GRAN TIERRA ENERGY INC
For the period ended Dec 31, 2024. Filed Feb 24, 2025.
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.
FY2024 · Filed Feb 24, 2025
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 2023-12-31; filed 2024-02-20.
0001273441-24-000006
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent 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 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 150 previous paragraphs and 160 current paragraphs.
65 unchanged; 54 reworded; 40 added; 31 removed; 0 previous and 1 current paragraphs rearranged.
Tables are not compared: 22 previous and 25 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 (40)
Current 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
Current report
•Adjusted EBITDA(2)in 2024 was$366.8 million compared to $399.4 million in 2023
Current report
•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 report
•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 report
•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 report
•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
Current 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.
Current report
(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure.
Current report
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 report
Oil, Natural Gas and NGL Sales
Current report
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 report
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 report
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 report
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 report
(1)Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure.
Current report
b
Current report
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).
Current report
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 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.
Current report
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 report
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 report
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 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.
Current report
Foreign Exchange (Gains) Losses
Current report
Income Tax Expense
Current report
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 report
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 report
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 report
Our Colombian, Canadian and Ecuadorian development operations are expected to represent approximately 52%, 37% and 11% of our 2025 production.
Current report
In 2024, we drilled 10 development plus four service wells in Colombia, seven exploration wells in Ecuador, and nine development wells in Canada. Of the wells drilled in Colombia, eight were drilled in Midas Block and six in Chaza Block. In Ecuador, five wells were drilled and Charapa Block and two in Chanangue Block. In Canada, we drilled nine development wells, four of which were in Clearwater acreage with the remaining wells drilled in our Rimbey, Lodgepole and Wapiti acreage. As at December 31, 2024, of the exploration and development wells drilled, 18 were producing and eight were in-progress.
Current report
Under the terms of 9.50% Senior Notes agreement, we are required to maintain compliance with the following financial covenants:
Current report
i. consolidated interest coverage ratio of not less than 2.5; and
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 3.0.
Current report
As at December 31, 2024, we were in compliance with all applicable covenants.
Current 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.
Current report
In connection with the i3 Energy acquisition closing on October 31, 2024, the Company amended and restated the existing revolving credit facility agreement of i3 Energy Canada Ltd. (“i3 Energy Canada”) with National Bank of Canada dated March 22, 2024. As a result of the amendment and restatement, among other things, the borrowing base was revised to C$100.0 million (US$69.5 million) with available commitment of a C$50.0 million (US$34.7 million) revolving credit facility. Subject to the next borrowing base redetermination, which will occur on or before June 30, 2025, the revolving credit facility is available until October 31, 2025 with a repayment date of October 31, 2026, which may be extended by further periods of up to 364 days, subject to lender approval. The drawn down amounts under the revolving credit facility can either be in Canadian or U.S. dollars and bear interest rates equal to either the Canadian prime rate or U.S. Base Rate plus a margin ranging from 2.00% to 4.00% per annum or for CORRA loans and SOFR loans plus a margin ranging from 3.00% to 5.00% per annum. Undrawn amounts under the revolving credit facility bear standby fee ranging from 0.75% to 1.25% per annum. In each case, the margin or standby fee, as applicable is based on Net Debt to EBITDA ratio of Gran Tierra Canada Ltd.
Current report
Established in 2017, NaturAmazonas addresses the root causes of deforestation and develops nature-based solutions for reversing the process while increasing the well-being of nearby communities. We are an industry leader in reforestation and conservation in Colombia. It has created an effective model for creating change at scale by engaging communities in protecting their environment and securing partnerships with public and private institutions, as well as stakeholders in long-term reforestation and conservation efforts. NaturAmazonas is projected to sequester approximately 8.7 million tonnes of CO2, equivalent to approximately 19 years of our 2024 Scope 1 and Scope 2 emissions 1. We have planted over 1.9 million trees and conserved, preserved, or reforested more than 5,300 hectares of land through all of our environmental efforts to date.
Current report
1 2024 emissions are based on full year emissions from Colombia and Ecuador, plus post-transaction date emissions in Canada (November & December).
Current report
Business Combination
Current 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.
Removed paragraphs (31)
Previous report
•Adjusted EBITDA(2)for 2023 was$399.4 million compared to $481.9 million in 2022
Previous report
•Our total 2023 average production NAR was 26,099 BOPD, an increase from 23,815 BOPD in 2022 as a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador
Previous report
•Oil sales per bbl for 2023 were $67.26, 18% lower compared to 2022, as a result of a decrease in benchmark oil prices
Previous report
•During 2023, the Company generated$57.9 million of free cash flow(2) which was used for debt reduction and share re-purchases
Previous report
•Operating expenses per bbl for 2023 were $19.73, 5% higher compared to 2022, primarily due to higher lifting costs attributed to road and pipeline maintenance, power generation and equipment rental, offset by lower workovers. Total operating expenses were$186.9 million in 2023, compared to $162.4 million in 2022, representing a 15% increase
Previous report
•Quality and transportation discounts per bbl decreased in 2023 to $14.90 when compared to $16.79 in 2022. The decrease was due to the utilization of more favorable delivery points than in 2022
Previous report
•Transportation expenses per bbl for 2023 increased by 31% to $1.54 compared to $1.18 in 2022, primarily due to utilization of new transportation routes in Colombia and Ecuador related to exploration wells and the depreciation of U.S. dollar against the Colombian peso during 2023
Previous report
•Capital expenditures decreased by$17.7 million or 7% to $218.9 million compared to 2022 due to a more condensed drilling program during 2023
Previous report
(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure.
Previous report
Oil production NAR for the year ended December 31, 2022, increased by 10% to 23,815 BOPD compared to 21,588 BOPD in 2021. Production increased as a result of successful drilling and workover campaigns in Acordionero and Costayaco fields, less disruptions from blockades in Suroriente and production from exploration success in Ecuador.
Previous report
Oil Sales
Previous report
Oil sales for the year ended December 31, 2022, increased by 50% to $711.4 million compared to $473.7 million in 2021, primarily as a result of a 40% increase in Brent price, 10% higher sales volumes, partially offset by 55% higher quality and transportation discounts in 2022. Castilla and Vasconia differentials increased to$9.81 and$4.99 from $5.74 and $3.52, respectively, per bbl in 2021.
Previous report
On a per bbl basis, average realized prices increased by 37% to $82.25 for the year ended December 31, 2022, compared to $60.09 in 2021, primarily as a result of the increase in benchmark oil prices, offset by higher Castilla and Vasconia differentials in 2022.
Previous report
Operating expenses for the year ended December 31, 2022, increased by 20% to $162.4 million compared to $135.7 million in 2021. On a per bbl basis, operating expenses increased by 9% or $1.55 to $18.77 compared to $17.22 in 2021, primarily as a result of $0.48 per bbl higher workovers and $1.07 per bbl higher lifting costs mainly attributed to higher power generation due to increased activities attributed to higher production and water flood program in all major fields.
Previous report
Transportation expenses for the year ended December 31, 2023, increased by 43% to $14.5 million or by $0.36 to$1.54 per bbl compared to $10.2 million or $1.18 per bbl in 2022, as a result of the utilization of new transportation routes related to sales from exploration wells in Colombia and Ecuador, the depreciation of the U.S. dollar against the Colombian peso and higher sales volumes.
Previous report
Transportation expenses for the year ended December 31, 2022, decreased by 12%to$10.2 million or by $0.30 per bbl to $1.18 per bbl compared to$11.6 million or $1.48 per bbl in 2021. The decrease in transportation expenses per bbl was a result of the higher volumes sold at the wellhead and higher sales volumes in 2022 compared to the corresponding year of 2021. In addition, during 2021, alternative transportation routes were utilized due to maintenance of the Impala terminal, which had higher transportation costs per bbl.
Previous report
(1)Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure.
Previous report
For the years ended December 31, 2023, 2022, and 2021, we had no ceiling test impairment losses. In accordance with GAAP, we used an average Brent price of $82.51 per bbl less corresponding differentials for the purpose of the December 31, 2023 ceiling test calculation (2022 and 2021 - $97.98 and $68.92 per bbl, respectively).
Previous report
On a per bbl basis, G&A expenses before stock-based compensation for the year ended December 31, 2022, increased by 5% to $3.69 compared to 2021 due to higher costs for optimization projects and lease obligations expenses related to additional leases capitalized during 2022. Total G&A expenses before stock-based compensation for the year ended December 31, 2022, increased 15% to $31.9 million compared to 2021 for the same reason mentioned above.
Previous report
On a per bbl basis, G&A expenses after stock-based compensation costs for the year ended December 31, 2022, increased by 3% to $4.74 per bbl compared to 2021 for the same reason mentioned above and higher stock-based compensation expense. Stock-based compensation per bbl decreased by 2% due to higher sales volumes in proportion to the increase in stock-based compensation expense in 2022. Total G&A expenses after stock-based compensation increased 13% to $41.0 million due to higher stock-based compensation expense for the year ended December 31, 2022, compared to 2021.
Previous report
Foreign Exchange Losses
Previous report
Income Tax Expense and Recovery
Previous report
Our effective tax rate was 43% for the year ended December 31, 2022, compared with (84)% in 2021. The increase in the effective tax rate was primarily due to an increase in valuation allowance, other permanent differences, stock-based compensation costs, and non-deductible third party royalties in Colombia. These were slightly offset by a decrease foreign currency translation adjustment and the impact of foreign taxes.
Previous report
The difference between our effective tax rate of (84)% for the year ended December 31, 2021, and the 31% Colombian statutory was primarily due to a decrease in the valuation allowance and other permanent differences, which were partially offset by an increase in foreign currency translation adjustment, foreign taxes, stock-based compensation costs, non-deductible third party royalties in Colombia, and non-deductible investment loss on PetroTal.
Previous report
Our Colombian development operation is expected to represent 93% of our production and approximately 60% - 70% of our 2024 capital budget, with the remainder allocated to exploration activities.
Previous report
In 2023, we spud 17 development and eight service wells in Colombia and none in Ecuador. Of the wells drilled in Colombia, 13 were drilled in Midas Block and 12 in Chaza Block. As at December 31, 2023, of the 17 development wells 15 were producing, and two were in-progress.
Previous report
On April 11, 2023, we and Ecopetrol S.A. renegotiated the terms of the contract for our operatorship of the Suroriente Block which was previously scheduled to end in mid-2024 and executed the Suroriente Continuation Agreement. The duration of the contract was extended for 20 years from September 1, 2023 (the “Effective Date”), the date on which we satisfied the relevant conditions precedent and regulatory approval was received. We continue to be the operator of the Suroriente Block. In connection with the contract extension, we paid cash consideration of $6.2 million and provided letters of credit of $123.0 million (refer to Note 12 to the Consolidated Financial Statements) related to committed capital investments to be made over a three-year period from the Effective Date.
Previous report
During the year ended December 31, 2023, we, as guarantor, and Gran Tierra Energy Colombia GmbH and Gran Tierra Operations Colombia GmbH, as borrowers, had a credit facility of $50 million which was paid in full and terminated on February 6, 2024. Interest under the credit facility was based on the secured overnight financing rate posted by the Federal Reserve Bank of New York plus a credit margin of 6.00% and a credit-adjusted spread of 0.26% with undrawn amounts under the credit facility bearing interest at 2.10% per annum, based on the amount available. Prior to termination, the credit facility was secured by our Colombian assets and economic rights and had a final maturity date of August 15, 2024. As of December 31, 2023, the credit facility was drawn by $36.4 million. During the year ended December 31, 2023, we incurred the weighted-average interest rate on credit facility of 11.59%.
Previous report
On October 20, 2023, we completed exchange offers of $247.1 million of 6.25% Senior Notes (the “6.25% Senior Notes”) and $275.8 million of 7.75% Senior Notes (the “7.75% Senior Notes”) for $487.6 million 9.50% Senior Secured Notes due 2029 (the “9.50% Senior Notes” and, together with the 7.75% Senior Notes and the 6.25% Senior Notes, the “Senior Notes”). The exchange consideration for $242.5 million of 6.25% Senior Notes included early participation premium of $80 for each $1,000 aggregate principal amount with the remainder of $4.6 million exchanged at $1,000 and for $274.2 million of 7.75% Senior Notes early participation premium of $20 for each $1,000 aggregate principal amount with the remainder of $1.6 million of 7.75% Senior Notes exchanged at $950 for each $1,000 aggregate principal amount. In addition, the Company paid cash consideration of $60.0 million for 6.25% Senior Notes exchanged as part of total consideration to eligible holders on a pro-rata basis, for each $1,000 aggregate principal amount tendered and accepted for the early exchange deadline. The Senior Notes tendered and accepted for exchange, as well as the notes held as treasury bonds, were cancelled. The exchange of the 6.25% Senior Notes was accounted for as debt extinguishment and resulted in a gain of $5.3 million. The exchange of 7.75% Senior Notes was accounted for as debt modification and resulted in a loss of $6.1 million related to third party fees.
Previous report
During the year ended December 31, 2023, we purchased in the open market $8.0 million of 6.25% Senior Notes for cash consideration of $6.8 million, including interest payable of $0.1 million. The purchase resulted in a $1.1 million gain, which included the write-off of deferred financing fees of $0.1 million. The Company canceled all previously purchased 6.25% Senior Notes as at December 31, 2023.
Previous report
We voluntarily support projects for the protection of the environment. Through programs like Gran Tierra’s flagship environmental initiative, NaturAmazonas, in partnership with the international non-governmental organization Conservation International, we have committed to reforesting 1,000 hectares of land and securing and maintaining 18,000 hectares of forest in the Andes-Amazon rainforest corridor. The NaturAmazonas project alone is expected to sequester approximately 8.7 million tonnes of carbon dioxide over its lifetime. During the year ended December 31, 2023, Gran Tierra signed a four-year extension with Conservation International to continue the NaturAmazonas project. This extension will, among other benefits, result in the development of the additional 100 restoration agreements to restore more than 250 additional hectares of land while ensuring the benefits from NaturAmazonas’ first phase sustain. We have planted over 1.5 million trees and conserved, preserved, or reforested more than 3,800 hectares of land through all of our environmental efforts since 2018. We will continue to implement projects that focus on environmental protection, conservation and reforestation efforts.
Reworded paragraphs (54)
Previous wording
We are a company focused on oil and gas exploration and production with assets currently in Colombia and Ecuador. Our Colombian properties represented 94% of our proved reserves NAR at December 31, 2023. For the year ended December 31, 2023, 97% of our revenue was generated in Colombia (2022 - 100% and 2021 -100%). 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 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.
Previous wording
As of December 31, 2023, we had estimated proved reserves NAR of 74.3 MMBOE, a 13% increase from the prior year, of which 53% were proved developed reserves and 100% were oil.
Current 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.
Previous wording
•Net loss in 2023 was $6.3 million or $(0.19) per share basic and diluted compared to a net income of $139.0 million or $3.81 per share basic and $3.76 per share diluted in 2022
Current 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
Previous wording
•Income before income taxes in 2023 was $106.2 million compared to $244.9 million in 2022
Current wording
•Income before income taxes in 2024 was $44.6 million compared to $106.2 million in 2023
Previous wording
•In 2023, we re-purchased 1.3 million and 1.0 million shares of Common Stock through the 2022 and 2023 share re-purchase programs, representing about 4% and 3%, respectively, of shares outstanding as of December 31, 2023
Current 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
Previous wording
•Our total 2023 oil sales volumes NAR increased by 9% to 25,947 BOPD compared to 23,696 BOPD in 2022
Current 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
Previous wording
•Oil sales for 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 Castilla and Vasconia differentials, partially offset by 9% increase in sales volumes and lower transportation discounts
Current 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
Previous wording
•In 2023, we generated net cash provided by operating activities of $228.0 million, a decrease of 47% from $427.7 million in 2022
Current 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
Previous wording
•General and administrative (“G&A”) expenses before stock-based compensation per bbl for 2023 increased by 15% to $4.24 compared to $3.69 in 2022 dueto business development activities, higher salaries related to increased headcount in Ecuador to support ramp-up of operations and the strengthening of the Colombian peso during 2023. G&A expenses before stock-based compensation were $40.1 million in 2023 compared to $31.9 million in 2022, representing a 26% increase
Current wording
•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 wording
Operating netback, EBITDA, adjusted EBITDA, funds flow from operations, and free cash flow are non-GAAP measures which do not have any standardized meaning prescribed under General Accepted Accounting Principles (“GAAP”). Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to net income or 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. Each non-GAAP financial measure is presented along with 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, funds flow from operations, and free cash flow are non-GAAP measures which do not have any standardized meaning prescribed under U.S. General Accepted Accounting Principles (“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 oil 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 sales to operating netback is provided in the table above.
Current 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.
Previous wording
EBITDA, as presented, is defined as net income or loss adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense, and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, lease payments, foreign exchange gains or losses, unrealized derivative instruments gains or losses, other financial instruments gains or losses, 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 or 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 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:
Previous wording
Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, deferred tax expense or recovery, stock-based compensation expense, 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 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 or 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, 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:
Previous wording
Oil Production and Sales Volumes, BOPD
Current wording
Oil, Natural Gas and NGL Production and Sales Volumes, BOEPD
Previous wording
Oil production NAR for the year ended December 31, 2023, increased by 10% to 26,099 BOPD compared to 23,815 in 2022. The increase in production was a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador.
Current wording
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 wording
Royalties as a percentage of production for the year ended December 31, 2023, decreased compared to 2022 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia.
Current 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.
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.
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 and Chanangue Blocks. Canada includes several areas in the Western Canadian Sedimentary Basin with all production in Alberta, Canada.
Previous wording
Oil 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 Castilla and Vasconia differentials partially offset by 9% higher sales volumes and lower transportation discounts in 2023. Castilla and Vasconia differentials increased to$10.22 and$5.39 from $9.81 and $4.99 per bbl in 2022, respectively. During the year ended December 31, 2023, we commenced sales in Ecuador which were subject to a $9.91 per bbl Oriente differential.
Current wording
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 wording
On a per bbl 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 and higher Castilla and Vasconia differentials in 2023.
Current wording
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 wording
The following table shows the effect of changes in realized price and sales volumes on our oil sales for the years ended December 31, 2023, 2022, and 2021:
Current wording
The following table shows the effect of changes in realized price and sales volumes on our oil, natural gas and NGL sales for the years ended December 31, 2024, 2023, and 2022:
Previous wording
Operating expensesfor the year ended December 31, 2023, increased by 15% to $186.9 million compared to $162.4 million in 2022. On a per bbl basis, despite significant inflationary pressures operating expenses only increased by only 5% or $0.96 to $19.73 compared to $18.77 in the prior year, primarily as a result of $2.23 per bbl 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 bbl of lower workovers. As a result of an El-Niño-induced drought, power costs have 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.
Current wording
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 wording
We have options to sell our oil through multiple pipelines and trucking routes. Each transportation route has varying effects on realized price and transportation expenses. The following table shows the percentage of oil volumes we sold in Colombia and Ecuador using each transportation method for each of the three years ended December 31, 2023:
Current wording
We have options to sell our oil, natural gas and NGL through multiple pipelines and, in Colombia, trucking routes. Each transportation route has varying effects on realized 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 transportation method for each of the last three years ending December 31, 2024:
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 bbl 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. Volumes sold in Ecuador are transported via pipeline. We focus on maximizing operating netback(1) per boe when choosing a transportation method.
Previous wording
The following table shows the variance in our average realized price net of transportation expenses in Colombia and Ecuador for each of the three years ended December 31, 2023:
Current wording
The following table shows the variance in our average realized price net of transportation expenses in Colombia, Ecuador and Canada for each of the three years ended December 31, 2024:
Previous wording
DD&A expenses for the year ended December 31, 2022, increased 29% or $3.10 per bbl from 2021. On a per bbl basis, the DD&A increase in 2022 was due to increased production and higher costs in the depletable base compared to 2021.
Current wording
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 wording
DD&A expenses for the year ended December 31, 2023, increased by 20% or $1.92 per bbl from 2022. On a per bbl 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, 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.
Previous wording
On a per bbl basis, G&A expenses before stock-based compensation for the year ended December 31, 2023, increased by 15% to $4.24 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. Total G&A expenses before stock-based compensation for the year ended December 31, 2023, increased by 26% to $40.1 million compared to 2022 for the same reason mentioned above.
Current wording
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 wording
On a per bbl basis, G&A expenses after stock-based compensation for the year ended December 31, 2023, increased by 2% to $4.84 compared to 2022 due to higher G&A expenses before stock-based compensation, partially offset by 43% decrease in stock-based compensation expense which was a result of lower share price in 2023. Total G&A expenses after stock-based compensation for the year ended December 31, 2023, increased by 12% to $45.8 million, compared to 2022 for the same reason mentioned above.
Current wording
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 wording
For the years ended December 31, 2023, 2022 and 2021, we had foreign exchange losses of $11.8 million, $2.6 million and $20.5 million, 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, 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.
Previous wording
Current income tax expense for the year ended December 31, 2023, was $55.7 million (2022 - $80.6 million; 2021 - $4.5 million). Current income tax expense decreased for the year ended December 31, 2023, compared to 2022, primarily due to a decrease in taxable income.
Current 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.
Previous wording
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. The deferred income tax recovery of $23.8 million for the year ended December 31, 2021, was mainly a result of the release of the valuation allowance in Colombia, which was partially offset by excess tax depreciation compared with 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.
Previous wording
Our effective tax rate was 106% for the year ended December 31, 2023, compared to 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 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.
Previous wording
The difference between our effective tax rate of 106% for the year ended December 31, 2023, and the 45% Colombian statutory tax 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 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.
Previous wording
The difference between our effective tax rate of 43% for the year ended December 31, 2022, and the 35% Colombian statutory rate 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.
Current wording
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 wording
(1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure.
Current wording
(1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure.
Previous wording
Our base capital program for 2024 is $210 million to $240 million for exploration and development activities. Based on the mid-point of the 2024 guidance, the capital budget is forecasted to be approximately 60% directed to development and 40% to exploration activities. Approximately 20% of the development activities included in the 2024 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 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.
Previous wording
We expect our 2024 capital program to be fully funded by cash flows from operations. Funding this program from cash flows from operations relies in part on Brent oil prices being $70 per bbl for 2024.
Current 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.
Previous wording
Capital expenditures during the year ended December 31, 2023 were $218.9 million.
Current wording
Capital expenditures during the year ended December 31, 2024 were $234.2 million.
Previous wording
During the year ended December 31, 2023, we spud the following wells in Colombia:
Current wording
During the year ended December 31, 2024, we spud the following wells in Colombia, Ecuador and Canada:
Previous wording
We believe that our capital resources, including cash on hand and cash generated from operations will provide us with sufficient liquidity to maintain current operations and execute the capital program for the next 12 months and beyond, given current oil price trends and production levels. 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 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, 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 maintain current operations and execute the capital program for the next 12 months and beyond, given current oil and natural gas price trends and production levels. 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 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, be located in basins or countries beyond our current operations, involve joint ventures, or be sizable compared to our current assets and operations.
Showing the first 40 of 54 pairs. Open the source sections for the rest.
Rearranged current paragraphs (1)
Current report — wording carried from 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.