What changed in GRAN TIERRA ENERGY INC.'s 10-K — 2022 vs 2023
vs
Paragraph-level year-over-year comparison of GRAN TIERRA ENERGY INC.'s 2022 and 2023 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2023 report.
+213 added−250 removedSource: 10-K (2024-02-20) vs 10-K (2023-02-22)
Top changes in GRAN TIERRA ENERGY INC.'s 2023 10-K
213 paragraphs added · 250 removed · 162 edited across 5 sections
- Item 7. Management's Discussion & Analysis+138 / −165 · 105 edited
- Item 1A. Risk Factors+47 / −53 · 39 edited
- Item 4. Mine Safety Disclosures+19 / −17 · 10 edited
- Item 5. Market for Registrant's Common Equity+4 / −11 · 4 edited
- Item 7A. Quantitative and Qualitative Disclosures About Market Risk+5 / −4 · 4 edited
Item 1A. Risk Factors
Risk Factors — what could go wrong, per management
39 edited+8 added−14 removed92 unchanged
Item 1A. Risk Factors
Risk Factors — what could go wrong, per management
39 edited+8 added−14 removed92 unchanged
2022 filing
2023 filing
Biggest changeThe extent to which the COVID-19 pandemic adversely affects our business, results of operations and financial condition will depend on future developments, many of which are outside of our control. such as the continued severity, including any sustained geographic resurgence; the emergence of new 18 variants and strains of the COVID-19 virus; the success of actions to contain or treat the virus, and actions taken by governmental authorities and other third parties in response to the pandemic.
Biggest changeThe extent to which our business, results of operations and financial condition will be affected by such events depend on future developments, many of which are outside of our control, such as the duration, severity, and sustained geographic spread of the virus, and the impact and effectiveness of governmental actions to contain and treat outbreaks, including government policies and restrictions; vaccine hesitancy, vaccine mandates, and voluntary or mandatory quarantines; and the global response surrounding such uncertainties.
Any changes in the oil and gas or investment regulations and policies or a shift in political attitudes in Ecuador or Colombia are beyond our control and may significantly hamper our ability to expand our operations or operate our business at a profit.
Any changes in the oil and gas or investment regulations and policies or a shift in political attitudes in Colombia or Ecuador are beyond our control and may significantly hamper our ability to expand our operations or operate our business at a profit.
Although a Peace Agreement was ratified by Colombian government in 2016, the result of which was the demobilization and disarmament of the Revolutionary Armed Forces of Colombia (“FARC”), there continue to be examples of violence against pipelines and other infrastructure that has been attributed to former FARC dissident groups and other illegal groups.
Although a Peace Agreement was ratified by the Colombian government in 2016, the result of which was the demobilization and disarmament of the Revolutionary Armed Forces of Colombia (“FARC”), there continue to be examples of violence against pipelines and other infrastructure that has been attributed to former FARC dissident groups and other illegal groups.
Revocation or suspension of our environmental and operating permits could have a material adverse effect on our business, financial condition and results of operations. In Colombia, the ANH is delegated by Ministry of Mining and Energy to offer and award new blocks through exploration and production (“E&P) and technical evaluation agreement contract terms.
Revocation or suspension of our environmental and operating permits could have a material adverse effect on our business, financial condition and results of operations. In Colombia, the ANH is delegated by the Ministry of Mining and Energy to offer and award new blocks through exploration and production (“E&P) and technical evaluation agreement contract terms.
Finally, although we strive to operate our business operations to accommodate expected climatic conditions, to the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather conditions in the markets we serve or the areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.
Finally, although we strive to operate our business operations to accommodate expected climatic conditions, to the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather conditions in the markets we serve or the 25 areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.
GTE mitigates this risk through the maintenance of surplus storage capacity at its facilities (typically 3-days by design) and the optionality of trucking oil to points of sale. We are vulnerable to risks associated with geographically concentrated operations The vast majority of our production comes from four fields located in Colombia.
GTE mitigates this risk through the maintenance of surplus storage capacity at its facilities (typically 3-days by design) and the optionality of trucking oil to points of sale. 20 We are vulnerable to risks associated with geographically concentrated operations The vast majority of our production comes from four fields located in Colombia.
Under new Colombia regulation, we may not be able to obtain new exploration licenses which can have adverse impact on our future exploration activities, production and operations. 24 Environmental regulation and risks may adversely affect our business Environmental regulation is stringent and the costs and expenses of regulatory compliance are increasing.
Under new Colombia regulation, we may not be able to obtain new exploration licenses which can have adverse impact on our future exploration activities, production and operations. Environmental regulation and risks may adversely affect our business Environmental regulation is stringent and the costs and expenses of regulatory compliance are increasing.
While blockages have been historically directed at the State, the resulting impact may hinder our ability to mobilize oil, personnel and equipment, resulting in temporary shut-in of production or negatively impacting Company assets. Colombia and Ecuador also both have a history of security problems.
While blockages have been historically directed at the State, the resulting impact may hinder our ability to mobilize oil, personnel and equipment, resulting in temporary shut-in of production or negatively impacting our assets. Colombia and Ecuador also both have a history of security problems.
Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a 20 relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.
Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.
The new administration has stated that no new bid rounds for exploration blocks will be done until it is decided differently by the government. In addition, in 2023 the government has issued a new decree eliminating the obligation of ANH to offer bid rounds for the blocks offered by Companies.
The new administration has stated that no new bid rounds for exploration blocks will be done until it is decided differently by the government. In addition, in 2023 the government issued a new decree eliminating the obligation of ANH to offer bid rounds for new blocks to Companies.
Moreover, if any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition or results of operations.
Moreover, if any of these events were to materialize, they could lead to losses of 22 sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition or results of operations.
Future oil and gas exploration may involve unprofitable efforts, not 19 only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.
Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.
Our operations create the risk of significant environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water or for certain other environmental impacts.
Our operations create the risk of significant environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, 24 soil or water or for certain other environmental impacts.
Any arbitrage activity could create unexpected volatility in the price of the Common Stock on any of these exchanges or the volume of Common Stock available for trading on any of these markets.
Any arbitrage activity could create unexpected volatility in the price of the shares of Common Stock on any of these exchanges or the volume of shares of Common Stock available for trading on any of these markets.
Our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.
Our future oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.
The threat and impact of cyberattacks may adversely impact our operations and could result in information theft, data corruption, operational disruption, and/or financial loss We use digital technologies and software programs to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, as well as to process and record financial and operating data.
The threat and impact of cybersecurity incidents may adversely impact our operations and could result in information theft, data corruption, operational disruption, and/or financial loss We use digital technologies and software programs to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, as well as to process and record financial and operating data.
While we have implemented strategies to mitigate impacts from these types of events, we cannot guarantee that measures taken to defend against cybersecurity threats will be sufficient for this purpose.
While we have implemented strategies to mitigate impacts from these types of events, we cannot guarantee that measures taken to defend against cybersecurity risks and threats will be sufficient for this purpose.
Although Colombia is currently eligible for such aid, Colombia may not remain eligible in the future.
Although Colombia is currently eligible for such aid, it may not remain eligible in the future.
Most of our administration costs in Canada are incurred in Canadian dollars. As a result, we are exposed to translation risk when local currency financial statements are translated to U.S. dollars, our reporting currency. An appreciation of local currencies can increase our costs and negatively impact our results from operations.
Most of our administration costs in Canada are incurred in Canadian dollars. As a result, we are exposed to translation risk when local currency transactions are translated to U.S. dollars, our reporting currency. An appreciation of local currencies can increase our costs and negatively impact our results from operations.
Colombia and Ecuador have experienced social turmoil related to changes in economic policy, which have resulted in illegal road blockades throughout the countries, and illegal invasions to private property and impacting regions where company activities are located.
Colombia and Ecuador have experienced social turmoil related to changes in economic policy, which have resulted in illegal road blockades throughout the countries, and illegal invasions to private property and impacting regions where our operating 21 activities are located.
While the Common Stock is traded on such markets, the price and volume levels could fluctuate significantly on any market independently of the price or trading volume on other markets.
While the shares of Common Stock are traded on such markets, the price and volume levels could fluctuate significantly on any market independently of the price or trading volume on other markets.
If cash flows from operations, cash on hand and available capacity under our credit facility are not sufficient to fund our capital program, we may be required to seek external financing or to delay or reduce our exploration and development activities, which could impact production, revenues and reserves.
If cash flows from operations and cash on hand are not sufficient to fund our capital program, we may be required to seek external financing or to delay or reduce our exploration and development activities, which could impact production, revenues and reserves.
In addition, shareholders in any of these jurisdictions will not be able to transfer such shares of Common Stock for trading on another market without effecting necessary procedures with our transfer agent or registrar. This could result in time delays and additional cost for shareholders of the Common Stock.
In addition, shareholders in any of these jurisdictions will not be able to transfer such shares of Common Stock for trading on another market without effecting necessary procedures with our transfer agent or registrar. This could result in time delays and additional cost for shareholders of the Common Stock. Item 1B. Unresolved Staff Comments None.
Future decreases in the prices of oil, sustained low prices, periods of extended pricing volatility, and increasing borrowing costs may have a material adverse effect on our financial condition, the future results of our operations (including rendering existing projects unprofitable or requiring temporary suspension of fields), financing available to us, and quantities of reserves recoverable on an economic basis, as well as the market price for our securities.
The differentials and transportation costs can change over time and have a detrimental impact on realized prices. 18 Future decreases in the prices of oil, sustained low prices, periods of extended pricing volatility, and increasing borrowing costs may have a material adverse effect on our financial condition, the future results of our operations (including rendering existing projects unprofitable or requiring temporary suspension of fields), financing available to us, and quantities of reserves recoverable on an economic basis, as well as the market price for our securities.
For the year ended December 31, 2022, the Acordionero, Costayaco, Moqueta and Cohembi fields collectively generated 89% of our production and at December 31, 2022, these four fields accounted for 80% of our proved reserves.
For the year ended December 31, 2023, the Acordionero, Costayaco, Moqueta and Cohembi fields collectively generated 88% of our production and at December 31, 2023, these four fields accounted for 84% of our proved reserves.
Our future reserves will depend not only on our ability to develop and effectively manage then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to identify and retain responsible service providers and contractors to efficiently drill and complete our wells and to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.
Our future reserves will depend not only on our ability to develop and effectively manage then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to identify and retain responsible service providers and contractors to efficiently drill and complete our wells and to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets. 19 Exploration for oil and natural gas, and development of new formations, is risky Oil and natural gas exploration involves a high degree of operational and financial risk.
Furthermore, prices which we receive for our oil sales, while based on international oil prices, are established by contracts with purchasers and include the deductions for transportation and quality differentials. The differentials and transportation costs can change over time and have a detrimental impact on realized prices.
Furthermore, prices which we receive for our oil sales, while based on international oil prices, are established by contracts with purchasers and include the deductions for quality differentials and transportation.
If these security problems disrupt our operations, our financial condition and results of operations could be adversely affected. 21 All of our revenue is generated outside of Canada and the United States, and if we determine to, or are required to, repatriate earnings from foreign jurisdictions, we could be subject to taxes All of our revenue is generated outside of Canada and the United States.
All of our revenue is generated outside of Canada and the United States, and if we determine to, or are required to, repatriate earnings from foreign jurisdictions, we could be subject to taxes All of our revenue is generated outside of Canada and the United States.
The referendums were organized by opponents of the mining or oil and natural gas industries. It remains unclear to what extent such results can impact the exercise of mineral rights conferred by the national government.
The referendums were organized by opponents of the mining or oil and natural gas industries. It remains unclear to what extent such results can impact the exercise of mineral rights conferred by the national government. In 2023, the Colombian government is undertaking other peace process conversations with illegal groups in the country.
To the extent the COVID-19 pandemic may continue to adversely affect our business, operations, financial condition and operating results, it may also have the effect of heightening the other risks described herein.
To the extent any global epidemic or public health crisis may adversely affect our business, operations, financial condition and operating results, it may also have the effect of heightening the other risks described herein.
It is 25 not possible at this time to predict whether proposed legislation or regulations will be adopted, and any such future laws and regulations could result in additional compliance costs or additional operating restrictions.
Current GHG emissions legislation has not resulted in material compliance costs; however, emissions, carbon and other regulations impacting climate and climate related matters are constantly evolving. It is not possible at this time to predict whether proposed legislation or regulations will be adopted, and any such future laws and regulations could result in additional compliance costs or additional operating restrictions.
We expect to fund our 2023 capital program through cash flows from operations. Funding this program from cash flow from operations relies in part on Brent oil prices being at least $60 per barrel or greater. For the period from January 1 to February 16, 2023, the average price of Brent oil was $83.95 per barrel.
Funding this program from cash flows from operations relies in part on Brent oil prices being $70 per barrel or greater. For the period from January 1 to February 15, 2024, the average price of Brent oil was $79.58 per barrel.
Certain sovereign wealth, pension and endowment funds, have promoted the divestment of fossil fuel equities and pressured lenders to cease or limit funding to companies engaged in the extraction of fossil fuel reserves, including recent divestment actions by several prominent New York State and New York public employee pension funds.
Public and investor sentiment towards climate change, fossil fuels and other Environmental, Social and Governance (“ESG”) matters could adversely affect our cost of capital and the price of our common stock Certain numbers of investment community (including investment fund managers, sovereign wealth, pension and endowment funds, and individual investors) have promoted the divestment of fossil fuel equities and pressured lenders to cease or limit funding to companies engaged in the extraction of fossil fuel reserves, including recent divestment actions by several prominent New York State and New York public employee pension funds.
Additionally, some of this equipment is specialized and may be difficult to obtain in our areas of operations, which could hamper or delay operations, and could increase the cost of those operations. In 2022 experienced several short-term localized farmers’ blockades directed at the Colombian government, which resulted in the Suroriente and PUT-7 Blocks being temporarily shut-in.
Additionally, some of this equipment is specialized and may be difficult to obtain in our areas of operations, which could hamper or delay operations, and could increase the cost of those operations.
To the extent financial markets view climate change and GHG emissions as a financial risk; this could negatively impact our cost of or access to capital. Increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and natural gas companies in connection with their GHG emissions.
Significant restrictions on GHG emissions could result in decreased demand for the oil that we produce, with a resulting decrease in the value of our reserves. Increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and natural gas companies in connection with their GHG emissions.
Despite our efforts to mitigate “spoof” and “phishing” emails through policies and education, “spoof” and “phishing” activities remain a serious problem that may damage our information technology infrastructure. 22 Risks Related to our Financial Condition Our business requires significant capital expenditures, and we may not have the resources necessary to fund these expenditures Our base capital program for 2023 is $210.0 million to $250.0 million for exploration and development activities.
Risks Related to our Financial Condition Our business requires significant capital expenditures, and we may not have the resources necessary to fund these expenditures Our base capital program for 2024 is $210.0 million to $240.0 million for exploration and development activities. We expect to fund our 2024 capital program through cash flows from operations.
Such environmental initiatives aimed at targeting climate changes could ultimately interfere with our access to capital and ability to finance our operations. A failure to meet goals or evolving stakeholder expectations of Environmental, Social and Governance (“ESG”) practices and reporting may potentially harm our reputation and impact employee retention, customer relationships, and access to capital.
These expectations and standards may continue to evolve. A failure to meet goals or evolving stakeholder expectations of ESG practices and reporting may potentially harm our reputation and impact employee retention, customer relationships, and access to capital.
Exploration for oil and natural gas, and development of new formations, is risky Oil and natural gas exploration involves a high degree of operational and financial risk. These risks are more acute in the early stages of exploration, appraisal and development.
These risks are more acute in the early stages of exploration, appraisal and development.
In 2022, the Colombian government has begun conversations with other illegal armed groups in order to seek execution of new peace processes and agreements aimed at dismantling such organizations. Security concerns in Colombia or Ecuador may disrupt our operations Oil pipelines have historically been primary targets of terrorist activity in Colombia.
Security concerns in Colombia or Ecuador may disrupt our operations Oil pipelines have historically been primary targets of terrorist activity in Colombia.
Removed
We may be adversely affected by global epidemics, including the ongoing COVID-19 pandemic The outbreak of COVID-19 continued throughout 2022. Worldwide economic climate continued to be volatile making accounting estimates more onerous. Despite the improvement in oil prices in 2022, this volatile economic climate has had and may in the future have significant adverse impacts on our Company.
Added
We may be adversely affected by global epidemics or public health crises Global epidemics and public health crises and fear of such events may adversely impact our operations and the global economy, including the worldwide demand for oil and natural gas.
Removed
For example, certain market participants use third party benchmarks or scores to measure a company’s ESG practices in making investment decisions and customers and suppliers may evaluate our ESG practices or require that we adopt certain ESG policies as a condition of awarding contracts.
Added
If these security problems disrupt our operations, our financial condition and results of operations could be adversely affected.
Removed
The borrowing base under our credit facility may be reduced by the lenders, which could prevent us from meeting our future capital needs The borrowing base under our credit facility is currently $150.0 million, of which $100.0 million is presently eligible for borrowing and an option for additional $50.0 million upon mutual agreement by the Company and the lender.
Added
Despite our efforts to mitigate “spoof” and “phishing” emails through policies and education, “spoof” and “phishing” activities remain a serious problem that may damage our information technology infrastructure.
Removed
Our borrowing base may decrease as a result of a decline in oil or natural gas prices, operating difficulties, declines in reserves, lending requirements or regulations, lenders willingness to lend to the oil and gas industry, the issuance of new indebtedness or for any other reason.
Added
There has also been pressure on lenders and other financial services companies to limit or curtail financing of companies in the oil and gas industry. Such environmental initiatives aimed at targeting climate changes could ultimately interfere with our access to capital and ability to finance our operations.
Removed
We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. In the event of a decrease in our borrowing base, we could be required to repay any indebtedness in excess of the redetermined borrowing base, which would deplete cash flow from operations or require additional financing.
Added
Some members of the investment community have increased their focus on ESG practices and disclosures by public companies, including practices and disclosures related to climate change and sustainability, Diversity, Equity and Inclusion (“DEI”) initiatives, and heightened governance standards.
Removed
Further, our borrowing base is made available to us subject to compliance with financial covenants under the terms of our credit facility, including compliance with ratios and other financial covenants of such facility, and a failure to comply with such ratios or covenants could force us to repay a portion of our borrowings and suffer adverse financial impacts.
Added
Furthermore, concerns over climate change have resulted in, and are expected to continue to result in, the adoption of regulatory requirements for climate-related disclosures. As a result, we may continue to face increasing pressure regarding our ESG disclosures and practices, and mandatory reporting obligations could increase our compliance burden and costs.
Removed
We are required to maintain Global Coverage Ratio of at least 150% calculated using net present value of consolidated future cash flows over the 23 outstanding amount on the credit facility, Prepayment Life Coverage Ratio of at least 150% calculated using the estimated aggregate value of commodities to be delivered over the outstanding amount on the credit facility and liquidity ratio where the Company’s projected sources of cash exceed projected uses of cash by at least 1.15 times.
Added
We publish a Sustainability Report, which outlines our progress and ongoing efforts to advance 23 our ESG initiatives. Our disclosures on these matters rely on management’s expectations as of the date the statements are first made, as well as standards for measuring progress that are still in development, and may change or fail to be realized.
Removed
As of December 31, 2022, the credit facility remained undrawn. On February 20, 2023, the the availability period for draws under the credit facility were extended for additional six months. Our credit facility matures in August 2024. Capital financing may not be available to us at economic rates Our credit facility will mature in August 2024.
Added
In 2023, El-Niño-induced drought across Colombia, the decrease in power generated from hydroelectricity increased power costs, which resulted in higher operating expenses.
Removed
There can be no assurance that financial market conditions or borrowing terms at the time our credit facility is renegotiated will be as favorable as the current terms and interest rates. We may be unable to obtain financing in the future for working capital, capital expenditures, acquisitions, debt service requirements, or other purposes.
Removed
Current GHG emissions legislation has not resulted in material compliance costs; however, emissions, carbon and other regulations impacting climate and climate related matters are constantly evolving.
Removed
Significant restrictions on GHG emissions could result in decreased demand for the oil that we produce, with a resulting decrease in the value of our reserves. Further, there have been efforts in recent years to influence the investment community to consider climate change in how they invest in companies.
Removed
If we cannot meet the NYSE American continued listing requirements, the NYSE may delist our shares of Common Stock Our shares of Common Stock are currently listed on the NYSE American, and the continued listing of our shares is subject to our compliance with a number of listing standards.
Removed
If we fail to maintain compliance with these continued listing standards, including if the price our shares of Common Stock remains at its current low for a substantial period of time and we fail to effect a reverse stock split upon notice from the NYSE, our shares of Common Stock may be delisted.
Removed
A delisting of our shares could negatively impact us by, among other things reducing the liquidity of our shares and limiting our ability to issue additional securities, obtain additional financing or pursuant strategic transactions. Item 1B. Unresolved Staff Comments None.
Item 4. Mine Safety Disclosures
Mine Safety Disclosures — required of mining issuers
10 edited+9 added−7 removed6 unchanged
Item 4. Mine Safety Disclosures
Mine Safety Disclosures — required of mining issuers
10 edited+9 added−7 removed6 unchanged
2022 filing
2023 filing
Biggest changeEvans has over 29 years of experience including working the last 18 years in the international oil and gas industry. Most recently, Mr.
Biggest changeHe is credited as the author of various publications and has presented in numerous professional forums. • James Evans, Vice President, Corporate Services . Mr. Evans has been Gran Tierra’s Vice President, Corporate Services, since May 2015. Mr. Evans has over 30 years of experience including working the last 19 years in the international oil and gas industry.
Ellson was Head of Finance for Glencore E&P (Canada) Inc. and prior thereto Vice President, Finance at Caracal Energy Inc.(“Caracal”), a London Stock Exchange (“LSE”) listed company with operations in Chad, Africa from August 2011 until July 2014. Glencore E&P (Canada) purchased Caracal in July 2014. Prior to Caracal, Mr.
Ellson was Head of Finance for Glencore E&P (Canada) Inc. and prior thereto Vice President, Finance at Caracal Energy Inc.(“Caracal”), a London Stock Exchange (“LSE”) listed company with operations in Chad, Africa from August 2011 until July 2014. Glencore E&P (Canada) purchased Caracal in July 2014. Mr.
Guidry is an Alberta-registered professional engineer (P. Eng.) and holds a B.Sc. in petroleum engineering from Texas A&M University. • Ryan Ellson, Chief Financial Officer and Executive Vice President, Finance. Mr. Ellson has been Gran Tierra’s Chief Financial Officer since May 2015. Mr.
Guidry is an Alberta-registered professional engineer (P. Eng.) and holds a B.Sc. in petroleum engineering from Texas A&M University. 27 • Ryan Ellson, Chief Financial Officer and Executive Vice President, Finance. Mr. Ellson has been Gran Tierra’s Chief Financial Officer since May 2015. Mr.
Ellson has held management and executive positions with companies operating in Chad, Egypt, India and Canada. Mr. Ellson is a Chartered Professional Accountant and holds a Bachelor of Commerce and a Master of Professional Accounting from the University of Saskatchewan. Mr.
Ellson has held management and executive positions with companies operating in Chad, Egypt, India and Canada. Mr. Ellson is a Chartered Professional Accountant and holds a Bachelor of Commerce and a Masters of Professional Accounting from the University of Saskatchewan. Mr.
Guidry currently sits on the board of Africa Oil Corp. (since April 2008) where he also serves as a member of the Audit Committee and the board of PetroTal Corp. (since December 2017). From September 2010 to October 2011, Mr.
Guidry currently sits on the board of Africa Oil Corp. (since April 2008) where he also serves as a member of the Audit Committee. Mr. Guidry was on the board of PetroTal Corp. from December 2017 until September 2022. From September 2010 to October 2011, Mr.
Item 4. Mine Safety Disclosures Not applicable. 26 Information About Our Executive Officers Set forth below is information regarding our executive officers as of February 16, 2023. Name Age Position Gary S.
Item 4. Mine Safety Disclosures Not applicable. Information About Our Executive Officers Set forth below is information regarding our executive officers as of February 15, 2024: Name Age Position Gary S.
Ellson has over 23 years of experience in a broad range of international corporate finance and accounting roles. Mr. Ellson is currently a Director of Canary Biofuels and until September 2022 was a Director at PetroTal Corp. (since December 2017). From July 2014 until December 2014 Mr.
Ellson has over 24 years of experience in a broad range of international corporate finance and accounting roles. Mr. Ellson is currently a Director of Canary Biofuels and Beyond Renewables (both private companies) and until September 2022 was a Director at PetroTal Corp. (since December 2017). From July 2014 until December 2014 Mr.
Evans held senior management and executive positions at Orion Oil and Gas and Tanganyika Oil, with operating experience in Egypt, Syria and Canada. Mr. Evans holds a Bachelor of Commerce degree from the University of Calgary. • Rodger Trimble, Vice President, Investor Relations . Mr. Trimble has been Gran Tierra’s Vice President, Investor Relations since June 2016.
Evans held senior management and executive positions at Orion Oil and Gas and Tanganyika Oil, with operating experience in Egypt, Syria and Canada. Mr. Evans holds a Bachelor of Commerce degree from the University of Calgary. PART II
Ellson has completed the Leadership for Senior Executives program at Harvard Business School and the General Management Program at the Wharton School of the University of Pennsylvania. • James Evans, Vice President, Corporate Services . Mr. Evans has been Gran Tierra’s Vice President, Corporate Services, since May 2015. Mr.
Ellson has completed the Leadership for Senior Executives program at Harvard Business School and the General Management Program at the Wharton School of the University of Pennsylvania. • Sebastien Morin, Chief Operating Officer. Mr. Morin was appointed as Gran Tierra’s Chief Operations Officer on November 6, 2023. Mr.
Guidry 67 President and Chief Executive Officer, Director Ryan Ellson 47 Chief Financial Officer and Executive Vice President, Finance James Evans 57 Vice President, Corporate Services Rodger Trimble 61 Vice President, Investor Relations Lawrence West 66 Vice President, Exploration • Gary S. Guidry, President and Chief Executive Officer, Director. Mr.
Guidry 68 President and Chief Executive Officer, Director Ryan Ellson 48 Chief Financial Officer and Executive Vice President, Finance Sebastien Morin 47 Chief Operating Officer Phillip Abraham 53 Vice President, Legal and Business Development James Evans 58 Vice President, Corporate Services • Gary S. Guidry, President and Chief Executive Officer, Director. Mr.
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Ellson was Vice President of Finance at Sea Dragon Energy from April 2010 until August 2011. In these positions, Mr. Ellson oversaw financial and accounting functions, implemented and oversaw internal financial controls, secured reserve based lending facility’s and was involved in multiple capital raises. Mr.
Added
Morin has more than 20 years of experience in the oil and gas industry in various management positions. Prior to his appointment as Chief Operating Officer of the Company, Mr.
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He is a Professional Engineer with more than 38 years of experience in domestic and international basins in various management positions. Prior to joining Gran Tierra, Mr. Trimble was Head of Corporate Planning, Budgeting & Finance with Glencore E&P (Canada) Inc. and prior thereto Director Corporate Planning, Budget & Business Development 27 with Caracal Energy Inc. (acquired by Glencore E&P).
Added
Morin served as President and Chief Operating Officer at WesternZagros Resources, a privately-owned petroleum operating company with production sharing contracts in the Kurdistan region of Iraq, from October 2021 to October 2023. Prior to his role at WesternZagros, Mr.
Removed
He has held several senior management positions ranging from Country Manager in Argentina with Canadian Hunter Exploration, Vice President, Exploitation with Esprit Energy Trust, Manager, Reservoir Engineering with Apache Canada Inc. and Manager, Upstream Evaluations - Frontiers & International with Husky Energy. Mr. Trimble is an Alberta-registered Professional Engineer and a member of APEGA.
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Morin was Vice President Global Drilling and Completions at Gran Tierra, leading up to that he held progressively more senior positions at Gran Tierra in Colombia and in the Corporate Office in Calgary from August 2014 to September 2021. From May 2001 to July 2014, Mr.
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He received a Bachelor of Science in Petroleum Engineering (with Distinction) from Stanford University. • Lawrence West, Vice President, Exploration . Mr. West has been Gran Tierra’s Vice President, Exploration, since May 2015. Mr. West has over 44 years of experience as an executive, explorationist, and geologist. Most recently, Mr.
Added
Morin worked at Imperial Oil (Esso) and ExxonMobil, where he achieved more senior technical and managerial positions in upstream and downstream including roles in drilling and completions, reservoir development, production, customer service and distribution, mostly onshore but also with experience offshore in the Gulf of Mexico. Mr.
Removed
West was Vice President, Exploration at Caracal Energy from July 2011 to June 2014. Mr. West built a multi-disciplinary team to assess resources and grow reserves in the interior rift basins within Chad and led a successful exploration program. During his tenure he successfully executed two large 2D/3D seismic shoots in remote frontier basins, on time and on budget.
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Morin has a Bachelor of Science degree in Geological Engineering from the University of Waterloo in 2001. • Phillip Abraham, Vice President, Legal and Business Development. Mr.
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Prior to Caracal he has been involved in starting and growing several public and private companies, including Reserve Royalty Corp., Chariot Energy, Auriga Energy and Orion Oil and Gas. Lawrence worked at Alberta Energy Company (AEC), where he was on the team that merged with Conwest. He built and led the AEC East team to the Rocky Mountain USA basins.
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Abraham has been with Gran Tierra in a variety of roles since January 2016 and, in addition to his current role as Vice President, Legal and Business Development, is also Gran Tierra’s Corporate Secretary. He is a lawyer with over 25 years of corporate and legal experience.
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His career began with Imperial Oil working on prospect and reservoir characterization, in multi-disciplinary teams, and as a technical mentor to exploration teams. Lawrence has an Honours Bachelor of Science in Geology from McMaster University and an MBA, specializing in economics, from the University of Calgary. PART II
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His legal experience includes positions at prominent law firms and is broadly based with a focus on international energy law. Mr. Abraham’s corporate experience extends to a variety of leadership positions with Cenovus Energy, Encana Corporation and Nexen Inc.
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His experience in oil and gas includes onshore and offshore projects located in Canada and various international jurisdictions in Latin America, Europe, Africa, Asia and the Middle East. Mr.
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Abraham is a member of Law Society of Alberta, holds both a B.A. and an LL.M. from the University of Calgary and a LL.B. from the University of Victoria, and was first called to the bar in British Columbia in 1997.
Item 5. Market for Registrant's Common Equity
Market for Common Equity — stock, dividends, buybacks
4 edited+0 added−7 removed2 unchanged
Item 5. Market for Registrant's Common Equity
Market for Common Equity — stock, dividends, buybacks
4 edited+0 added−7 removed2 unchanged
2022 filing
2023 filing
Biggest changeDividend Policy We have never declared or paid dividends on the shares of Common Stock and we intend to retain future earnings, if any, to support the development of the business and therefore do not anticipate paying cash dividends for the foreseeable future.
Biggest changeAs of February 15, 2024, there were approximately 32 holders of record of shares of our Common Stock and 32,246,501 shares outstanding with $0.001 par value. 28 Dividend Policy We have never declared or paid dividends on the shares of Common Stock and we intend to retain future earnings, if any, to support the development of the business and therefore do not anticipate paying cash dividends for the foreseeable future.
(2) On August 29, 2022, we implemented a share re-purchase program (the “2022 Program”) through the facilities of the TSX and eligible alternative trading platforms in Canada commencing September 1, 2022 and ending on August 31, 2023.
(2) On October 31, 2023, we implemented a share re-purchase program (the “2023 Program”) through the facilities of the TSX, the NYSE American or alternative trading programs in Canada or the United States commencing November 3, 2023 and ending on November 2, 2024.
Issuer Purchases of Equity Securities (a) Total Number of Shares Purchased (b) Average Price Paid per Share (1) (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (d) Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs (2) October 1-31, 2022 — $ — — 25,300,267 November 1-30, 2022 4,313,006 $ 1.31 4,313,006 20,987,261 December 1-31, 2022 7,700,754 $ 0.95 7,700,754 13,286,507 Total 12,013,760 $ 1.08 12,013,760 13,286,507 (1) Including commission fees paid to the broker to re-purchase the Common Stock.
Issuer Purchases of Equity Securities (a) Total Number of Shares Purchased (b) Average Price Paid per Share (1) (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (d) Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs (2) October 1-31, 2023 — $ — — 3,234,914 November 1-30, 2023 755,790 $ 6.34 755,790 2,479,124 December 1-31, 2023 286,014 $ 5.87 286,014 2,193,110 Total 1,041,804 $ 6.21 1,041,804 2,193,110 (1) Including commission fees paid to the broker to re-purchase the shares of Common Stock.
We will be able to purchase for cancellation at prevailing market prices up to 36,033,969 shares of Common Stock, representing approximately 10% of our issued and outstanding shares of Common Stock as of August 22, 2022.
Under the 2023 Program, we are able to purchase at prevailing market prices up to 3,234,914 shares of Common Stock, representing approximately 10% of the public float of common shares as of October 20, 2023.
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As of February 16, 2023, there were approximately 32 holders of record of shares of our Common Stock and 346,151,157 shares outstanding with $0.001 par value.
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Performance Graph 28 The information in this Annual Report on Form 10-K appearing under the heading “Performance Graph” is being “furnished” pursuant to Item 201(e) of Regulation S-K under the securities Act and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act or the Exchange Act except to the extent that we specifically incorporate it by reference into such filing.
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The performance graph below shows the cumulative total shareholder return on our shares of the period starting on December 31, 2017, and ending on December 31, 2022, which was the end of our fiscal 2022 year.
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This is compared with the cumulative total returns over the same period of the S&P 500 Total Return Index and the S&P O&G E&P Select Index Total Return.
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The graph assumes that, on December 31, 2017, $100 was invested in our shares and $100 was invested in each of the other two indices, with dividends reinvested on the ex-dividend date without payment of any commissions.
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The performance shown in the graph represents past performance and should not considered an indication of future performance. 12/31/2017 12/31/2018 12/31/2019 12/31/2020 12/31/2021 12/31/2022 Gran Tierra Energy Inc.
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(GTE) $ 100.0 $ 80.4 $ 47.8 $ 13.5 $ 28.2 $ 36.7 S&P 500 Total Return (SPXT) $ 100.0 $ 95.6 $ 125.7 $ 148.9 $ 191.6 $ 156.9 S&P O&G E&P Select Index Total Return (SPSIOPTR) $ 100.0 $ 72.0 $ 65.4 $ 41.5 $ 69.5 $ 101.3
Item 7. Management's Discussion & Analysis
Management's Discussion & Analysis (MD&A) — revenue / margin commentary
105 edited+33 added−60 removed41 unchanged
Item 7. Management's Discussion & Analysis
Management's Discussion & Analysis (MD&A) — revenue / margin commentary
105 edited+33 added−60 removed41 unchanged
2022 filing
2023 filing
Biggest changeFinancial and Operational Highlights Key Highlights • Net income in 2022 was $139.0 million or $0.38 per share basic and diluted compared to a net income of $42.5 million or $0.12 per s hare basic and diluted in 2021 • Income before income taxes in 2022 was $244.9 million compared to $23.1 million in 2021 • Adjusted EBITDA (2) for 2022 was $489.6 million compared to $241.5 million in 2021 • Our total 2022 average production NAR was 23,815 bopd, an increase from 21,588 bopd in 2021 as a result of successful drilling and workover campaigns in Acordionero and Costayaco fields, less disruption from blockades compared to 2021, and production from exploration success in Ecuador • Our total 2022 oil sales volumes NAR increased by 10% to 23,696 bopd compared to 21,598 bopd in 2021 • Oil sales for 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, a 10% increase in sales volumes, partially offset by 55% higher quality and transportation discounts • Oil sales per bbl for 2022 were $82.25, 37% higher compared to 2021, directly a result of increased benchmark pricing • In 2022, we generated net cash provided by operating activities of $427.7 million, an increase of 75% from $244.8 million in 2021 • Funds flow from operations (2) for 2022 increased by 96% to $366.0 million or $1.00 per share basic and $0.99 per share diluted compared with $186.5 million or $0.51 per share basic and diluted in 2021 • During 2022 the Company generated $129.4 million of free cash flow (2) which was used for debt reduction and share re-purchase • Operating expenses per bbl for 2022 were $18.77, 9% higher than 2021, primarily as a result of higher workovers and higher power generation expense due to increased activities attributed to higher production and waterflood program in all major fields.
Biggest changeAs 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. 29 Financial and Operational Highlights Key Highlights • 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 s hare basic and $3.76 per s hare diluted in 2022 • Income before income taxes in 2023 was $106.2 million compared to $244.9 million in 2022 • Adjusted EBITDA (2) for 2023 was $399.4 million compared to $481.9 million in 2022 • 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 • 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 • Our total 2023 oil sales volumes NAR increased by 9% to 25,947 BOPD compared to 23,696 BOPD in 2022 • 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 • Oil sales per bbl for 2023 were $67.26, 18% lower compared to 2022, as a result of a decrease in benchmark oil prices • In 2023, we generated net cash provided by operating activities of $228.0 million, a decrease of 47% from $427.7 million in 2022 • During 2023, the Company generated $57.9 million of free cash flow (2) which was used for debt reduction and share re-purchases • 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.
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 our financial results.
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.
Oil Sales 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 and 10% higher sales volumes partially offset by 55% higher quality and transportation discounts in 2022.
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.
However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impact oil and gas prices and costs change. Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures.
However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impact oil and natural gas prices and costs change. Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures.
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.
Income Taxes 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.
Asset Retirement Obligations We are required to remove or remedy the effect of our activities on the environment at our present and former operating sites by dismantling and removing production facilities and remediating any damage caused. Estimating our future ARO requires us to make estimates and judgments with respect to activities that will occur many years into the future.
Asset Retirement Obligations (“ARO”) We are required to remove or remedy the effect of our activities on the environment at our present and former operating sites by dismantling and removing production facilities and remediating any damage caused. Estimating our future ARO requires us to make estimates and judgments with respect to activities that will occur many years into the future.
In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate. We record ARO in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities.
In addition, the ultimate 51 financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate. We record ARO in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities.
A reconciliation from oil sales to operating netback is provided in the table above. 31 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.
A reconciliation from oil sales to operating netback is provided in the table above. 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.
Unproved properties, the costs of which are individually significant, are assessed individually by considering seismic data, plans or requirements to 52 relinquish acreage, drilling results and activity, remaining time in the commitment period, remaining capital plans and political, economic and market conditions.
Unproved properties, the costs of which are individually significant, are assessed individually by considering seismic data, plans or requirements to relinquish acreage, drilling results and activity, remaining time in the commitment period, remaining capital plans and political, economic and market conditions.
Climate Change We have considered the impact of the climate events on the following items presented in this Annual Report on Form 10-K for the fiscal year ended December 31, 2022: Impairment We have considered the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in the ceiling test impairment assessment on oil and gas properties.
Climate Change We have considered the impact of the climate events on the following items presented in this Annual Report on Form 10-K for the fiscal year ended December 31, 2023: Impairment We have considered the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in the ceiling test impairment assessment on oil and gas properties.
Information regarding our asset retirement obligation can be found in Note 10 to the Consolidated Financial Statements, Asset Retirement Obligation, in Item 8 “Financial Statements and Supplementary Data.” As is customary in the oil and gas industry, we may at times have commitments in place to reserve or earn certain acreage positions or wells.
Information regarding our asset retirement obligation can be found in Note 9 to the Consolidated Financial Statements, Asset Retirement Obligation, in Item 8 “Financial Statements and Supplementary Data.” As is customary in the oil and gas industry, we may at times have commitments in place to reserve or earn certain acreage positions or wells.
Castilla and Vasconia differentials increased to $9.81 and $4.99 from $5.74 and $3.52 per bbl in 2021.
Castilla and Vasconia differentials increased to $9.81 and $4.99 from $5.74 and $3.52, respectively, per bbl in 2021.
Estimates of standardized measure of our future cash flows from proved reserves for our December 31, 2022, ceiling tests were based on wellhead prices per bbl as of the first day of each month within that twelve month period.
Estimates of standardized measure of our future cash flows from proved reserves for our December 31, 2023 ceiling tests were based on wellhead prices per bbl as of the first day of each month within that twelve-month period.
Discussions of items related to the fiscal year ended December 31, 2021 and year-to-year comparisons between 29 the fiscal years ended December 31, 2021 and 2020, respectively, that are not included in this Annual Report on Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2021.
Discussions of items related to the fiscal year ended December 31, 2022 and year-to-year comparisons between the fiscal years ended December 31, 2022 and 2021, respectively, that are not included in this Annual Report on Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
This Management’s Discussion and Analysis of Financial Condition and Results of Operations generally discusses items related to the fiscal year ended December 31, 2022, and year-to-year comparisons between the fiscal years ended December 31, 2022, and 2021, respectively.
This Management’s Discussion and Analysis of Financial Condition and Results of Operations generally discusses items related to the fiscal year ended December 31, 2023, and year-to-year comparisons between the fiscal years ended December 31, 2023, and 2022, respectively.
However, the majority of the cash flows associated with proved reserves per the 2022 reserve report should be realized prior to the potential elimination of carbon-based energy.
However, the majority of the cash flows associated with proved reserves per the 2023 reserve report should be realized prior to the potential elimination of carbon-based energy.
The following table presents the change in the Colombian peso and Canadian dollar against the U.S. dollar for the last three years ended December 31, 2022: Year Ended December 31, 2022 2021 2020 Change in the Colombian peso against the U.S. dollar weakened by weakened by weakened by 21 % 16 % 5 % Change in the Canadian dollar against the U.S. dollar weakened by consistent strengthened by 7 % — % 2 % 42 Financial Instruments Gains or Losses The following table presents the nature of our financial instruments gains or losses for each of the three years ended December 31, 2022: Year Ended December 31, (Thousands of U.S.
The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the last three years ended December 31, 2023: Year Ended December 31, 2023 2022 2021 Change in the U.S. dollar against the Colombian peso weakened by strengthened by strengthened by 21 % 21 % 16 % Change in the U.S. dollar against the Canadian dollar weakened by strengthened by consistent 2 % 7 % — % Financial Instruments Gains or Losses The following table presents the nature of our financial instruments gains or losses for each of the three years ended December 31, 2023: Year Ended December 31, (Thousands of U.S.
The Board meets with management periodically to review the reserves process, results and related disclosures and appoints and meets with the independent reserves consultants to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent reserves consultants, their independence.
The Board meets with management periodically to review the reserves process, results and related disclosures and appoints and meets with the independent reservoir engineering specialists to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent reservoir engineering specialists, their independence.
The credit facility bears interest 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%. Undrawn amounts under the credit facility bear interest at 2.10% per annum, based on the amount available.
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.
Adjusted EBITDA, as presented, is defined as EBITDA adjusted for asset impairment, goodwill impairment, non-cash lease expense, lease payments, unrealized 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.
Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, 31 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.
The following table shows the percentage of oil volumes we sold in Colombia using each transportation method for each of the three years ended December 31, 2022: Year Ended December 31, 2022 2021 2020 Volume transported through pipelines — % 12 % 4 % Volume sold at wellhead 47 % 34 % 48 % Volume transported via truck to pipelines 53 % 54 % 48 % 100 % 100 % 100 % Volumes transported through pipelines or via trucks receive a higher realized price but incur higher 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: Year Ended December 31, 2023 2022 2021 Volume transported through pipelines 2 % — % 12 % Volume sold at wellhead 47 % 47 % 34 % Volume transported via truck to pipelines 51 % 53 % 54 % 100 % 100 % 100 % Colombian volumes transported through pipelines or via trucks receive a higher realized price but incur higher transportation expenses.
Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 39 DD&A Expenses Year Ended December 31, 2022 2021 2020 DD&A Expenses, Thousands of U.S. Dollars $ 180,280 $ 139,874 $ 164,233 DD&A Expenses, U.S.
Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 39 DD&A Expenses Year Ended December 31, 2023 2022 2021 DD&A Expenses, Thousands of U.S. Dollars $ 215,584 $ 180,280 $ 139,874 DD&A Expenses, U.S.
Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 45 2023 Work Program and Capital Expenditures Our Colombian development operation is expected to represent 95% of our production and approximately 70% of our 2023 capital budget, with the remainder allocated to exploration activities.
Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 44 2024 Work Program and Capital Expenditures 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.
Volumes sold at the wellhead have the opposite effect of lower realized price, offset by lower transportation expense. We focus on maximizing operating netback (1) per bbl when choosing a transportation method.
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.
Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the United States as prescribed by the Society of Petroleum Engineers. Reserve estimates are evaluated at least annually by independent qualified reserves consultants.
Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted 50 industry practices in the United States as prescribed by the Society of Petroleum Engineers. Reserve estimates are evaluated at least annually by independent reservoir engineering specialists.
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 performance and our financial results.
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.
During the year ended December 31, 2022, we re-purchased in the open market $20.1 million of 6.25% Senior Notes for cash consideration of $17.3 million, including interest payable of $0.1 million. The re-purchase resulted in a $2.6 million gain, which included the write-off of deferred financing fees of $0.3 million.
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 46 included the write-off of deferred financing fees of $0.1 million.
Dollars) 2022 % Change 2021 % Change 2020 Cash and cash equivalents $ 126,873 386 $ 26,109 91 $ 13,687 Revolving credit facility $ — (100) $ 67,500 (64) $ 190,000 Senior Notes $ 579,909 (3) $ 600,000 — $ 600,000 (1) Sales volumes represent production NAR adjusted for inventory changes (2) Non-GAAP measures Operating netback, 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”).
Dollars) 2023 % Change 2022 % Change 2021 Cash and cash equivalents $ 62,146 (51) $ 126,873 386 $ 26,109 Credit facility $ 36,364 100 $ — (100) $ 67,500 Senior Notes $ 536,619 (7) $ 579,909 (3) $ 600,000 (1) Sales volumes represent production NAR adjusted for inventory changes (2) Non-GAAP measures 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”).
Dollars) 2022 2021 2020 Commodity price derivative loss (gain) $ 26,611 $ 48,723 $ (220) Foreign currency derivative loss — 115 3,155 $ 26,611 $ 48,838 $ 2,935 Unrealized investment loss $ — $ 2,032 $ 46,883 Loss on sale of investment — 1,355 — Financial instruments (gain) loss (7) (18) 1,164 $ (7) $ 3,369 $ 48,047 Income Tax Expense and Recovery Year Ended December 31, (Thousands of U.S.
Dollars) 2023 2022 2021 Commodity price derivative loss $ — $ 26,611 $ 48,723 Foreign currency derivative loss — — 115 $ — $ 26,611 $ 48,838 Unrealized investment loss $ — $ — $ 2,032 Loss on sale of investment — — 1,355 Other financial instruments loss (gain) 15 (7) (18) $ 15 $ (7) $ 3,369 42 Income Tax Expense and Recovery Year Ended December 31, (Thousands of U.S.
Dollars per bbl Sales Volumes NAR) Brent $ 99.04 $ 70.95 $ 43.21 Quality and transportation discounts (16.79) (10.86) (10.98) Average realized price 82.25 60.09 32.23 Transportation expenses (1.18) (1.48) (1.45) Average realized price, net of transportation expenses 81.07 58.61 30.78 Operating expenses (18.77) (17.22) (15.50) Operating netback (1) $ 62.30 $ 41.39 $ 15.28 (1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
Dollars per bbl Sales Volumes NAR) Brent $ 82.16 $ 99.04 $ 70.95 Quality and transportation discounts (14.90) (16.79) (10.86) Average realized price 67.26 82.25 60.09 Transportation expenses (1.54) (1.18) (1.48) Average realized price, net of transportation expenses 65.72 81.07 58.61 Operating expenses (19.73) (18.77) (17.22) Operating netback (1) $ 45.99 $ 62.30 $ 41.39 (1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
Management uses this financial measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results.
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.
These were partially offset by $13.2 million of non-taxable foreign exchange gain. 43 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.
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. 43 Net Income (Loss) and Funds Flow From Operations (a Non-GAAP Measure) (Thousands of U.S.
Operating expenses for the year ended December 31, 2021, increased by 19% to $135.7 million compared to $114.4 million in 2020.
Operating expenses for the year ended December 31, 2022, increased by 20% to $162.4 million compared to $135.7 million in 2021.
Actual results will differ from these estimates and assumptions. At December 31, 2022, we had provided promissory notes totaling $111.1 million (2021 - $103.0 million) to support letters of credit or surety bonds relating to work commitment guarantees contained in exploration contracts and other capital or operating requirements.
Actual results will differ from these estimates and assumptions. At December 31, 2023, we provided promissory notes totaling $220.1 million (2022 - $111.1 million) to support letters of credit relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, the Suroriente Block and other capital or operating requirements.
Dollars per bbl Sales Volumes NAR) 2022 2021 2020 Average Brent price $ 99.04 $ 70.95 $ 43.21 Average realized price, net of transportation expenses for the comparative period $ 58.61 $ 30.78 $ 51.76 Increase (decrease) in benchmark prices 28.09 27.74 (20.95) (Increase) decrease in quality and transportation discounts (5.93) 0.12 (0.50) Decrease (increase) in transportation expense 0.30 (0.03) 0.47 Average realized price, net of transportation expenses for the year $ 81.07 $ 58.61 $ 30.78 38 Operating Netbacks Year Ended December 31, Consolidated 2022 2021 2020 (Thousands of U.S.
Dollars per bbl Sales Volumes NAR) 2023 2022 2021 Average Brent price $ 82.16 $ 99.04 $ 70.95 Average realized price, net of transportation expenses for the comparative period $ 81.07 $ 58.61 $ 30.78 (Decrease) increase in benchmark prices (16.88) 28.09 27.74 Decrease (increase) in quality and transportation discounts 1.89 (5.93) 0.12 (Increase) decrease in transportation expense (0.36) 0.30 (0.03) Average realized price, net of transportation expenses for the year $ 65.72 $ 81.07 $ 58.61 Average realized price, net of transportation expenses as a % of Brent 80 % 82 % 83 % 38 Operating Netbacks Year Ended December 31, Consolidated 2023 2022 2021 (Thousands of U.S.
Cash and Cash Equivalents Held Outside of Canada and the United States At December 31, 2022 , 100% of our cash and cash equivalents were held by subsidiaries outside Canada and the United States. 48 Cash Flows The following table presents our sources and uses of cash and cash equivalents for the periods presented: Year Ended December 31, 2022 2021 2020 Sources of Cash and Cash Equivalents: Net income (loss) $ 139,029 $ 42,482 $ (777,967) Adjustments to reconcile net income (loss) to funds flow from operations DD&A expenses 180,280 139,874 164,233 Asset impairment — — 564,495 Goodwill Impairment — — 102,581 Deferred tax expense (recovery) 25,340 (23,825) (76,148) Stock-based compensation expense 9,049 8,396 1,216 Amortization of debt issuance costs 3,528 3,809 3,625 Unrealized foreign exchange loss 10,251 21,879 5,271 Other non-cash (gain) loss (2,598) 44 2,026 Derivative instruments loss 26,611 48,838 2,935 Cash settlement on derivative instruments (26,611) (58,427) 4,874 Other financial instruments (gain) loss (7) 3,369 48,047 Non-cash lease expenses 2,818 1,667 1,951 Lease payments (1,666) (1,621) (1,926) Funds flow from operations (1) 366,024 186,485 45,213 Changes in non-cash operating working capital 64,317 59,154 36,062 Proceeds from other debt, net of issuance costs — — 88,332 Changes in non-cash investing working capital 26,273 1,431 — Proceeds from exercise of stock options 1,298 100 — Proceeds from issuance of Common Stock, net of issuance costs 2 — — Proceeds on disposition of investment, net of transaction costs — 43,126 — 457,914 290,296 169,607 Uses of Cash and Cash Equivalents: Additions to property, plant and equipment (236,604) (149,879) (96,281) Repayment of debt (67,803) (122,500) (17,000) Lease payments (2,228) (2,182) (879) Proceeds from other debt, net of issuance costs — (228) — Changes in non-cash investing working capital — — (48,642) Cash settlement of asset retirement obligation (2,630) (805) (201) Re-purchase of shares of Common Stock (27,317) — — Re-purchase of Senior Notes (17,274) — — Foreign exchange loss on cash and cash equivalents and restricted cash and cash equivalents (2,104) (821) (156) (355,960) (276,415) (163,159) Net increase in cash and cash equivalents and restricted cash and cash equivalents $ 101,954 $ 13,881 $ 6,448 (1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
Cash and Cash Equivalents Held Outside of Canada and the United States At December 31, 2023 , 100% of our cash and cash equivalents were held by subsidiaries outside Canada and the United States. 47 Cash Flows The following table presents our sources and uses of cash and cash equivalents for the periods presented: Year Ended December 31, 2023 2022 2021 Sources of Cash and Cash Equivalents: Net (loss) income $ (6,287) $ 139,029 $ 42,482 Adjustments to reconcile net (loss) income to funds flow from operations DD&A expenses 215,584 180,280 139,874 Deferred tax expense (recovery) 56,759 25,340 (23,825) Stock-based compensation expense 5,722 9,049 8,396 Amortization of debt issuance costs 5,831 3,528 3,809 Unrealized foreign exchange (gain) loss (5,085) 10,251 21,879 Other non-cash loss (gain) 2,297 (2,598) 44 Derivative instruments loss — 26,611 48,838 Cash settlement on derivative instruments — (26,611) (58,427) Other financial instruments loss (gain) 15 (7) 3,369 Non-cash lease expenses 4,967 2,818 1,667 Lease payments (3,018) (1,666) (1,621) Funds flow from operations (1) 276,785 366,024 186,485 Changes in non-cash operating working capital — 64,317 59,154 Changes in non-cash investing working capital — 26,273 1,431 Proceeds from exercise of stock options 8 1,300 100 Proceeds from debt, net of issuance costs 48,014 — — Proceeds on disposition of investment, net of transaction costs — — 43,126 Foreign exchange gain on cash and cash equivalents and restricted cash and cash equivalents 5,869 — — 330,676 457,914 290,296 Uses of Cash and Cash Equivalents: Additions to property, plant and equipment (218,882) (236,604) (149,879) Repayment of Senior Notes (60,000) — — Proceeds from debt, net of issuance costs — — (228) Repayment of debt (13,636) (67,803) (122,500) Lease payments (6,527) (2,228) (2,182) Proceeds from other debt, net of issuance costs (13,351) — — Changes in non-cash operating working capital (48,416) — — Changes in non-cash investing working capital (7,702) — — Cash settlement of asset retirement obligation (377) (2,630) (805) Re-purchase of shares of Common Stock (17,300) (27,317) — Re-purchase of Senior Notes (6,805) (17,274) — Foreign exchange loss on cash and cash equivalents and restricted cash and cash equivalents — (2,104) (821) (392,996) (355,960) (276,415) Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents $ (62,320) $ 101,954 $ 13,881 (1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
Contractual Obligations The following is a schedule by year of purchase obligations, future minimum payments for firm agreements and leases that have initial or remaining non-cancelable terms in excess of one year as of December 31, 2022: (Thousands of U.S.
Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 48 Contractual Obligations The following is a schedule by year of purchase obligations, future minimum payments for firm agreements and leases that have initial or remaining non-cancelable terms in excess of one year as of December 31, 2023: (Thousands of U.S.
The deferred income tax expense of $25.3 million for the year ended December 31, 2022, was mainly the 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 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.
We used an average Brent price of $97.98 per bbl less corresponding differentials for the purposes of the December 31, 2022 ceiling test calculations (2021 and 2020 - $68.92 and $43.43, respectively).
For the years ended December 31, 2023, 2022 and 2021 we had no ceiling test impairment losses. We used an average Brent price of $82.51 per bbl less corresponding differentials for the purposes of the December 31, 2023 ceiling test calculations (2022 and 2021 - $97.98 and $68.92, respectively).
Dollars per bbl $ 20.84 $ 17.74 $ 22.25 40 DD&A expenses for the year ended December 31, 2022, increased by 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.
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. DD&A expenses for the year ended December 31, 2022, increased 29% or $3.10 per bbl from 2021.
Dollars) 2022 % Change 2021 % Change 2020 Cash and cash equivalents $ 126,873 386 $ 26,109 91 $ 13,687 Current restricted cash and cash equivalents $ 1,142 191 $ 392 (8) $ 427 Revolving credit facility $ — (100) $ 67,500 (64) $ 190,000 Senior Notes $ 579,909 (3) $ 600,000 — $ 600,000 46 We believe that our capital resources, including cash on hand, cash generated from operations, and available capacity on our credit facility, 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.
Dollars) 2023 % Change 2022 % Change 2021 Cash and cash equivalents $ 62,146 (51) $ 126,873 386 $ 26,109 Credit facility $ 36,364 100 $ — (100) $ 67,500 Senior Notes $ 536,619 (7) $ 579,909 (3) $ 600,000 45 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.
Dollars) 2022 % Change 2021 % Change 2020 Oil sales $ 711,388 50 $ 473,722 99 $ 237,838 Operating expenses 162,385 20 135,722 19 114,371 Transportation expenses 10,197 (12) 11,618 8 10,739 Operating netback (1) 538,806 65 326,382 190 112,728 DD&A expenses 180,280 29 139,874 (15) 164,233 Asset impairment — — — (100) 564,495 Goodwill Impairment — — — (100) 102,581 G&A expenses before stock-based compensation 31,908 15 27,867 15 24,134 G&A stock-based compensation expense 9,049 8 8,396 590 1,216 Foreign exchange loss 2,578 (87) 20,477 389 4,184 Derivative instruments loss 26,611 (46) 48,838 1,564 2,935 Other financial instruments (gain) loss (7) (100) 3,369 (93) 48,047 Interest expense 46,493 (15) 54,381 — 54,140 296,912 (2) 303,202 (69) 965,965 Other gain (loss) 2,598 (6,005) (44) (91) (469) Interest income 443 100 — (100) 345 Income (loss) before income taxes 244,935 959 23,136 103 (853,361) 33 Current income tax expense 80,566 1,699 4,479 494 754 Deferred income tax expense (recovery) 25,340 206 (23,825) 69 (76,148) Total income tax expense (recovery) 105,906 647 (19,346) 74 (75,394) Net income (loss) $ 139,029 227 $ 42,482 105 $ (777,967) Sales Volumes (NAR) Total sales volumes, BOPD 23,696 10 21,598 7 20,163 Brent Price per bbl $ 99.04 40 $ 70.95 64 $ 43.21 Consolidated Results of Operations per bbl Sales Volumes (NAR) Oil sales $ 82.25 37 $ 60.09 86 $ 32.23 Operating expenses 18.77 9 17.22 11 15.50 Transportation expenses 1.18 (20) 1.48 2 1.45 Operating netback (1) 62.30 51 41.39 171 15.28 DD&A expenses 20.84 17 17.74 (20) 22.25 Asset impairment — — — (100) 76.49 Goodwill Impairment — — — (100) 13.90 G&A expenses before stock-based compensation 3.69 5 3.53 8 3.27 G&A stock-based compensation expense 1.05 (2) 1.07 569 0.16 Foreign exchange loss 0.30 (88) 2.60 356 0.57 Derivative instruments loss 3.08 (50) 6.19 1,448 0.40 Other financial instruments (gain) loss — (100) 0.43 (93) 6.51 Interest expense 5.38 (22) 6.90 (6) 7.34 34.34 (11) 38.46 (71) 130.89 Other gain (loss) 0.30 (3,100) (0.01) (83) (0.06) Interest income 0.05 100 — (100) 0.05 Income (loss) before income taxes 28.31 870 2.92 103 (115.62) Current income tax expense 9.31 1,533 0.57 470 0.10 Deferred income tax expense (recovery) 2.93 197 (3.02) 71 (10.32) Total income tax expense (recovery) 12.24 600 (2.45) 76 (10.22) Net income (loss) $ 16.07 199 $ 5.37 105 $ (105.40) (1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
Dollars) 2023 % Change 2022 % Change 2021 Oil sales $ 636,957 (10) $ 711,388 50 $ 473,722 Operating expenses 186,864 15 162,385 20 135,722 Transportation expenses 14,546 43 10,197 (12) 11,618 Operating netback (1) 435,547 (19) 538,806 65 326,382 DD&A expenses 215,584 20 180,280 29 139,874 G&A expenses before stock-based compensation 40,124 26 31,908 15 27,867 G&A stock-based compensation expense 5,722 (37) 9,049 8 8,396 Foreign exchange loss 11,822 359 2,578 (87) 20,477 Derivative instruments loss — (100) 26,611 (46) 48,838 Other financial instruments loss (gain) 15 314 (7) (100) 3,369 Interest expense 55,806 20 46,493 (15) 54,381 329,073 11 296,912 (2) 303,202 Other (loss) gain (2,297) (188) 2,598 6,005 (44) Interest income 1,983 348 443 100 — Income before income taxes 106,160 (57) 244,935 959 23,136 Current income tax expense 55,688 (31) 80,566 1,699 4,479 Deferred income tax expense (recovery) 56,759 124 25,340 206 (23,825) Total income tax expense (recovery) 112,447 6 105,906 647 (19,346) 33 Net (loss) income $ (6,287) (105) $ 139,029 227 $ 42,482 Sales Volumes (NAR) Total sales volumes, BOPD 25,947 9 23,696 10 21,598 Brent Price per bbl $ 82.16 (17) $ 99.04 40 $ 70.95 Consolidated Results of Operations per bbl Sales Volumes (NAR) Oil sales $ 67.26 (18) $ 82.25 37 $ 60.09 Operating expenses 19.73 5 18.77 9 17.22 Transportation expenses 1.54 31 1.18 (20) 1.48 Operating netback (1) 45.99 (26) 62.30 51 41.39 DD&A expenses 22.76 9 20.84 17 17.74 G&A expenses before stock-based compensation 4.24 15 3.69 5 3.53 G&A stock-based compensation expense 0.60 (43) 1.05 (2) 1.07 Foreign exchange loss 1.25 317 0.30 (88) 2.60 Derivative instruments loss — (100) 3.08 (50) 6.19 Other financial instruments loss — — — (100) 0.43 Interest expense 5.89 9 5.38 (22) 6.90 34.74 1 34.34 (11) 38.46 Other (loss) gain (0.24) (180) 0.30 3,100 (0.01) Interest income 0.21 320 0.05 100 — Income before income taxes 11.22 (60) 28.31 870 2.92 Current income tax expense 5.88 (37) 9.31 1,533 0.57 Deferred income tax expense (recovery) 5.99 104 2.93 197 (3.02) Total income tax expense (recovery) 11.87 (3) 12.24 600 (2.45) Net (loss) income $ (0.65) (104) $ 16.07 199 $ 5.37 (1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
On a per bbl basis, operating expenses increased by 9% or $1.55 to $18.77 compared to $17.22 in the prior year, 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 waterflood program in all major fields.
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. 36 Transportation Expenses We have options to sell our oil through multiple pipelines and trucking routes.
Current income tax expense increased for the year ended December 31, 2022, compared to 2021, primarily due to an increase in taxable income.
Current income tax expense decreased for the year ended December 31, 2023, compared to 2022, primarily due to a decrease in taxable income.
Dollars) 2022 2021 2020 Oil sales for the comparative year $ 473,722 $ 237,838 $ 570,983 Realized sales price increase (decrease) effect 191,664 219,641 (158,334) Sales volume increase (decrease) effect 46,002 16,243 (174,811) Oil sales for the current year $ 711,388 $ 473,722 $ 237,838 36 Operating Expenses Operating expenses for the year ended December 31, 2022, increased by 20% to $162.4 million compared to $135.7 million in 2021.
Dollars) 2023 2022 2021 Oil sales for the comparative year $ 711,388 $ 473,722 $ 237,838 Realized sales price (decrease) increase effect (141,997) 191,664 219,641 Sales volume increase effect 67,566 46,002 16,243 Oil sales for the current year $ 636,957 $ 711,388 $ 473,722 Operating Expenses Operating expenses for the year ended December 31, 2023, increased by 15% to $186.9 million compared to $162.4 million in 2022.
Full Cost Method of Accounting, Proved Reserves, DD&A, and Impairment of Oil and Gas Properties We follow the full cost method of accounting for our oil and natural gas properties in accordance with SEC Regulation S-X Rule 4-10, as described in Note 2 to the Consolidated Financial Statements, Significant Accounting Policies, in Item 8 “Financial Statements and Supplementary Data.” Under the full cost method of accounting, all costs incurred in the acquisition, exploration, and development of properties are capitalized, including internal costs directly attributable to these activities.
We follow the full cost method of accounting for our oil and natural gas properties in accordance with SEC Regulation S-X Rule 4-10, as described in Note 2 to the Consolidated Financial Statements, Significant Accounting Policies, in Item 8 “Financial Statements and Supplementary Data.” Our estimates of proved oil and natural gas reserves are a major component of the depletion and full cost ceiling calculations.
Dollars, unless otherwise noted) Year Ended December 31, 2022 % Change 2021 % Change 2020 SEC Compliant Reserves, NAR (MMBOE) Estimated proved oil and gas reserves 66 (1) 67 3 65 Estimated probable oil and gas reserves 36 — 36 (18) 44 Estimated possible oil and gas reserves 39 26 31 (30) 44 Average Consolidated Daily Volumes (BOPD) Working interest (“WI”) production before royalties 30,746 16 26,507 17 22,624 Royalties (6,931) 41 (4,919) 93 (2,552) Production NAR 23,815 10 21,588 8 20,072 (Increase) decrease in inventory (119) (1,290) 10 (89) 91 Sales (1) 23,696 10 21,598 7 20,163 Net Income (Loss) $ 139,029 227 $ 42,482 105 $ (777,967) Operating Netback Oil sales $ 711,388 50 $ 473,722 99 $ 237,838 Operating expenses (162,385) 20 (135,722) 19 (114,371) Transportation expenses (10,197) (12) (11,618) 8 (10,739) Operating netback (2) $ 538,806 65 $ 326,382 190 $ 112,728 G&A Expenses Before Stock-Based Compensation $ 31,908 15 $ 27,867 15 $ 24,134 G&A Stock-Based Compensation $ 9,049 8 $ 8,396 590 $ 1,216 Adjusted EBITDA (2) $ 489,555 103 $ 241,536 150 $ 96,482 Net Cash Provided By Operating Activities $ 427,711 75 $ 244,834 202 $ 81,074 Funds Flow From Operations (2) $ 366,024 96 $ 186,485 312 $ 45,213 Capital Expenditures $ 236,604 58 $ 149,879 56 $ 96,281 As at December 31, (Thousands of U.S.
Dollars, unless otherwise noted) Year Ended December 31, 2023 % Change 2022 % Change 2021 SEC Compliant Reserves, NAR (MMBOE) Estimated proved oil and gas reserves 74 12 66 (1) 67 Estimated probable oil and gas reserves 46 28 36 — 36 Estimated possible oil and gas reserves 49 26 39 26 31 Average Consolidated Daily Volumes (BOPD) Working interest (“WI”) production before royalties 32,647 6 30,746 16 26,507 Royalties (6,548) (6) (6,931) 41 (4,919) Production NAR 26,099 10 23,815 10 21,588 (Increase) decrease in inventory (152) (28) (119) (1,290) 10 Sales (1) 25,947 9 23,696 10 21,598 Net (Loss) Income $ (6,287) (105) $ 139,029 227 $ 42,482 Operating Netback Oil sales $ 636,957 (10) $ 711,388 50 $ 473,722 Operating expenses (186,864) 15 (162,385) 20 (135,722) Transportation expenses (14,546) 43 (10,197) (12) (11,618) Operating netback (2) $ 435,547 (19) $ 538,806 65 $ 326,382 G&A Expenses Before Stock-Based Compensation $ 40,124 26 $ 31,908 15 $ 27,867 G&A Stock-Based Compensation $ 5,722 (37) $ 9,049 8 $ 8,396 Adjusted EBITDA (2) $ 399,355 (17) $ 481,882 101 $ 240,134 Net Cash Provided By Operating Activities $ 227,992 (47) $ 427,711 75 $ 244,834 Funds Flow From Operations (2) $ 276,785 (24) $ 366,024 96 $ 186,485 Capital Expenditures $ 218,882 (7) $ 236,604 58 $ 149,879 As at December 31, (Thousands of U.S.
Dollars) 2022 2021 2020 Income (loss) before income taxes $ 244,935 $ 23,136 $ (853,361) Current income tax expense $ 80,566 $ 4,479 $ 754 Deferred income tax expense (recovery) 25,340 (23,825) (76,148) Total income tax expense (recovery) $ 105,906 $ (19,346) $ (75,394) Effective tax rate 43 % (84) % 9 % Current income tax expense for the year ended December 31, 2022, was $80.6 million (2021 - $4.5 million; 2020 - $0.8 million).
Dollars) 2023 2022 2021 Income before income taxes $ 106,160 $ 244,935 $ 23,136 Current income tax expense $ 55,688 $ 80,566 $ 4,479 Deferred income tax expense (recovery) 56,759 25,340 (23,825) Total income tax expense (recovery) $ 112,447 $ 105,906 $ (19,346) Effective tax rate 106 % 43 % (84) % Current income tax expense for the year ended December 31, 2023, was $55.7 million (2022 - $80.6 million; 2021 - $4.5 million).
Under GAAP, income taxes, deferred taxes, and PEF are considered monetary assets and liabilities and require translation from local currency to U.S. dollar functional currency at each balance sheet date.
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.
In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12-month period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first day-of-the-month price for each month within such period for that oil and natural gas.
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.
The ceiling calculation dictates that a 10% discount factor be used and future net revenues are calculated using prices that represent the average of the first day of each month price for the 12-month period.
The ceiling test calculation dictates that a 10% discount factor be used and future net revenues are calculated 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.
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.
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.
Dollars) Year Ended December 31, 2022 % change 2021 % change 2020 G&A expenses before stock-based compensation $ 31,908 15 $ 27,867 15 $ 24,134 G&A stock-based compensation 9,049 8 8,396 590 1,216 G&A expenses including stock-based compensation $ 40,957 13 $ 36,263 43 $ 25,350 (U.S.
Dollars) Year Ended December 31, 2023 % change 2022 % change 2021 G&A expenses before stock-based compensation $ 40,124 26 $ 31,908 15 $ 27,867 G&A stock-based compensation 5,722 (37) 9,049 8 8,396 G&A expenses including stock-based compensation $ 45,846 12 $ 40,957 13 $ 36,263 (U.S.
In accordance with GAAP, we used an average Brent price of $97.98 per bbl less corresponding differentials for the purpose of the December 31, 2022 ceiling test calculation (2021 and 2020 - $68.92 and $43.43 per bbl, respectively). For the years ended December 31, 2022, and 2021, we had no oil inventory 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). G&A Expenses (Thousands of U.S.
The decrease in transportation expenses per bbl was a result of higher volumes sold at wellhead and higher sales volumes in 2022 compared to the corresponding period 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.
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.
Dollars) Oil sales $ 711,388 $ 473,722 $ 237,838 Transportation expenses (10,197) (11,618) (10,739) 701,191 462,104 227,099 Operating expenses (162,385) (135,722) (114,371) Operating netback (1) $ 538,806 $ 326,382 $ 112,728 (U.S.
Dollars) Oil sales $ 636,957 $ 711,388 $ 473,722 Transportation expenses (14,546) (10,197) (11,618) 622,411 701,191 462,104 Operating expenses (186,864) (162,385) (135,722) Operating netback (1) $ 435,547 $ 538,806 $ 326,382 (U.S.
Our estimates of proved oil and gas reserves are a major component of the depletion and full cost ceiling calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production, and the amount and timing of future expenditures.
Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production, and the amount and timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries.
Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 34 Oil Production and Sales Volumes, BOPD Year Ended December 31, Average Daily Volumes (BOPD) 2022 2021 2020 WI production before royalties 30,746 26,507 22,624 Royalties (6,931) (4,919) (2,552) Production NAR 23,815 21,588 20,072 (Increase) decrease in inventory (119) 10 91 Sales 23,696 21,598 20,163 Royalties, % of working interest production before royalties 23 % 19 % 11 % Oil production NAR for the year ended December 31, 2022, increased by 10% to 23,815 BOPD from 2021.
Oil Production and Sales Volumes, BOPD Year Ended December 31, Average Daily Volumes (BOPD) 2023 2022 2021 WI production before royalties 32,647 30,746 26,507 Royalties (6,548) (6,931) (4,919) Production NAR 26,099 23,815 21,588 (Increase) decrease in inventory (152) (119) 10 Sales 25,947 23,696 21,598 Royalties, % of working interest production before royalties 20 % 23 % 19 % Oil production NAR for the year ended December 31, 2023, increased by 10% to 26,099 BOPD compared to 23,815 in 2022.
In 2021 the Castilla and Vasconia differentials per bbl averaged $5.74 and $3.52, respectively compared to $6.79 and $4.31 in 2020. The following table shows the effect of changes in realized price and sales volumes on our oil sales for the years ended December 31, 2022, 2021, and 2020: Year Ended December 31, (Thousands of U.S.
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: Year Ended December 31, (Thousands of U.S.
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.
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.
Total operating expenses were $162.4 million in 2022, compared to $135.7 million in 2021, representing a 20% increase • Quality and transportation discounts per bbl for 2022 were $16.79 compared to $10.86 in 2021.
Total operating expenses were $186.9 million in 2023, compared to $162.4 million in 2022, representing a 15% increase • Quality and transportation discounts per bbl decreased in 2023 to $14.90 when compared to $16.79 in 2022.
Share capital The evolving energy transition and general sentiment to the oil and gas industry may result in reduced access to capital markets.
We did not experience material credit losses on our accounts receivable during 2023. Share capital The evolving energy transition and general sentiment to the oil and gas industry may result in reduced access to capital markets.
The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates.
Different reserve engineers may make different estimates of reserve quantities based on the same data. We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates.
On a per bbl basis, average realized prices increased by 86% to $60.09 for the year ended December 31, 2021, compared to $32.23 in 2020, primarily as a result of the increase in benchmark oil prices and lower Castilla and Vasconia differentials in 2021.
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.
Funding this program from cash flow from operations relies in part on Brent oil prices being at least $60 per bbl for 2023. Capital Program Capital expenditures during the year ended December 31, 2022 were $236.6 million.
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. Capital Program Capital expenditures during the year ended December 31, 2023 were $218.9 million.
G&A expenses before stock-based compensation for the year ended December 31, 2021, increased 15% to $27.9 million or 8% to $3.53 per bbl compared to 2020 due to 2021 performance bonus, which was slightly offset by lower travel, information technology, consulting, and legal expenses. 41 On per bbl basis, G&A expenses after stock-based compensation for the year ended December 31, 2022, increased 3% to $4.74 per bbl compared to 2021 for the same reason mentioned above and higher stock-based compensation expense.
On a per bbl basis, G&A expenses after stock-based compensation costs for the year ended December 31, 2022, increased by 3% to $4.74 per bbl compared to 2021 for the same reason mentioned above and higher stock-based compensation expense.
The table below shows the break-down of our 2023 capital program: Number of Wells (Gross and Net) 2023 Capital Budget ($ million) Development - Colombia 18 - 23 150 - 170 Exploration - Colombia and Ecuador 4 - 6 60 - 80 22 - 29 210-250 Our base capital program for 2023 is $210 million to $250 million for exploration and development activities.
The table below shows the break-down of our 2024 capital program: Number of Wells (Gross) Number of Wells (Net) 2024 Capital Budget ($ million) Development - Colombia 13 - 17 12 - 16 130 - 140 Exploration - Colombia and Ecuador 6 - 9 6 - 9 80 - 100 19 - 26 18 - 25 210 - 240 Our base capital program for 2024 is $210 million to $240 million for exploration and development activities.
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.
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.
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.
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. 52
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.
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. For the years ended December 31, 2023, 2022, and 2021, we had no ceiling test impairment losses.
(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.
Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure.
Transportation expenses for the year ended December 31, 2022, decreased b y 12% to $10.2 million , compared to $11.6 million in 2021 as a result of higher volumes sold at wellhead during 2022. On a per bbl basis, transportation expenses decreased 20% 37 to $1.18 from $1.48 in 2021.
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.
Dollars) 2022 2021 2020 2022 2021 2022 Net income (loss) $ 139,029 $ 42,482 $ (777,967) $ 33,275 $ 62,524 $ 38,663 Adjustments to reconcile net income (loss) to funds flow from operations DD&A expenses 180,280 139,874 164,233 51,781 41,574 45,320 Asset impairment — — 564,495 — — — Goodwill impairment — — 102,581 — — — Deferred tax expense (recovery) 25,340 (23,825) (76,148) (11,528) (50,634) 4,914 Stock-based compensation expense (recovery) 9,049 8,396 1,216 2,673 1,799 (170) Amortization of debt issuance costs 3,528 3,809 3,625 759 1,127 751 Non-cash lease expense 2,818 1,667 1,951 809 445 851 Lease payments (1,666) (1,621) (1,926) (532) (382) (402) Unrealized foreign exchange loss 10,251 21,879 5,271 4,113 4,934 6,636 Unrealized derivative instruments (gain) loss — (9,589) 7,809 — (12,088) (219) Other financial instruments (gain) loss (7) 3,369 48,047 (7) 15,794 — Other non-cash (gain) loss (2,598) 44 2,026 — 44 (2,598) Funds flow from operations (non-GAAP) $ 366,024 $ 186,485 $ 45,213 $ 81,343 $ 65,137 $ 93,746 Capital expenditures $ 236,604 $ 149,879 $ 96,281 $ 72,887 $ 40,229 $ 57,035 Free cash flow (non-GAAP) $ 129,420 $ 36,606 $ (51,068) $ 8,456 $ 24,908 $ 36,711 Consolidated Results of Operations Year Ended December 31, (Thousands of U.S.
Dollars) 2023 2022 2021 2023 2022 2023 Net (loss) income $ (6,287) $ 139,029 $ 42,482 $ 7,711 $ 33,275 $ 6,527 Adjustments to reconcile net (loss) income to funds flow from operations DD&A expenses 215,584 180,280 139,874 52,635 51,781 55,019 Deferred tax expense (recovery) 56,759 25,340 (23,825) 13,517 (11,528) 13,990 Stock-based compensation expense 5,722 9,049 8,396 1,974 2,673 1,931 Amortization of debt issuance costs 5,831 3,528 3,809 2,437 759 1,594 Non-cash lease expense 4,967 2,818 1,667 1,479 809 1,235 Lease payments (3,018) (1,666) (1,621) (1,100) (532) (676) Unrealized foreign exchange (gain) loss (5,085) 10,251 21,879 2,729 4,113 (266) Unrealized derivative instruments gain — — (9,589) — — — Other financial instruments loss (gain) 15 (7) 3,369 15 (7) — Other non-cash loss (gain) 2,297 (2,598) 44 3,266 — (354) Funds flow from operations (non-GAAP) $ 276,785 $ 366,024 $ 186,485 $ 84,663 $ 81,343 $ 79,000 Capital expenditures $ 218,882 $ 236,604 $ 149,879 $ 39,175 $ 72,887 $ 43,080 Free cash flow (non-GAAP) $ 57,903 $ 129,420 $ 36,606 $ 45,488 $ 8,456 $ 35,920 Consolidated Results of Operations Year Ended December 31, (Thousands of U.S.
Dollars Per bbl Sales Volumes NAR) G&A expenses before stock-based compensation $ 3.69 5 $ 3.53 8 $ 3.27 G&A stock-based compensation 1.05 (2) 1.07 569 0.16 G&A expenses including stock-based compensation $ 4.74 3 $ 4.60 34 $ 3.43 On a per bbl basis, G&A expenses before stock-based compensation increased by 5% to $3.69 per bbl due to higher costs for optimization projects and lease obligations expenses related to additional leases capitalized during 2022.
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.
In 2022, the Acordionero field represented 52% percent of our production. As of December 31, 2022, we incurred capital expenditures of $0.6 million on gas-to-power facilities in the Cohembi field to reduce emissions principally by the recovery of natural gas and displacement of diesel.
Expenditures on property, plant and equipment From 2018 to 2023, we incurred $22.9 million on gas-to-power facilities in the Acordionero field to reduce emissions principally by the recovery and use of natural gas in the field for power generation and reduction of diesel use for power generation. In 2023, the Acordionero field represented 52% of our production.
Royalties as a percentage of production for the year ended December 31, 2022, increased compared to prior year commensurate with the increase in benchmark oil prices and the price sensitive royalty regime in Colombia. Oil production NAR for the year ended December 31, 2021, increased by 8% to 21,588 BOPD compared to 20,072 BOPD in 2020.
The increase in production was a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador. 34 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.
During the year ended December 31, 2022, we spud the following wells in Colombia and Ecuador: Number of Wells (Gross and Net) Colombia Development 20.0 Exploration 4.0 Service 8.0 32.0 Ecuador Exploration 2.0 2.0 Total Company 34.0 In 2022 we spud 20 development, four exploration and eight service wells in Colombia and two exploration wells in Ecuador.
During the year ended December 31, 2023, we spud the following wells in Colombia: Number of Wells (Gross and Net) Colombia Development 17.0 Service 8.0 Total 25.0 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.
Stock-based compensation per bbl decreased by 2% due to higher sales volumes in proportion to 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.
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. 41 Foreign Exchange Losses 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.
Current assets and current liabilities These amounts are short-term in nature, and during 2022 management was not aware of any material impacts on these items related to climate change and climate events. We did not experience material credit losses on our accounts receivable during 2022.
We will continue to implement projects that focus on environmental protection, conservation and reforestation efforts. Current assets and current liabilities These amounts are short-term in nature, and during the year ended December 31, 2023, management was not aware of any material impacts on these items related to climate change and climate events.
We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions. In addition to cash on hand, cash generated from operations and borrowings under our credit facility, in pursuing our strategic acquisitions and growth opportunities, we may seek other sources of capital.
We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market Risk — interest-rate, FX, commodity exposure
4 edited+1 added−0 removed4 unchanged
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market Risk — interest-rate, FX, commodity exposure
4 edited+1 added−0 removed4 unchanged
2022 filing
2023 filing
Biggest changeAs a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency. A strengthening in one Colombian peso against the U.S. dollar results in foreign exchange gain of approximately $6 thousand on deferred tax asset balance and a foreign exchange loss of approximately $7 thousand on taxes payable.
Biggest changeAs a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency.
Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issues at overnight rates, or U.S. or Canadian government-backed federal, 55 provincial or state securities or other money market instruments with high credit ratings and short-term liquidity.
Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issues at overnight rates, or U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity.
Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso and Canadian dollar (“CAD”) due to our current and deferred tax assets, and taxes receivable denominated in the local currency of the Colombian foreign operations which are our monetary assets.
Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our accounts payable, taxes receivable and payable and deferred tax assets and liabilities in Colombia are denominated in the local currency of the Colombian foreign operations which are our monetary assets.
Interest Rate Risk Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our credit facility, which bears floating rates of interest. At December 31, 2022, our credit facility remained undrawn (December 31, 2021 - $67.5 million).
Interest Rate Risk Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our credit facility, which bears floating rates of interest. At December 31, 2023, our credit facility was drawn by $36.4 million (December 31, 2022 - undrawn).
Added
A one percent strengthening in Colombian peso against the U.S. dollar results in foreign exchange loss of approximately 0.4 million U.S. dollars on accounts payable, gain of approximately $0.3 million U.S. dollars on taxes receivable and payable and loss of approximately $0.4 million U.S. dollars on deferred tax assets and liabilities.