UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
(Mark One)
OR
For the fiscal year ended
OR
For the transition period from ______________________ to ___________________________
OR
Date of event requiring this shell company report
Commission file number:
(Exact name of Registrant as specified in its charter)
(Jurisdiction of incorporation)
(Address of principal executive offices)
Chief Strategy, Sustainability and Legal Officer
GeoPark Limited
Phone: +
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
Copies to:
Yasin Keshvargar, Esq.
Davis Polk & Wardwell LLP
Phone: (
Fax: (212) 701 5800
Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbols | Name of each exchange on which registered |
Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital stock or common stock as of the close of business covered by the annual report.
Common shares:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ☐
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes ☐
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer”, “accelerated filer”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☐ | Non-accelerated filer ☐ | Emerging growth company |
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
US GAAP ☐ |
| Other ☐ |
If “Other” has been checked in response to the previous question indicate by check mark which financial statement item the registrant has elected to follow.
☐ Item 17 ☐ Item 18
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
GEOPARK LIMITED
TABLE OF CONTENTS
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ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS | 1 | |
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ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 155 | |
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES | 155 | |
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ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS | 156 | |
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Management’s Annual Report on Internal Control over Financial Reporting | 156 | |
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ITEM 16D. Exemptions from the listing standards for audit committees | 158 | |
ITEM 16E. Purchases of equity securities by the issuer and affiliated purchasers. | 158 | |
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ITEM 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 160 | |
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GLOSSARY OF OIL AND NATURAL GAS TERMS
The terms defined in this section are used throughout this annual report:
“appraisal well” means a well drilled to further confirm and evaluate the presence of hydrocarbons in a reservoir that has been discovered.
“API” means the American Petroleum Institute’s inverted scale for denoting the “light” or “heaviness” of crude oils and other liquid hydrocarbons.
“bbl” means one stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
“bcf” means one billion cubic feet of natural gas.
“bcm” means billion cubic meters.
“boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.
“boepd” means barrels of oil equivalent per day.
“bopd” means barrels of oil per day.
“British thermal unit” or “btu” means the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
“basin” means a large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“CEOP” (Contrato Especial de Operación) means a special operating contract the Chilean signs with a company or a consortium of companies for the exploration and exploitation of hydrocarbon wells.
“completion” means the process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“developed acreage” means the number of acres that are allocated or assignable to productive wells or wells capable of production.
“developed reserves” are expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify developed reserves as undeveloped.
“development well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
“dry hole” means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“E&P contract” means exploration and production contract.
“economic interest” means an indirect participation interest in the net revenues from a given block based on bilateral agreements with the concessionaires.
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“economically producible” means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
“exploratory well” means a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well as those items are defined below.
“field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
“formation” means a layer of rock which has distinct characteristics that differ from nearby rock.
“mbbl” means one thousand barrels of crude oil, condensate, or natural gas liquids.
“mboe” means one thousand barrels of oil equivalent.
“mcf” means one thousand cubic feet of natural gas.
“Measurements” include:
| ● | “m” or “meter” means one meter, which equals approximately 3.28084 feet; |
| ● | “km” means one kilometer, which equals approximately 0.621371 miles; |
| ● | “sq. km” means one square kilometer, which equals approximately 247.1 acres; |
| ● | “bbl” “bo,” or “barrel of oil” means one stock tank barrel, which is equivalent to approximately 0.15898 cubic meters; |
| ● | “boe” means one barrel of oil equivalent, which equals approximately 160.2167 cubic meters, determined using the ratio of 6,000 cubic feet of natural gas to one barrel of oil; |
| ● | “cf” means one cubic foot; |
| ● | “m,” when used before bbl, boe or cf, means one thousand bbl, boe or cf, respectively; |
| ● | “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf, respectively; |
| ● | “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf, respectively; and |
| ● | “pd” means per day. |
“metric ton” or “MT” means one thousand kilograms. Assuming standard quality oil, one metric ton equals 7.9 bbl.
“mmbbl” means one million barrels of crude oil, condensate or natural gas liquids.
“mmboe” means one million barrels of oil equivalent.
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“mmbtu” means one million British thermal units.
“productive well” means a well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“prospect” means a potential trap which may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of them fail neither oil nor natural gas will be present, at least not in commercial volumes.
“proved developed reserves” means those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
“proved reserves” means estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4 10(a)(2).
“proved undeveloped reserves” means are those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.
“reasonable certainty” means a high degree of confidence.
“recompletion” means the process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
“reserves” means estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, a revenue interest in the production, installed means of delivering oil, gas, or related substances to market, and all permits and financing required to implement the project.
“reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“royalty” means a fractional undivided interest in the production of oil and natural gas wells or the proceeds therefrom, to be received free and clear of all costs of development, operations or maintenance.
“service well” means a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, saltwater disposal, water supply for injection, observation, or injection for in-situ combustion.
“shale” means a fine-grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.
“spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing, and is often established by regulatory agencies).
“stratigraphic test well” means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to
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hydrocarbon exploration. Stratigraphic test wells are classified as (i) exploratory-type, if not drilled in a proved area, or (ii) development-type, if drilled in a proved area.
“undeveloped reserves” are quantities expected to be recovered through future investments: (1) from new wells on undrilled acreage in known accumulation, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g., when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.
“unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“wellbore” means the hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.
“working interest” means the right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
“workover” means operations in a producing well to restore or increase production.
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PRESENTATION OF FINANCIAL AND OTHER INFORMATION
Certain definitions
Unless otherwise indicated or the context otherwise requires, all references in this annual report to:
| ● | “GeoPark Limited,” “GeoPark,” “we,” “us,” “our,” the “Company” and words of a similar effect, are to GeoPark Limited, an exempted company incorporated under the laws of Bermuda, together with its consolidated subsidiaries; |
| ● | “Amerisur” are to Amerisur Resources Limited and its subsidiaries; |
| ● | “GeoPark Brazil” are to GeoPark Brasil Exploração e Produção de Petróleo e Gás Ltda.; |
| ● | “Petroperu” are to Petróleos del Perú S.A.; |
| ● | “YPF” are to YPF S.A.; |
| ● | “ONGC” are to ONGC Videsh Limited, international petroleum company of India; |
| ● | “Petroamazonas” are to Petroamazonas Ecuador S.A.; |
| ● | “Petroecuador” are to Empresa Pública de hidrocarburos del Ecuador; |
| ● | “MSCI” are to Morgan Stanley Capital International; |
| ● | “Notes due 2024” are to our 2017 issuance of US$425.0 million aggregate principal amount of 6.50% senior notes due 2024; |
| ● | “Notes due 2027” are to our 2020 issuance of US$350.0 million aggregate principal amount of 5.50% senior notes due 2027; |
| ● | “Banco Santander Loan” are to our loan agreement with Banco Santander from October 2018, for Brazilian reais 77.6 million (equivalent to US$20 million at the moment of the loan execution) to repay an existing intercompany loan, which outstanding amount of Brazilian reais 19.4 million (equivalent to US$3.4 million at the moment of the refinancing execution) was refinanced with the bank in September 2020, and was paid in three equal installments in October 2021, April 2022, and October 2022; |
| ● | “US$” and “U.S. dollar” are to the official currency of the United States of America; |
| ● | “Ch$” and “Chilean pesos” are to the official currency of Chile; |
| ● | “AR$” and “Argentine pesos” are to the official currency of Argentina; |
| ● | “real,” “reais” and “R$” are to the official currency of Brazil; |
| ● | “ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels Agency (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis); |
| ● | “ANH” are to the Colombian National Hydrocarbons Agency (Agencia Nacional de Hidrocarburos); |
| ● | “ENAP” are to the Chilean National Petroleum Company (Empresa Nacional de Petróleo); |
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| ● | “RODA” are to the Oil Pipeline Network of the Amazonian District (Red de Oleoductos del Distrito Amazónico); |
| ● | “SOTE” are to the Ecuadorian Oil Pipeline System (Sistema de Oleoducto Transecuatoriano); |
| ● | “IOGP” are to the International Association of Oil and Gas Producers; |
| ● | “IPIECA” are to the International Petroleum Industry Environmental Conservation Association; |
| ● | “IADC” are to the International Association of Drilling Contractors; |
| ● | “ARPEL” are to the Regional Association of Oil and Gas Companies, a non-profit association gathering oil, gas and biofuels sector companies and institutions in Latin America and the Caribbean; |
| ● | “UTA” are to Unidad Tributaria Anual; |
| ● | “economic interest” are to an indirect participation interest in the net revenues from a given block based on bilateral agreements with the concessionaires; |
| ● | “ESG” are to Environmental, Social and Governance; and |
| ● | “IFC” are to International Finance Corporation. |
Financial statements
Our historical financial data presented does not include any results or other financial information of any acquisitions, including the acquisition of Amerisur, prior to their incorporation into our financial statements.
Our consolidated financial statements
This annual report includes our audited consolidated financial statements as of December 31, 2022 and 2021 and for each of the years ended December 31, 2022, 2021 and 2020 (hereinafter “Consolidated Financial Statements”).
Our Consolidated Financial Statements are presented in US$ and have been prepared in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”).
Our Consolidated Financial Statements for the year ended December 31, 2022, have been audited by Pistrelli, Henry Martin y Asociados S.R.L., (member of Ernst & Young Global Limited), an independent registered public accounting firm, as stated in their reports included elsewhere in this annual report.
Our fiscal year ends December 31. References in this annual report to a fiscal year, such as “fiscal year 2022,” relate to our fiscal year ended on December 31 of that calendar year.
Non IFRS financial measures
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-IFRS financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, to assess the performance of our Company and the operating segments.
We define Adjusted EBITDA as profit (loss) for the period (determined as if IFRS 16 Leases has not been adopted), before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs
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of unsuccessful exploration efforts, accrual of share-based payment, unrealized result on commodity risk management contracts, geological and geophysical expenses allocated to capitalized projects, and other non-recurring events. Adjusted EBITDA is not a measure of profit or cash flows as determined by IFRS.
We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from profit (loss) for the period in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, profit (loss) for the period or cash flows from operating activities as determined in accordance with IFRS or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, or unrealized results in commodity risk management contracts, none of which are components of Adjusted EBITDA. Our computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit for the year, see Note 6 to our Consolidated Financial Statements as of and for the years ended 2022, 2021 and 2020.
Oil and gas reserves and production information
DeGolyer and MacNaughton 2022 Year-end Reserves Report
The information included elsewhere in this annual report regarding estimated quantities of proved reserves in Colombia, Chile, Brazil and Ecuador is derived from estimates of the proved reserves as of December 31, 2022. The reserves estimates described herein are derived from the DeGolyer and MacNaughton Reserves Report (“D&M Reserves Report”), which was prepared for us by the independent reserves engineering team of DeGolyer and MacNaughton Corp. and is included as an exhibit to this annual report. The D&M Reserves Report presents oil and gas reserves estimates located in the Llanos 32, Llanos 34, Platanillo and CPO-5 Blocks in Colombia, the Fell Block in Chile, the BCAM-40 (Manati) Block in Brazil and the Espejo and Perico Blocks in Ecuador.
Market share and other information
Market data, other statistical information, information regarding recent developments in Colombia, Chile, Brazil, Argentina and Ecuador and certain industry forecast data used in this annual report were obtained from internal reports and studies, where appropriate, as well as estimates, market research, publicly available information and industry publications. Industry publications generally state that the information they include has been obtained from sources believed to be reliable, but that the accuracy and completeness of such information is not guaranteed. Similarly, internal reports and studies, estimates and market research, which we believe to be reliable and accurately extracted by us for use in this annual report, have not been independently verified. However, we believe such data is accurate and agree that we are responsible for the accurate extraction of such information from such sources and its correct reproduction in this annual report.
In addition, we have provided definitions for certain industry terms used in this annual report in the “Glossary of oil and natural gas terms”.
Rounding
We have made rounding adjustments to some of the figures included elsewhere in this annual report. Accordingly, numerical figures shown as totals in some tables may not be an arithmetic aggregation of the figures that precede them.
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FORWARD-LOOKING STATEMENTS
This annual report contains statements that constitute forward-looking statements. Many of the forward-looking statements contained in this annual report can be identified by the use of forward-looking words such as “anticipate,” “believe,” “could,” “expect,” “should,” “plan,” “intend,” “will,” “estimate” and “potential,” among others.
Forward-looking statements appear in a number of places in this annual report and include, but are not limited to, statements regarding our intent, belief or current expectations. Forward-looking statements are based on our management’s beliefs and assumptions and on information currently available to our management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors, including, but not limited to, those identified under the section “Item 3. Key Information—D. Risk factors” in this annual report. These risks and uncertainties include factors relating to:
| ● | pandemics, or the future outbreak of any other highly infectious or contagious disease, including the COVID-19 pandemic; |
| ● | the volatility of oil and natural gas prices; |
| ● | operating risks, including equipment failures and the amounts and timing of revenues and expenses; |
| ● | termination of, or intervention in, concessions, rights or authorizations granted by the Colombian, Chilean, Brazilian and Ecuadorian governments to us; |
| ● | uncertainties inherent in making estimates of our oil and natural gas data; |
| ● | environmental constraints on operations and environmental liabilities arising out of past or present operations; |
| ● | discovery and development of oil and natural gas reserves; |
| ● | climate change related risks; |
| ● | project delays or cancellations; |
| ● | financial market conditions and the results of financing efforts; |
| ● | political, legal, regulatory, governmental, administrative and economic conditions and developments in the countries in which we operate; |
| ● | the recent social and political unrest, driven in many cases by populist groups, in many countries in which we operate; |
| ● | fluctuations in inflation and exchange rates in Colombia, Chile, Brazil, Ecuador and in other countries in which we may operate in the future; |
| ● | availability and cost of drilling rigs, production equipment, supplies, personnel and oil field services; |
| ● | contract counterparty risk; |
| ● | projected and targeted capital expenditures and other cost commitments and revenues; |
| ● | weather and other natural phenomena; |
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| ● | armed conflicts, including the current armed conflict in Ukraine; |
| ● | the impact of recent and future regulatory proceedings and changes, changes in environmental, health and safety and other laws and regulations to which our company or operations are subject, as well as changes in the application of existing laws and regulations; |
| ● | current and future litigation; |
| ● | our ability to successfully identify, integrate and complete pending or future acquisitions and dispositions; |
| ● | our ability to retain key members of our senior management and key technical employees; |
| ● | competition from other similar oil and natural gas companies; |
| ● | market or business conditions and fluctuations in global and local demand for energy; |
| ● | the direct or indirect impact on our business resulting from terrorist incidents or responses to such incidents, including the effect on the availability of and premiums on insurance; |
| ● | the adverse effect which a substantial or extended decline in oil, natural gas and methanol price may have on our business; |
| ● | the difficulty in integrating significant acquisitions or unexpected contingencies or changes in reserves estimates we discover following the completion of such acquisitions; and |
| ● | other factors discussed under “Item 3. Key Information—D. Risk factors” in this annual report. |
Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances or to reflect the occurrence of unanticipated events.
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PART I
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
A. Directors and senior management
Not applicable.
B. Advisers
Not applicable.
C. Auditors
Not applicable.
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE
A. Offer statistics
Not applicable.
B. Method and expected timetable
Not applicable.
ITEM 3. KEY INFORMATION
A. Reserved
B. Capitalization and indebtedness
Not applicable.
C. Reasons for the offer and use of proceeds
Not applicable.
D. Risk factors
Our business, financial condition and results of operations could be materially and adversely affected if any of the risks described below occur. As a result, the market price of our common shares could decline, and you could lose all or part of your investment. This annual report also contains forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements.” The risks below are not the only ones facing our Company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. The following risk factors have been grouped as follows:
| a) | Risks relating to our business; |
| b) | Risks relating to the countries in which we operate; and |
| c) | Risks relating to our common shares. |
1
Summary of Key Risks
Our business is subject to numerous risks and uncertainties, discussed in more detail below. These risks include, among others, the following key risks:
| ● | The COVID-19 pandemic has and may continue to adversely impact our business, financial condition, and results of our operations, the global economy, and the demand for and prices of oil and natural gas. The uncertainty of the impact an endemic or pandemic disease may have makes it impossible for us to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on our business. |
| ● | A substantial or extended decline in oil, natural gas and methanol prices may materially adversely affect our business, financial condition, or results of operations. |
| ● | Low oil prices may impact our operations and corporate strategy. |
| ● | Unless we replace our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities. |
| ● | We derive a significant portion of our revenues from sales to a few key customers. |
| ● | Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange rates. |
| ● | There are inherent risks and uncertainties relating to the exploration and production of oil and natural gas. |
| ● | Our identified potential drilling location inventories are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. |
| ● | Our business requires significant capital investment and maintenance expenses, which we may be unable to finance on satisfactory terms or at all. |
| ● | Oil and gas operations contain a high degree of risk, and we may not be fully insured against all risks we face in our business. |
| ● | The development schedule of oil and natural gas projects is subject to cost overruns and delays. |
| ● | Competition in the oil and natural gas industry is intense, which makes it difficult for us to attract capital, acquire properties and prospects, market oil and natural gas and secure trained personnel. |
| ● | Our estimated oil and gas reserves are based on assumptions that may prove inaccurate. |
| ● | Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production. |
| ● | We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities, including indigenous communities, where our reserves are located. |
| ● | Under the terms of some of our various CEOPs, E&P contracts, production sharing agreements and concession agreements, we are obligated to drill wells, declare any discoveries, and file periodic reports to retain our rights and establish development areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts of our blocks or concession areas. |
| ● | Our contracts in obtaining rights to explore and develop oil and natural gas reserves are subject to contractual expiration dates and operating conditions, and our CEOPs, E&P contracts, production sharing agreements and concession agreements are subject to early termination in certain circumstances. |
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| ● | We sell all our natural gas in Chile to a single customer, who has in the past temporarily idled its principal facility. |
| ● | We are not, and may not be in the future, the sole owner or operator of all our licensed areas and do not, and may not in the future, hold all the working interests in some of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly owned, assets. |
| ● | Acquisitions that we have completed, and any future acquisitions, strategic investments, partnerships, or alliances could be difficult to integrate and/or identify, could divert the attention of key management personnel, disrupt our business, dilute stockholder value and adversely affect our financial results, including impairment of goodwill and other intangible assets. |
| ● | The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. |
| ● | The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our proved undeveloped reserves ultimately may not be developed or produced. |
| ● | We are exposed to the credit risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations. |
| ● | Our operations are subject to operating hazards, including extreme weather events, which could expose us to potentially significant losses. |
| ● | We are highly dependent on certain members of our management and technical team, including our geologists and geophysicists, and on our ability to hire and retain new qualified personnel. |
| ● | We and our operations are subject to numerous environmental, social, health and safety laws, regulations and rulings, which may result in material liabilities and costs. |
| ● | Changing investor sentiment towards fossil fuels may affect our operations, impact the price of our common shares and limit our access to financing and insurance. |
| ● | Legislation and regulatory initiatives relating to hydraulic fracturing and other drilling activities for unconventional oil and gas resources could increase the future costs of doing business, cause delays or impede our plans, and materially adversely affect our operations. |
| ● | Our indebtedness and other commercial obligations could adversely affect our financial health and our ability to raise additional capital and prevent us from fulfilling our obligations under our existing agreements and borrowing of additional funds. |
| ● | Our business could be negatively impacted by security threats, including cybersecurity threats as well as other disasters, and related disruptions. |
| ● | We operate in an industry with climate related risks. |
| ● | We operate in areas of significant biodiversity value. |
| ● | We operate in areas that have historical and current ties to indigenous peoples. |
| ● | Exploration blocks in the Putumayo area carry significant costs related to biodiversity management and reputational risk due to overlapping claims of rightful ownership. |
| ● | Our operations may be adversely affected by political and economic circumstances in the countries in which we operate and in which we may operate in the future. |
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| ● | We depend on maintaining good relations with the respective host governments and national oil companies in each of our countries of operation. |
| ● | Oil and natural gas companies in Colombia, Chile, Brazil and Ecuador do not own any of the oil and natural gas reserves in such countries. |
| ● | Oil and gas operators are subject to extensive regulation in the countries in which we operate. |
| ● | Colombia has experienced and continues to experience internal security issues that have had or could have a negative effect on the Colombian economy. |
| ● | Our operations in Colombia are subject to security and human rights risks. |
| ● | We expect that a limited number of financial institutions in the countries in which we operate, as well as some institutions located in the United States, will hold all or most of our cash. |
| ● | An active, liquid, and orderly trading market for our common shares may not develop and the price of our stock may be volatile, which could limit your ability to sell our common shares. |
| ● | Any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of our board of directors, and will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors. |
| ● | We are a holding company and our only material assets are our equity interests in our operating subsidiaries and our other investments; as a result, our principal source of revenue and cash flow is distributions from our subsidiaries; our subsidiaries may be limited by law and by contract in making distributions to us. |
| ● | Sales of substantial amounts of our common shares in the public market, or the perception that these sales may occur, could cause the market price of our common shares to decline. |
| ● | Provisions of the Notes due 2027 could discourage an acquisition of us by a third party. |
| ● | Certain shareholders have substantial influence over us and could limit your ability to influence the outcome of key transactions, including a change of control. |
| ● | Shareholder activism could cause us to incur significant expenses, hinder execution of our business strategy and impact our stock price. |
| ● | As a foreign private issuer, we are subject to different U.S. securities laws and NYSE governance standards than domestic U.S. issuers. This may afford less protection to holders of our common shares, and you may not receive corporate and company information and disclosure that you are accustomed to receiving or in a manner in which you are accustomed to receiving it. |
| ● | There are regulatory limitations on the ownership and transfer of our common shares which could result in the delay or denial of any transfers you might seek to make. |
| ● | We are a Bermuda company, and it may be difficult for you to enforce judgments against us or against our directors and executive officers. |
| ● | The transfer of our common shares may be subject to capital gains taxes pursuant to indirect transfer rules in Colombia. |
| ● | Legislation enacted in Bermuda as to Economic Substance may affect our operations. |
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Risks relating to our business
The COVID-19 pandemic has and may continue to adversely impact our business, financial condition, and results of our operations, the global economy, and the demand for and prices of oil and natural gas. The uncertainty of the impact an endemic or pandemic disease may have makes it impossible for us to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on our business.
The COVID-19 pandemic and the actions taken by third parties, including, but not limited to, governmental authorities, businesses, and consumers, in response to the pandemic adversely impacted the global economy and created significant volatility in the global financial markets. The COVID-19 pandemic resulted in significant volatility in the financial and commodities markets worldwide, including the dramatic drop in the price of crude oil during 2020. In the event of a potential resurgence of the COVID-19 pandemic, responsive measures may be implemented and further disruptions to the global economy, demand, supply chain and others may occur.
As of the date of this annual report, we believe we have implemented adequate operational measures (such as remote working procedures) to avoid or minimize major disruptions to our business. However, our operations rely on our workforce being able to access our wells, structures and facilities located upon or used in connection with our oil and gas blocks. The uncertainty of the impact that an endemic or pandemic disease may have makes it impossible for us to identify all potential risks related to the COVID-19 pandemic and we cannot assure if, and to what extent, our business, financial condition, cash flows or results of operations may be adversely impacted by any potential resurgence or outbreak of the COVID-19 pandemic, or any other regional or global outbreaks related to any other endemic or pandemic disease.
The COVID-19 pandemic and its unprecedented consequences amplified, and may continue to amplify, the other risks identified in this annual report.
A substantial or extended decline in oil, natural gas and methanol prices may materially adversely affect our business, financial condition, or results of operations.
The prices that we receive for our oil and natural gas production heavily influence our revenues, profitability, access to capital and growth rate. Historically, the markets for oil, natural gas, and methanol (which influence the price for our Chilean gas sales) have been volatile and will likely continue to be volatile in the future. International oil, natural gas and methanol prices have fluctuated widely in recent years and may continue to do so in the future.
The prices that we will receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited, to the following:
| ● | global economic conditions; |
| ● | changes in global supply and demand for oil, natural gas and methanol; |
| ● | the conflict in Ukraine and other armed conflicts; |
| ● | the actions of the Organization of the Petroleum Exporting Countries (“OPEC”); |
| ● | political and economic conditions, including embargoes, in oil-producing countries or affecting other countries; |
| ● | the level of oil- and natural gas-producing activities, particularly in the Middle East, Africa, Russia, South America and the United States; |
| ● | the level of global oil and natural gas exploration and production activity; |
| ● | the level of global oil and natural gas inventories; |
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| ● | the price of methanol; |
| ● | availability of markets for natural gas; |
| ● | weather conditions and other natural disasters; |
| ● | technological advances affecting energy production or consumption; |
| ● | domestic and foreign governmental laws and regulations, including environmental, health and safety laws and regulations; |
| ● | proximity and capacity of oil and natural gas pipelines and other transportation facilities; |
| ● | the price and availability of competitors’ supplies of oil and natural gas in captive market areas; |
| ● | quality discounts for oil production based, among other things, on API, sulphur and mercury content; |
| ● | taxes and royalties under relevant laws and the terms of our contracts; |
| ● | our ability to enter into oil and natural gas sales contracts at fixed prices; |
| ● | the level of global methanol demand and inventories and changes in the uses of methanol; |
| ● | the price and availability of alternative fuels, and possible regulations establishing costs for carbon emissions along the value chain; and |
| ● | future changes to our hedging policies. |
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and methanol price movements. For example, during the three-year period from March 1, 2020, to February 28, 2023, Brent spot prices ranged from a low of US$19.3 per barrel to a high of US$128.0 per barrel. Furthermore, oil, natural gas and methanol prices do not necessarily fluctuate in direct relationship to each other.
Starting in March 2020, the oil market experienced a significant over-supply condition that resulted in a sharp drop in prices, with Brent falling from over US$50 per barrel at the beginning of March 2020, up to under US$20 per barrel in late April 2020. There were two key drivers for this market scenario:
| ● | On the demand side, the sustained impact of the COVID-19 pandemic across the world and the associated containment measures, resulted in a sharp and sudden drop in fuel demand and hence on crude demand as well. This impact had been felt since early 2020 but accelerated significantly in March and April. |
| ● | Concurrently, on the supply side, during the first week of March 2020, OPEC and non-OPEC producers (sometimes referred to as OPEC+) met to discuss the prospect of extending or increasing oil production cuts that had been first put in place in late 2016 and had been renewed and expanded ever since. No consensus was reached among the 24 participating countries, effectively eliminating output reduction targets as of April 1, 2020. As a consequence, OPEC+ countries and especially Saudi Arabia, significantly increased production during April 2020. |
The combined impact of sharply lower demand and growing supply led the market into a significant oil surplus with inventories building around the world and prices dropping to levels last seen in the early 2000s.
In mid-April, in the midst of a significant demand reduction, OPEC+ agreed to a historical 9.7 MMbbl/d output cut. They were joined by other G-20 countries, which indicated they would reduce their production between 3 and 5 MMbbl/d.
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The crude oil market continued normalizing during early 2021 and shifted into an undersupply condition towards the end of the year. This condition was mainly driven by continued demand recovery while supply grew at a slower pace. OPEC+ paced output increase and capital discipline elsewhere, especially within the US Shale producers, were the key factors for moderate supply growth. In addition, natural gas prices spiked significantly during the last quarter of 2021, especially in Europe, pushing oil prices higher as well. These factors brought Brent prices up to US$78 per barrel at the end of 2021.
The armed conflict between Russia and Ukraine during 2022, and the imposition of comprehensive sanctions against Russia (including in relation to the Russian energy sector), as well as the announcement of prohibitions on Russian oil and gas imports by certain members of the European Union, the United Kingdom, the United States, and other countries, has led to volatility in the price of global oil and gas. For example, Brent spot price rose to a maximum of US$128 per barrel in March 2022.
By the second half of 2022, sharply rising inflation has led central banks to shift to a more restrictive policy stance, which historically is indicative of a potential economic recession. An economic recession could influence crude oil demand and, therefore, lead to a drop in crude oil prices, which dropped to US$86 per barrel by the end of 2022, 30% lower from the levels observed in June 2022. The oil embargo on Russia, the OPEC+ preemptive cuts in production and expectations of rising Chinese demand have managed to stabilize prices, but the risks of further declines continue to rise, especially as it is difficult to predict the magnitude of the impact that a potential economic recession would have.
For the year ended December 31, 2022, 97% of our revenues were derived from oil. Because we expect that our production mix will continue to be weighted towards oil, our financial results are more sensitive to movements in oil prices.
For the year ended December 31, 2022, natural gas comprised 3% of our revenues. A decline in natural gas prices could negatively affect our future growth, particularly for future gas sales where we may not be able to secure or extend our current long-term contracts.
Lower oil and natural gas prices may impact our revenues on a per unit basis and may also reduce the amount of oil and natural gas that can be produced economically. In addition, changes in oil and natural gas prices can impact the valuation of our reserves and, in periods of lower commodity prices, we may curtail production and capital spending or may defer or delay drilling wells because of lower cash generation. Lower oil and natural gas prices could also affect our growth, including future and pending acquisitions. A substantial or extended decline in oil or natural gas prices could adversely affect our business, financial condition, and results of operations.
Continuing our hedging strategy, we entered into derivative financial instruments to manage exposure to oil price risk. These derivatives were zero-premium collars and were placed with major financial institutions and commodity traders. We entered into the derivatives under ISDA Master Agreements and Credit Support Annexes.
To the extent that we engage in oil price risk management activities to protect ourselves from declines in oil price, we may be prevented from realizing the benefits of oil price increases above the levels of the zero-premium collars used to manage oil price risk.
As market values of these derivatives fluctuate, we may post or receive variation cash collaterals with our counterparties. In the event of a significant decrease in the market value of the derivatives, we may have to post cash collateral, if they exceed our available credit lines. Even though cash collateral is returned to us upon reductions in the underlying Brent oil price, having to post cash collaterals could affect our near-term liquidity needs. As of the date of this annual report, we have no cash collateral posted related to our commodity risk management contracts. See Note 8 to our Consolidated Financial Statements for details regarding Commodity Risk Management Contracts.
Low oil prices may impact our operations and corporate strategy.
We face limitations on our ability to increase prices or improve margins on the oil and natural gas that we sell. As a consequence of the oil price crisis which started in the first half of 2020 (WTI and Brent, the main international oil price
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markers, fell by more than 45% between December 2019 and March 2020), we immediately took decisive measures to ensure our ability to both maximize ongoing projects and to preserve our cash, such as reducing our work program and made adjustments to our operating and administrative costs, with continuous monitoring to adjust further if necessary. While oil prices have rebounded in 2021 and 2022, oil prices may continue to be volatile and thus, we develop multiple scenarios for our capital expenditure plan. See “Item 4. Information on the Company—B. Business Overview—2023 Strategy and Outlook”.
Funding our anticipated capital expenditures relies in part on oil prices remaining close to our estimates or higher levels and other factors to generate sufficient cash flow. Low oil prices affect our revenues, which in turn affect our debt capacity and the covenants in our financing agreements, as well as the amount of cash we can borrow using our oil reserves as collateral, the amount of cash we are able to generate from current operations and the amount of cash we can obtain from prepayment agreements. If we are not able to generate the sales which, together with our current cash resources, are sufficient to fund our capital program, we will not be able to efficiently execute our work program, which would cause us to further decrease our work program and would harm our business outlook, investor confidence and our share price.
In addition, actions taken by the company to maximize ongoing projects and to reduce expenses, including renegotiations and reduction of oil and gas service contracts and other initiatives such as cost cutting may expose us to claims and contingencies from interested parties that may have a negative impact on our business, financial condition, results of operations and cash flows. If oil prices are lower than expected, we may be unable to meet our contractual obligations with oil and service contracts and suppliers. Equally, those third parties may be unable to meet their contractual obligations to us as a result of the oil price crisis, impacting on our operations.
In budgeting for our future activities, we have relied on a number of assumptions, including, with regard to our discovery success rate, the number of wells we plan to drill, our working interests in our prospects, the costs involved in developing or participating in the development of a prospect, the timing of third-party projects and our ability to obtain needed financing with respect to any further acquisitions and the availability of both suitable equipment and qualified personnel. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental, and competitive uncertainties, conditions in the financial markets, contingencies, and risks, all of which are difficult to predict and many of which are beyond our control. In addition, we opportunistically seek out new assets and acquisition targets to complement our existing operations and have financed such acquisitions in the past through the incurrence of additional indebtedness, including additional bank credit facilities, equity issuances or the sale of minority stakes in certain operations to our partners. We may need to raise additional funds more quickly if one or more of our assumptions prove to be incorrect or if we choose to expand our hydrocarbon asset acquisition, exploration, appraisal or development efforts more rapidly than we presently anticipate, and we may decide to raise additional funds even before we need them if the conditions for raising capital are favorable. The ultimate amount of capital that we will expend may fluctuate materially based on market conditions, our continued production, decisions by the operators in blocks we do not operate, the success of our drilling results and future acquisitions. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and natural gas and the prices we receive from the sale thereof, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production and the actual cost of exploration, appraisal and development of our oil and natural gas assets.
Unless we replace our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.
Production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Accordingly, our current proved reserves will decline as these reserves are produced. As of December 31, 2022, our reserves-to-production (or reserve life) ratio for net proved reserves in Colombia, Chile, Brazil and Ecuador was 5.1 years. According to estimates, if on January 1, 2023, we ceased all drilling and development activities, including recompletions, refracs and workovers, our proved developed producing reserves base in Colombia, Chile, Brazil, and Ecuador would decline 29% during the first year.
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Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and using cost-effective methods to find or acquire additional recoverable reserves. While we have had success in identifying and developing commercially exploitable fields and drilling locations in the past, we may be unable to replicate that success in the future. We may not identify any more commercially exploitable fields or successfully drill, complete or produce more oil or gas reserves, and the wells which we have drilled, and currently plan to drill within our blocks or concession areas, may not discover or produce any further oil or gas or may not discover or produce additional commercially viable quantities of oil or gas to enable us to continue to operate profitably. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be materially adversely affected.
We derive a significant portion of our revenues from sales to a few key customers.
In Colombia, we allocate our sales on a competitive basis to industry leading participants including traders and other producers. During 2022, the oil and gas production was sold to three clients which concentrate 97% of the Colombian subsidiaries’ revenue (accounting for 90% of the consolidated revenue). Delivery points include wellhead and other locations on the Colombian pipeline system for the Llanos Basin production. The Putumayo Basin production is delivered to clients FOB in Esmeraldas, Ecuador, and to the Colombian pipeline system in case of contingencies in Ecuador that affect the transport through the Ecuadorian pipeline system. The outstanding contracts for Colombian production extend through the first half of 2023. We manage our counterparty credit risk associated to sales contracts by performing periodic evaluations of our counterparties’ credit profile and, in certain contracts, including early payment conditions to minimize the exposure.
In Chile, the oil production is sold to ENAP, the State-owned oil and gas company (accounting for 1% of our consolidated revenue), and the gas production is sold to the local subsidiary of Methanex, a Canadian public company (accounting for 1% of our consolidated revenue).
In Brazil, all the hydrocarbons from the Manati Field were sold to Petrobras, the Brazilian State-owned company, which is the operator of the Manati Field (accounting for 2% of our consolidated revenue). See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Brazil—Petrobras Natural Gas Purchase Agreement.”
In Ecuador, oil is transported through the Ecuadorean pipeline system, with Esmeraldas as the delivery point, and 100% of the sales are exported on a competitive basis to industry leading participants including traders and other producers. Sales of crude oil in Ecuador accounted for 1% of our consolidated revenue.
We entered into a crude oil purchase agreement with an oil producer in the Putumayo Basin. The volumes purchased are transported and exported alongside the Group’s Putumayo Basin production. Sales of crude oil purchased from third parties accounted for 1% of our consolidated revenue.
If any of our buyers were to decrease or cease purchasing oil or gas from us, or if any of them were to decide not to renew their contracts with us or to renew them at a lower sales price, this could have a material adverse effect on our business, financial condition, and results of operations. For example, see “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Colombia” and “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Chile.”
Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange rates.
Although most of our revenues are denominated in US$, unfavorable fluctuations in foreign currency exchange rates for certain of our expenses in Colombia, Chile, Brazil and Ecuador could have a material adverse effect on our results of operations. An appreciation of local currencies can increase our costs and negatively impact our results from operations.
Because our Consolidated Financial Statements are presented in US$, we must translate revenues, expenses and income, as well as assets and liabilities, into US$ at exchange rates in effect during or at the end of each reporting period. Since December 2018, we decided to manage exposure to local currency fluctuation with respect to income tax balances in Colombia. Consequently, from time to time we entered into derivative financial instruments in order to anticipate any
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currency fluctuation with respect to estimated income taxes to be paid during the first half of the following year. As of December 31, 2022 and 2021, we had no currency risk management contracts in place. In January 2023, we entered into derivative financial instruments (zero-premium collars) with local banks in Colombia, for an amount equivalent to US$38.0 million in order to anticipate any currency fluctuation with respect to a portion of the estimated income taxes to be paid in April and June 2023.
There are inherent risks and uncertainties relating to the exploration and production of oil and natural gas.
Our performance depends on the success of our exploration and production activities and on the existence of the infrastructure that will allow us to take advantage of our oil and gas reserves. Oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that exploration activities will not identify commercially viable quantities of oil or natural gas. Our decisions to purchase, explore, develop, or otherwise exploit prospects or properties will depend in part on the evaluation of seismic and other data obtained through geophysical, geochemical and geological analysis, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.
Furthermore, the marketability of any oil and natural gas production from our projects may be affected by numerous factors beyond our control. These factors include, but are not limited to, proximity and capacity of pipelines and other means of transportation, the availability of upgrading and processing facilities, equipment availability and government laws and regulations (including, without limitation, laws and regulations relating to prices, sale restrictions, taxes, governmental stake, allowable production, importing and exporting of oil and natural gas, environmental protection and health and safety). The effect of these factors, individually or jointly, cannot be accurately predicted, but may have a material adverse effect on our business, financial condition, and results of operations.
There can be no assurance that our drilling programs will produce oil and natural gas in the quantities or at the costs anticipated, or that our currently producing projects will not cease production, in part or entirely. Drilling programs may become uneconomic due to an increase in our operating costs or as a result of a decrease in market prices for oil and natural gas. Our actual operating costs or the actual prices we may receive for our oil and natural gas production may differ materially from current estimates. In addition, even if we are able to continue to produce oil and gas, there can be no assurance that we will have the ability to market our oil and gas production. See “—Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production” below.
Our identified potential drilling location inventories are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management team has specifically identified and scheduled certain potential drilling locations as an estimate of our future multi-year drilling activities on our existing acreage. These identified potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy.
Our ability to drill and develop these identified potential drilling locations depends on a number of factors, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, the availability of gathering systems, marketing and transportation constraints, refining capacity, regulatory approvals and other factors. Because of the uncertainty inherent in these factors, there can be no assurance that the numerous potential drilling locations we have identified will ever be drilled or, if they are, that we will be able to produce oil or natural gas from these or any other potential drilling locations.
Our business requires significant capital investment and maintenance expenses, which we may be unable to finance on satisfactory terms or at all.
Because the oil and natural gas industry is capital intensive, we expect to make substantial capital expenditures in our business and operations for the exploration and production of oil and natural gas reserves. See “Item 4. Information on the Company—B. Business Overview—2023 Strategy and Outlook.” We incurred capital expenditures of US$168.8 million and US$129.3 million during the years ended December 31, 2022 and 2021, respectively. See “Item 5. Operating and
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Financial Review and Prospects—A. Operating Results—Factors Affecting our Results of Operations—Discovery and exploitation of reserves.”
The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other equipment and services, and regulatory, technological and competitive developments. In response to changes in commodity prices, we may increase or decrease our actual capital expenditures. For example, as a result of the oil price decline in 2020 we adjusted the capital expenditures program for that year to US$65-75 million, approximately a 60% reduction from prior preliminary estimates (approximately US$180-200 million including capital expenditures for Amerisur assets).
We intend to finance our future capital expenditures through cash generated by our operations and potential future financing arrangements. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets.
If our capital requirements vary materially from our current plans, we may require further financing. In addition, we may incur significant financial indebtedness in the future, which may involve restrictions on other financing and operating activities. We may also be unable to obtain financing or financing on terms favorable to us. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. A significant reduction in cash flows from operations or the availability of credit could materially adversely affect our ability to achieve our planned growth and operating results.
Oil and gas operations contain a high degree of risk, and we may not be fully insured against all risks we face in our business.
Oil and gas exploration and production is speculative and involves a high degree of risk and hazards. Our operations may be disrupted by risks and hazards that are beyond our control and that are common among oil and gas companies, including environmental hazards, blowouts, industrial accidents, occupational safety and health hazards, technical failures, labor disputes, nationwide or regional social protests or blockades, unusual or unexpected geological formations, flooding, earthquakes and extended interruptions due to weather conditions, explosions and other accidents. For example, from April through July 2022, there were mobilizations and social protests in our operations in Putumayo (Colombia), with the purpose of interrupting oil activities to provoke a reaction from the government. This situation affected production in the Platanillo Block and caused delays in the drilling campaign planned for that block.
While we believe that we maintain customary insurance coverage for companies engaged in similar operations, we are not fully insured against all risks in our business because certain risks, such as public order related issues or natural disasters, are not subject to insurance coverage because they are not under our control. In addition, insurance that we do, and plan to, carry may contain significant exclusions from and limitations on coverage. We may elect not to obtain certain non-mandatory types of insurance if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of a significant event or a series of events against which we are not fully insured, and any losses or liabilities arising from uninsured or underinsured events could have a material adverse effect on our business, financial condition or results of operations.
The development schedule of oil and natural gas projects is subject to cost overruns and delays.
Oil and natural gas projects may experience capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies, personnel, and oil field services. The cost to execute projects may not be properly established and remains dependent upon a number of factors, including the completion of detailed cost estimates and final engineering, contracting and procurement costs. The development of projects may be materially adversely affected by one or more of the following factors:
| ● | shortages of equipment, materials and labor; |
| ● | fluctuations in the prices of construction materials; |
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| ● | delays in delivery of equipment and materials; |
| ● | labor disputes; |
| ● | political events; |
| ● | title problems; |
| ● | obtaining easements and rights of way; |
| ● | blockades or embargoes; |
| ● | litigation; |
| ● | compliance with governmental laws and regulations, including environmental, health and safety laws and regulations; |
| ● | adverse weather conditions; |
| ● | unanticipated increases in costs; |
| ● | natural disasters; |
| ● | epidemics or pandemics; |
| ● | accidents; |
| ● | transportation; |
| ● | unforeseen engineering and drilling complications; |
| ● | delays during prior consultation processes; |
| ● | delays attributable to the operator of the project; |
| ● | environmental or geological uncertainties; and |
| ● | other unforeseen circumstances. |
Any of these events or other unanticipated events could give rise to delays in development and completion of our projects and cost overruns.
For example, in 2022, the drilling and completion cost for the exploratory well Alea NW 1 in our Platanillo Block in Colombia was originally estimated at US$5.1 million, but the actual cost was US$5.9 million, mainly due to delays and overruns caused by a local community blockade.
Additionally, we may not be able to follow the development schedules we believe are optimal for blocks in which we are not the operator, such as the CPO-5 Block, which could adversely affect our financial condition and results of operations.
Delays in the construction and commissioning of projects or other technical difficulties may result in future projected target dates for production being delayed or further capital expenditures being required. These projects may often require
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the use of new and advanced technologies, which can be expensive to develop, purchase and implement and may not function as expected. Such uncertainties and operating risks associated with development projects could have a material adverse effect on our business, results of operations or financial condition.
Competition in the oil and natural gas industry is intense, which makes it difficult for us to attract capital, acquire properties and prospects, market oil and natural gas and secure trained personnel.
We compete with the major oil and gas companies engaged in the exploration and production sector, including state-owned exploration and production companies that possess greater financial and technical resources than we do for researching and developing exploration and production technologies and access to markets, equipment, labor and capital required to acquire, develop and operate our properties. We also compete for the acquisition of licenses and properties in the countries where we operate.
Our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources allow. Our competitors may also be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. As a result of each of the aforementioned, we may not be able to successfully compete in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel or raising additional capital, which could have a material adverse effect on our business, financial condition or results of operations. See “Item 4. Information on the Company—B. Business Overview—Our competition.”
Our estimated oil and gas reserves are based on assumptions that may prove inaccurate.
Our oil and gas reserves estimate in Colombia, Chile, Brazil and Ecuador as of December 31, 2022, are based on the D&M Reserves Report. Although classified as “proved reserves,” the reserves estimate set forth in the D&M Reserves Reports are based on certain assumptions that may prove inaccurate. DeGolyer and MacNaughton’s primary economic assumptions in estimates included oil and gas sales prices determined according to SEC guidelines, future expenditures and other economic assumptions (including interests, royalties and taxes) as provided by us.
Oil and gas reserves engineering is a subjective process of estimating accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers may differ materially from those set out herein. Numerous assumptions and uncertainties are inherent in estimating quantities of proved oil and gas reserves, including projecting future rates of production, timing and amounts of development expenditures and prices of oil and gas, many of which are beyond our control. Post estimate drilling, testing and production results may require revisions. For example, if we are unable to sell our oil and gas to customers, this may impact the estimate of our oil and gas reserves. Accordingly, reserves estimates are often materially different from the quantities of oil and gas that are ultimately recovered, and if such recovered quantities are substantially lower than the initial reserves estimate, this could have a material adverse impact on our business, financial condition and results of operations.
Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production.
Our ability to market our oil and natural gas production depends substantially on the availability and capacity of processing facilities, transportation facilities (such as pipelines, crude oil unloading stations and trucks) and other necessary infrastructure, which may be owned and operated by third parties. Our failure to obtain such facilities on acceptable terms or on a timely basis could materially harm our business. We may be required to shut down oil and gas wells because access to transportation or processing facilities may be limited or unavailable when needed. If that were to occur, we would be unable to realize revenue from those wells until arrangements were made to deliver the production to the market, which could cause a material adverse effect on our business, financial condition and results of operations. In addition, the shutting down of wells can lead to mechanical problems upon bringing the production back on-line, potentially resulting in decreased production and increased remediation costs. The exploitation and sale of oil and natural gas and liquids will also be subject to timely commercial processing and marketing of these products, which depends on the contracting, financing, building and operating of infrastructure by us and third parties.
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In Colombia, producers of crude oil have historically suffered from trucking transportation logistics issues and limited pipeline and storage capacity, which cause delays in delivery and transfer of title of crude oil. To reduce this exposure, we and our partner in the Llanos 34 Block have constructed a flowline to evacuate crude oil from the Jacana field, reducing transportation costs, blockade risks and supporting our sustainable performance by reducing carbon emissions. During 2020, the Jacana-ODL flowline was converted into the Oleoducto del Casanare Pipeline (“ODCA”) after receiving authorization from the Ministry of Energy and Mines to operate as such. We also inaugurated a truck unloading facility at Jacana Field and connected Tigana field to ODCA at the end of the year. During 2021, ODCA was a key element in the transport of crude production of our Llanos 34 Block. During May and June 2021, extensive protests and demonstrations across Colombia affected overall logistics and supply chains, restricting our crude oil transportation, drilling and the mobilization of personnel, equipment, and supplies. These events caused us to manage production curtailments that started in early May 2021, and normalized towards the end of June 2021. During 2022, the scheduled maintenance of the oil pipelines in Colombia frequently affected the logistics of evacuating the crude oil produced in the Llanos 34 and CPO-5 Blocks. As an alternative to these limitations in the use of the oil pipelines, trucks were used to transport the crude oil to alternative pumping stations closer to ports and refineries.
In the case of our Putumayo Basin production, we have also reduced our exposure to trucking issues by implementing the use of flowlines alongside trucking to gather our production at the Platanillo Block and transport it via the Oleoducto Binacional Amerisur (“OBA”) pipeline that connects us to the Ecuador pipeline system.
Trucking transportation was key to our crude delivery strategy during 2022 and will continue to be part of our strategy in the future. Although we were able to enable alternative delivery points and transport oil by trucks, avoiding any significant negative impact in our production during this period, we cannot assure we would be able to do so in the future.
In Chile, we transport the crude oil we produce in the Fell Block by truck to ENAP’s processing, storage and selling facilities at the Gregorio Refinery. As of the date of this annual report, ENAP purchases all the crude oil we produce in Chile. During 2022, ENAP had problems with its terminal's storage capacity. This made it necessary to limit, for 40 days, the production of the Fell Block to gas wells and to manage the associated liquids with internal storage capacity. We rely upon the continued good condition, maintenance, and accessibility of the roads we use to deliver the crude oil we produce. If the condition of these roads were to deteriorate or if they were to become inaccessible for any period of time, this could delay delivery of crude oil in Chile and materially harm our business.
In the Fell Block, we depend on ENAP-owned gas pipelines to deliver the gas we produce to Methanex, our main buyer. If ENAP’s pipelines were unavailable to deliver, this could have a materially adverse effect on our ability to deliver and sell our product to Methanex, which could have a material adverse effect on our gas sales.
While Brazil has a well-developed network of hydrocarbon pipelines, storage and loading facilities, we may not be able to access these facilities when needed. Pipeline facilities in Brazil are often full and seasonal capacity restrictions may occur, particularly in natural gas pipelines. Our gas production from the Manati Field is transported on Petrobras-operated pipelines. If those pipelines became unavailable, our overall production levels in the Manati Field would be negatively impaired.
In Ecuador, our oil production is transported through the existing pipeline infrastructure. While the Ecuadorian pipeline system is well-developed and has operated reliably in the past, we cannot guarantee this will be the case in the future. Also, as production in Ecuador increases, available capacity may be limited. An inability to access transport capacity could adversely affect our production levels or the transport costs associated with getting our production to the market.
We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities, including indigenous communities, where our reserves are located.
Access to the sites where we operate requires agreements (including easements, rights-of-way and access authorizations), primarily with the owners of the lands on which we intend to develop our operational projects. If we are unable to negotiate easements with landowners, we may have to go to court to obtain access to the sites of our operations, which may delay the progress of our operations at such sites. In Chile, for example, we have negotiated the necessary
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agreements for many of our current operations in the Magallanes Basin. In Brazil, if social unrest occurs, it may lead to delays or damage relating to our ability to operate the assets we have acquired or may acquire in the future.
In Colombia, although we have agreements with many landowners and are in negotiations with others, the economic expectations of landowners have generally increased, which may delay access to existing or future sites. Additionally, local communities and other stakeholders in the territory, such as workers' associations, trade unions and unions for activities related to the industry, are leading demands to the operators, beyond what is legally established, sometimes exerting pressures under de facto means or blockades to oil activities. Although oil and gas companies are managing these situations and stakeholder expectations in the territory, it ultimately becomes necessary to establish agreements for the viability of the operations, which on occasions translates into higher execution costs. Additionally, there are demands for improvements of transport infrastructure and the addressing of unsatisfied basic needs that have been historically ignored by the authorities and the fulfillment of such demands may be redirected towards the oil and gas companies.
In Putumayo (Colombia), where we have operating sites, there is presence of illegal groups which may pressure farmers to oppose the control and eradication of illicit crops, and instrumentalize the oil and gas industry with blockades, seeking to draw the attention of the national government and prevent the eradication of these crops.
As part of its international commitments, the Colombian government may seek to enhance the participatory phases of hydrocarbon projects, which could broaden the parameters of community participation and access to information and ultimately affect project timelines.
Furthermore, local communities’ expectations may increase because of several reforms the government has announced, including one to the country’s labor framework. If the government reforms do not meet the communities’ expectations, the pressure to reform may shift to the oil and gas industry.
The expectations and demands of local communities on oil and gas companies operating in Colombia may also increase. As a result, local communities have demanded that oil and gas companies invest in fixing and improving public access roads, compensate them for any damages related to use of such roads and, more generally, invest in infrastructure which is commonly paid for with public funds. Due to these circumstances, oil and gas companies in Colombia, including us, are now dealing with increasing difficulties resulting from instances of social unrest, temporary road blockades and conflicts with landowners.
In addition, community and indigenous protests and blockades may arise near our operations in Colombia, which could adversely affect our business, financial condition or results of operations. For example, on February 25, 2021, some communities in the Putumayo Basin protested against the government’s plans for the eradication of coca plantations in the area, blocking access to the Platanillo operations. Similar protests occurred between April and July 2022, sometimes affecting the continuity of operations in Platanillo.
Other legal proceedings such as land restitution, a judicial process implemented because of the peace agreement in Colombia, focus on returning illegally held land to its rightful owners, may delay access to future sites.
There can be no assurance that disputes with landowners and local communities or legal proceedings will not delay our operations or that any agreements we reach with such landowners and local communities or legal proceedings in the future will not require us to incur additional costs, thereby materially adversely affecting our business, financial condition and results of operations. Local communities may also protest or take actions that restrict or cause their elected government to restrict our access to the sites of our operations, which may have a material adverse effect on our operations at such sites.
In Ecuador, we have successfully, and on schedule, started exploration and production activities in 2022. However, a complex social and political environment regarding the development of extractive activities is also present there, as well as greater expectations and demands on oil and gas companies, which could lead to blockades and delays in the development of operational activities.
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Under the terms of some of our various CEOPs, E&P contracts, production sharing agreements and concession agreements, we are obligated to drill wells, declare any discoveries, and file periodic reports to retain our rights and establish development areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts of our blocks or concession areas.
To protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. In general, unless we make and declare discoveries within periods specified in our various special operation contracts (CEOPs, E&P contracts, production sharing agreements and concession agreements), our interests in the undeveloped parts of our license areas may lapse. Should the prospects we have identified under these contracts and agreements yield discoveries, we may face delays in drilling these prospects or be required to relinquish them. The costs to maintain or operate the CEOPs, E&P contracts, production sharing agreements and concession agreements over such areas may fluctuate and may increase significantly, and we may not be able to meet our commitments under such contracts and agreements on commercially reasonable terms or at all, which may force us to forfeit our interests in such areas. For example, in 2022, we transferred commitments from certain blocks to others and asked for termination of certain E&P contracts. See “Item 4. Information on the Company—B. Business Overview—Our operations—Operations in Colombia.”
A significant amount of our reserves or production have been derived from our operations in certain blocks, including the Llanos 34, CPO-5, Platanillo and Llanos 32 Blocks in Colombia, the Fell Block in Chile, the BCAM-40 Concession in Brazil and the Espejo and Perico Blocks in Ecuador.
For the year ended December 31, 2022, the Llanos 34 Block contained 77.1% of our net proved reserves and generated 66.7% of our production, the CPO-5 Block contained 8.2% of our net proved reserves and generated 14.5% of our total production, the Platanillo Block contained 3.7% of our net proved reserves and generated 5.4% of our production, the Llanos 32 Block contained 2.7% of our net proved reserves and generated 1.1% of our production, the Fell Block contained 5.6% of our net proved reserves and generated 6.1% of our total production, the BCAM-40 Concession contained 2.2% of our net proved reserves and generated 3.9% of our production, the Perico Block contained 0.4% of our net proved reserves and generated 2.2% of our production and the Espejo Block contained 0.1% of our net proved reserves and generated 0.1% of our production. While our continuing expansion with new exploratory blocks incorporated in our portfolio means that the above-mentioned blocks may be expected to be a less significant component of our overall business, we cannot be sure that we will be able to continue diversifying our reserves and production. Resulting from these, any government intervention, impairment, or disruption of our production due to factors outside of our control or any other material adverse event in our operations in such blocks would have a material adverse effect on our business, financial condition, and results of operations.
Our contracts in obtaining rights to explore and develop oil and natural gas reserves are subject to contractual expiration dates and operating conditions, and our CEOPs, E&P contracts, production sharing agreements and concession agreements are subject to early termination in certain circumstances.
Under certain CEOPs, E&P contracts, production sharing contracts and concession agreements to which we are or may in the future become parties, we are or may become subject to guarantees to perform our commitments and/or to make payment for other obligations, and we may not be able to obtain financing for all such obligations as they arise. If such obligations are not complied with when due, in addition to any other remedies that may be available to other parties, this could result in cancelation of our CEOPs, E&P contracts, production sharing contracts and concession agreements or dilution or forfeiture of interests held by us. As of December 31, 2022, the aggregate outstanding amount of this potential liability for guarantees was US$96.7 million, mainly related to capital commitments in the Llanos 34, Llanos 87, CPO-5, PUT-8, and Platanillo Blocks in Colombia, the Campanario Block in Chile, and the Perico and Espejo Blocks in Ecuador. See “Item 4. Information on the Company—B. Business Overview—Our operations” and Note 33.2 to our Consolidated Financial Statements.
Additionally, certain CEOPs, E&P contracts, production sharing contracts and concession agreements to which we are or may in the future become a party are subject to set expiration dates. Although we may want to extend some of these contracts beyond their original expiration dates, there is no assurance that we can do so on terms that are acceptable to us or at all, although some of these agreements contain provisions enabling exploration extensions.
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In Colombia, our E&P contracts are subject to early termination for a breach by the parties, a default declaration, application of any of the contracts’ unilateral termination clauses or pursuant to termination clauses mandated by Colombian law. Anticipated termination declared by the ANH results in the immediate enforcement of monetary guaranties against us and may result in an action for damages by the ANH and/or a restriction on our ability to engage in contracts with the Colombian government during a certain period of time. See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Colombia—E&P contracts.” To avoid the breach of an E&P contract due to unfulfillment of our exploration commitments, regulation gives us options such as the ability to transfer or credit those commitments to other E&P contracts, subject to meeting certain regulatory conditions.
In Chile, our CEOPs provide for early termination by Chile in certain circumstances, depending upon the phase of the CEOP. For example, pursuant to the Fell Block CEOP, Chile has the right to terminate the CEOP under certain circumstances if we fail to perform. If the Fell Block CEOP is terminated in the exploitation phase, we will have to transfer to the Chilean government, free of charge, any productive wells, and related facilities, provided that such transfer does not interfere with our abandonment obligations and excluding certain pipelines and other assets. See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Chile—CEOPs—Fell Block CEOP.” If the CEOP is terminated early due to a breach of our obligations, we may not be entitled to compensation. Our CEOPs for the Campanario and Isla Norte Blocks, which are in the exploration phase, may be subject to early termination during this phase under certain circumstances, including if we fail to perform under the terms of the CEOPs, voluntarily relinquish all areas under the CEOPs or if we cease to operate in the CEOP area or declare bankruptcy. If these CEOPs are terminated within the exploration phase, we are released from all obligations under the CEOPs, except for obligations regarding the abandonment of fields, if any. See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Chile—CEOPs.” There can be no assurance that the early termination of any of our CEOPs would not have a material adverse effect on us. In addition, according to the Chilean Constitution, Chile is entitled to expropriate our rights in our CEOPs for reasons of public interest. Although Chile would be required to indemnify us for such expropriation, there can be no assurance that any such indemnification will be paid in a timely manner or in an amount sufficient to cover the harm to our business caused by such expropriation.
In Brazil, concession agreements in the production phase generally may be renewed at the ANP’s discretion for an additional period, provided that a renewal request is made at least 12 months prior to the termination of the concession agreement and there has not been a breach of the terms of the concession agreement. We expect that all our concession agreements will provide for early termination in the event of: (i) government expropriation for reasons of public interest; (ii) revocation of the concession pursuant to the terms of the concession agreement; or (iii) failure by us or our partners to fulfill all our respective obligations under the concession agreement (subject to a cure period). Administrative or monetary sanctions may also be applicable, as determined by the ANP, which shall be imposed based on applicable law and regulations. In the event of early termination of a concession agreement, the compensation to which we are entitled may not be sufficient to compensate us for the full value of our assets. Moreover, in the event of early termination of any concession agreement due to failure to fulfill obligations thereunder, we may be subject to fines and/or other penalties.
In Argentina, hydrocarbon exploration permits and exploitation concessions are subject to termination for: (a) failure to pay any annual license fees within three months after they are due; (b) failure to pay royalties within three months after they are due; (c) material and unjustified failure to comply with the specified obligations in respect to productivity, conservation, investments, works or special benefits; (d) repeated infringement of the obligations to submit demandable information, to facilitate inspections by the competent authority or to employ the proper techniques for the execution of the works; (e) failure to request an exploitation concession after a commercial discovery or to submit a development program after obtaining an exploitation concession; (f) the bankruptcy of the holder declared by a court; (g) the death or liquidation of the holder; or, (h) failure to comply with the obligation to transport hydrocarbons for third parties under open access conditions or repeated infringement of the tariff regime approved for such transport. Before declaring the termination under any of the grounds provided under items (a), (b), (c), (d), (e), and (h), notice shall be served, requiring the holder to remedy any such infringement. Upon expiration, relinquishment or termination of any permit or concession, the holder of such permit or concession shall surrender to the government the acreage together with all the improvements, facilities, wells and other equipment that may have been used in the performance of the activities.
In Ecuador, our production sharing contracts may be subject to early termination in case of breach of the obligations under the contract, non-performance of the exploratory commitments or unjustified suspension of the operations, lack of
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remediation of environmental damages or unauthorized assignment of a working interest under the production sharing contracts, among others, as specified under the laws of the contract. The declaration of an early termination is subject to prior due process, which would allow us to remedy any hypothetical breach claimed against us, or to present our defense allegations. A declaration of early termination will cause forfeiture of equipment and facilities and enforcement of monetary guarantees.
Early termination or nonrenewal of any CEOP, E&P contract, production sharing agreements or concession agreement could have a material adverse effect on our business, financial situation, or results of operations.
We sell all our natural gas in Chile to a single customer, who has in the past temporarily idled its principal facility.
For the year ended December 31, 2022, all our natural gas sales in Chile were made to Methanex under a long-term contract, the Methanex Gas Supply Agreement, which expires on December 31, 2026. During 2022, we negotiated an amendment to the gas supply contract to increase prices in the high methanol price cycle. Sales to Methanex represented 1% of our consolidated revenues for the year ended December 31, 2022. Methanex also buys gas from ENAP and a consortium that Methanex has formed with ENAP. If Methanex were to decrease or cease its purchase of gas from us, this would have a material adverse effect on our revenues derived from the sale of gas.
Methanex has two methanol producing facilities (trains) at its Cabo Negro production facility, near the city of Punta Arenas in southern Chile. Methanex has relied on local suppliers of natural gas, including ENAP, for its operations. We alone cannot supply Methanex with all the natural gas it requires for its operations. Over the past years, Argentina has been approving gas exports to Chile (including to Methanex) and other countries. These are annual authorizations which depend on the supply and demand balances of Argentina.
In the past, the Methanex plant was idled due to an anticipated insufficient supply of natural gas. In July 2020, the Methanex plant shut down because of a technical failure which affected our natural gas production and sales for 10 days. See “Item 4. Information on the Company—B. Business Overview—Marketing and delivery commitments—Chile.”
However, we cannot be sure that Methanex will continue to purchase our gas, including the above committed levels, or that its efforts to reduce the risk of future shut-downs will be successful, which could have a material adverse effect on our gas revenues. Additionally, we cannot be sure that Methanex will have sufficient supplies of gas to operate its plant and continue to purchase our gas production or that methanol prices would be sufficient to cover the operating costs. We cannot be sure that we would be able to sell our gas production to other parties or on similar terms, which could have a material adverse effect on our business, financial condition, and results of operations.
We are not, and may not be in the future, the sole owner or operator of all our licensed areas and do not, and may not in the future, hold all the working interests in some of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly owned, assets.
As of December 31, 2022, we are not the operator of 24% or sole owner of 47% of the blocks included in our portfolio. See “Item 4. Information on the Company—B. Business Overview—Operations in Colombia”, “—Operations in Chile”, “—Operations in Brazil”, “—Operations in Argentina” and “—Operations in Ecuador.”
In addition, the terms of the joint operations agreements or association agreements governing our other partners’ interests in almost all of the blocks that are not wholly owned or operated by us require that certain actions be approved by supermajority vote. The terms of our other current or future license or venture agreements may require at least the majority of working interests to approve certain actions. As a result, we may have limited ability to exercise influence over operations or prospects in the blocks operated by our partners, or in blocks that are not wholly owned or operated by us. A breach of contractual obligations by our partners who are the operators of such blocks could eventually affect our rights in exploration and production contracts in some of our blocks in Colombia, Brazil, Argentina, and Ecuador. Our dependence on our partners could prevent us from achieving our target returns for those discoveries or prospects.
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Moreover, as we are not the sole owner or operator of all our properties, we may not be able to control the timing of exploration or development activities or the amount of capital expenditures and may therefore not be able to carry out our key business strategies of minimizing the cycle time between discovery and initial production at such properties. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:
| ● | the timing and amount of capital expenditures; |
| ● | the operator’s expertise and financial resources; |
| ● | approval of other block partners in drilling wells; |
| ● | the scheduling, pre-design, planning, design and approvals of activities and processes; |
| ● | selection of technology; and |
| ● | the rate of production of reserves, if any. |
This limited ability to exercise control over the operations on some of our license areas may cause a material adverse effect on our financial condition and results of operations.
For example, we are not the operator of the CPO-5 Block, and do not control the execution of the development schedule. Any delays in the execution schedule of the CPO-5 Block could have a material adverse effect in our financial condition and results of operation.
Acquisitions that we have completed, and any future acquisitions, strategic investments, partnerships, or alliances could be difficult to integrate and/or identify, could divert the attention of key management personnel, disrupt our business, dilute stockholder value and adversely affect our financial results, including impairment of goodwill and other intangible assets.
One of our principal business strategies includes acquisitions of properties, prospects, reserves and leaseholds and other strategic transactions, including in jurisdictions in which we do not currently operate. The successful acquisition and integration of producing properties requires an assessment of several factors, including:
| ● | recoverable reserves; |
| ● | future oil and natural gas prices; |
| ● | development and operating costs; and |
| ● | potential environmental and other liabilities. |
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review and the review of advisors and independent reserves engineers will not reveal all existing or potential problems, nor will it permit us or them to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental conditions are not necessarily observable even when an inspection is undertaken. We, advisors or independent reserves engineers may apply different assumptions when assessing the same field. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even in those circumstances in which we have contractual indemnification rights for pre-closing liabilities, it remains possible that the seller will not be able to fulfill its contractual obligations. There can be no assurance that problems related to the assets or management of the companies
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and operations we have acquired, or