31, 2024, 2023 and 2022, we had an $8.8 million gain, $11.8 million loss and $2.6 million loss on foreign exchange, respectively. The main sources of foreign exchange gains and losses are the revaluation of taxes receivable and payable, deferred tax assets and liabilities and accounts payable. Under GAAP, income taxes, deferred taxes and accounts payable are considered monetary assets and liabilities and require translation from local currency to the U.S. dollar functional currency at each balance sheet date.
Current wording
For the years ended December 31, 2025, 2024 and 2023, we had an $8.7 million loss, $8.8 million gain and $11.8 million loss on foreign exchange, respectively. The main sources of foreign exchange gains and losses are the revaluation of taxes receivable and payable, deferred tax assets and liabilities and accounts payable. Under GAAP, income taxes, deferred taxes and accounts payable are considered monetary assets and liabilities and require translation from local currency to the U.S. dollar functional currency at each balance sheet date.
Previous wording
Current income tax expense for the year ended December 31, 2024, was $69.3 million (2023 - $55.7 million; 2022 - $80.6 million). Current income tax expense increased for the year ended December 31, 2024, compared to 2023, primarily due to the additional taxable income generated in Ecuador and Canada.
Current wording
Current income tax expense for the year ended December 31, 2025, was $15.9 million (2024 - $69.3 million; 2023 - $55.7 million). Current income tax expense decreased for the year ended December 31, 2025, compared to 2024, primarily due to the lower taxable income generated in Colombia.
Previous wording
The deferred income tax expense was a recovery of $27.9 million for the year ended December 31, 2024, primarily as a result of the recognition of additional tax losses resulting from a tax planning strategy, which were partially offset by tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia.
Current wording
The deferred income tax expense was a recovery of $27.9 million for the year ended December 31, 2024, primarily as a result of the recognition of additional tax losses resulting from a tax planning strategy, which were partially offset by tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia. The deferred income tax expense of $56.8 million for the year ended December 31, 2023 was primarily a result of tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia.
Previous wording
Our effective tax rate was 106% for the year ended December 31, 2023, compared with 43% in 2022. The increase in the effective tax rate was primarily due to an increase in non-deductible foreign exchange adjustments, impact of foreign taxes and other permanent differences. These were partially offset by a decrease in valuation allowance and non-deductible stock-based compensation.
Current wording
Our effective tax rate was 17% for the year ended December 31, 2025, compared to 93% in 2024. The decrease in the effective tax rate was primarily due to a decrease in valuation allowance and impact of foreign taxes, partially offset by an increase in non-deductible foreign exchange adjustments and other permanent differences.
Previous wording
Our effective tax rate was 93% for the year ended December 31, 2024, compared to 106% in 2023. The decrease in the effective tax rate was primarily due to a decrease in non-deductible foreign exchange adjustments, 2022 true-up related to tax planning strategy, other permanent differences and impact of foreign taxes. These were partially offset by an increase in valuation allowance.
Current wording
Our effective tax rate was 93% for the year ended December 31, 2024, compared with 106% in 2023. The decrease in the effective tax rate was primarily due to a decrease in non-deductible foreign exchange adjustments, 2022 true-up related to tax planning strategy, other permanent differences and impact of foreign taxes. These were partially offset by an increase in valuation allowance.
Previous wording
The difference between our effective tax rate of 93% for the year ended December 31, 2024, and the 45% Colombian statutory tax rate was primarily due to an increase in impact of foreign taxes, valuation allowance, non-deductible royalties in Colombia, other permanent differences and non-deductible stock-based compensation. These were partially offset by a 2022 true-up related to tax planning strategy and non-taxable foreign exchange adjustments.
Current wording
The difference between our effective tax rate of 93% for the year ended December 31, 2024, and the 21% US statutory rate was primarily due to the impact of foreign taxes, valuation allowance, non-deductible royalties in Colombia, other permanent differences and non-deductible stock-based compensation. These were partially offset by a 2022 true-up related to tax planning strategy and non-taxable foreign exchange adjustments.
Previous wording
During the year ended December 31, 2024, the company strategically revised its 2022 tax return to use its tax receivable balance to offset current tax liabilities, rather than applying net operating loss carryforwards. This decision was driven by the expectation of higher future income tax rates and increased profitability. As a result, there was an increase in current tax expense of approximately $27.8 million which was offset by long-term tax receivable, ensuring no impact on cash flows. This approach preserved the Company’s net operating loss carryforward for future periods, providing greater tax benefits and flexibility in recovering tax receivables, while strengthening our equity position.
Current wording
During the year ended December 31, 2024, we strategically revised our 2022 tax return to use our tax receivable balance to offset current tax liabilities, rather than applying net operating loss carryforwards. This decision was driven by the expectation of higher future income tax rates and increased profitability. As a result, there was an increase in current tax expense of approximately $27.8 million which was offset by long-term tax receivable, ensuring no impact on cash flows. This approach preserved the Company’s net operating loss carryforward for future periods, providing greater tax benefits and flexibility in recovering tax receivables, while strengthening our equity position.
Previous wording
The difference between our effective tax rate of 106% for the year ended December 31, 2023, and the 45% Colombian statutory rate was primarily due to an increase in non-deductible foreign exchange adjustments, other permanent differences, the impact of foreign taxes, non-deductible royalties in Colombia and non-deductible stock-based compensation. These were partially offset by a decrease in valuation allowance.
Current wording
The difference between our effective tax rate of 106% for the year ended December 31, 2023, and the 21% US statutory was primarily due to the impact of foreign taxes, non-deductible foreign exchange adjustments, other permanent differences, non-deductible royalties in Colombia and non-deductible stock-based compensation.
Previous wording
Our Colombian, Canadian and Ecuadorian development operations are expected to represent approximately 52%, 37% and 11% of our 2025 production.
Current wording
Our Colombian, Canadian and Ecuadorian development expenditures are expected to represent approximately 50%,35% and 15% of our 2026 capital program.
Previous wording
Our base capital program for 2025 is $240 million to $280 million for exploration and development activities. Based on the mid-point of the 2025 guidance, the capital budget is forecasted to be approximately 75%directed to development activities and 25% directed to exploration activities. Approximately 30% of the development activities included in the 2025 capital program are expected to be directed to facilities to support future production growth and enhance recovery factors.
Current wording
Our base capital program for 2026 is $120 million to $160 million with over 90% attributed to development activities. Based on the mid-point of the 2026 guidance, approximately 20% of the development activities included in the 2026 capital program are expected to be directed to facilities to support future production growth and enhance recovery factors.
Previous wording
We expect our 2025 capital program to be fully funded by cash flows from operations. Funding this program from cash flows from operations relies in part on average Brent oil prices of $75.00 per boe, WTI oil prices of $71.00 per boe and average AECO gas prices of C$2.50 per mcf for 2025.
Current wording
We expect cash flows from operations to fully fund our 2026 capital program, assuming average Brent oil prices of $65.00 per boe, WTI oil prices of $61.00 per boe and average AECO natural gas prices of C$3.00 per mcf, together with expected production of 42,000 to 47,000 boepd.
Showing the first 40 of 57 pairs. Open the source sections for the rest.
Rearranged current paragraphs (3)
Current report — wording carried from elsewhere
The deferred income tax expense was a recovery of $55.6 million for the year ended December 31, 2025, primarily as a result of the recognition of additional tax losses from Colombia.
Current report — wording carried from elsewhere
We were in compliance with all applicable covenants related to the RBL facility as of December 31, 2025.
Current report — wording carried from elsewhere
Angeles, Cohembi fields in Colombia, and Charapa and Chanangue Blocks in Ecuador. In total, we converted 2.6 billion standard cubic feet of natural gas into electricity instead of being flared for the year ended December 31, 2025 and have incurred capital expenditures of $45.5 million since 2018. The extent of spending on projects is directly linked to reducing the climate impact of our operations.
Rearranged previous paragraphs (4)
Previous report — wording carried elsewhere
•Transportation expenses per boe for 2024 increased by 19% to $1.84 compared to $1.54 in 2023, due tohigher sales volumes transported in Ecuador, two months transportation of sales volumes in Canada through pipelines, and an increase in trucking tariffs for Acordionero volumes in 2024
Previous report — wording carried elsewhere
DD&A expenses for the year ended December 31, 2024, increased by 7% or $0.21 per boe from 2023 due to higher production in Ecuador, the addition of DD&A expense from Canadian operations acquired in the i3 Energy acquisition, and higher costs in the depletable base as a result of higher future development costs compared to 2023.
Previous report — wording carried elsewhere
For the years ended December 31, 2024, 2023 and 2022, we hadno ceiling test impairment losses. In accordance with GAAP, we used unweighted arithmetic average of the first-day-of-the-month prices as follows; Brent Crude $80.42 per boe, Edmonton Light Crude of C$98.01 per boe, Alberta AECO spot price of C$1.46 per MMBtu Edmonton Propane C$30.46 per boe, Edmonton Butane C$48.39 per boe and Edmonton Condensate C$100.83 per boe for the December 31, 2024 ceiling test calculations (December 31, 2023, and 2022 Brent Crude - $82.51 and $97.98 per boe, respectively).
Previous report — wording carried elsewhere
The deferred income tax expense of $56.8 million and $25.3 million for the years ended December 31, 2023 and 2022, respectively, were primarily a result of tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia.