141 |
i
ii
ii
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.
iii
“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.
iv
“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
v
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.
vi
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, |
| “Amerisur” are to Amerisur Resources Limited and its subsidiaries; |
| ● | “Agencia” are to GeoPark Latin America Limited Agencia en Chile, an established branch, under the laws of Chile, of GeoPark Latin America Limited (“GeoPark Latin America”), an exempted company incorporated under the laws of Bermuda; |
| “GeoPark Colombia” are |
| ● | “GeoPark Brazil” are to GeoPark |
| ● | “GeoPark TdF S.A.”, a |
| “Petroperu” are to Petróleos del Perú S.A.; |
| ● | “LGI” are to LG International Corp., a company incorporated under the laws of Korea; |
| “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$3.4 million at the moment of the refinancing execution) was refinanced with the bank in September 2020, and agreed to be paid in three equal installments in October 2021, April 2022, and October 2022; |
| ● | “US$” and “U.S. dollar” are to the official currency of the United States of America; |
| “Ch$” and “Chilean pesos” are to the official currency of Chile; |
vii
| “AR$” and “Argentine pesos” are to the official currency of Argentina; |
| “real,” “reais” and “R$” are to the official currency of Brazil; |
| “ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels Agency (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis); |
| “ANH” are to the Colombian National Hydrocarbons Agency (Agencia Nacional de Hidrocarburos); |
| “ENAP” are to the Chilean National Petroleum Company (Empresa Nacional de Petróleo); |
| “RODA” are to the Oil Pipeline Network of the Amazonian District (Red de Oleoductos del Distrito Amazónico); |
| ● | “SOTE” are to the Ecuadorian Oil Pipeline System (Sistema de Oleoducto Transecuatoriano); |
| ● | “IOGP” are to the International Association of Oil and Gas Producers; |
| ● | “IPIECA” are to the International Petroleum Industry Environmental Conservation Association; |
| ● | “IADC” are to the International Association of Drilling Contractors; |
| ● | “ARPEL” are to the Regional Association of Oil and Gas Companies, a non-profit association gathering oil, gas and biofuels sector companies and institutions in Latin America and the Caribbean; |
| ● | “UTA” are toUnidad Tributaria Anual; and |
| “economic interest” |
Financial statements
Our historical financial data presented does not include any results or other financial information of any acquisitions, including the acquisition of Amerisur, prior to their incorporation into our financial statements.
Our consolidated financial statements
This annual report includes our audited consolidated financial statements as of December 31, 20182021 and 20172020 and for each of the years ended years ended December 31, 2018, 20172021, 2020 and 20162019 (hereinafter “Consolidated Financial Statements”).
iii
Our Consolidated Financial Statements are presented in US$ 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, 2021 have been audited by Price WaterhousePistrelli, Henry Martin y Asociados S.R.L., (member of Ernst & Co. S.R.L.Young Global), Argentina (“PwC”), a member firm of PricewaterhouseCoopers Network, an independent registered public accounting firm, as stated in their reportreports 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 2018,2021,” relate to our fiscal year ended on December 31 of that calendar year.
viii
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 before net finance cost (determined in accordance with the indentures governing our Notes due 2024 and 2027, which do not give effect to the adoption of IFRS 16 Leases), income tax, depreciation, amortization, and certain non-cash items such as impairment charges or impairment reversals,impairments and write-offs of unsuccessful exploration and evaluation assets,efforts, accrual of stock options and stock awards,share-based payment, unrealized gainsresult in commodity risk management contracts, geological and bargain purchase gain on acquisition of subsidiaries.geophysical expenses allocated to capitalized projects and other events defined therein. 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 gainsresults 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 2018, 20172021, 2020 and 2016.
2019.
Oil and gas reserves and production information
DeGolyer and MacNaughton 20182021 Year-end Reserves Report
The information included elsewhere in this annual report regarding estimated quantities of proved reserves in Colombia, Chile, Brazil Argentina and PeruArgentina is derived in part, from estimates of the proved reserves as of December 31, 2018.2021. 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 and is included as an exhibit to this annual report. The D&M Reserves Report presents oil and gas reserves estimates located in the Fell, Campanario, Flamenco and Isla Norte Blocks in Chile, Llanos 32, Llanos 34, YamúPlatanillo and La CuervaCPO-5 Blocks in Colombia, the Fell Block in Chile, the BCAM-40 (Manati) Block in Brazil and the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina and the Morona Block in Peru.
iv
Argentina.
Market share and other information
Market data, other statistical information, information regarding recent developments in Colombia, Chile, Colombia, Brazil, PeruArgentina and ArgentinaEcuador 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.
ix
In addition, we have provided definitions for certain industry terms used in this annual report in the “Glossary of oil and natural gas terms” included as Appendix A to this annual report.
.
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.
v
x
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, |
| 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; |
| 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, Argentina, |
| 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; |
| armed conflicts, including the current armed conflict in Ukraine; |
xi
| ● | 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; |
vi
| 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.
vii
xii
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
We have derived our selected historical balance sheet data as of December 31, 2018 and 2017 and our consolidated statement of income and cash flow data for the years ended December 31, 2018, 2017 and 2016 from our consolidated financial statements included elsewhere in this annual report, which have been audited by PwC. We have derived our selected balance sheet data as of December 31, 2016, 2015, and 2014 and our consolidated statement of income and cash flow data for the years ended December 31, 2015 and 2014 from our consolidated financial statements not included in this annual report.
During 2015, Management changed the presentation of the Consolidated Statement of Income by reordering the profit and loss line items, eliminating gross profit and presenting depreciation and write-off of unsuccessful efforts as separate line items. This change is intended to provide readers of our financial statements with more relevant information and a better explanation of the elements of performance. This change has been applied to comparative figures for 2014 presented in this document.
We maintain our books and records in US$ and prepare our Consolidated Financial Statements in accordance with IFRS.
This financial information should be read in conjunction with “Presentation of Financial and Other Information,” “Item 5. Operating and Financial Review and Prospects” and our Consolidated Financial Statements and the related notes thereto.
The selected historical financial data set forth in this section does not include any results or other financial information of any acquisitions prior to their incorporation into our financial statements.
Consolidated Statement of Income data
| For the year ended December 31, | ||||||||||||||||||||
| 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||||
| (in thousands of US$, except per share numbers) | ||||||||||||||||||||
| Revenue | ||||||||||||||||||||
| Net oil sales | 545,490 | 279,162 | 145,193 | 162,629 | 367,102 | |||||||||||||||
| Net gas sales | 55,671 | 50,960 | 47,477 | 47,061 | 61,632 | |||||||||||||||
| Net revenue | 601,161 | 330,122 | 192,670 | 209,690 | 428,734 | |||||||||||||||
| Commodity risk management contracts | 16,173 | (15,448 | ) | (2,554 | ) | - | - | |||||||||||||
| Production and operating costs | (174,260 | ) | (98,987 | ) | (67,235 | ) | (86,742 | ) | (131,419 | ) | ||||||||||
| Geological and geophysical expenses | (13,951 | ) | (7,694 | ) | (10,282 | ) | (13,831 | ) | (13,002 | ) | ||||||||||
| Administrative expenses | (52,074 | ) | (42,054 | ) | (34,170 | ) | (37,471 | ) | (45,867 | ) | ||||||||||
| Selling expenses | (4,023 | ) | (1,136 | ) | (4,222 | ) | (5,211 | ) | (24,428 | ) | ||||||||||
| Depreciation | (92,240 | ) | (74,885 | ) | (75,774 | ) | (105,557 | ) | (100,528 | ) | ||||||||||
| Write-off of unsuccessful exploration efforts | (26,389 | ) | (5,834 | ) | (31,366 | ) | (30,084 | ) | (30,367 | ) | ||||||||||
| Impairment loss reversed/(recognized) for non-financial assets | 4,982 | - | 5,664 | (149,574 | ) | (9,430 | ) | |||||||||||||
| Other operating expense | (2,887 | ) | (5,088 | ) | (1,344 | ) | (13,711 | ) | (1,849 | ) | ||||||||||
| Operating profit (loss) | 256,492 | 78,996 | (28,613 | ) | (232,491 | ) | 71,844 | |||||||||||||
| Financial costs | (36,262 | ) | (51,495 | ) | (34,101 | ) | (35,655 | ) | (27,622 | ) | ||||||||||
| Foreign exchange (loss) gain | (11,323 | ) | (2,193 | ) | 13,872 | (33,474 | ) | (23,097 | ) | |||||||||||
| Profit (Loss) before tax | 208,907 | 25,308 | (48,842 | ) | (301,620 | ) | 21,125 | |||||||||||||
| Income tax (expense) benefit | (106,240 | ) | (43,145 | ) | (11,804 | ) | 17,054 | (5,195 | ) | |||||||||||
| Profit (Loss) for the year | 102,667 | (17,837 | ) | (60,646 | ) | (284,566 | ) | 15,930 | ||||||||||||
| Non-controlling interest | 30,252 | 6,391 | (11,554 | ) | (50,535 | ) | 7,845 | |||||||||||||
| Profit (Loss) attributable to owners of the Company | 72,415 | (24,228 | ) | (49,092 | ) | (234,031 | ) | 8,085 | ||||||||||||
| Earnings (Losses) per share for profit attributable to owners of the Company—Basic | 1.19 | (0.40 | ) | (0.82 | ) | (4.05 | ) | 0.14 | ||||||||||||
| Earnings (Losses) per share for profit attributable to owners of the Company—Diluted | 1.11 | (0.40 | ) | (0.82 | ) | (4.05 | ) | 0.14 | ||||||||||||
| Weighted average common shares outstanding—Basic | 60,612,230 | 60,093,191 | 59,777,145 | 57,759,001 | 56,396,812 | |||||||||||||||
| Weighted average common shares outstanding—Diluted | 65,370,782 | 60,093,191 | 59,777,145 | 57,759,001 | 58,840,412 | |||||||||||||||
| Common Shares outstanding at year-end | 60,483,447 | 60,596,219 | 59,940,881 | 59,535,614 | 57,790,533 | |||||||||||||||
Balance sheet data
| As of December 31, | ||||||||||||||||||||
| 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||||
| (In thousands of US$) | ||||||||||||||||||||
| Assets | ||||||||||||||||||||
| Non-current assets | ||||||||||||||||||||
| Property, plant and equipment | 557,170 | 517,403 | 473,646 | 522,611 | 790,767 | |||||||||||||||
| Prepaid taxes | 3,275 | 3,823 | 2,852 | 1,172 | 1,253 | |||||||||||||||
| Other financial assets | 10,570 | 22,110 | 19,547 | 13,306 | 12,979 | |||||||||||||||
| Deferred income tax | 31,793 | 27,636 | 23,053 | 34,646 | 33,195 | |||||||||||||||
| Prepayments and other receivables | 219 | 235 | 241 | 220 | 349 | |||||||||||||||
| Total non-current assets | 603,027 | 571,207 | 519,339 | 571,955 | 838,543 | |||||||||||||||
| Current assets | ||||||||||||||||||||
| Other financial assets | 898 | 21,378 | 2,480 | 1,118 | — | |||||||||||||||
| Inventories | 9,309 | 5,738 | 3,515 | 4,264 | 8,532 | |||||||||||||||
| Trade receivables | 16,215 | 19,519 | 18,426 | 13,480 | 36,917 | |||||||||||||||
| Prepayments and other receivables | 9,489 | 7,518 | 7,402 | 11,057 | 13,993 | |||||||||||||||
| Prepaid taxes | 45,170 | 26,048 | 15,815 | 19,195 | 13,459 | |||||||||||||||
| Derivative financial instrument assets | 27,539 | — | — | — | — | |||||||||||||||
| Cash and cash equivalents | 127,727 | 134,755 | 73,563 | 82,730 | 127,672 | |||||||||||||||
| Assets held for sale | 23,286 | — | — | — | — | |||||||||||||||
| Total current assets | 259,633 | 214,956 | 121,201 | 131,844 | 200,573 | |||||||||||||||
| Total assets | 862,660 | 786,163 | 640,540 | 703,799 | 1,039,116 | |||||||||||||||
| Share capital | 60 | 61 | 60 | 59 | 58 | |||||||||||||||
| Share premium | 237,840 | 239,191 | 236,046 | 232,005 | 210,886 | |||||||||||||||
| Other | (94,879 | ) | (154,327 | ) | (130,341 | ) | (85,412 | ) | 164,613 | |||||||||||
| Equity attributable to owners of the Company | 143,021 | 84,925 | 105,765 | 146,652 | 375,557 | |||||||||||||||
| Equity attributable to non-controlling interest | – | 41,915 | 35,828 | 53,515 | 103,569 | |||||||||||||||
| Total equity | 143,021 | 126,840 | 141,593 | 200,167 | 479,126 | |||||||||||||||
| Liabilities | ||||||||||||||||||||
| Non-current liabilities | ||||||||||||||||||||
| Borrowings | 429,027 | 418,540 | 319,389 | 343,248 | 342,440 | |||||||||||||||
| Provisions for other long-term liabilities | 42,577 | 46,284 | 42,509 | 42,450 | 46,910 | |||||||||||||||
| Trade and other payables | 14,789 | 25,921 | 34,766 | 19,556 | 16,583 | |||||||||||||||
| Deferred income tax | 14,801 | 2,286 | 2,770 | 16,955 | 30,065 | |||||||||||||||
| Total non-current liabilities | 501,194 | 493,031 | 399,434 | 422,209 | 435,998 | |||||||||||||||
| Current liabilities | ||||||||||||||||||||
| Borrowings | 17,975 | 7,664 | 39,283 | 35,425 | 27,153 | |||||||||||||||
| Derivative financial instrument liabilities | - | 19,289 | 3,067 | – | – | |||||||||||||||
| Current income tax | 58,776 | 42,942 | 5,155 | 208 | 7,935 | |||||||||||||||
| Trade and other payables | 131,420 | 96,397 | 52,008 | 45,790 | 88,904 | |||||||||||||||
| Liabilities associated with assets held for sale | 10,274 | – | – | – | – | |||||||||||||||
| Total current liabilities | 218,445 | 166,292 | 99,513 | 81,423 | 123,992 | |||||||||||||||
| Total liabilities | 719,639 | 659,323 | 498,947 | 503,632 | 559,990 | |||||||||||||||
| Total equity and liabilities | 862,660 | 786,163 | 640,540 | 703,799 | 1,039,116 | |||||||||||||||
Cash flow data
| For the year ended December 31, | ||||||||||||||||||||
| 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||||
| (In thousands of US$) | ||||||||||||||||||||
| Cash provided by (used in) | ||||||||||||||||||||
| Operating activities | 256,206 | 142,158 | 82,884 | 25,895 | 230,746 | |||||||||||||||
| Investing activities | (164,594 | ) | (105,604 | ) | (39,306 | ) | (48,842 | ) | (344,041 | ) | ||||||||||
| Financing activities | (97,641 | ) | 23,968 | (51,136 | ) | (18,022 | ) | 124,716 | ||||||||||||
| Net (decrease) increase in cash and cash equivalents | (6,029 | ) | 60,522 | (7,558 | ) | (40,969 | ) | 11,421 | ||||||||||||
Other financial data
| For the year ended December 31, | ||||||||||||||||||||
| 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||||
| Adjusted EBITDA(1) (US$ thousands) | 330,556 | 175,776 | 78,321 | 73,787 | 220,077 | |||||||||||||||
| Adjusted EBITDA margin(2) | 55.0 | % | 53.2 | % | 40.6 | % | 35.2 | % | 51.3 | % | ||||||||||
| Adjusted EBITDA per boe(3) | 26.5 | 18.4 | 10.2 | 10.5 | 33.0 | |||||||||||||||
Exchange rates
In Colombia, Chile, Argentina and Peru, our functional currency is the U.S. dollar. In Brazil, our functional currency is thereal.
Our operations in Brazil accounted for 12% and 8% of our consolidated assets and 10% and 5% of our revenues for the years ended December 31, 2017 and 2018, respectively. This portion of our business is exposed to losses that may arise from currency fluctuation, as a significant amount of our revenues, operating costs, administrative expenses and taxes in Brazil are denominated inreais.
The real may depreciate or appreciate substantially against the U.S. dollar. We recorded exchange rate losses amounting to US$5.9 million for the year ended December 31, 2018, principally due to the devaluation of the real and its impact on US dollar denominated intercompany debt cancelled by our Brazilian subsidiary in October 2018. We recorded exchange rate losses amounting to US$1.3 million for the year ended December 31, 2017 as a result of the devaluation of the local currency in our Brazilian subsidiary which was mainly generated by the credit facility with Itaú BBA International plc that we incurred on March 31, 2014 to acquire Rio das Contas, which we repaid in September 2017. See “—D. Risk factors—Risks relating to our business—Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange rates.”
Exchange rate fluctuation may affect the US$ value of any distributions we make with respect to our common shares. See “—D. Risk factors—Risks relating to our business—Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange rates.”
| 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 unprecedented nature of the current situation makes it impossible for the Company to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on its 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. |
| ● | We derive a significant portion of our revenues from sales to a few key customers. |
| ● | 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. |
| ● | We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities, including native 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 in order 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. |
2
| ● | We sell all of 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 of our licensed areas and do not, and may not in the future, hold all of the working interests in certain 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 may not have the capital to develop our unconventional oil and gas resources. |
| ● | Our operations are subject to operating hazards, including extreme weather events, which could expose us to potentially significant losses. |
| ● | 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. |
| ● | We operate in an industry with significant environmental, social, governance (ESG) and climate related risks. |
| ● | 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. |
| ● | 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, Argentina, 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. |
| ● | 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. |
| ● | Certain shareholders have substantial influence over us and could limit your ability to influence the outcome of key transactions, including a change of control. |
| ● | We are a Bermuda company, and it may be difficult for you to enforce judgments against us or against our directors and executive officers. |
3
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 unprecedented nature of the current situation 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 have adversely impacted the global economy and created significant volatility in the global financial markets. COVID-19 significantly impacted the world economy in 2020 and 2021 and may continue to do so in the years to come. Many countries have imposed travel bans on millions of people and additionally people in many locations have been subject to quarantine measures. Businesses have been dealing with lost revenue and disrupted supply chains. Countries have imposed lockdowns in response to the pandemic and, as a result of the disruption to businesses, millions of workers have lost their jobs. The COVID-19 pandemic has also resulted in significant volatility in the financial and commodities markets worldwide, including the dramatic drop in the price of crude oil during 2020. Numerous governments have implemented measures to provide both financial and non-financial assistance to the affected entities. We have applied and used any extension granted, specifically in Colombia, Brazil, Argentina, Peru and Spain. In Colombia, we entered into an agreement with the tax authority to pay the 2019 income tax in twelve installments from August 2020 to July 2021.Despite the uncertainty of the lasting effect of the COVID-19 outbreak, the crude oil demand recovery resulted in improvements in market conditions from the end of 2020 and onwards.
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. Additionally, because we have implemented remote working procedures for a significant portion of our workforce for health and safety reasons and/or to comply with applicable national, state, and/or local government requirements, we rely on such persons having sufficient access to our information technology systems, including through telecommunication hardware, software and networks. If a significant portion of our workforce cannot effectively perform their responsibilities, whether resulting from a lack of physical or virtual access, quarantines, illnesses, governmental actions or restrictions, information technology or telecommunication failures, or other restrictions or adverse impacts resulting from the pandemic, our business, financial condition, cash flows, and results of operations may be materially adversely affected.
The unprecedented nature of the current situation resulting from the COVID-19 pandemic 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, financial condition, cash flows, or results of operations. Such results will depend on future events, which we cannot predict, including the scope, duration and potential reoccurrence of the COVID-19 pandemic or any other localized epidemic or global pandemic, the distribution and effectiveness of vaccines and treatments, the demand for and the prices of oil and natural gas and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors and suppliers, in response to the COVID-19 pandemic or any other epidemics or pandemics. The COVID-19 pandemic and its unprecedented consequences have 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 have influenced prices for almost all of 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; |
4
| 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; |
| 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 |
| 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, recently, oil and natural gas prices have fluctuated significantly. From January 1, 20142019, to December 31, 2018,February 28, 2022, Brent spot prices ranged from a low of US$27.919.3 per barrel to a high of US$118.9101.0 per barrel, Henry Hub natural gas average spot prices ranged from a low of US$1.71.6 per mmbtu to a high of US$6.05.5 per mmbtu, US Gulf methanol spot barge prices ranged from a low of US$250.0260.4 per metric ton to a high of US$635.1657.6 per metric ton. 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 US$16 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
5
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 reduction of demand, 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. Following this agreement, global crude production dropped significantly with high compliance from OPEC+ countries and economic-driven shut-ins in other regions, especially the United States and Canada, helping re-attain some balance in the market during the second half of 2020.
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, and especially within the US Shale producers, were the key factors for moderate supply growth. In addition, natural gas prices spike 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 ongoing armed conflict, and the continuation of, or any increase in, the armed conflict between Russia and Ukraine, has led and may continue to lead to volatility in the price of global oil and gas. In addition, 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 certain other countries, as of March 2022, including additional countries that may enforce prohibitions of a similar nature in the future, has led to and is expected to continue to lead to volatility in the price of global oil and gas.
The crude price trajectory is highly uncertain for the months to come, as the long-term economic impact of COVID-19 and the armed conflict in Ukraine may impact energy demand around the globe.
For the year ended December 31, 2018, 91%2021, 94% 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.
As of December 31, 2018,2021, natural gas comprised 9%6% 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.
For example, during 2014 and 2015, we evaluated the recoverability of our fixed assets affected by the oil price decline and recorded2021, an impairment of non-financial assets amountingloss was recognized for US$4.3 million (compared to respectively,an impairment loss recognized for US$9.4133.9 million and US$149.6 million. US$5.7 million of the impairment recorded in 2015 was reversed in 2016 due to increased estimated market prices for 2017 and 2018 and improvements in cost structure.2020). After conducting an impairment test procedure for the year ended December 31, 20182021 we recognized an impairment loss of US$ 11.517.6 million in the Fell Block due to the decline in the proved reserves
6
estimates in 2021 and the commercial viability decreasing significantly as a consequence of the lower crude prices relative to its high cash costs of production in 2020, and we recognized a reversal of impairment losses due to increasesloss of US$ 13.3 million in estimated market pricesthe Aguada Baguales and improvements in cost structure, and also the known fair value less costs of disposal of the La Cuerva and YamuEl Porvenir Blocks in Colombia, partially offset by an impairment loss in Chile of US$ 6.5 million2021 due to the terminationknown market price of the sales agreement forblocks in the TdF’s blocks, with no renovation in place ascontext of the date of this annual report.transaction described in Note 36.3.1 to our Consolidated Financial Statements. See Note 3637 to our Consolidated Financial Statements for details regarding the key assumptions considered in our impairment test and Note 1.1 for details regarding the impact of COVID-19 and the oil price scenarios, discount rates considered and sensitivity analysis affecting the impairment charges.
crisis in our business.
Continuing our hedging strategy, we entered into derivative financial instruments to manage exposure to oil price risk. These derivatives were zero-premium collars or zero premium three way hedges (put, spread and call) and were placed with major financial institutions and commodity traders. We entered into the derivatives under ISDA Master Agreements and Credit Support Annexes, which provideAnnexes.
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 forlines. Even though cash collateral posting thus alleviating possibleis returned to us upon reductions in the underlying Brent oil price, having to post cash collaterals could affect our near-term liquidity needs underneeds. As of the instruments and protecting us from potential non-performancedate of this annual report, we have no cash collateral posted related to our commodity risk by our counterparties.management contracts. See Note 8 to our Consolidated Financial Statements for details regarding Commodity Risk Management Contracts.
TheLow oil price crisis has impactedprices 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 secondfirst half of 20142020 (WTI and Brent, the main international oil price markers, fell by more than 60%45% between August 2014December 2019 and March 2016)2020), the Companywe immediately took decisive measures to ensure its ability to both maximize ongoing projects and to preserve its cash.
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—2022 Strategy and Outlook” and Note 1.1 to our Consolidated Financial Statements.
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 our 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
7
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 where we are not the operator, 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, 2018,2021, our reserves-to-production (or reserve life) ratio for net proved reserves in Colombia, Chile, Argentina and Brazil and Peru was 8.26.4 years. According to estimates, if on January 1, 20192022, we ceased all drilling and development activities, including recompletions, refracs and workovers, our proved developed producing reserves base in Colombia, Chile, Brazil, Argentina and PeruArgentina would decline 34%24% during the first year.
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, for the year ended December 31, 2018, we made 99% ofallocate our oil sales from operated blocks to C.I. Trafigura Petroleum Colombia S.A.S., a leading commodity trading and logistics company (“Trafigura”), representing 82% of our consolidated revenues for the same period. Considering the expiration of our long-term contract with Trafigura in December 2018, we have started diversifying our client base in Colombia, allocating sales on a competitive basis to industry leading industry participants including traders and other producers. The contracts extend through 2019 with no long-term delivery commitments in place.During 2021, the oil and gas production was sold to three clients which concentrate 99% of the Colombian subsidiaries’ revenue (accounting for 89% of our consolidated revenue). Delivery points include wellhead and other locations inon 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 2023. We manage theour counterparty credit risk associated to sales contracts by including, in certain contracts, early payment conditions whichto minimize our exposure.the exposure.
In Chile, 100% of our crudethe oil production is sold to ENAP, the State-owned oil and condensate sales are made to ENAP. For the year ended December 31, 2018, sales to ENAP represented 3% of our total revenues. ENAP imports the majority of the oil it refines and partially supplements those imports with volumes supplied locally by its own operated fields and those operated by us. On April 21, 2017, we renewed our sales agreement with ENAP. As part of this agreement, ENAP has committed to purchase our oil production in the Fell Block in the amounts that we produce, subject to the limitation of available storage capacity at the Gregorio Terminal. The sales agreement provides us with the option to interrupt sales to ENAP periodically if conditions in the export markets allowgas company (accounting for more competitive price levels. While the agreement renews automatically on an annual basis, we typically make an annual revision jointly with ENAP. In addition, for the year ended December 31, 2018, almost all of our natural gas sales in Chile were made to Methanex Chile SpA., the Chilean subsidiary of the Methanex Corporation (“Methanex”), a leading global methanol producer, under a long-term contract (the “Methanex Gas Supply Agreement”), which will expire on December 31, 2026. Sales to Methanex represented 3%1% of our consolidated revenues forrevenue), and the year ended December 31, 2018.
gas production is sold to the local subsidiary of Methanex, a Canadian public company (representing 2% of our consolidated revenue).
In Brazil, all of our gas and condensate produced inthe hydrocarbons from the Manati Field isare sold to Petróleo Brasileiro S.A. (“Petrobras”),Petrobras, the Brazilian State-owned company, which is the operator of the Manati Field pursuant to a long-term gas off-take contract and a condensate purchase agreement.(accounting for 3% of our consolidated revenue). See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Brazil—Petrobras Natural Gas Purchase Agreement.”
In Argentina, all the gas produced in 2018 was sold to Grupo Albanesi, a leading Argentine privately held conglomerate focused on the energy market that offers natural gas and power supply and transport services to its customers. We have an annual agreement effective from May 2018 through April 2019. Gas sales in Argentina represented 1% of our total revenue. The oil sales in Argentina are diversified across clients and delivery points: i) 30% of the oil produced in Argentina (2% of our total revenue) is sold locally in Neuquén Province, delivered at well-head; and ii) 70% of the oil produced in Argentina (3% of our total revenues) is sold to major Argentine refineries, and delivered via pipeline.
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.
8
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 a majority of our net revenues is denominated in US$, unfavorable fluctuations in foreign currency exchange rates for certain of our expenses in Colombia, Chile, Brazil Argentina and PeruArgentina could have a material adverse effect on our results of operations. A portion of the cost reductions that we achieved in 2015 and 2016 (as compared to 2014) were related to the depreciation of local currencies, including mainly the Col$, the Ch$ and the Brazilianreal. 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. InSince December 2018, we decided to manage exposure to local currency fluctuation with respect to income tax balances in Colombia. Consequently, we entered into a derivative financial instrumentinstruments with a local bankbanks in Colombia, for an amount equivalent to US$ 92.183.7 million as of December 31, 2019, in order to anticipate any currency fluctuation with respect to estimated income taxes to be paid during the first half of 2019.
the following year. As of December 31, 2021 and 2020, we have no currency risk management contracts in place.
Through our Brazilian operations, we are exposed to fluctuations in thereal against the US$, as our Brazilian revenues and expenses are mostly denominated inreais. In the past, the Brazilian Central Bank has occasionally intervened to control unstable movements in foreign exchange rates. We cannot predict whether the Brazilian Central Bank or the Brazilian government will continue to permit thereal to float freely or will intervene in the exchange rate market through the return of a currency band system or otherwise. Furthermore, Brazilian law provides that, whenever there is a serious imbalance in Brazil’s balance of payments or there are reasons to foresee a serious imbalance, temporary restrictions may be imposed on remittances of foreign capital abroad. We cannot assure you that such measures will not be taken by the Brazilian government in the future. Thereal has experienced frequent and substantial variations in relation to the US$ and other foreign currencies, which could materially and adversely affect the growth of the Brazilian economy and our business, financial condition and results of operations.
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 as a result of 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
9
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 estimationestimate 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.Company—B. Business Overview—20192022 Strategy and Outlook.” We incurred capital expenditures of US$125129.3 million and US$10675.3 million during the years ended December 31, 20182021 and 2017,2020, respectively. See “Item 5. Operating and 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. In particular, 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, community protests or blockades, unusual or unexpected geological formations, flooding, earthquakes and extended interruptions due to weather conditions, explosions and other accidents. For example, on February 25, 2021, some communities in the Putumayo basin began protesting against the Government of Colombia for
10
the eradication of coca plantations in the area, blocking access to the Platanillo operations. The protest was not directed at us or at the oil industry, however, to protect our employees, we evacuated all personnel and shut in the production of 2,400 barrels per day between March 4, 2021, and March 11, 2021.
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. 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. 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; |
| 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; |
| transportation; |
11
| ● | 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 2017,2021, the drilling and completion cost for the exploratory well Río Grande Oeste x-1Alea oeste 1 in our CN-VPlatanillo Block in ArgentinaColombia was originally estimated at US$4.25.4 million, but the actual cost was US$5.56.2 million, mainly due to mechanical issues relateda sidetrack required after a disruption in our operations.
Additionally, we may not be able to failuresfollow 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.
Furthermore, with an electric submersible pump, as well as testing of additional formations which had not been budgeted.
the recent oil price decline we have begun to prioritize lower-risk, higher netback and quick cash flow generating projects, while implementing operating, administrative and capital cost-reduction measures.
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 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 substantially greater financial and other 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 in which 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 permit. 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 compete successfully in the future 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 estimatesestimate in Colombia, Chile, Argentina, Brazil and PeruArgentina as of December 31, 20182021 are based on the D&M Reserves Report. Although classified as “proved reserves,” the reserves estimatesestimate set forth in the D&M Reserves Reports are based on certain assumptions that may prove inaccurate. DeGolyer and MacNaughton’s primary economic
12
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. Results of drilling, testing and production after the date of the estimate may require revisions to be made. 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 estimates, 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, oil tankers, 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, then 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,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.
In Colombia, producers of crude oil have historically suffered from tankertrucking transportation logistics issues and limited pipeline and storage capacity, which cause delays in delivery and transfer of title of crude oil. Such capacity issuesIn order to reduce this exposure, we and our partner in Colombia may require usthe Llanos 34 Block have constructed a flowline to evacuate crude oil from the Jacana field, reducing transportation costs, blockage 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 fromproduction of our Colombian operations via truck, which may increaseLlanos 34 field. If the costs of those operations. Road infrastructure is limited in certain areas in which we operate, and certain communities have used and may continue to use road blockages, which can sometimes interfere with our operations in these areas. For example, in 2018, theOleoducto de Los Llanos “ODL” (the main delivery point for our Colombian production) were to have any maintenance or operational issues, we would resort to alternative delivery points via truck transportation. 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 Colombianmobilization 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.
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 Oloeducto Binacional Amerisur (“OBA”) pipeline that connects us to the Ecuador pipeline system.
Trucking transportation was Oleoducto de Los Llanos “ODL.” Duringkey to our crude delivery strategy during 2021 and will continue to be part of our strategy in the last week of July 2018, the operation of the Ocensa Pipeline, which receives oil flow from the ODL Pipeline, was disrupted because of a contingency.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 of the crude oil we produce in Chile. We rely upon the continued good condition, maintenance and accessibility of the roads we use to deliver the crude
13
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, the principal purchaser of the gas we produce. If ENAP’s pipelines were unavailable, 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. In addition, gas production in some areas in the Tierra del Fuego Blocks and the Tranquilo Block could require us in the future to build a new network of gas pipelines in order for us to be able to deliver our product to market, which could require us to make significant capital investments.
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 failure to secure transportation or access togas production from the Manati Field is transported on Petrobras-operated pipelines. If those pipelines or other facilities once we commence operationsbecame unavailable, our overall production levels in the concessions we were awarded in Brazil on acceptable terms or on a timely basis could materially harm our business.
Manati Field would be negatively impaired.
In Peru,Ecuador, future production from blocks acquired in the Morona Block2019 is expected to be transported through the existing North Peruvian Pipeline, which was out of servicepipeline infrastructure. While the Ecuadorian pipeline system is well-developed and has operated reliably in 2017 duethe past, we cannot guarantee this will continue in the future. Also, as production in Ecuador increases, available capacity may be limited. An inability to technical issues and presented some interruptions to service during 2018. Though the Peruvian government is implementing a program to maintain and modernize the pipeline, future technical issues, other general infrastructure problems or social unrest affecting pipeline operation mayaccess transport capacity could adversely affect our production levels or the recoverability oftransport costs associated with getting our future investments, our future production or revenues related to the Morona Block.
In addition, as the Morona Block is located in a remote area of the tropical rainforest, the development of the project involves significant infrastructure to be built, including processing facilities, storages tanks and a 37 kilometers-long flexible pipeline which is required to start production. In addition, the full development of the project would require a 97 kilometers-long pipeline from the site to the North Peruvian Pipeline. Also, as there are no roads available in the surrounding area, logistics will be performed by helicopters or barges. These issues may lead us to incur significant costs or investments that may not be recoverable through our commercial activities in the Morona Block.
market.
In Argentina, we deliver a portion of our oil production and all of our gas production via existing pipeline infrastructure controlled by third parties. While both the oil and gas pipeline systems in Argentina are well-developed and have operated reliably in the past, we cannot guarantee this will continue in the future. In addition, as Argentina’s production grows, pipeline capacity may become insufficient. We also deliver a portion of our crude production at well-head. This volume is lifted from our loading facilities by third-party operated trucks contracted by our clients. The roads around our fields are in good condition but changes in those conditions could adversely affect our operations. Our failure to secure transportation or access to pipelines or other facilities on acceptable terms or on a timely basis could materially harm our business.
Through our Brazilian operations, we face operational risks relating to offshore drilling.
Our operations in the BCAM-40 Concession in Brazil may include shallow-offshore drilling activity in one area in the Camamu-Almada Basin, which we expect will continue to be operated by Petrobras.
Offshore operations are subject to a variety of operating risks and laws and regulations, including among other things, with respect to environmental, health and safety matters, specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities, compliance costs, fines or penalties that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. For example, the Manati Field has been subject to administrative infraction notices, which have resulted in fines against Petrobras in an aggregate amount of approximately US$12 million, all of which are pending a final decision of the Brazilian Institute for the Environment and Natural Renewable Resources (Instituto Brasileiro do Meio-Ambiente e dos Recursos Naturais Renováveis). Although the administrative fines were filed against Petrobras, as a party to the concession agreement governing the Manati Field, we may be liable up to our participation interest of 10%.
Additionally, offshore drilling generally requires more time and more advanced drilling technologies, involving a higher-risk of technological failure and usually higher drilling costs. Offshore projects often lack proximity to existing oilfield service infrastructure, necessitating significant capital investment in flow line infrastructure before we can market the associated oil or gas of a commercial discovery, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some offshore reserve discoveries may never be produced economically.
Further, because we are not the operator of our offshore fields, all of these risks may be heightened since they are outside of our control. We have a 10% interest in the Manati Field which limits our operating flexibility in such offshore fields. See “—We are not, and may not be in the future, the sole owner or operator of all of our licensed areas and do not, and may not in the future, hold all of the working interests in certain 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.”
Our pending acquisition of the Espejo and Perico blocks in Ecuador is subject to regulatory approvals.
In March 2019, GeoPark, in consortium with Frontera (50% GeoPark, 50% Frontera) was awarded the Espejo and Perico blocks in the form of production sharing contracts in the Intracampos Bid Round carried out on March 12, 2019 in Quito, Ecuador. The closing of the acquisition is subject to the occurrence of certain conditions, including obtaining other governmental approvals. Failure to obtain such approvals may result in the termination of the agreement. We expect the transaction to close in the second quarter of 2019 but we cannot guarantee that the regulatory approvals will be obtained by that time or that the acquisition will be completed on this timeline.
Following the eventual completion of this acquisition, conducting operations in Ecuador, a new jurisdiction for us, will subject us to risks that are inherent for foreign companies operating in Ecuador, including challenges posed by different laws and customs; lack of familiarity and burdens of complying with such foreign laws, legal standards, regulatory requirements, tariffs and other barriers; unexpected changes in regulatory requirements, taxes, trade laws, tariffs, export quotas, custom duties or other trade restrictions; potential difficulties in collecting accounts receivable; difficulties in managing and staffing operations; varying expectations as to employee standards; potentially adverse tax consequences, including possible restrictions on the repatriation of earnings. Moreover, operations in Ecuador could be interrupted and negatively affected by economic changes, geopolitical regional conflicts, terrorist activity, political unrest, civil strife, acts of war and other economic or political uncertainties. All of these risks could result in increased costs which could have a material adverse effect on our financial condition, results of operations and cash flows.
We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities, including native communities, where our reserves are located.
Access to the sites where we operate requires agreements (including, for example, assessments, rights of way and access authorizations) with landowners and local communities. If we are unable to negotiate agreements 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 and in Argentina, for example, we have negotiated the necessary agreements for many of our current operations in the Magallanes Basin in Neuquén and in Mendoza, (when we had the operatorship of the CN-V Block), respectively. In Brazil, in the event that social unrest continues or intensifies, thisoccurs, it may lead to delays or damage relating to our ability to operate the assets we have acquired or may acquire in our Brazil Acquisitions.
the future.
In Colombia, although we have agreements with many landowners and are in negotiations with others, we expect our costs to increase following current and future negotiations regarding access to our blocks, as the economic expectations of landowners have generally increased, which may delay access to existing or future sites. In addition, 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 remediating and improving public access roads, compensate them for any damages related to use of such roads and, more generally, invest in infrastructure that was previously 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 blockages and conflicts with landowners.
In some areas operated by us in Putumayo, illegal groups fight to dominate the territory, amongst other reasons, to control illegal activities such as the cultivation and commercialization of illicit crops. Furthermore, these illegal groups oppose to our entrance, to avoid the parallel entrance of governmental entities in these territories under disputes.
In addition, from time to time, 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
14
February 25, 2021, some communities in the Putumayo basin began protesting against the Government of Colombia for the eradication of coca plantations in the area, blocking access to the Platanillo operations.
Other legal proceedings such as land restitution, a judicial process implemented as a consequence of the peace agreement in Colombia focused 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 Peru,Ecuador, we are in an early diagnosis stage with local landowners and communities and we could suffer delays in the Morona Block is located in land inhabited by native communities. Though we have already signed certain agreements with native communities authorizing the executionexploration and operation of the environmental impact assessment for the Morona Project, which the environmental authority is currently analyzing, similar projects in the Peruvian rainforest have faced significant social conflicts and work delays due to community claims. Social conflicts or community claims could adversely affect the recoverability of our future investments, our future production and revenues related to the Morona Block.
fields.
Under the terms of some of our various CEOPs, E&P Contractscontracts, production sharing agreements and concession agreements, we are obligated to drill wells, declare any discoveries and file periodic reports in order 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.
In order 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 certain time periods specified in our various special operation contracts (Contratos Especiales de Operación para la Exploración y Explotación de Yacimientos de Hidrocarburo; hereinafter “CEOP”),(CEOPs, E&P Contractscontracts, production sharing agreements and concession agreements,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 these prospects. The costs to maintain or operate the CEOPs, E&P Contractscontracts, 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 2016,2020, after fulfilling the committed exploratory commitments, fivefour exploratory blocks were relinquished to the ANP. See “Item 4. Information on the Company—B. Business Overview—Our operations—Operations in Brazil.”
In Peru, the rights to explore and produce hydrocarbons are granted through a license contract signed with Perupetro. The scope and schedule of such development will depend on us and Petroperu. The license contract could be terminated by Perupetro if the development obligations included in such agreement are not fulfilled. In addition, there is also an exploratory commitment consisting of the drilling of one exploratory well every two and a half years. Failure to fulfill the exploratory commitment will lead to acreage relinquishment materially affecting the project. Moreover, we have entered into a Joint Investment Agreement with Petroperu by which, subject to the economic and technical feasibility of the Morona Project, we are obliged to bear 100% of capital cost required to carry out long test to existing well Situche Central 3X, and if we decide to continue with the project after that, to the existing well Situche Central 2X. In addition, we are required to cover any capital or operational expenditures associated with the project until December 31, 2020. We expect these expenditures to be substantially reimbursed by Petroperu from revenues associated with future sales. Failure to fulfill such obligations will result in the loss of our participating interest in the License Contract of the Morona Block, and subject us to possible damage claims from Petroperu.
For additional details regarding the status of our operations with respect to our various special contracts and concession agreements, see “Item 4. Information on the Company—B. Business Overview—Our operations.”
A significant amount of our reserves or production have been derived from our operations in certain blocks, including the Llanos 34, BlockCPO-5, Platanillo and Llanos 32 Blocks in Colombia, the Fell Block in Chile and the BCAM-40 Concession in Brazil, the Aguada Baguales Block in Argentina and the Morona Block in Peru.
Brazil.
For the year ended December 31, 2018,2021, the Llanos 34 Block contained 67%79% of our net proved reserves and generated 76%67% of our production, the FellCPO-5 Block contained 6% of our net proved reserves and generated 8%10% of our total production, the Platanillos Block contained 2% of our net proved reserves and generated 5% of our production, the Llanos 32 Block contained 3% of our net proved reserves and generated 1% of our production, the Fell Block contained 5% of our net proved reserves and generated 6% of our total production and the BCAM-40 Concession contained 3% of our net proved reserves and generated 8%5% of our production, the Aguada Baguales Block contained 3% of our proved reserves and generated 3% of our total production and the Morona Block contained 17% of our net proved reserves.production. While our continuing expansion with new exploratory blocks incorporated in our portfolio mean that the above mentionedabove-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.
15
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 Contractscontracts, production sharing agreements and concession agreements are subject to early termination in certain circumstances.
Under certain CEOPs, E&P Contractscontracts, 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 Contractscontracts, production sharing contracts and concession agreements or dilution or forfeiture of interests held by us. As of December 31, 2018,2021, the aggregate outstanding amount of this potential liability for guarantees was US$38.974.9 million, mainly related to capital commitments in Isla Norte, Campanariothe VIM-3, Llanos 34, PUT-8, PUT-9, PUT-12 and FlamencoPlatanillo Blocks in Chile, rounds 11, 12 and 13 concessions in Brazil,Colombia, the MoronaCampanario Block in PeruChile, and the VIM-3,Perico and Llanos 34Espejo Blocks in Colombia.Ecuador. See “Item 4. Information on the Company—B. Business Overview—Our operations” and Note 32.233.2 to our Consolidated Financial Statements.
Additionally, certain of the CEOPs, E&P Contractscontracts, 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 CEOPs contain provisions enabling exploration extensions.
In Colombia, our E&P Contracts may becontracts 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.”
In order to avoid the breach of an E&P contract due to unfulfillment of our exploration commitments, regulation gives us the option to transfer 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 Chile,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 Tierra del FuegoCampanario 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 the Tierra del Fuego Blockthese 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 of 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
16
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 Peru, License Contracts for hydrocarbon exploitation are in force and will remain in effect for 30 years. This term is non-renewable. With regard to the Morona Block, approximately one-third of the contract term has already elapsed, and twenty years remain. Nevertheless, since May 14, 2013, the License Contract related to the Morona Block is under force majeure. During a force majeure period contract terms are suspended (including the term time) as long as the party to the contract is fulfilling certain obligations related to obtaining environmental permits, as is currently the case with the Morona Block. The term of the agreement will be extended by the same amount of time it has been suspended by a force majeure event. The concession year expiration is related to the approval of the environmental impact assessment for the project’s development. The expiration of the License Contract will occur twenty years after the approval of the environmental impact assessment. The License Contract is also subject to early termination in case of our breach of contractual obligations. In such an event, all the existing facilities and wells located in the block will be transferred, without charge, to Perupetro, and we will have to carry out abandonment plans for remediation and restoration of any polluted area in the block and for de-commission the facilities that are no longer required for the block’s operations.
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 of 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 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 Contractcontract, production sharing agreements or concession agreement could have a material adverse effect on our business, financial situation or results of operations.
We sell almost all of 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, 2018, almost2021, all of 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. UnderIn 2019, we amended the gas supply agreement with Methanex committed to increase the purchase commitment up to 400,000460,000 SCM/d of gas produced by us. Dueto accommodate increased production from our successful drilling in the Jauke project. In 2020, we amended the gas supply agreement to increase the purchase commitment to 550,000 SCM/d if Methanex is operating two trains. In 2021 we negotiated an amendment to the declinegas supply agreement to increase the purchase commitment to 600,000 SCM/d. This amendment is still in our gas production, the commitment was reduced to 315,000 SCM/d in 2018, according to the initial termsprocess of our contract. The commitment has remained at 315,000 SCM/d for 2019. We also hold an option to deliver up to 15% above this volume.being executed. Sales to Methanex represented 3%2% of our consolidated revenues for the year ended December 31, 2018.2021. 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. In 2018,Over the past years, Argentina approved export permits of naturalhas been approving gas exports to Chile and other countries, including deliveries to Methanex.
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. The supply of natural gas decreased during the winter months of 2015 due to the increase in seasonal gas demand from the city of Punta Arenas, to which gas producers, including us, gave priority by delivering gas to the city through Methanex which re-sold our gas to ENAP. In May 2017,July 2020, the Methanex plant shut down because of a technical failure which affected our natural gas production and sales for 2010 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 the gas from us, 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
17
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 of our licensed areas and do not, and may not in the future, hold all of the working interests in certain 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,non-wholly owned, assets.
As of December 31, 2018,2021, we are not the operator of 27%24% or sole owner of 31%43% of the blocks included in our portfolio. See “Item 4. Information on the Company—B. Business Overview—Operations in Colombia, Colombia”, “—Operations in Chile, Chile”, “—Operations in Brazil, Brazil”, “—Operations in PeruArgentina” and “—Operations in Argentina.Ecuador.”
In addition, the terms of the joint operationoperations 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 Brazil.Ecuador. Our dependence on our partners could prevent us from realizing our target returns for those discoveries or prospects.
Moreover, as we are not the sole owner or operator of all of 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.
18
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, including the acquisition of Amerisur, 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 and operations we have acquired, or operations we may acquire or add to our portfolio in the future, will not arise in future, and these problems could have a material adverse effect on our business, financial condition and results of operations.
Significant acquisitions, and other strategic transactions may involve other risks, including:
| diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions; |
| challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with ours while carrying on our ongoing business; |
| contingencies and liabilities that could not be or were not identified during the due diligence process, including with respect to possible deficiencies in the internal controls of the acquired operations; and |
| challenge of attracting and retaining personnel associated with acquired operations. |
It is also possible that we may not identify suitable acquisition targets or strategic investment, partnership or alliance candidates. Our inability to identify suitable acquisition targets, strategic investments, partners or alliances, or our inability to complete such transactions, may negatively affect our competitiveness and growth opportunities. Moreover, if we fail
19
to properly evaluate acquisitions, alliances or investments, we may not achieve the anticipated benefits of any such transaction, and we may incur costs in excess of what we anticipate.
Future acquisitions financed with our own cash could deplete the cash and working capital available to adequately fund our operations. We may also finance future transactions through debt financing, the issuance of our equity securities, existing cash, cash equivalents or investments, or a combination of the foregoing. Acquisitions financed with the issuance of our equity securities could be dilutive, which could affect the market price of our stock. Acquisitions financed with debt could require us to dedicate a substantial portion of our cash flow to principal and interest payments and could subject us to restrictive covenants.
The PN-T-597 Concession Agreement in Brazil may not close.
In Brazil, GeoPark Brasil is a party to a class action filed by the Federal Prosecutor’s Office regarding a concession agreement of exploratory Block PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil and gas bidding round held in November 2013. The Brazilian Federal Court issued an injunction against the ANP and GeoPark Brasil in December 2013 that prohibited GeoPark Brasil’s execution of the concession agreement until the ANP conducted studies on whether drilling for unconventional resources would contaminate the dams and aquifers in the region. On July 17, 2015, GeoPark Brasil, at the instruction of the ANP, signed the concession agreement, which included a clause prohibiting GeoPark Brasil from conducting unconventional exploration activity in the area. Despite the clause containing the prohibition, the judge in the case concluded that the concession agreement should not be executed. Thus, GeoPark Brasil requested that the ANP comply with the decision and annul the concession agreement, which the ANP’s Board did on October 9, 2015. The annulment reverted the status of all parties to thestatus quo ante, which maintains GeoPark Brasil’s right to the block.
There is no assurance that we will be able to enter into a concession agreement in the PN-T-597 Block that would be favorable to our exploration goals. See “Item 8—Financial Information—A. Consolidated statements and other financial information—Legal proceedings.”
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.
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. For the year ended December 31, 2018,2021, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-monthfirst day-of-the-month price for the preceding 12 months. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:
| actual prices we receive for oil and natural gas; |
| actual cost of development and production expenditures; |
| the amount and timing of actual production; and |
| changes in governmental regulations, taxation or the taxation invariability provisions in our CEOPs. |
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
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.
As of December 31, 2018, 38%2021, 63% of our net proved reserves are developed. Development of our undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Additionally, delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the standardized measure value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, and may result in some projects becoming uneconomic, causing the quantities associated with these uneconomic projects to no longer be classified as reserves. This was due to the uneconomic status of the reserves, given the proximity to the end of the concessions for these blocks, which does not allow for future capital investment in the blocks. There can be no assurance that we will not experience similar delays or increases in costs to drill and develop our reserves in the future, which could result in further reclassifications of our reserves.
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 customers may experience financial problems that could have a significant negative effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements.
20
The combination of declining cash flows as a result of declines in commodity prices, a reduction in borrowing basis under reserves-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payments or perform on their obligations to us.
Furthermore, someSome of our customers may be highly leveraged, and, in any event, are subject to their own operating expenses. Therefore, the risk we face in doing business with these customers may increase. Other customers may also be subject to regulatory changes, which could increase the risk of defaulting on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, a decrease in our operating cash flows and may also reduce or curtail our customers’ future use of our products and services, which may have an adverse effect on our revenues and may lead to a reduction in reserves.
Furthermore, the COVID-19 pandemic is currently having an indeterminable adverse impact on the world economy and has begun to have numerous worldwide effects on general commercial activity. At this time, given the uncertainty of the lasting effect of the COVID-19 pandemic, its impact on our customers cannot be determined.
We may not have the capital to develop our unconventional oil and gas resources.
We have identified opportunities for analyzing the potential of unconventional oil and gas resources in some of our blocks and concessions. Our ability to develop this potential depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services and personnel and drilling results. In addition, as we have no previous experience in drilling and exploiting unconventional oil and gas resources, the drilling and exploitation of such unconventional oil and gas resources depends on our ability to acquire the necessary technology, to hire personnel and other support needed for extraction or to obtain financing and venture partners to develop such activities. Because of these uncertainties, we cannot give any assurance as to the timing of these activities, or that they will ultimately result in the realization of proved reserves or meet our expectations for success.
Our operations are subject to operating hazards, including extreme weather events, which could expose us to potentially significant losses.
Our operations are subject to potential operating hazards, extreme weather conditions and risks inherent to drilling activities, seismic registration, exploration, production, development and transportation and storage of crude oil, such as explosions, fires, car and truck accidents, floods, labor disputes, social unrest, community protests or blockades, guerilla attacks, security breaches, pipeline ruptures and spills and mechanical failure of equipment at our or third-party facilities. Any of these events could have a material adverse effect on our exploration and production operations or disrupt transportation or other process-related services provided by our third-party contractors.
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.
The ability, expertise, judgment and discretion of our management and our technical and engineering teams are key in discovering and developing oil and natural gas resources. Our performance and success are dependent to a large extent upon key members of our management and exploration team, and their loss or departure would be detrimental to our future success. In addition, our ability to manage our anticipated growth depends on our ability to recruit and retain qualified personnel. Our ability to retain our employees is influenced by the economic environment and the remote locations of our exploration blocks, which may enhance competition for human resources where we conduct our activities, thereby increasing our turnover rate. There is strong competition in our industry to hire employees in operational, technical and other areas, and the supply of qualified employees is limited in the regions where we operate and throughout Latin America generally. The loss of any of our key management or other key employees of our technical team or our inability to hire and retain new qualified personnel could have a material adverse effect on us.
21
We and our operations are subject to numerous environmental, social, health and safety laws and regulations and rulings, which may result in material liabilities and costs.
We and our operations are subject to various international, foreign, federal, state and local environmental, health and safety laws and regulations governing, among other things, the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use, transportation and disposal of regulated materials; and human health and safety. Our operations are also subject to certain environmental risks that are inherent in the oil and gas industry and which may arise unexpectedly and result in material adverse effects on our business, financial condition and results of operations. Breach of environmental laws could result in environmental administrative investigations and/or lead to the termination of our concessions and contracts. Other potential consequences include fines and/or criminal or civil environmental actions. For instance, non-governmental organizations seeking to preserve the environment may bring actions against us or other oil and gas companies in order to, among other things, halt our activities in any of the countries in which we operate or require us to pay fines. Additionally, in Colombia, recent rulings have provided that environmental licenses are administrative acts subject to class actions that could eventually result in their cancellation, with potential adverse impacts on our E&P Contracts.contracts.
In Colombia, the Supreme Court of Justice issued ruling STC3460-2018 on April 5th, 2018, whereby it declared the Amazonia zone as subject of rights to be protected by the authorities. The Supreme Court ordered local, regional and national authorities to adopt measures to reduce deforestation in the Amazonia and protect the environment. This ruling could indirectly affect our operations in the Putumayo E&P contracts operated by Amerisur, as authorities are expected to issue regulations restricting oil and gas operations in the area.
We have not been and may not be at all times in complete compliance with environmental permits that we are required to obtain for our operations and the environmental and health and safety laws and regulations to which we are subject. If we fail to comply with such requirements, we could be fined or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our operations. If we fail to obtain, maintain or renew permits in a timely manner or at all, our operations could be adversely affected, impeded, or terminated, which could have a material adverse effect on our business, financial condition or results of operations. Some environmental licenses related to operation of the Manati Field production system and natural gas pipeline have expired. However, the operator submitted in a timely manner a request for renewal of those licenses and as such this operation is not in default as long as the regulator does not state its final position on the renewal.
We have contracted with and intend to continue to hire third parties to perform services related to our operations. We could be held liable for some or all environmental, health and safety costs and liabilities arising out of our actions and omissions as well as those of our block partners, third-party contractors, predecessors or other operators. To the extent we do not address these costs and liabilities or if we do not otherwise satisfy our obligations, our operations could be suspended, terminated or otherwise adversely affected. There is a risk that we may contract with third parties with unsatisfactory environmental, health and safety records or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions.
Releases of regulated substances may occur and can be significant. Under certain environmental laws and regulations applicable to us in the countries in which we operate, we could be held responsible for all of the costs relating to any contamination at our past and current facilities and at any third-party waste disposal sites used by us or on our behalf. Pollution resulting from waste disposal, emissions and other operational practices might require us to remediate contamination, or retrofit facilities, at substantial cost. We also could be held liable for any and all consequences arising out of human exposure to such substances or for other damage resulting from the release of hazardous substances to the environment, property or to natural resources, or affecting endangered species or sensitive environmental areas. We are currently required to, and in the future may need to, plug and abandon sites in certain blocks in each of the countries in which we operate, which could result in substantial costs.
In addition, we expect continued and increasing attention to climate change issues. Various countries and regions have agreed to regulate emissions of greenhouse gases including methane (a primary component of natural gas) and carbon dioxide (a byproduct of oil and natural gas combustion). The regulation of greenhouse gases and the physical impacts of climate change in the areas in which we, our customers and the end-users of our products operate could adversely impact our operations and the demand for our products.
22
In Peru,Table of Contents
We have set a target to reduce operational Scope 1 and 2 GHG emissions by 50 percent by year-end 2030 from a 2019 baseline. We also have a long-term ambition to achieve net zero Scope 1 and 2 GHG emissions from operations by 2050. Our ability to meet the beginning of2030 GHG reduction target and the construction and development phase of the Morona Block2050 net zero ambition is subject to numerous risks and uncertainties and actions taken in implementing such target and ambition may also expose us to certain additional and/or heightened financial and operational risks. Furthermore, the approvallong-term ambition of an environmental impact assessmentreaching net zero emissions by 2050 is inherently less certain due to the Peruvian environmental authority.longer timeframe and certain factors outside of our control, including the commercial application of future technologies that may be necessary to achieve this long-term ambition. A reduction in GHG emissions relies on, among other things, the ability to develop, access and implement commercially viable and scalable emission reduction strategies and related technology and products. If we are unable to implement these strategies and technologies as planned without negatively impacting expected operations or cost structures, or such environmental impact assessment isstrategies or technologies do not approved duringperform as expected, we may be unable to meet the first half of 2019, we2030 GHG reduction target or 2050 net zero emissions ambition on the current timelines, or at all.
In addition, achieving the 2030 GHG reduction target and 2050 net zero ambition relies on a stable regulatory framework and will not be able to transport allrequire capital expenditures and resources, with the goods and materials required forpotential that actual costs may differ from the development of the project during the fluvial transportation window of the Morona River in 2019original estimates and the construction stagedifferences may be material. Furthermore, the cost of investing in emissions-reduction technologies, and the project will be negatively impacted. If this isresultant change in the case, the beginningdeployment of the production stage of the Morona Projectresources and focus, could also be impacted.
have a negative impact on future operating and financial results.
Environmental, health and safety laws and regulations are complex and change frequently, and our costs of complying with such laws and regulations may adversely affect our results of operations and financial condition. See “Item 4. Information on the Company—B. Business Overview—Health, safety and environmental matters” and “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework.”
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.
A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, the impact of oil and gas operations on the environment, environmental damage relating to spills of petroleum products during transportation and indigenous rights, have affected certain investors' sentiments towards investing in the oil and gas industry.
As a result of these concerns, some institutional, retail and public investors have announced that they no longer are willing to fund or invest in oil and gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from our Board, management and employees. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in our Company or not investing in our Company at all.
Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, our Company, may result in limiting our access to capital and insurance, increasing the cost of capital and insurance, and decreasing the price and liquidity of our common shares even if our operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause a decrease in the value of our assets which may result in an impairment charge.
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.
Hydraulic fracturing of unconventional oil and gas resources is a process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate a higher flow of hydrocarbons into the wellbore. We are contemplatingmay eventually contemplate, after due environmental approvals, such use of hydraulic fracturing in the production of oil and natural gas from certain reservoirs in Chile,
23
especially shale formations. In Colombia, the Council of State is reviewing the regulation for “non-conventional hydrocarbons” and its decision will impact the future of unconventional oil and gas resources in Colombia. The ANH is leading some non-conventional pilot projects (Kalé and Platero in Valle Medio del Magdalena) which have not started yet. The environmental license for Kalé has already been obtained and we will apply for the environmental license for Platero in 2022. Drilling in these pilot projects by the ANH is expected to begin in 2023. The way in which these pilot projects are carried out will surely impact the future of these resources in Colombia. We currently are not aware of any proposals in Colombia, Chile, Brazil, Argentina or PeruEcuador to regulate hydraulic fracturing beyond the regulations already in place. However, various initiatives in other countries with substantial shale gas resources have been or may be proposed or implemented to, among other things, regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing. If any of the countries in which we operate adopts similar laws or regulations, which is something we cannot predict right now, such adoption could significantly increase the cost of, impede or cause delays in the implementation of any plans to use hydraulic fracturing for unconventional oil and gas resources.
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.
As of December 31, 2018,2021, we had US$447674.1 million outstanding amount of total indebtedness outstanding on a consolidated basis, consisting primarily of our US$425.0171.9 million Notes due 2024 which we issued in September 2017. As of December 31, 2018,and our annual debt service obligation was US$27.7499.9 million see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources—Indebtedness.”
Notes due 2027.
Our indebtedness could:
| limit our capacity to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations of any of our debt instruments, including restrictive covenants and borrowing conditions, could result in an event of default under the agreements governing our indebtedness; |
| require us to dedicate a substantial portion of our cash flow from operations to the payments on our indebtedness, thereby reducing the availability of our cash flow to fund acquisitions, working capital, capital expenditures and other general corporate purposes; |
| place us at a competitive disadvantage compared to certain of our competitors that have less debt; |
| limit our ability to borrow additional funds; |
| in the case of our secured indebtedness, lose assets securing such indebtedness upon the exercise of security interests in connection with a default; |
| make us more vulnerable to downturns in our business or the economy; and |
| limit our flexibility in planning for, or reacting to, changes in our operations or business and the industry in which we operate. |
The indentureindentures governing our Notes due 2024 includesand our Notes due 2027 include covenants restricting dividend payments. For a description, see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources—Indebtedness—Notes due 2024.Indebtedness.”
As a result of these restrictive covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs. We have in the past been unable to meet incurrence tests under the indenture governing our prior notes, which limited our ability to incur indebtedness. Failure to comply with the restrictive covenants included in our Notes due 2024 or our Notes due 2027 would not trigger an event of default.
24
Similar restrictions could apply to us and our subsidiaries when we refinance or enter into new debt agreements which could intensify the risks described above.
Our business could be negatively impacted by security threats, including cybersecurity threats as well as other disasters, and related disruptions.
The global cyber-threats constantly evolve and the oil and gas industry is exposed to it.
Digital technologies have become an integral part of our business. The oil and gas industry has become increasingly dependent on computer and telecommunications systems to conduct exploration, development and production activities.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increasedescalated in the world. ComputerOur industry is subject to fast-evolving risks from cyber threat actors, including states, criminals, terrorists, hacktivists and telecommunications systems are used to conduct our exploration, development and production activities and have become an integral part of our business. Our business processes depend on the availability, capacity, reliability and security of our information technology infrastructure and our ability to expand and continually update this infrastructure in response to our changing needs. It is critical to our business that our facilities and infrastructure remain secure. insiders.
Although we have implemented internal controla strong cyber security strategy and procedures to prevent and assure the confidentiality, availability and security of our data, we cannot guarantee that these measures will be sufficientenough for this purpose. Cyber-attacks, could compromise our computerswhose techniques are regularly renewed, are becoming more and telecommunications systems and result in disruptions to our business operationmore sophisticated.
Therefore, it is necessary to deliver our production to market or the loss of our data.
Although we have extended our security policy to the main systems of the Companycontinue identifying and implemented strategies to mitigate the impact from cybersecurity threats, reinforcing the defenses in case of denial of servicefixing any technical vulnerabilities and increasing the monitoring of suspicious activities, our technologies, systems, networks, and those of our business partners have been and may continue to be the target of cyber-attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized release of confidential or protected information, corruption of data or other disruptions of our business operations. The ability of the information technology function to support our businessweaknesses in the event of a security breach or a disaster such as fire or flood and our ability to recover key systems and information from unexpected interruptions cannot be fully tested and there is a risk that, if such an event actually occurs, we may not be able to address immediately the repercussions of a breach. In the event of a breach, key information and systems may be unavailable for a number of days leading to an inability to conduct our business or perform some businessoperating processes, in a timely manner. We have implemented strategies to mitigate the impact from these types of events.
In addition, the oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data. We depend on digital technology, including information systems and related infrastructure as well as cloud applicationto continue strengthening capabilities to detect and react to incidents. This includes the need to strengthen security controls in the supply chain (from our partners and other third parties), as well as to ensure the security of the services in the cloud.
As a result of the circumstances brought by the COVID-19 pandemic, security measures related to processremote access and record financial and operating data, communicate with ourteleworking of employees and business partners, analyze seismiccollaborators have been reviewed and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. Our business partners, including vendors, service providers, co-venturers, purchasersstrengthened, but no assurance can be provided that such security measures will be effective.
A breach or failure of our production, and financial institutions, are also dependent on digital technology. As dependence on digital technologies has increased,infrastructure – including control systems – due to breaches of our cyber incidents, including deliberate attacksdefenses, or unintentional events, have also increased.
A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. Our technologies, systems, networks, and those of third parties, negligence, intentional misconduct or other reasons, could seriously disrupt our business partners may become the target of cyber-attacks or information security breaches thatoperations. This could result in the unauthorized release, gathering, monitoring, misuse, loss or destructionmisuse of proprietary and otherdata or sensitive information, or otherinjury to people, disruption ofto our business, operations. harm to the environment or our assets, legal or regulatory breaches and legal liability.
Furthermore, the rapid detection of attempts to gain unauthorized access to our digital infrastructure, often through the use of sophisticated and coordinated means, is a challenge we must face and any delay or failure to detect cyber incidents could compound these potential harms. This could result in significant losses including the cost of remediation and reputational consequences.
Our employees have been and will continue to be targeted by parties using fraudulent “spam”, “scam”, “phishing” and “phishing”“spoofing” emails to misappropriate information or to introduce viruses or other malware through “trojan horse” programs to our computers. These emails appear to be legitimate emails sent by us but direct recipients to fake websites operated by the sender of the email or request that the recipient send a password or other confidential information through email or download malware. Despite our efforts to mitigate “spoof” and “phishing” emails through education, “spoof” and “phishing” activities remain a serious problem that may damage our information technology infrastructure.
Certain cyber incidents, such as surveillance, may remain undetected for an extended period. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations. Although to date wecyber-attacks have not experienced any significant cyber-attacks,had a material impact in our operations or financial results, there can be no assurance that we will not be the target of cyber-attacks in the future or suffer such losses related to any cyber-incident.
As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhancemodifying and enhancing our protective measures orand to investigate and remediate any information security vulnerabilities.
In August 2021, we strengthened our corporate insurance package, with the acquisition of a cyber security insurance policy, to get coverage and indemnification from a potential cyber-attack or data breach. However, no assurances can be made as to whether the insurance policy will be enough to cover all our potential liability.
25
We operate in an industry with significant environmental, social, governance (ESG) and climate related risks.
Our operations in Latin America are in areas of significant biodiversity value and many have historical and current ties to indigenous peoples’ lands. Indigenous project affected communities have a growing expectation of the right to free, prior and informed consent based on the United Nations Declaration on the Rights of Indigenous Peoples and national legislation across Latin America increasingly recognizes the right to free, informed and prior consultation. These updates to laws and expectations introduce the need for greater resources put toward community engagement and understanding as well as benefit sharing mechanisms. We may be exposed to challenges related to proper biodiversity management, as some operations exist in key biodiversity areas. This could delay and/or increase the cost of our exploration and development projects. Changes in laws, international norms, investor expectations and other stakeholder perceptions could result in increased liabilities and project expenses.
Amerisur’s exploration blocks carry significant costs related to biodiversity management and reputational risk due to overlapping claims of rightful ownership.
With the acquisition of Amerisur in January 2020, we have assumed significant and unpredictable costs for biodiversity management if we are to comply with best industry practices aligned to IFC’s Performance Standard 6. Costs related to mitigation measures to protect the habitat could be larger than currently anticipated due to unanticipated findings in baseline biodiversity studies.
Nine out of twelve of the Amerisur’s oil and gas development and exploration blocks in Colombia overlap with indigenous territories that are either formalized or are being considered for formal tribal land title under the Colombian land restitution law. In all instances we have taken ownership and responsibility over the consultation process with indigenous groups and ensure that broad community support is achieved for our presence in these areas. Project completion and cost expectations could change depending on the agreements achieved. Prolonged negotiations with indigenous communities and affected communities more generally, could draw the attention of international non-profit organizations and potentially result in social unrest, protests and blockades or legal actions, which could provoke material cost overruns and impacts to our reputation.
In Colombia, despite the fact that we closed prior consultations with tribal communities in our PUT-12 Block, some of the communities ignored such consultations and openly oppose to any hydrocarbons exploration and production activities in their territories, with the cooperation of environmental and indigenous NGO’s. Furthermore, this tribal communities are subject of precautionary measurements issued by the Human Rights Interamerican Commission, whereby the Colombian Government is obliged to adopt measures to protect the life and integrity of these communities. In addition, some of these tribal communities are also subject of precautionary measures issued by a Colombian Land Restitution Judge, who forbid all hydrocarbons and industrial activities within the communities’ legal territories and within those territories subject to the land restitution. This scenario may replicate in other areas operated by us, which may adversely affect our operations in the Putumayo area.
Pursuant to the prior consultation processes with indigenous communities and other ethnic groups, we comply with the applicable legislation in each of the countries in which we operate, as well as the provisions of ILO Convention 169. We also implement processes and best practices such as those established in IFC standard No. 7. We recognize that our entry and stay in the territories is determined by the social license granted to us by the indigenous communities that inhabit it, and that we will make all our efforts to gain their trust and acceptance to achieve a relationship of mutual benefit in the long term.
We may also become liable for the results of a litigation in the United Kingdom, where 270 members of the community of the area of influence of the Platanillo Block operated by us, claim to have suffered damages derived from Amerisur’s hydrocarbons exploration and production activities since 2009. Liabilities in this process may amount up to £4.47 million (equivalent to US$6.0 million as of December 31, 2021) if the court evidences the damages claimed by the 270 community members.
For example, on February 25, 2021, some communities in the Putumayo basin began protesting against the Government of Colombia for the eradication of coca plantations in the area, blocking access to the Platanillo operations.
26
Risks relating to the countries in which we operate
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.
All of our current operations are located in South America. If local, regional or worldwide economic trends adversely affect the economy of any of the countries in which we have investments or operations, our financial condition and results from operations could be adversely affected.
Oil and natural gas exploration, development and production activities are subject to political and economic uncertainties (including but not limited to changes in energy policies or the personnel administering them), changes in laws and policies governing operations of foreign-based companies, expropriation of property, cancellation or modification of contract rights, revocation of consents or approvals, the obtaining of various approvals from regulators, foreign exchange restrictions, price controls, currency fluctuations, royalty increases and other risks arising out of foreign governmental sovereignty, as well as to risks of loss due to civil strife, acts of war and community-based actions, such as protests or blockades, guerilla activities, terrorism, acts of sabotage, territorial disputes and insurrection. In addition, we are subject both to uncertainties in the application of the tax laws in the countries in which we operate and to possible changes in such tax laws (or the application thereof), each of which could result in an increase in our tax liabilities. These risks are higher in developing countries, such as those in which we conduct our activities.
The main economic risks we face and may face in the future because of our operations in the countries in which we operate include the following:
| difficulties incorporating movements in international prices of crude oil and exchange rates into domestic prices; |
| the possibility that a deterioration in Colombia’s, Chile’s, |
| inflation, exchange rate movements (including devaluations), exchange control policies (including restrictions on remittance of dividends), price instability and fluctuations in interest rates; |
| liquidity of domestic capital and lending markets; |
| tax policies; and |
| the possibility that we may become subject to restrictions on repatriation of earnings from the countries in which we operate in the future. |
In addition, our operations in these areas increase our exposure to risks of guerilla and other illegal armed group activities, social unrest, local economic conditions, political disruption, civil disturbance, community protests or blockades, expropriation, piracy, tribal conflicts and governmental policies that may: disrupt our operations; require us to incur greater costs for security; restrict the movement of funds or limit repatriation of profits; lead to U.S. government or international sanctions; limit access to markets for periods of time; or influence the market’s perception of the risk associated with investments in these countries.
Some countries in the geographic areas where we operate have experienced, and may experience in the future, political instability, and losses caused by these disruptions may not be covered by insurance. For example, during 2019, Chile and Colombia experienced social and political turmoil, including riots, nationwide protests, strikes and street demonstrations against their governments which led to acts of violence and social and political tensions. Future protests could adversely and materially affect the Chilean and Colombian economy and our businesses in those countries. Consequently, our exploration, development and production activities may be substantially affected by factors which could have a material
27
adverse effect on our results of operations and financial condition. We cannot guarantee that current programs and policies that apply to the oil and gas industry will remain in effect.
For example, in spring 2022 there will be national elections in Colombia to elect a new president and a new Congress. A new president and national government may take positions on oil and gas policy issues that are contrary to our interests. Changes regarding oil and gas or investment regulations and policies or a shift in political attitudes in Colombia are beyond our control and may significantly reduce our ability to expand our operations or operate a profitable business.
Our operations may also be adversely affected by laws and policies of the jurisdictions, including Bermuda, Colombia, Chile, Brazil, Argentina, Peru,Ecuador, Spain, the United Kingdom the Netherlands and other jurisdictions in which we do business, that affect foreign trade and taxation, and by uncertainties in the application of, possible changes to (or to the application of) tax laws in these jurisdictions. For example, in 20182020, the Chilean and Spanish governments and, in 2021 the Argentine and the Colombian governmentgovernments introduced tax reforms with provisions that are effective January 1, 2019.reforms. See Note 16 to our Consolidated Financial Statements.
With regards to Chile, although our CEOPs have protection against tax changes through invariability tax clauses, potential issues may arise on certain aspects not clearly defined in current or future tax reforms.
Changes in any of these laws or policies or the implementation thereof, and uncertainty over potential changes in policy or regulations affecting any of the factors mentioned above or other factors in the future may increase the volatility of domestic securities markets and securities issued abroad by companies operating in these countries, which could materially and adversely affect our financial position, results of operations and cash flows. Furthermore, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the United States, which could adversely affect the outcome of such dispute. Changes in tax laws may result in increases in our tax payments, which could materially adversely affect our profitability and increase the prices of our products and services, restrict our ability to do business in our existing and target markets and cause our results of operations to suffer. There can be no assurance that we will be able to maintain our projected cash flow and profitability following any increase in taxes applicable to us and to our operations.
The political and economic uncertainty in Brazil along with the ongoing “Lava Jato” investigations regarding corruption at Petrobras may hinder the growth of the Brazilian economy and could have an adverse effect on our business.
Our Brazilian operations represent 5% of our revenues as of December 31, 2018. The Brazilian economy has been experiencing a slowdown. Inflation, unemployment and interest rates have increased more recently and the Brazilian reais has weakened significantly in comparison to the US$. Our results of operations and financial condition may be adversely affected by the economic conditions in Brazil.
Petrobras and certain other Brazilian companies in the energy and infrastructure sectors are facing investigations by the Securities Commission of Brazil (Comissão de Valores Mobiliários), the U.S. Securities and Exchange Commission (the “SEC”), the Brazilian Federal Police and the Brazilian Federal Prosecutor’s Office in connection with corruption allegations (the “Lava Jato” investigations). Depending on the duration and outcome of such investigations, the companies involved may face downgrades from rating agencies, funding restrictions and a reduction in their revenues. Given the significance of the companies under investigation including Petrobras, this could adversely affect Brazil’s growth prospects and could have a protracted effect on the oil and gas industry. In addition to the recent economic crisis, protests, strikes and corruption scandals have led to a fall in confidence.
We depend on maintaining good relations with the respective host governments and national oil companies in each of our countries of operation.
The success of our business and the effective operation of the fields in each of our countries of operation depend upon continued good relations and cooperation with applicable governmental authorities and agencies, including national oil companies such as Ecopetrol, ENAP, Petrobras, PetroperuYPF and YPF.Petroecuador. For instance, for the year ended December 31, 2018,2021, 100% of our crude oil and condensate sales in Chile were made to ENAP, the Chilean state-owned oil company. In addition, our Brazilian operations in BCAM-40 Concession provide us with a long-term off-take contract with Petrobras, the Brazilian state-owned company that covers 100% of net proved gas reserves in the Manati Field, one of the largest non-associated gas fields in Brazil. If we, the respective host governments and the national oil companies are not able to cooperate with one another, it could have an adverse impact on our business, operations and prospects.
Oil and natural gas companies in Colombia, Chile, Brazil, Argentina, and PeruEcuador do not own any of the oil and natural gas reserves in such countries.
Under Colombian, Chilean, Brazilian, PeruvianArgentine and ArgentineEcuadorian law, all onshore and offshore hydrocarbon resources in these countries are owned by the respective sovereign. Although we are the operator of the majority of the blocks and concessions in which we have a working and/or economic interest and generally have the power to make decisions as how to market the hydrocarbons we produce, the Colombian, Chilean, Colombian, Brazilian, PeruvianArgentine and ArgentineEcuadorian governments have full authority to determine the rights, royalties or compensation to be paid by or to private investors for the exploration or production of any hydrocarbon reserves located in their respective countries.
If these governments were to restrict or prevent concessionaires, including us, from exploiting oil and natural gas reserves, or otherwise interfered with our exploration through regulations with respect to restrictions on future exploration and production, price controls, export controls, foreign exchange controls, income taxes, expropriation of property,
28
environmental legislation or health and safety, this could have a material adverse effect on our business, financial condition and results of operations.
Additionally, we are dependent on receipt of government approvals or permits to develop the concessions we hold in some countries. There can be no assurance that future political conditions in the countries in which we operate will not result in changes to policies with respect to foreign development and ownership of oil, environmental protection, health and safety or labor relations, which may negatively affect our ability to undertake exploration and development activities in respect of present and future properties, as well as our ability to raise funds to further such activities. Any delays in receiving government approvals in such countries may delay our operations or may affect the status of our contractual arrangements or our ability to meet contractual obligations.
Oil and gas operators are subject to extensive regulation in the countries in which we operate.
The Colombian, Chilean, Brazilian, PeruvianArgentine and ArgentineEcuadorian hydrocarbons industries are subject to extensive regulation and supervision by their respective governments in matters such as the environment, social responsibility, tort liability, health and safety, labor, the award of exploration and production contracts, the imposition of specific drilling and exploration obligations, taxation, foreign currency controls, price controls, export and import restrictions, capital expenditures and required divestments. In some countries in which we operate, such as Colombia, we are required to pay a percentage of our expected production to the government as royalties. See “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework—Colombia” and see Note 32.133.1 to our Consolidated Financial Statements. In Argentina, energy regulation gives absolute priority to domestic gas supply, which in case of a gas shortage occurs, will restrict our ability to fulfill our export commitments, if any. This regulation also established subsidies to domestic gas prices, which may negatively affect our revenues considering market prices. See “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework—Argentina.”
For example, in Brazil there is potential liability for personal injury, property damage and other types of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of operations or our being subjected to administrative, civil and criminal penalties, which could have a material adverse effect on our financial condition and expected results of operations. We expect to also operate in a consortium in some of our concessions, which, under the Brazilian Petroleum Law, establishes joint and strict liability among consortium members, and failure to maintain the appropriate licenses may result in fines from the ANP, ranging from R$105 thousand to R$500 million. In addition, there is a contractual requirement in Brazilian concession agreements regarding local content, which has become a significant issue for oil and natural gas companies operating in Brazil given the penalties related with breaches thereof. The local content requirement will also apply to the production sharing contract regime. See “Item 4. Information on the Company—B. Business Overview—Our operations—Operations in Brazil.”
Significant expenditures may be required to ensure our compliance with governmental regulations related to, among other things, licenses for drilling operations, environmental matters, drilling bonds, reports concerning operations, the spacing of wells, unitization of oil and natural gas accumulations, local content policy and taxation.
Colombia has experienced and continues to experience internal security issues that have had or could have a negative effect on the Colombian economy.
In 2016, the Colombian government and the Revolutionary Armed Forces of Colombia (FARC) signed a peace agreement, pursuant to which the FARC agreed to demobilize its troops and to hand over its weapons to a United Nations mission. Our business, financial condition and results of operations could be adversely affected by rapidly changing economic or social conditions, including the Colombian government’s response to current peace agreements and negotiations with other groups, including the ELN, which may result in legislation that increases our tax burden or that of other Colombian companies.
ELN has targeted crude oil pipelines in Colombia, including the Caño Limón-Coveñas pipeline, and other related infrastructure, disrupting the activities of certain oil and natural gas companies and resulting in unscheduled shut-downsshutdowns of transportation systems. These activities, their possible escalation and the effects associated with them have had and may
29
have in the future a negative impact on the Colombian economy or on our business, which may affect our employees or assets.
Our operations in Colombia are subject to security and human rights risks
Civil disturbances and criminal activities such as drug trafficking, vandalism, extortion or kidnapping may disrupt our operations in Colombia. Such incidents may halt or delay exploration and production, increase operating costs, result in harm to employees or trespassers, decrease operational efficiency and increase community tensions. In addition, the manner in which our personnel and the Colombian government respond to civil disturbances and criminal activities can give rise to additional risks where those responses are not conducted in a manner that is consistent with international standards relating to human rights. While we remain committed to strengthening our security processes and protocols, there is no guarantee that such incidents will not occur in the future. For example, in 2021, our supply chain in the Llanos and Putumayo basins was affected by a series of extensive protests and demonstrations across Colombia that included road blockades, which resulted in temporary production curtailments.
In addition, from timevarious laws, conventions and guidelines relating to time, community protests and blockadeshuman rights may arise nearimpact our operations, including those mandating prior consultations with indigenous communities. While we have experience managing these consultations, one or more groups may oppose our current and future operations or further development of our projects or operations. Such opposition may be directed through legal or administrative proceedings or expressed in Colombia,manifestations such as protests, roadblocks or other forms of public expression against our activities, and may have a negative impact on our reputation, operation and financial results. Opposition by such groups to our operations may require modification of, or preclude the operation or development of, our projects or may require us to enter into agreements with such groups or local governments with respect to our projects, which could adversely affectmay result in considerable delays to the advancement of our business, financial condition or results of operations.
projects.
Risks relatedrelating to our common shares
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.
Our common shares began to trade on the New York Stock Exchange (the “NYSE”) on February 7, 2014, and as a result have a limited trading history. We cannot predict the extent to which investor interest in our company will maintain an active trading market on the NYSE, or how liquid that market will be in the future.
The market price of our common shares may be volatile and may be influenced by many factors, some of which are beyond our control, including:
| our operating and financial performance and identified potential drilling locations, including reserve estimates; |
| quarterly variations in the rate of growth of our financial indicators, such as net income per common share, net income and revenues; |
| changes in revenue or earnings estimates or publication of reports by equity research analysts; |
| fluctuations in the price of oil or gas; |
| speculation in the press or investment community; |
| sales of our common shares by us or our shareholders, or the perception that such sales may occur; |
| involvement in litigation; |
| changes in personnel; |
30
| announcements by the company; |
| domestic and international economic, legal and regulatory factors unrelated to our performance; |
| variations in our quarterly operating results; |
| volatility in our industry, the industries of our customers and the global securities markets; |
| changes in our dividend policy; |
| risks relating to our business and industry, including those discussed above; |
| strategic actions by us or our competitors; |
| actual or expected changes in our growth rates or our competitors’ growth rates; |
| investor perception of us, the industry in which we operate, the investment opportunity associated with our common shares and our future performance; |
| adverse media reports about us or our directors and officers; |
| addition or departure of our executive officers; |
| change in coverage of our company by securities analysts; |
| trading volume of our common shares; |
| future issuances of our common shares or other securities; |
| terrorist acts; or |
| the release or expiration of transfer restrictions on our outstanding common shares. |
We have never declared or paid, and do not expect to pay in the foreseeable future, cash dividends on our common shares, and, consequently, your only opportunity to achieve a return on your investment is if the price of our stock appreciates.
We have never paid, and do not expect to pay in the foreseeable future, cash dividends on 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 our shareholders, and will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors.
On November 6, 2019, our Board of Directors declared the initiation of a quarterly cash dividend of US$0.0413 per share. The first one was paid on December 10, 2019 and the second one was paid on April 8, 2020. After that, on April 20, 2020 we declared the temporary suspension of quarterly cash dividends and share buybacks as part of our revised work program for 2020 to help address the recent decline in oil prices. On November 4, 2020 we declared an extraordinary cash dividend and a quarterly cash dividend of $0.0206 per share each one, paid on December 9, 2020 to our shareholders of record at the close of business on November 20, 2020. The quarterly cash dividend supplements the existing share buyback program which as of December 31, 2020, has returned US$75.3 million in value to shareholders during 2019 and 2020.
On March 10, 2021, and May 5, 2021, our Board of Directors declared quarterly cash dividend of US$0.0205 per share payable on April 13, 2021, and May 28, 2021, to our shareholders of record at the close of business on March 31, 2021, and May 17, 2021, respectively.
On August 4, 2021 and November 10, 2021, our Board of Directors declared a quarterly cash dividend of US$0.041 per share payable on August 31, 2021, and December 7, 2021, to our shareholders of record at the close of business on August 17, 2021, and November 23, 2021, respectively.
31
On March 9, 2022, our Board of Directors declared a quarterly cash dividend of US$0.082 per share payable on March 31, 2022, to our shareholders of record at the close of business on March 24, 2022.
Due to losses resulting from the oil price decline, in previous years, accumulated losses amount to US$206.7314.8 million as of December 31, 2018.
2021, and our total equity as of December 31, 2021, is negative US$61.9 million.
We are also subject to Bermuda legal constraints that may affect our ability to pay dividends on our common shares and make other payments. Under the Companies Act, 1981 (as amended) of Bermuda (“Bermuda Companies(the “Companies Act”), we may not declare or pay a dividend or make a distribution out of contributed surplus, if there are reasonable grounds for believing that (i) we are, or would after the payment be, unable to pay our liabilities as they become duedue; or (ii) that the realizable value of our assets would thereafterthereby be less than our liabilities. We are also subject to contractual restrictions under certain of our indebtedness.
“Contributed surplus” is defined for purposes of section 54 of the Companies Act to include the proceeds arising from donated shares, credits resulting from the redemption or conversion of shares at less than the amount set up as nominal capital and donations of cash and other assets to the company.
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.
As a holding company, our only material assets are our cash on hand, the equity interests in our subsidiaries and other investments. Our principal source of revenue and cash flow is distributions from our subsidiaries. Thus, our ability to service our debt, finance acquisitions and pay dividends to our stockholders in the future is dependent on the ability of our subsidiaries to generate sufficient net income and cash flows to make upstream cash distributions to us. Our subsidiaries are and will be separate legal entities, and although they may be wholly-owned or controlled by us, they have no obligation to make any funds available to us, whether in the form of loans, dividends, distributions or otherwise. The ability of our subsidiaries to distribute cash to us will also be subject to, among other things, restrictions that are contained in our subsidiaries’ financing and joint ventureoperations agreements, availability of sufficient funds in such subsidiaries and applicable state laws and regulatory restrictions. Claims of creditors of our subsidiaries generally will have priority as to the assets of such subsidiaries over our claims and claims of our creditors and stockholders. To the extent the ability of our subsidiaries to distribute dividends or other payments to us could be limited in any way, our ability to grow, pursue business opportunities or make acquisitions that could be beneficial to our businesses, or otherwise fund and conduct our business could be materially limited.
We may not be able to fully control the operations and the assets of our joint venturesoperations and we may not be able to make major decisions or take timely actions with respect to our joint venturesoperations unless our joint ventureoperation partners agree. We may, in the future, enter into joint ventureoperations agreements imposing additional restrictions on our ability to pay dividends.
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.
We may issue additional common shares or convertible securities in the future, for example, to finance potential acquisitions of assets, which we intend to continue to pursue. 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. This could also impair our ability to raise additional capital through the sale of our equity securities. Under our memorandum of association, we are authorized to issue up to 5,171,949,000 common shares, of which 60,483,44760,238,026 common shares were outstanding as of December 31, 2018.2021. We cannot predict the size of future issuances of our common shares or the effect, if any, that future sales and issuances of shares would have on the market price of our common shares.
Provisions of the Notes due 2024 and Notes due 2027 could discourage an acquisition of us by a third party.
Certain provisions of the Notes due 2024 and the Notes due 2027 could make it more difficult or more expensive for a third party to acquire us or may even prevent a third party from acquiring us. For example, upon the occurrence of a fundamental change of control, holders of the Notes due 2024 will have the right, at their option, to require us to repurchase all of their
32
notes at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts, if any) to the date of purchase. By discouraging an acquisition of us by a third party, these provisions could have the effect of depriving the holders of our common shares of an opportunity to sell their common shares at a premium over prevailing market prices.
Certain shareholders have substantial controlinfluence over us and could limit your ability to influence the outcome of key transactions, including a change of control.
Mr. Gerald E. O’Shaughnessy,Certain members of our Chairman, Mr. James F. Park,board of directors and our Chief Executive Officer, Mr. Jamie Coulter, director, Mr. Constantine Papadimitriou, director, and Mr. Juan Cristóbal Pavez, director, control 35.4%senior management held 20.5% of our outstanding common shares as of March 15, 2019,12, 2022, holding the shares either directly or through privately held funds. As a result, these shareholders, if acting together, would be able to influence or control matters requiring approval by our shareholders, including the election of directors and the approval of amalgamations, mergers or other extraordinary transactions. They may also have interests that differ from yours and may vote in a way with which you disagree, and which may be adverse to your interests. The concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their common shares as part of a sale of our company and might ultimately affect the market price of our common shares. See “Item 7. Major Shareholders and Related Party Transactions—A. Major shareholders” for a more detailed description of our share ownership.
Shareholder activism could cause us to incur significant expense, hinder execution of our business strategy and impact our stock price.
Shareholder activism has been increasing generally and in the energy industry specifically. Investors may from time to time attempt to effect changes to our business or governance, with respect to climate change or otherwise, by means such as shareholder proposals, public campaigns, proxy solicitations or otherwise. Such actions could adversely impact us by distracting the Board and employees from core business operations, increasing advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future direction of the business.
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.
As a foreign private issuer, the rules governing the information that we disclose differ from those governing U.S. corporations pursuant to the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Although we intend to report quarterly financial results and report certain material events, we are not required to file quarterly reports on Form 10-Q or provide current reports on Form 8-K disclosing significant events within four days of their occurrence and our quarterly or current reports may contain less information than required under U.S. filings. In addition, we are exempt from the Section 14 proxy rules, and proxy statements that we distribute will not be subject to review by the SEC. Our exemption from Section 16 rules regarding sales of common shares by insiders means that you will have less data in this regard than shareholders of U.S. companies that are subject to the Exchange Act. As a result, you may not have all the data that you are accustomed to having when making investment decisions. For example, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and the rules thereunder with respect to their purchases and sales of our common shares. The periodic disclosure required of foreign private issuers is more limited than that required of domestic U.S. issuers and there may therefore be less publicly available information about us than is regularly published by or about U.S. public companies. See “Item 10. Additional Information—H. Documents on display.”
As a foreign private issuer, we are exempt from complying with certain corporate governance requirements of the NYSE applicable to a U.S. issuer, including the requirement that a majority of our board of directors consist of independent directors as well as the requirement that shareholders approve any equity issuance by us which represents 20% or more of our outstanding common shares. As the corporate governance standards applicable to us are different than those applicable to domestic U.S. issuers, you may not have the same protections afforded under U.S. law and the NYSE rules as shareholders of companies that do not have such exemptions.
33
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.
The permission of the Bermuda Monetary Authority (the “BMA”), must specifically approveis required, under the provisions of the Exchange Control Act 1972 and related regulations, for all issuances and transfers of securitiesshares (which includes our common shares) of Bermuda companies to or from a non-resident of Bermuda exempted company like us unless itfor exchange control purposes, other than in cases where the Bermuda Monetary Authority has granted a general permission. We are ableThe Bermuda Monetary Authority, in its notice to rely onthe public dated June 1, 2005, has granted a general permission fromfor the BMA to issue our common shares, and to freelysubsequent transfer our common shares as long as the common shares are listed on the NYSEof any securities of a Bermuda company from and/or other appointed stock exchange, to and among persons who are non-residentsa non-resident of Bermuda for exchange control purposes.purposes for so long as any “Equity Securities” of the company (which would include our common shares) are listed on an “Appointed Stock Exchange” (which would include the New York Stock Exchange). In granting the general permission the Bermuda Monetary Authority accepts no responsibility for our financial soundness or the correctness of any of the statements made or opinions expressed in this annual report. Any other transfers remain subject to approvalchanges in the permission granted by the BMABermuda Monetary Authority and such approval may be deniedrelated regulations could result in a delay or delayed.
denial of any transfer of shares an investor might seek.
We are a Bermuda company, and it may be difficult for you to enforce judgments against us or against our directors and executive officers.
We are incorporated as an exempted company under the laws of Bermuda and substantially all of our assets are located in Colombia, Chile, Argentina, Brazil and Peru.Ecuador. In addition, most of our directors and executive officers reside outside the United States and all or a substantial portion of the assets of such persons are located outside the United States. As a result, it may be difficult or impossible to effect service of process within the United States upon us, or to recover against us on judgments of U.S. courts, including judgments predicated upon the civil liability provisions of the U.S. federal securities laws. Further, no claim may be brought in Bermuda against us or our directors and officers in the first instance for violation of U.S. federal securities laws because these laws have no extraterritorial application under Bermuda law and do not have force of law in Bermuda. However, a Bermuda court may impose civil liability, including the possibility of monetary damages, on us or our directors and officers if the facts alleged in a complaint constitute or give rise to a cause of action under Bermuda law.
There is no treaty in force between the United States and Bermuda providing for the reciprocal recognition and enforcement of judgments in civil and commercial matters. AsHowever, the courts of Bermuda would recognize any final and conclusive monetary in personam judgement obtained in a result, whetherU.S. court (other than a United States judgmentsum of money payable in respect of multiple damages, taxes or other charges of a like nature or in respect of a fine or other penalty) and would be enforceable in Bermuda against us or our directors and officers depends on whethergive a judgement based thereon provided that (i) the U.S. court that entered the judgment is recognized by the Bermuda court as having jurisdiction over us or our directors and officers, as determined by reference to Bermuda conflict of law rules. Arules, (ii) such court did not contravene the rules of natural justice of Bermuda, such judgment debt from a U.S. court that is final and for a sum certain based on U.S. federal securities laws willwas not obtained by fraud, the enforcement of the judgment would not be enforceable incontrary to the public policy of Bermuda, unless(iii) no new admissible evidence relevant to the action is submitted prior to the rendering of the judgment debtor had submitted toby the jurisdiction of the U.S. court, and the issue of submission and jurisdiction is a mattercourts of Bermuda, (not U.S.) law.
and (iv) there is due compliance with the correct procedures under the laws of Bermuda.
In addition, and irrespective of jurisdictional issues, the Bermuda courts will not enforce a U.S. federal securities law that is either penal or contrary to Bermuda public policy. An action brought pursuant to a public or penal law, the purpose of which is the enforcement of a sanction, power or right at the instance of the state in its sovereign capacity, will not be entertained by a Bermuda court. Certain remedies available under the laws of U.S. jurisdictions, including certain remedies under U.S. federal securities laws, would not be available under Bermuda law or enforceable in a Bermuda court, as they would be contrary to Bermuda public policy.
The transfer of our common shares may be subject to capital gains taxes pursuant to indirect transfer rules in Chile.
Colombia.
In September 2012, ChileAugust 2020, the Colombian government enacted Decree 1103 that regulates the indirect transfer tax established “indirectin article 90-3 of the Colombian Tax Code. Through this regulation, the transfer rules,” which impose taxes, under certain circumstances, on capital gains resulting from indirect transfers of shares equity rights, interests or other rightsand assets of entities located abroad are taxed in the equity, control or profitsColombia when such transaction represents a transfer of a Chilean entity, as well as on transfers of other assets and property of permanent establishments or other businesseslocated in ChileColombia (“ChileanColombian Assets”). Although certain conditions and exemptions apply, corporate reorganizations shall monitor this new regulation.
34
As we indirectly own ChileanColombian Assets, the indirect transfer rules would apply to transfers of our common shares provided certain conditions outside of our control are met. If such conditions were present and as a result the indirect transfer rules were to apply to sales of our common shares, such sales would be subject to indirect transfer tax on the capital gain realized in connection with such sales. For a description of the indirect transfer rules and the conditions of their application see “Item 10. Additional Information—E. Taxation—ChileanColombian tax on transfers of shares.”
Legislation enacted in Bermuda as to Economic Substance may affect our operations.
As an exempted company incorporated under Bermuda law, our operations may be subjectPursuant to economic substance requirements.
On December 5, 2017, following an assessment of the tax policies of various countries by the Code of Conduct Group for Business Taxation of the European Union (the “COCG”), the Council of the EU approved and published Council conclusions containing a list of non-cooperative jurisdictions for tax purposes (the “Conclusions”). Although not considered so-called “non-cooperative jurisdictions,” certain countries, including Bermuda, were listed as having “tax regimes that facilitate offshore structures which attract profits without real economic activity.” In connection with the Conclusions, and to avoid being placed on the list of “non-cooperative jurisdictions,” the government of Bermuda, among others, committed to addressing COCG proposals relating to economic substance for entities doing business in or through their respective jurisdictions and to pass legislation to implement any appropriate changes by the end of 2018.
The Economic Substance Act 2018 and the Economic Substance Regulations 2018(as amended) of Bermuda (the “Economic Substance“ES Act” and the “Economic Substance Regulations”, respectively) became operative) that came into force on December 31, 2018. The Economic Substance Act applies to every registered entity in Bermuda that engages in a relevant activity and requires that every such entity shall maintain a substantial economic presence in Bermuda. Relevant activities for the purposes of the Economic Substance Act are banking business, insurance business, fund management business, financing business, leasing business, headquarters business, shipping business, distribution and service center business, intellectual property holding business and conducting business as a holding entity, which may include a pure equity holding entity.
The Bermuda Economic Substance Act provides thatJanuary 1, 2019, a registered entity other than an entity which is resident for tax purposes in certain jurisdictions outside Bermuda (“non-resident entity”) that carries on as a relevant activity compliesbusiness any one or more of the “relevant activities” referred to in the ES Act must comply with economic substance requirements if (a) it isrequirements. The ES Act may require in-scope Bermuda entities which are engaged in such “relevant activities” to be directed and managed in Bermuda, (b) itshave an adequate of qualified employees in Bermuda, incur an adequate level of annual expenditure in Bermuda, maintain physical offices and premises in Bermuda or perform core income-generating activities (as may be prescribed) are undertaken in Bermuda with respect to the relevant activity, (c) it maintains adequate physical presence in Bermuda, (d) it has adequate full time employees in Bermuda with suitable qualificationsBermuda. The list of “relevant activities” includes carrying on any one or more of: banking, insurance, fund management, financing, leasing, headquarters, shipping, distribution and (e) it incurs adequate operating expenditure in Bermuda in relation to the relevant activity.
A registered entity that carries on a relevant activity is obliged under the Bermuda Economic Substance Act to file a declaration in the prescribed form (the “Declaration”) with the Registrar of Companies (the “Registrar”) on an annual basis.
service center, intellectual property and holding entities.
The Economic Substance Regulations provide that minimum economic substance requirements shall applyES Act could affect the manner in relation to an entity if the entity is a pure equity holding entity which only holds or manages equity participations, and earns passive income from dividends, distributions, capital gains and other incidental income only. The minimum economic substance requirements include a) compliance with applicable corporate governance requirements set forth in the Bermuda Companies Act 1981 including keeping records of account, books and papers and financial statements and b) submission of an annual economic substance declaration form. Additionally, the Economic Substance Regulations provide that a pure equity holding entity complies with economic substance requirements where it also has adequate employees for holding and managing equity participations, and adequate premises in Bermuda.
If we fail to comply withoperate our obligations under the Bermuda Economic Substance Act or any similar law applicable to us in any other jurisdictions, webusiness, which could be subject to financial penalties and spontaneous disclosure of information to foreign tax officials in related jurisdictions and may be struck from the register of companies in Bermuda or such other jurisdiction. Any of these actions could have a material adverse effect onadversely affect our business, financial condition and results of operations.
On March 12, 2019, Bermuda was placed by Although it is presently anticipated that the EUES Act will have little material impact on its list of non-cooperative jurisdictions for tax purposes dueus or our operations, as the legislation is new and remains subject to an issue with Bermuda’s economic substance legislation which wasfurther clarification and interpretation, it is not resolved in time forcurrently possible to ascertain the EU’s deadline. At present, theprecise impact of being includedthe ES Act on the list of non-cooperative jurisdictions for tax purposes is unclear. While Bermuda has now amended its legislation which the Bermuda Government has stated has addressed this issue and expects to be removed from the list of non-cooperative jurisdictions at the EU’s Economic and Financial Affairs Council’s next meeting which is scheduled to be in May 2019, there can be no assurance that Bermuda will be removed from such list. If Bermuda is not removed from the list and sanctions or other financial, tax or regulatory measures were applied by European Member States to countries on the list or further economic substance requirements were imposed by Bermuda, our business could be negatively impacted.us.
ITEM 4. INFORMATION ON THE COMPANY
| A. History and development of the company |
General
We were incorporated as an exempted company pursuant to the laws of Bermuda as GeoPark Holdings Limited in February 2006. On July 30, 2013, our shareholders approved a change in our name to GeoPark Limited, effective from July 31, 2013. We maintain a registered office in Bermuda at CumberlandClarendon House, 9th Floor, 1 Victoria2 Church Street, Hamilton HM 11,HM11, Bermuda. Our principal executive offices are located at Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile, telephone number +562 2242 9600, Street 94 N° 11-30, 8, 9, 8th floor, Bogotá, Colombia, telephone number +57 1 743 2337, and Florida 981, 1st floor, Buenos Aires, Argentina, telephone number +5411 4312 9400.
The SEC maintains an internet website that contains reports, proxy, information statements and other information about issuers, like us, that file electronically with the SEC. The address of that website is www.sec.gov. The Company’s website address is www.geo-park.com. The information contained on, or that can be accessed through, the Company’s website is not part of, and is not incorporated into, this Annual Report.annual report.
Our Company
We are a leading independent oil and natural gas exploration and production (“E&P”) company with operations in Latin America and a proven track record of growth in production and reserves since 2006.America. We operate in Colombia, Chile, Brazil, Argentina and Peru.Ecuador. We are focused on Latin America because we believe it is one of the most important regions globally in terms of hydrocarbon potential, with less presence of independent E&P companies compared to the United StatedStates and Canada. In this region, much of the acreage has historically been controlled or owned by state-owned companies. We believe that these factors create an opportunity for smaller, more agile companies like us to build a long-term business.
We produced a net average of 36.037.6 mboepd during the year ended December 31, 2018,2021, of which 79%83%, 8%6%, 5%6% and 8%5% were, respectively, in Colombia, Chile, Argentina and Brazil, and of which 85%86% was oil. As of AugustDecember 31, 2018,2021, according to the ANH, we were ranked as the thirdsecond largest oil operator in Colombia, where we made the largest new oil field discovery in the last 20 years. Weyears and we are the first private oil and gas operator in Chile and we are operating the inaugural project of Petroperu in its return to the upstream business in Peru.Chile. We partnered with Petrobras in one of Brazil’s largest producing gas fieldsfields. During 2019, we signed the final participation contracts to start our operations in Ecuador. In January 2020, we successfully closed the acquisition and initiated operational takeover and
35
integration of Amerisur’s assets in Colombia. In 2021, we drilled our first exploratory well in the Perico Block and we have recently increased our activities inaccepted an offer to divest non-core Argentina with the acquisitionassets for a consideration of three blocks in the Neuquén Basin in March 2018.
US$16 million, which closed on January 31, 2022.
We have built our company around three principal capabilities:
| as an Explorer, which is our ability, experience, methodology and creativity to find and develop oil and gas reserves in the subsurface, based on the best science, solid economics and ability to take the necessary managed risks. |
| as an Operator, which is our ability to execute in a timely manner and to have the know-how to profitably drill for, produce, treat, transport and sell our oil and gas – with the drive and persistence to find solutions, overcome obstacles, seize opportunities and achieve results. |
| as a Consolidator, which is our ability and initiative to assemble the right balance and portfolio of upstream assets in the right hydrocarbon basins in the right regions with the right partners and at the right price – coupled with the visions and skills to transform and improve value above ground. |
Our business model reflects our principal capabilities:
Asset Management, Performance & Quality
Effectively and profitably manage our entire asset portfolio and teams, work with partners, obtain regulatory and other permits, and carry out our work programs to explore, develop and produce our oil and gas reserves and resources.
Exploration & Subsurface
Use our brainpower, experience, creativity and discipline to find and develop new oil and gas reserves – based on the best science, solid economics and the ability to take the necessary managed risks.
Operations & Execution
Execute in a timely manner to be the safest lowest cost producer, and with the necessary know-how to profitably drill, produce, transport and sell our oil and gas with the drive and creativity to find solutions, overcome obstacles, seize opportunities and achieve results.
Nature & Neighbors
Having the cleanest and kindest hydrocarbons by minimizing the impact of our projects on the environment, making our operational footprint cleaner and smaller, and being the preferred neighbor and partner by creating a mutually beneficial exchange with the local communities where we work.
Value Delivery & Generation
Create consistent stakeholder value through disciplined capital allocation, rigorous and comprehensive risk management, self-funded and flexible work programs, capital and operating cost efficiency, maximizing the value of every barrel, expanding scale, protecting the balance sheet and returning tangible value to our shareholders.
Commitment & Culture
Build a performance-driven and trust-based culture, based on SPEED, that values and protects our communities, employees, environment and shareholders to underpin and strengthen our long-term plan for success.
36
We believe that our risk and capital management policies have enabled us to compile a geographically diverse portfolio of properties that balances exploration, development and production of oil and gas. These attributes have also allowed us to raise capital and to partner with premier international companies. Most importantly, we believe we have developed a distinctive culture within our organization that promotes and rewards trust, partnership, entrepreneurship and merit. Consistent with this approach, all of our employees are eligible to participate in our long-term incentive program, which is the Performance-Based Employee Long-Term Incentive Program. See “Item 6. Directors, Senior Management and Employees—B. Compensation—Equity Incentive Compensation—Employee Performance-Based Employeeand Long-Term Incentive Program.Programs.”
Our regional platform and risk-balanced portfolio has been built following a proactive but conservative long termlong-term technical approach, converting projects into successful value-generating assets.
History
We were founded in 2002 by Gerald E. O’Shaughnessy and James F. Park, who have over 40 years of international oil and natural gas experience, respectively. Mr. O’Shaughnessy currently servesserved as our Chairman anduntil June 8, 2021. Mr. Park currently serves as our Chief Executive Officer and Deputy Chairman.
Chairman of the Board. In 2021, Sylvia Escovar Gomez was appointed as new Chair of the Board.
We are a leading independent oil and natural gas exploration and production (“E&P”), company with operations in Latin America and a proven track record of growth in production and reserves since 2006. We operateAmerica. During 2021, we operated in Colombia, Chile, Brazil, Argentina and Peru.
Ecuador.
Our History can be summarized by our growth in each country and our performance in the capital markets:
Chile
In 2006, after demonstrating our technical expertise and committing to an exploration and development plan, we obtained a 100% operating working interest in the Fell Block from the Republic of Chile. In 2008 and 2009, we continued our growth in Chile by acquiring operating working interests in each of the Otway and Tranquilo Blocks. Then, in 2011, ENAP awarded us the opportunity to obtain operating working interests in each of the Isla Norte, Flamenco and Campanario Blocks in Tierra del Fuego, Chile, which we refer to collectively as the Tierra del Fuego Blocks, and in 2012, jointly with ENAP, we entered into CEOPs with Chile for the exploration and exploitation of hydrocarbons within these blocks.
Also, in 2011, LGI acquired a 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark TdF for US$148.0 million.
Finally, in November 2018, we acquired all of LGI’s equity interest in GeoPark’s Chilean and Colombian subsidiaries. This acquisition increased GeoPark’s equity interest to 100% in its Colombian and Chilean businesses. The acquisition price includes a fixed payment of US$81 million already paid at closing, plus two equal installments of US$15 million each, to be paid in June 2019 and June 2020. Additionally, three contingent payments of US$5 million each could be payable over the next three years, subject to certain production thresholds being exceeded.
Colombia
In the first quarter of 2012, we moved into Colombia by acquiring three privately held E&P companies: (i) Winchester Oil and Gas S.A., a Colombian branch of asociedad anónima incorporated under the laws of Panama, which merged into GeoPark Colombia SAS (“Winchester”), (ii) La Luna Oil Company Limited S.A., asociedad anónima incorporated under the laws of Panama, which merged into GeoPark Colombia SAS (“Luna”) and (iii) Hupecol Cuerva LLC, a limited liability company incorporated under the laws of the state of Delaware, which merged into GeoPark Colombia SAS (“Cuerva”). These acquisitions provided us with an attractive platform of reserves and resources in Colombia.
In December 2012, LGIDuring 2019, jointly with Ecopetrol/Hocol, we acquired five low-cost, low-risk and high-potential exploration blocks in the Llanos Basin, surrounding the Llanos 34 Block, and we also executed an agreement with Parex to assume a 20% equity50% working interest in GeoPark Colombia Coöperatie U.A by makingthe Llanos 94 Block.
On January 16, 2020, we acquired the entire share capital of Amerisur, a US$14.9 million capital contributioncompany previously listed on the Alternative Investment Market (“AIM”) of the London Stock Exchange. The principal activities of Amerisur were exploration, development and assuming the existing debt for an amountproduction of US$4.9 million.oil and gas reserves in Latin America.
Brazil
Brazil
In MaySince 2013, we entered into agreements to expand our operations to Brazil. have participated many times in the Brazilian ANP Bid Rounds and every time we participated we have been awarded exploratory concessions.
37
As of 2014, following the Rio das Contas acquisition, we have a 10% working interest in the BCAM-40 Concession, which includes an interest in the Manati Gas Field operated by Petrobras.
Since 2013,On November 22, 2020, we have participatedsigned an agreement to sell our 10% non-operated working interest in the Brazilian ANP Bid Rounds and have been awarded exploratory concessions in each oneManati gas field to Gas Bridge for a total consideration of them.
Argentina
In August 2014, in partnership with Pluspetrol, a private oil and gas company with strong presence across Latin America, we were awarded two exploration licenses in the Sierra del Nevado and Puelen Blocks,R$144.4 million (approximately US$27 million as part of the 2014 Mendoza Bidding Round in Argentina.date of the agreement at the exchange rate of R$5.35 to US$1.00), including a fixed payment of R$124.4 million plus an earn-out of R$20.0 million, which is subject to obtaining certain regulatory approvals. The transaction was agreed with an effective date of December 31, 2020 and is subject to certain conditions, including the acquisition by Gas Bridge of the remaining 90% working interest and operatorship of the Manati gas field. As of the date of this annual report these conditions have not been met.
Argentina
In July 2015, we signed a farm-in agreement with Wintershall for the CN-V Block in the Mendoza Province.
Additionally, in December 2017, we agreed to purchase from Pluspetrol, a 100% working interest and operatorship of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina. We entered into an asset purchase agreement with Pluspetrol, dated December 18, 2017 (the “APA”). The transaction closed on March 27, 2018.
Finally, In June 2018, we entered intoannounced a partnership with YPF, the state-owned oil company of Argentina, on the Los Parlamentos block – a large high potential block in the Neuquén Basin with both conventional and unconventional prospects. The assignment of rights agreement was signed in October 2019.
During May 2021, we initiated a process to evaluate farm-out or divestment opportunities to sell our 100% working interest and operatorship in the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina, including the associated gas transportation license through the Puesto Touquet pipeline.
PeruOn November 3, 2021, the sale and purchase and assignment agreement was signed for a total consideration of US$16 million, subject to working capital adjustments. Closing of the transaction took place on January 31, 2022.
Peru
In October 2014, we expanded our footprint into Peru by acquiring the Morona Block in a joint ventureoperation with Petroperu. This transaction awarded us a 75% working interest of the Morona Block. In December 2016, we obtained final regulatory approval for our acquisition of the Morona Block in Peru. The Joint Investment and Operating Agreement dated October 1, 2014 and its amendments were closed on December 1, 2016, following the issuance of Supreme Decree 031-2016-MEM.
On July 15, 2020, we notified our irrevocable decision to retire from the non-producing Morona Block (Block 64) in Peru, due to extended force majeure, which allows for the termination of the license contract. On April 6, 2021, the final agreement with Petroperu was signed and, on May 31, 2021, the joint operation agreement was terminated. On September 28, 2021, the supreme decree approving the assignment was issued by the Peruvian Government, and the public deed corresponding to that assignment was executed by us and Petroperu on November 15, 2021. Consequently, from such date, Petroperu holds all the rights and obligations under the Morona Block license contract.
New potential country platformEcuador
In December 2015, as part of our long-term effort to build an upstream platformOn May 22, 2019, we signed final participation contracts for the Espejo (GeoPark operated, 50% working interest) and Perico (GeoPark non-operated, 50% working interest) Blocks in Mexico, we participated in the Mexican Bid Round 1.3 with Grupo Alfa for onshore projects, however, no blocksEcuador, which were awarded to us.
In March 2019, we announced our expected entry into Ecuador through the acquisition of the Espejo and Perico exploratory blocksGeoPark in the Intracampos Bid Round held in Quito, Ecuador in April 2019. We assumed a commitment of carrying out 3D seismic in the Oriente Basin locatedEspejo Block and drilling four exploration wells in each block, which amounts to US$39 million in capital expenditures for our working interest, until June 2025.
In December 2021 we drilled and completed the first exploration well in the north-eastern partPerico Block, which resulted in discovery of Ecuador. The blocks were awarded tooil, with testing activities currently underway and we are carrying out the GeoPark and Frontera consortium (50% GeoPark, 50% Frontera)acquisition of 60 sq km of 3D seismic in the form of production sharing contracts. The final award is contingent upon regulatory approvals andEspejo Block, targeting to spud the execution of the contracts is expected forfirst exploration well in the second quarterhalf of 2019. See “Item 3. Key Information—A. Risk Factors—Risks relating to our business— Our pending acquisition2022.
38
Funding
In February 2013, we issued US$300 million aggregate principal amount of 7.50% senior secured notes due 2020 (the “Notes due 2020”). We repurchased US$284 million aggregate principal amount of the outstanding Notes due 2020 in September 2017 and redeemed the remaining US$16 million aggregate principal amount outstanding in October 2017.
In February 2014, we commenced trading on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over-allotment option granted to and exercised by the underwriters, through the issuance of 13,999,700 common shares.
In September 2017, we issued US$425.0 million aggregate principal amount of 6.50% senior notes due 2024. The net proceeds from the Notes were used by us (i) to make a capital contribution to our wholly-owned subsidiary, GeoPark Latin America Limited Agencia, en Chile, providing it with sufficient funds to fully repay the Notessenior secured notes due 2020 and to pay any related fees and expenses, including a call premium, and (ii) for general corporate purposes, including capital expenditures, such as the acquisition of Aguada Baguales, El Porvenir and Puesto Touquet blocks in the Neuquén Basin in Argentina and to repay existing indebtedness, including the Itaú loan.
In January 2020, we issued US$350.0 million aggregate principal amount of 5.5% senior notes due 2027. The net proceeds from the Notes were used by us (i) to make an intercompany loan to our wholly-owned subsidiary, GeoPark Colombia S.A.S., providing it with sufficient funds to pay the total consideration for the acquisition of Amerisur (see Note 36.1 to our Consolidated Financial Statements) and to pay related fees and expenses, and (ii) for general corporate purposes.
In April 2021, we executed a series of transactions that included a successful tender to purchase US$255.0 million of the 2024 Notes that was funded with a combination of cash in hand and a US$150.0 million new issuance from the reopening of the 2027 Notes. The new notes offering, and the tender offer closed on April 23, 2021, and April 26, 2021, respectively.
We have grown our business through drilling, developing and producing oil and gas, winning new licenses and acquiring strategic assets and businesses. Since our inception, we have supported our growth through our prospect development efforts, drilling program, long-term strategic partnerships and alliances with key industry participants, accessing debt and equity capital markets, developing and retaining a technical team with vast experience and creating a successful track record of finding and producing oil and gas in Latin America. A key factor behind our success ratio is our experienced team of geologists, geophysicists and engineers, including professionals with specialized expertise in the geology of Colombia, Chile, Brazil, Argentina and Peru.Ecuador.
39
The following map shows the countries in which we have blocks with working and/or economic interests as of December 31, 2018.2021. For information on our working interests in each of these blocks, see “—Our assets” below.
| (1) | In process of relinquishment. See “—Our operations—Operations in Colombia” and “—Our operations—Operations in Argentina.” |
| (2) | On |
40
| (3) |
| (4) |
The following table sets forth our net proved reserves and other data as of and for the year ended December 31, 2018.2021.
| For the year ended December 31, 2018 | |||||||||||||||||||||||||||||||||||||
| | | | | | | | | | | | | | ||||||||||||||||||||||||
| | For the year ended December 31, 2021 |
| ||||||||||||||||||||||||||||||||||
|
| |
| |
| Oil |
| |
| Revenues |
| |
| ||||||||||||||||||||||||
| | Oil | | Gas | | equivalent | | | | (in thousands | | % of total |
| ||||||||||||||||||||||||
| Country | Oil (mmbbl) | Gas (bcf) | Oil equivalent (mmboe) | % Oil | Revenues (in thousands of US$) | % of total revenues | | (mmbbl) | | (bcf) | | (mmboe) | | % Oil | | of US$) | | revenues |
| ||||||||||||||||||
| Colombia | 74.8 | 2.1 | 75.1 | 100 | % | 497,870 | 83 | % |
| 78.8 |
| 1.2 |
| 79.0 |
| 100 | % | 618,268 |
| 90 | % | ||||||||||||||||
| Chile | 3.3 | 20.8 | 6.8 | 49 | % | 37,359 | 6 | % |
| 1.3 |
| 16.7 |
| 4.2 |
| 31 | % | 21,471 |
| 3 | % | ||||||||||||||||
| Brazil | 0.1 | 17.3 | 3.0 | 3 | % | 30,053 | 5 | % |
| — |
| 13.6 |
| 2.3 |
| — | % | 20,109 |
| 3 | % | ||||||||||||||||
| Peru | 18.5 | - | 18.5 | 100 | % | - | -% | ||||||||||||||||||||||||||||||
| Argentina | 3.4 | 9.4 | 5.0 | 68 | % | 35,879 | 6 | % |
| 1.8 |
| 3.4 |
| 2.3 |
| 78 | % | 28,695 |
| 4 | % | ||||||||||||||||
| Total | 100.1 | 49.6 | 108.4 | 92 | % | 601,161 | 100 | % |
| 81.9 |
| 34.9 |
| 87.8 |
| 93 | % | 688,543 |
| 100 | % | ||||||||||||||||
Our commitment to growth has translated into a strong compounded annual growth rate (“CAGR”), of 16%8% for production in the period from 20142017 to 2018,2021, as measured by boepd in the table below.
| For the year ended December 31, | |||||||||||||||||||||||||||||||
| 2018 | 2017 | 2016 | 2015 | 2014 | |||||||||||||||||||||||||||
| | | | | | | | | | | | ||||||||||||||||||||
| | For the year ended December 31, | | ||||||||||||||||||||||||||||
|
| 2021 |
| 2020 |
| 2019 |
| 2018 |
| 2017 |
| ||||||||||||||||||||
| Average net production (mboepd) | 36.0 | 27.6 | 22.4 | 20.4 | 19.7 |
| 37.6 |
| 40.2 |
| 40.0 |
| 36.0 |
| 27.6 | | |||||||||||||||
| % oil | 85 | % | 83 | % | 75 | % | 74 | % | 74 | % |
| 86 | % | 87 | % | 86 | % | 85 | % | 83 | % | ||||||||||
The following table sets forth our production of oil and natural gas in the blocks in which we have a working and/or economic interest as of December 31, 2018.2021.
| Average daily production | ||||||||||||||||||||||||||||||
| For the year ended December 31, 2018 | ||||||||||||||||||||||||||||||
| Colombia | Chile | Brazil | Argentina(1) | Total | ||||||||||||||||||||||||||
| | | | | | | | | | | ||||||||||||||||||||
| | Average daily production | ||||||||||||||||||||||||||||
| | For the year ended December 31, 2021 | ||||||||||||||||||||||||||||
|
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Total | ||||||||||||||||||||
| Oil production |
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
| Total crude oil production (bopd) | 28,421 | 782 | 42 | 1,202 | 30,447 |
| 30,920 |
| 313 |
| 26 |
| 1,215 |
| 32,474 | |||||||||||||||
| Natural gas production |
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
| Total natural gas production (mcf/day) | 740 | 11,640 | 17,300 | 3,796 | 33,476 |
| 1,374 |
| 12,507 |
| 11,357 |
| 5,529 |
| 30,767 | |||||||||||||||
| Oil and natural gas production |
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
| Total oil and natural gas production (mboepd) | 28,545 | 2,722 | 2,925 | 1,835 | 36,027 |
| 31,150 |
| 2,397 |
| 1,919 |
| 2,136 |
| 37,602 | |||||||||||||||
Our assets
We have a well-balanced portfolio of assets that includes working and/or economic interests in 2542 hydrocarbon blocks, 2441 of which are onshore blocks, including 10 in production as of December 31, 2018.2021. Our assets give us access to more than 56.7 million gross exploratory and productive acres.
According to the D&M Reserves Report, as of December 31, 2018,2021, the blocks in Colombia, Chile, Brazil Argentina and PeruArgentina in which we have a working interest had 108.487.8 mmboe of net proved reserves, with 69%90%, 6%5%, 3%, 5% and 17%3% of such net proved reserves located in Colombia, Chile, Brazil and Argentina, and Peru, respectively.
We produced a net average of 36.037.6 mboepd during the year ended December 31, 20182021, of which 79%83%, 8%6%, 5%6% and 8%5%, were in Colombia, Chile, Argentina and Brazil, respectively, and of which 85%86% was oil.
41
We are the operatorTable of the majority of the blocks in which we have a working interest.Contents
Our strengths
We believe that we benefit from the following competitive strengths:
High quality and diversified asset base built through a successful track record of organic growth and acquisitions
Our assets include a diverse portfolio of oil and natural gas-producing reserves, operating infrastructure, operating licenses and valuable geological surveys in Latin America. Throughout our history, we have delivered continuous growth in our production, and our management team has been able to identify under-exploited assets and turn them into valuable, productive assets, and to allocate resources effectively based on prevailing conditions.
| ● | Argentina. On December 18, 2017, we executed an asset purchase agreement (the “APA”) with Pluspetrol to acquire a 100% working interest and operatorship of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina. Closing of the transaction occurred on March 27, 2018. In June 2018, we announced the acquisition of a 50% working interest in the Los Parlamentos exploratory block in partnership with YPF S.A., and in October 2019, we signed the final agreement. On November 3, 2021, we signed the sale and purchase and assignment agreement to sell our 100% working interest and operatorship in the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina, including the associated gas transportation license through the Puesto Touquet pipeline for a total consideration of US$16 million, subject to working capital adjustments. Closing of the transaction took place on January 31, 2022, after the corresponding regulatory approvals. |
42
Significant drilling inventory and resource potential from existing asset base
Our portfolio includes large land holdings in high-potential hydrocarbon basins and blocks with multiple drilling leads and prospects in different geological formations, which provide several attractive opportunities with varying levels of risk. Our drilling inventory and our development plans target locations that provide attractive economics and support a predictable production profile, as demonstrated by our expansions in Colombia.
Our geoscience team continues to identify new potential accumulations and expand our inventory of prospects and drilling opportunities.
Continue to grow a risk-balanced asset portfolio
We intend to continue to focus on maintaining a risk-balanced portfolio of assets, combining cash flow-generating assets with upside potential opportunities, and on increasing production and reserves through finding, developing and producing oil and gas reserves in the countries in which we operate. In general, when we enter a new country we look for a mix of three elements: (i) producing fields, or existing discoveries with near-term possibility of production, to generate cash flows; (ii) an inventory of adjacent low-risk prospects that can offer medium-term upside for steady growth; and (iii) a periphery of higher-risk projects which have a potential to generate significant upside in the long run.
For example, in Colombia, we acquired three companies simultaneouslyAmerisur to pursue a risk-balanced approach: one companyblock had mainly proven production and reserves to provide us with a steady cash flow base, and the remaining blocks had highly prospective exploration license blocks. Within four years of entering Colombia, we made multiple oil discoveries in block Llanos 34 that allowed us to increase production and cash flows.
licenses.
We believe this approach will allow us to sustain continuous and profitable growth and also participate in higher risk growth opportunities with upside potential. See “—Our operations.”
Platform and Funding
We are focused on continued growth utilizing a disciplined capital structure and a conservative financial philosophy. Due to the volatile nature of commodity prices, expenditure discipline and a focus on disciplined capital structure are critical to our business. Our multi-country platform and asset portfolio is managed through our capital allocation methodology, which also allows us to quickly adapt and grow. Under this methodology, each country, has a local team running the business who recommends and advocates for the projects with which they want to move forward. The corporate team then ranks all of the projects based on economic, technical, environmental, social and corporate governance and strategic criteria, for the purpose of comparing projects. This also creates opportunities for improvements in the projects that can, in turn, improve their ranking. Finally, once the production and reserve growth targets are defined, the corporate team decides the amount of capital to be invested and allocates that capital to the highest value-adding projects. As an example, for the 20192022 capital allocation process, over 135115 projects were presented with a final selection of 74selected which comprise our 20192022 work program, under the base capital program. Additionally, given the inherent oil price volatility, we design our work programs to be flexible, which means that they can be increased or decreased depending on the oil price scenario.
We have historically benefited from access to debt and equity capital markets and cash flows from operations, as well as other funding sources, which have provided us with funds to finance our organic growth and the pursuit of potential new opportunities.
We generated US$256.2216.8 million and US$142.2168.7 million in cash from operations in the years ended December 31, 20182021 and 2017,2020, respectively, and had US$127.7100.6 million and US$134.8201.9 million of cash and cash equivalents as of December 31, 20182021 and 2017,2020, respectively.
As of December 31, 2018,2021, we had US$447.0674.1 million of total outstanding indebtedness and over 96%99% of our debt hadis scheduled to mature in 2024 (25.5%) and 2027 (74.2%).
In April 2021, we executed a maturityseries of 2024.
During October 2018, we entered intotransactions that included a loan agreement with Banco Santander for Brazilian Real 77.6successful tender to purchase US$255.0 million (equivalent to US$ 20 million at the moment of the loan execution) to repay an existing2024 Notes that was funded with a combination of cash in hand and a US$-denominated intercompany loan, which matures in October 2020. As a result150.0 million new issuance from the
43
reopening of the 2027 Notes. The new notes offering, and the tender offer closed on April 23, 2021, and April 26, 2021, respectively.
In September 2017, we issuedThe tender total consideration included the tender offer consideration of US$425.0 million aggregate1,000 for each US$1,000 principal amount of 6.50% senior notes duethe 2024 (the “Notes due 2024”)Notes plus the early tender payment of US$50 for each US$1,000 principal amount of the 2024 Notes. The tender also included a consent solicitation to align the covenants of the 2024 Notes to those of the 2027 Notes.
The reopening of the 2027 Notes was priced above par at 101.875%, representing a yield to maturity of 5.117%. The debt issuance cost for this transaction amounted to US$2.0 million. The Notes due 2024 contain incurrence-based limitations on theare fully and unconditionally guaranteed jointly and severally by GeoPark Chile SpA and GeoPark Colombia S.A.S.
Following these transactions, we reduced our total indebtedness nominal amount of indebtedness we can incur, see “Item 5. Operatingby US$105.0 million and Financial Review and Prospects—Liquidity and capital resources—Indebtedness—Notes due 2024—Covenants.”improved our financial profile by extending our debt maturities.
In December 2015,June 2020, we entered into an offtake and prepayment agreement with Trafigura, under which we sold and delivered a portion of our Colombian crude oil production to Trafigura. The offtake agreement also provided us with a prepayment line of up to US$10075 million subject to applicable volumes corresponding to the terms of the agreement, in the form of prepaid future oil sales.
The availability period for the prepayment agreement expired on August 10, 2021. We have not withdrawn any amount from this prepayment agreement.
In March 2014,January 2020, we borrowedissued US$70.5350.0 million pursuant to a five-year term variable interest secured loan, secured by the benefits we receive under the Purchase and Sale Agreement for Natural Gas with Petrobras, equal to 6-month LIBOR + 3.9% to finance partaggregate principal amount of the purchase price of our Rio das Contas acquisition. In March 2015, we reached an agreement to: (i) extend the principal payments that were5.50% senior notes due in 2015 (amounting to approximately US$15 million), which were divided pro-rata during the remaining principal installments, starting in March 2016 and (ii) to increase the variable interest rate equal to the 6-month LIBOR + 4.0%2027 (the “Notes due 2027”). The loan was fully repaid in September 2017.
In February 2014, we commenced tradingNotes due 2027 contain incurrence-based limitations on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over-allotment option grantedamount of indebtedness we can incur. See Note 27 to and exercised by the underwriters, through the issuance of 13,999,700 common shares.our Consolidated Financial Statements.
Strong cash flow
We benefit from a strong cash flow from operating activities. For the year ended December 31, 2018,2021, cash provided byflows from operating activities waswere US$256.2216.8 million. Our cash flowflows from operating activities plays a significant role in funding our capital expenditures.
Maintain financial strength
We seek to maintain a prudent and sustainable capital structure and a strong financial position to allow us to maximize the development of our assets and capitalize on business opportunities as they arise. We intend to remain financially disciplined by limiting substantially all our debt incurrence to identified projects with repayment sources. We expect to continue benefiting from diverse funding sources such as our partners and customers in addition to the international capital markets.
Our cash flow generation is complemented by our financial hedging program. Since October 2016, we have entered into derivative financial instruments to manage our exposure to oil price risk. The purpose of our hedging strategy is to establish minimum oil prices to secure a stable cash flow and the execution of our work program. For the period commencing January 2018more information regarding our financial hedging program please see Note 8 to December 2018, we hedged between 13,000 and 14,000 bopd via zero premium collars and three-way hedges (US$10/bbl wide put spread and call), with a minimum average Brent price of US$55 per barrel and a maximum average price of US$73 per barrel, representing 44% of our oil production for that period. For the period from January 2019 to March 2019, we have secured 15,000 bopd with a minimum average price of US$64 per barrel and a maximum average price of US$92 per barrel via zero premium collars and three-way hedges (US$10/bbl wide put spread and call). For the period from April 2019 to June 2019, we have secured 11,000 bopd with a minimum average price of US$65 per barrel and a maximum average price of US$91 per barrel via zero premium collars and three-way hedges (US$10/bbl wide put spread and call). For the period commencing July 2019 to September 2019, we have secured 5,000 bopd with a minimum average price of US$65 per barrel and a maximum average price of US$92 per barrel via zero premium collars.Consolidated Financial Statements.
InSince December 2018 we decided to manage our future exposure to local currency fluctuation with respect to income tax balances in Colombia. Consequently, we entered into a derivative financial instrumentinstruments with a local bankbanks in Colombia, for an amount equivalent to US$83.7 million in 2019 and US$92.1 million in 2018, in order to anticipate any currency fluctuation with respect to income taxes to be paid during the first half of 2019.the following year. As of December 31, 2021, and 2020, we have no currency risk management contracts in place.
In relation to the cash consideration payable for the acquisition of Amerisur, we were exposed to fluctuations of the British pound sterling as of December 31, 2019. Consequently, we decided to manage this exposure by entering into a deal-contingent forward with a British bank, in order to anticipate any currency fluctuation.
44
Since 2020, we have entered into Vasconia-based derivative contracts, a new instrument within our hedging portfolio. These derivatives protect both the overall crude price exposure to ICE Brent as well as the Vasconia differential, which reflects the quality adjustment for our Llanos Basin crude production in Colombia.
We believe that by maintaining a disciplined capital structure and a conservative financial philosophy, including limiting our debt incurrence to specified projects with repayment sources and our use of financial hedges, we are positioned to maintain sufficient liquidity and remain flexible in volatile commodity price environments. Our financial flexibility also gives us the ability to pursue new opportunities through future potential acquisitions.
Pursue strategic acquisitions in Latin America
We have historically benefited from, and intend to continue to grow through, strategic acquisitions in Latin America. These acquisitions have provided us with additional attractive platforms in the region. Our Colombian acquisitions, for example, highlight our ability to identify and execute on attractive growth opportunities, as we have grown to become the thirdsecond largest operator in Colombia. We acquired our interest in the Llanos 34 Block in the first quarter of 2012 for US$30 million and have achieved 1P reserve PV-10 of US$1,340 million1.1 billion as of December 31, 2018.2021. Our enhanced regional portfolio, including investment-grade countries and strong partnerships, position us as a regional consolidator. We intend to continue to grow through strategic acquisitions in other countries in Latin America, which we may consider from time to time. Our acquisition strategy is aimed at maintaining a balanced portfolio of lower-risk cash flow-generating properties and assets that have upside potential, keeping a balanced mix of oil and gas-producing assets (though we expect to remain weighted towards oil) and focusing on both assets and corporate targets.
On January 16, 2020, we acquired the entire share capital of Amerisur, a company listed on the Alternative Investment Market (“AIM”) of the London Stock Exchange. The principal activities of Amerisur were exploration, development and production for oil and gas reserves in Latin America. Amerisur owned thirteen production, development and exploration blocks in Colombia (twelve operated blocks in the Putumayo Basin and one non-operated block in the Llanos Basin) and a cross-border oil pipeline from Colombia to Ecuador named Oleoducto Binacional Amerisur (“OBA”).
Maintain a high degree of operatorship to control production costs
As of the date of this annual report, we are and intend to continue to be the operator of a majority of the blocks and concessions in which we have working interests. Operating the majority of our blocks and concessions gives us the flexibility to allocate our capital and resources opportunistically and efficiently within a diversified asset portfolio. We believe that this strategy has allowed, and will continue to allow us, to leverage our unique culture, focused on excellence, and our talented technical, operating and management teams. For example, as commodity prices were projected to decline throughout 2015,2020, on March 19, 2020, we announced in the first quarter of 2015 a decision to shift our development plan primarily to our operations in the Llanos 34 Block to focus on the Llanos Basin, which had demonstrated strong returns on capital. Our operating team reacted quickly to pivot our operations that were unburdened by drilling obligations and worked with our service partners to coordinate a smooth and efficient transition to a new plan. Since then, we were able to control production costs, as exemplified by our average operating costs for the Llanos 34 Block, which were US$4.05.8 per boe for the year ended December 31, 2018. 2021.
Long-term strategic partnerships and strong strategic relationships provide us with additional funding flexibility to pursue further acquisitions
We benefit from a number of strong partnerships and relationships. In Chile, we believe we have strong long-term commercial relationships with Methanex and ENAP, and in Colombia, we believe we have developed a strong relationship with Ecopetrol, the Colombian state-owned oil and gas company. In Brazil, we believe we will continue to derive benefits from the long-term relationship GeoPark Brazil has with Petrobras.
In February 2018, we announced the formation of a new long-term strategic partnership to jointly acquire, invest in, and create value from upstream oil and gas projects with the objective of building a large-scale, economically-profitable and risk-balanced portfolio of assets and operations across Latin America with ONGC Videsh, the wholly-owned subsidiary and international arm of Oil and Natural Gas Corporation Limited, India’s national oil company.
45
Maintain our commitment to environmental, safety, human rights and social responsibility
A major component of our business strategy is our focus on and commitment to our safety, environmental and social responsibilities, in line with international standards. We see this as a fundamental element of ensuring long-term business initiatives. We are committed to minimizing the impact of our projects on the environment and aim to create mutually beneficial relationships with the local communities in which we operate in order to enhance our ability to create sustainable value in our projects. These commitments are embodied in our in-house designed Environmental, Health, Safety and Security management program,value system, which we refer to as “S.P.E.E.D.” (Safety, Prosperity, Employees, Environment and Community Development). Our S.P.E.E.D. program was developed in accordance with several international quality standards, including ISO 14001 (for environmental management issues), OHSAS 18001ISO 45001 (for occupational health and safety management issues), ISO 26000 (for social accountability and workers’ rights issues), and applicable World Bank standards.associations guidelines including IOGP, IPIECA, IADC and ARPEL. See “—Health, safety and environmental matters.”
During 2016, we began the ISO 14001 certifying process through programs related to the efficient use of natural resources and compliance with environmental regulation. We have also provided training to our staff and the communities in which we operate with respect to these matters.
In August 2017, we obtained the ISO 14001:2015 certification for our environmental management process for the design, construction, operation, maintenance, modernization and dismantlement of GeoPark Colombia S.A.S.’s facilities, and the performance of exploration and oil and gas production activities in the Llanos 34 and VIM-3 blocks with a commitment to continuously improve our processes. We obtained the ISO 14001:2015 re-certification in 2018 and in 2020 the certification was renewed and extended until August 2023.
Since 2017, GeoPark has certified the greenhouse gas inventory of its operations in Scopes 1 and 2 in Colombia, through the NTC-ISO 14064-3:2006 standard of the Colombian Institute of Technical Standards and Certification (ICONTEC). GeoPark was the second private company to get this certification in Colombia, allowing us to draw a roadmap to reduce our emissions of greenhouse gases and help the country meet the commitment it took on at the 2015 United Nations Climate Change Conference.
In 2018, the Colombian government granted GeoPark the “Best Social Practices in the Energy Industry” award for our good neighbor social conflict prevention program. GeoPark’s model for community engagement was chosen out of 107 different initiatives by a panel composed of representatives from the Ministry of Mines and Energy, the National Hydrocarbons Agency and the United Nations Development Program. In 2019, we won the “Best Social Practices in the Energy Industry” award for the second year in a row, along with the “Best Socio-Laboral Practices” award, for our “Juntos Sumamos” program. Once again in 2021 we won the “Best Social Practices in the Energy Industry” award through our ‘Viviendas Sostenibles’ housing program that improves the living conditions and welfare of our Casanare and Putumayo neighbors. The jury was composed of public sector members and representatives from academic and multilateral organizations. The award was determined based on the impact of each initiative, its sustainability efforts, innovation and relation to the 2030 agenda.
In spite of physical distancing due to the COVID-19 pandemic, in 2021 we kept in permanent contact with the local communities in which we operate, contributing to food security for vulnerable households and supporting local and national authorities’ efforts to halt the spread of the virus.
In 2019, we joined the Equipares gender equality certification program, an initiative of the Colombian government and the United Nations Development Program (UNDP) focused on achieving parity in the workplace. In 2020, we created a standing company-wide committee to implement action plans that encourage and sustain the values of equity, inclusion and diversity. In 2020, we reported for the first time our gender equality metrics using the Bloomberg Gender Reporting Framework. In 2021 we achieved the Equipares Silver Seal, after the Colombian Institute of Technical Standards and Certification (ICONTEC) gave a 91/100 rating to our SGIG (Gender Equality Management System).
In January 2022 GeoPark was added to the Bloomberg Gender-Equality Index, including companies with best-in-class gender-related practices and policies. In January 2021, we participated in but were not included due to our market capitalization, but we were highlighted nevertheless for our score.
46
In 2021, we reported our S.P.E.E.D. and Environment, Social and Governance metrics according to the Global Reporting Initiative (GRI) standards as well as the sustainability reporting guide of the Global Oil and Gas Association for Advancing Environmental and Social Performance (IPIECA, 2020) and the Sustainability Accounting Standards Board (SASB, 2018).
Among the material sustainability topics included in our 2020 S.P.E.E.D. and ESG report are: safety and health management, supply chain management, stakeholder relations, legal compliance, employee development and training, integrated water resources management, energy efficiency, emissions management, biodiversity protection, social risk assessment, and relationship with indigenous communities.
On March 26, 2021, we received a rating of BBB (on a scale of AAA-CCC) in the MSCI ESG Ratings assessment. We progressed from B in 2018 to BBB in 2021. The improvement in ratings was principally due to governance and greenhouse gas emission plan. The 2021 upgrade was based on our improvements in Health & Safety and Carbon Emissions.
Our approach on human rights seeks to conduct business in a way that is consistent with the UN Guiding Principles on Business and Human Rights (the “UN Guiding Principles”), the ten UN Global Compact Principles and the Voluntary Principles on Security and Human Rights. Our commitment to the Voluntary Principles on Security and Human Rights is reflected in our S.P.E.E.D. program, as well as in all our policies and procedures. Human rights aspects are integrated into relevant internal management processes, tools, and trainings. On-going activities, business relationships and new business opportunities are assessed for potential human rights impacts and aspects, following a risk-based approach, with continued efforts to strengthen the diversity of our workforce, considering gender, nationality, background, ethnicity, competence, age and preferences.
In 2021, we continued the strengthening of our processes for managing human rights in our supply chain and on raising awareness. A compliance appendix, covering human rights and anti-corruption standards for suppliers, was introduced for all material contracts.
On October 13, 2021, five United Nations rapporteurships on human rights matters, coordinated by the working group on the issue of human rights and transnational corporations and other business enterprises, delivered to our Chief Executive Officer a letter under the special procedures of the United Nations Human Rights Council, to request: i) clarification on the information received from the Siona Buenavista Indigenous community, located in Puerto Asis, Putumayo, related with human rights alleged violations and, ii) information on the Human Rights Due Diligence procedures, policies, processes and actions implemented by us to prevent, mitigate and remediate human rights violations within its operations.
On December 7, 2021, we replied to the letter received from the UN Special Procedures Secretariat dated October 13, 2021, providing information on each of the matters addressed therein.
On December 14, 2021, and January 4, 2022, the chancelleries of Chile and Colombia submitted their reply to the United Nations Human Rights Council letter, respectively.
In February 2022, we met with the Latin American representative to the UN Working Group on Business and Human Rights, to establish direct contact with this group, which will enable further communication as may be required.
Transparency, ethics and anti-corruption
Transparency is a cornerstone of good governance. It is embodied in our corporate values. Transparency allows business to prosper in a predictable and competitive environment. We believe that doing business in an ethical and transparent manner is a prerequisite for sustainable business. We have zero-tolerance policy towards all forms of corruption. This policy is embedded across our Company through our corporate values, our Code of Conduct (Our Code), and our Compliance Program. They prohibit all forms of corruption and bribery and reflects our values and our commitment to high ethical standards in business activities; they apply to all our employees, board members and third parties.
47
We support and engage in global transparency initiatives through our membership in the Extractive Industries Transparency Initiative (EITI). Since 2018, we have actively participated in the Colombian EITI initiative and taken part of a multi-stakeholder working group organized by Transparency International Colombia in preparation of the report.
Highly committed founding shareholdersshareholder and technical and management teams with proven industry expertise and technically-driven culture
Our founding shareholders, managementManagement and operating teams have significant experience in the oil and gas industry and a proven technical and commercial performance record in onshore fields, as well as complex projects in Latin America and around the world, including expertise in identifying acquisition and expansion opportunities. Moreover, we differentiate ourselves from other E&P companies through our technically-driven culture, which fosters innovation, creativity and timely execution. Our geoscientists, geophysicists and engineers are pivotal to the success of our business strategy, and we have created an environment and supplied the resources that enable our technical team to focus its knowledge, skills and experience on finding and developing oil and gas fields.
In addition, we strive to provide a safe and motivating workplace for employees in order to attract, protect, retain and train a quality team in the competitive marketplace for capable energy professionals.
Our CEO, Mr. James F. Park, has been involved in E&P projects in Latin America since 1978. He has been closely involved in grass-roots exploration activities, drilling and production operations, surface and pipeline construction, legal and regulatory issues, crude oil marketing and transportation and capital raising for the industry. As of March 15, 2019,12, 2022, Mr. Park held 13.2%14.0% of our outstanding common shares.
Our Chairman, Mr. Gerald O’Shaughnessy, has been actively involved in the oil and gas business internationally and in North America since 1976. As of March 15, 2019, Mr. O’Shaughnessy held 11.5% of our outstanding common shares.
Our management and operating team hashave an average experience in the energy industry of more than 25 years in companies such as Chevron, ENAP, Petrobras, Pluspetrol, San Jorge, Total and YPF, among others. Throughout our history, our management and operating team has had success in unlocking unexploited value from previously underdeveloped assets.
In addition, as of March 15, 2019,12, 2021, our executive directors and key management (excluding one of our founding shareholders, Mr. Gerald E. O’Shaughnessy and Mr. James F. Park) owned 30.7%2.1% of our outstanding common shares, aligning their interests with those of our shareholders and helping retain the talent we need to continue to support our business strategy. See “Item 6. Directors, Senior Management and Employees—B. Compensation.” OurOne of our founding shareholders areis also involved in our daily operations and strategy.
Technically-driven culture and capitalization of local knowledge
We intend to continue to pursue strategies that maximize value. For this purpose, we intend to continue expanding our technical teams and to foster a culture that rewards talent according to results. For example, we have been able to maintain the technical teams we inherited through our Colombian and Brazilian acquisitions. We believe local technical and professional knowledge is key to operational and long-term success and intend to continue to secure local talent as we grow our business in different locations.
Innovation
We are committedcontinuously looking for opportunities to an innovation culture driven by the continuous searchinnovate driving efficiency, employee productivity, engagement, collaboration, communication, and application of state-of-the-art technologies, agile processes and creative new solutions to challengesdecision-making leveraging technology in both our fields and our offices. Our guiding principle is that everyone can innovate, and this is promoted through a cross-collaborative and trust-based work environment. To ensure that this is taken as a key priority, as of 2018 we have included innovation as oneall areas of our metrics in our Balanced Scorecard and have allocated seed money in our annual budget to kick-start new projects. As an example of the success we have had, in 2018 we were awarded a prize for innovative road safety measures by the Colombian Council of Security. Additionally,organization. We believe we have successfully incorporated new digital capabilities like artificial intelligence, machine learning, internet of things, big data, automation and cloud computing. During 2021, we implemented multiple new technology-basedmore than 40 innovative initiatives with top partners like Microsoft, Google, Halliburton, Cisco, SAP, among others. The following are some of the projects that have been part of or innovation culture:
| ● | Digital drilling: We automated the drilling platforms using sophisticated technology with partners such as Halliburton, aimed at increasing the rate of penetration and reducing costs focused on non-production time and unplanned events based on information from the drillers. During our drilling operations, our platform |
48
| helps the operation make quicker, smarter decisions to stay on plan and achieve predictable results consistently. The digital drilling transformation program is on track and is expected to be fully implemented by the first semester of 2022. |
| ● | Hydraulic stimulation: We implemented hydraulic stimulation techniques to increase productivity of low-performance wells (Jacana 33 and Jacana 44 in Llanos 34 Block in Colombia) and we are expecting results by the first semester of 2022. |
| ● | ESP failure prediction: During the second semester of 2021, we embraced the challenge to create a model using artificial intelligence and machine learning to predict failures of the electro submersible pump platforms with positive results. Following its successful implementation, we expect to continue using this technology during 2022. |
| ● | Separation of mercury from oil: We implemented a chemical treatment process of the crude produced in the Fell Block to reach the mercury content specification for sales. We expect this to generate positive results during the first semester of 2022. |
| ● | Micro-bubble: We embraced the challenge to implement a simplified crude water separation process by incorporating the micro-bubble generation technology in the skim tank that allows increasing efficiencies in the removal of fats and oils to values greater than 90%, allowing us to reduce the use of chemicals in the treatment and elimination of flotation cell equipment. If the results continue to be positive in the short term, we expect to expand our use of this technology on a large scale by 2022. |
| ● | Transition to cloud and enhanced cyber security: A successful transition to cloud has been implemented with sophisticated security controls based on end point response technology, firewalls, and software protections. This project has helped to boost productivity taking advantage of cloud services. We also implemented a data interconnection platform based on SDWAN software that allows our offices to be connected and at the same time with Microsoft Azure clouds, reducing MPLS interconnection services costs significantly. |
Other innovation projects such as cryobox virtual gas technology in Neuquén Province, in Argentina,the optimization and implementation of water disposal, oil data capture, electrical reliability, artificial intelligence for geologists, automation of critical processes and data portals are part of the Digital Innovation roadmap that we intend to put intoadvance going forward. We continue to look for opportunities that drive efficiency, mitigate risk, reduce costs, and increase production using internal and external talent with advanced technology.
For a well that was previously shut-in due to a lackmore in-depth discussion of facilities,our 2021 results, liquidity and a gas based artificial lift system for mature wells in Chile that results in low maintenance costs.its capital resources, please see “Item 5—Operating and Financial Review and Prospects”.
20192022 Strategy and Outlook
Oil prices have been volatile sinceover the end of 2014.past years. In preparation for continued volatility and the prolonged effects of the COVID-19 pandemic, we have developed multiple scenarios for our 20192022 capital expenditure program.
Our preliminary base capital program for 2019 considers2022 considered a reference oil price assumption of US$7065-70 per barrel and callscalled for approximately US$220-240160-180 million to fund our exploration and development which we intend to fund through cash flows from operations and cash-in-hand, to be allocated approximately as follows:
| Colombia: US$ |
| ● | Ecuador: US$13-17 million. Focus on two or three gross exploration |
| Espejo block and one or two in the Perico block plus the acquisition of 60 square kilometers of 3D seismic in the Espejo block. |
49
| Other activities in Putumayo and Chile: US$ |
In addition, we have developed downside and upside work program scenarios based on different oil prices and project performance. The downside scenario work program considers a reference oil price assumption below US$6550 per barrel and consists of an alternative capital expenditure program of approximately US$120 million-US$140150 million consisting mainly of certain low risk and quick cash flow generating projects. The upside scenario work program considers a reference oil price assumption above US$7580 per barrel or higher and consists of an alternative capital expenditure program of approximately US$240190 million-US$270220 million to be selected from identified projects designed to increase reserves and production.
In order to secure minimum oil prices for our 2022 production and beyond, we have commodity risk management contracts in place covering a portion of our production for 2022 and 2023 and monitor market conditions on a continuous basis to evaluate additional new commodity risk management contracts for the future.
Additionally, we continue to monitor the potential impact of the COVID-19 pandemic and the oil price volatility as a result of the armed conflict in Ukraine on our financial condition, cash flows and results of operations.
Our operations
We have a well-balanced portfolio of assets that includes working and/or economic interests in 2542 hydrocarbon blocks, 2441 of which are onshore blocks, including 10 in production as of December 31, 2018,2021.
Our well-balanced portfolio of assets provides the ability to quickly optimize capital allocation as well as in anmarket conditions change. The current crisis, however, is still evolving and may become more severe and complex. For additional shallow-offshore concession in Brazil that includesinformation about the Manati Field. In addition, we have one concession in Brazil, the PN-T-597 Block, that is subjectbusiness risks relating to the entry intoCOVID-19 pandemic and related governmental actions, See “Item 3. Key Information—D. Risk factors—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 concession agreement byglobal economy, and the ANPdemand for and one concession in Argentina, the Parlamentos Block, that remains subject to regulatory approval asprices of oil and natural gas. The unprecedented nature of the date of this annual report.current situation 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”.
Operations in Colombia
OurAs of December 31, 2021, our Colombian assets currently givegave us access to more than 244,9003,690,000 gross exploratory and productive acres across 623 blocks in what we believe to be one of South America’s most attractive oil and gas geographies.
Since we entered Colombia in 2012, we have achieved consistent growth inand we were able to maintain our oil production and proved reserves, in Colombia, mainly achieved through successful exploration and development activities we made at our operated Llanos 34 Block, which as of December 31, 20182021 accounts for 95%81% of our production and 97%88% of our proved reserves in Colombia.
The table below shows average production and proved oil and gas reserves (derived from D&M Reserves Report) in Colombia for the years ended December 31, 2018, 20172021, 2020 and 2016:2019:
| 2018 | 2017 | 2016 | ||||||||||||||||
| Average net production (mboepd) | 28.4 | 21.8 | 15.5 | |||||||||||||||
| | | | | | | ||||||||||||
|
| 2021 |
| 2020 |
| 2019 | ||||||||||||
Average net oil production (mboepd) |
| 30.9 |
| 33.0 |
| 32.1 | ||||||||||||
| Net proved reserves at year-end (mmboe) | 75.1 | 65.5 | 37.3 |
| 79.0 |
| 89.3 |
| 91.0 | |||||||||
Highlights of the year ended December 31, 20182021 related to our operations in Colombia included:
50
| ● | We were awarded with the Equipares Silver Award by Colombian Ministry of Labor, for our commitment to promote equality, inclusion and diversity; |
| ● | In September 2021, we were included in the S&P Colombia BMI, to continue expanding our investor base; |
| ● | The Colombian government awarded us a first prize for the Company’s “Viviendas Sostenibles” initiative, as part of the “Significant Experiences Program” that recognizes sustainability best practices in the mining and energy industries; |
| ● | Drilling campaign with |
| ● | Completed 250 and 112 sq. km. of 3D seismic acquisitions in the CPO-5 and PUT-8 Blocks respectively, in the second quarter of 2021; |
| ● | Recent successful results in the Tigui area in Llanos 34 Block, expanding field limits and opening new drilling opportunities; |
| ● | Successful drilling of the Jacana 49 development in Llanos 34 Block in November 2021. The well shows higher productivity rates and improved reservoir conditions than neighboring wells, opening new drilling opportunities that will be tested in 2022. Jacana 49 is located close to the southwest limits of the field and 1.7 km. from the CPO-5 Block; |
| ● | Successfully drilling of the Alea Oeste 1 development well in Platanillo Block, with completion and testing |
| Proved oil and gas reserves |
| Capital expenditures increased by |
Our interests in Colombia include working interests and economic interests. “Working interests” are direct participation interests granted to us pursuant to an E&P Contract with the ANH, whereas “economic interests” are indirect participation interests in the net revenues from a given block based on bilateral agreements with the concessionaires.
51
The map below shows the location of the blocks in Colombia in which we have working and/or economic interests.
| (1) |
| On February 23, 2021, we requested the termination of the contract due to the occurrence of force majeure events relating to legal proceedings commenced by ethnic communities. This request is subject to ANH approval as of the date of this annual report. |
52
The table summarizes information about the blocks in Colombia in which we have working interests as of and for the year ended December 31, 2018.2021.
| Block | Gross acres (thousand acres) | Working | Partners(2) | Operator | Net proved | Production (boepd) | Basin | Concession expiration year | ||||||||||||||||||
| Llanos 34 | 82.2 | 45 | % | Parex | GeoPark | 72.5 | 27,219 | Llanos | Exploration: 2019 Exploitation: 2039-2042(4) | |||||||||||||||||
| La Cuerva | 24.5 | 100 | % | — | GeoPark | 1.2 | 606 | Llanos | Exploitation: 2038 | |||||||||||||||||
| Yamú | 5.6 | 100 | % | — | GeoPark | 1.0 | 375 | Llanos | Production: 2036 | |||||||||||||||||
| Llanos 32 | 57.0 | 12.5 | % | Parex | Parex | 0.4 | 306 | Llanos | Exploitation: 2039 | |||||||||||||||||
| VIM-3 | 48.9 | 100 | % | — | GeoPark | — | — | Magdalena | Exploration: 2021 Exploitation: 2045 | |||||||||||||||||
| | | | | | | | | | | | | | | | |
|
| Gross acres |
| |
| |
| |
| Net proved |
| |
| |
| |
| | (thousand | | Working | | | | | | reserves | | Production | | | | Concession |
Block | | acres) | | interest(1) | | Partners(2) | | Operator | | (mmboe) | | (boepd) | | Basin | expiration year | |
Llanos 34 |
| 63.5 |
| 45 | % | Verano Energy |
| GeoPark |
| 69.6 |
| 25,187 |
| Llanos |
| Exploitation: 2039-2045(3) |
Llanos 32 |
| 50.2 |
| 12.5 | % | Verano Energy |
| Verano Energy |
| 2.4 |
| 456 |
| Llanos |
| Exploration: 2022 |
| | | | | | | | | | | | | | | | Exploitation: 2040-2045(3) |
VIM-3 |
| 46.9 |
| 100 | % | — |
| GeoPark |
| — |
| — |
| Magdalena |
| In process of termination |
Llanos 86 | | 255.5 | | 50 | % | Hocol | | GeoPark | | — | | — | | Llanos |
| Phase zero(4) |
Llanos 87 | | 107.6 | | 50 | % | Hocol | | GeoPark | | — | | — | | Llanos | | Exploration: 2023 |
Llanos 104 | | 274.8 | | 50 | % | Hocol | | GeoPark | | — | | — | | Llanos | | Phase zero(4) |
Llanos 123 | | 88.3 | | 50 | % | Hocol | | GeoPark | | — | | — | | Llanos | | Exploration: 2024 |
Llanos 124 | | 27.6 | | 50 | % | Hocol | | GeoPark | | — | | — | | Llanos | | Exploration: 2024 |
Llanos 94 | | 89.2 | | 50 | % | Parex | | Parex | | — | | — | | Llanos | | Exploration: 2023 |
Andaquíes | | 114.9 | | 100 | % | — | | GeoPark | | — | | — | | Putumayo | | In process of termination |
Coatí | | 61.8 | | 100 | % | — | | GeoPark | | — | | — | | Putumayo | | Exploration: Currently suspended |
CPO-5 | | 490.8 | | 30 | % | ONGC Videsh | | ONGC Videsh | | 5.1 | | 3,722 | | Llanos | | Exploration: 2022 |
| | | | | | | | | | | | | | | | Exploitation: 2042 |
Mecaya | | 74.1 | | 50 | % | Sierracol Energy | | GeoPark | | — | | — | | Putumayo | | Exploration: Currently suspended |
Platanillo | | 27.3 | | 100 | % | — | | GeoPark | | 1.9 | | 1,766 | | Putumayo | | Exploitation: 2033(3) |
PUT-8 | | 102.8 | | 50 | % | Sierracol Energy | | GeoPark | | — | | — | | Putumayo | | Exploration: 2022 |
PUT-9 | | 121.5 | | 50 | % | Sierracol Energy | | GeoPark | | — | | — | | Putumayo | | Exploration: Currently suspended |
PUT-12 | | 134.5 | | 60 | % | Pluspetrol | | GeoPark | | — | | — | | Putumayo | | In process of termination |
PUT-14 | | 114.6 | | 100 | % | — | | GeoPark | | — | | — | | Putumayo | | Phase zero(4) |
PUT-30 | | 95.2 | | 100 | % | — | | GeoPark | | — | | — | | Putumayo | | In process of termination |
PUT-36 | | 148.0 | | 50 | % | Sierracol Energy | | GeoPark | | — | | — | | Putumayo | | Exploration: Currently suspended |
Tacacho | | 589.0 | | 50 | % | Sierracol Energy | | GeoPark | | — | | — | | Putumayo | | Exploration: Currently suspended |
Terecay | | 586.6 | | 50 | % | Sierracol Energy | | GeoPark | | — | | — | | Putumayo | | Exploration: Currently suspended |
| (1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in |
| (2) | Partners with working interests. |
| (3) |
| The concession expiration year is set on a field by field basis. |
| (4) | In this phase the Ministry of Interior must certify the presence or absence of indigenous communities and carry out a prior consultation process, if applicable. Only when this process has been completed and the corresponding regulatory approvals have been obtained, the blocks will enter into Phase 1, where the exploratory commitments become mandatory. |
The table summarizes information about the blocks in Colombia in which we have economic interests as of and for the year ended December 31, 20182021
| Block | Gross acres (thousand acres) | Economic | Operator | Production (boepd) | Basin | |||||||||||
| Abanico | 26.7 | 10 | % | Pacific | 39 | Magdalena | ||||||||||
| | | | | | | | | | |
|
| Gross acres |
| |
| |
| |
| |
| | (thousand | | Economic | | | | Production | | |
Block | | acres) | | interest(1) | | Operator | | (boepd) | | Basin |
Abanico |
| 25.7 |
| 10 | % | Frontera |
| 19 |
| Magdalena |
(1) | Economic interest corresponds to indirect participation interests in the net revenues from the block, granted to us pursuant to a joint operating agreement. |
53
Eastern Llanos Basin: (Llanos 34, La Cuerva, Yamú, Llanos 32, Abanico, and VIM-3 Blocks)
The Eastern Llanos Basin is a Cenozoic Foreland basin in the eastern region of Colombia. Two giant fields (Caño Limón and Castilla), three major fields (Rubiales, Apiay and Tame Complex) and approximately fifty minor fields had been discovered. The source rock for the basin is located beneath the east flank of the Eastern Cordillera, as a mixed marine-continental shale basinal facies of the Gachetá formation. The main reservoirs of the basin are represented by the Paleogene Carbonera and Mirador sandstones. Within the Cretaceous sequence, several sandstones are also considered to have good reservoirs.
Llanos 34 Block. We are the operator of, and have a 45% working interest in, the Llanos 34 Block, which covers approximately 82,20063,529 gross acres (333(257 sq. km)km.). We acquired an interest in and took operatorship of the block in the first quarter of 2012, which at that time had no production, reserves or wells drilled on it, and with 210 sq. kmkm. of existing 3D seismic data on which our team had mapped multiple exploration prospects. From 2012 to 20182021 we engaged in exploration and development activities that resulted in multiple10 new oil fields discovereddiscoveries and increased production and proved reserves and oil production year by year.year up to a peak oil production of 34,995 bopd. Average net production in 20182021 was 27,21925,187 bopd and net reserves of 72.569.6 mmboe. By the end of 2021, we have drilled more than 160 wells, with 139 producer wells that have accumulated more than 139 million barrels of oil. The remainingLlanos 34 Block has three reservoirs: the Guadalupe Formation, which produces 88% of our oil production in the Block, Mirador, which produces 11% of our oil production in the Block and Gacheta, which produces 1% of our oil production in the Block, with an API gravity between 13° and 30.6°. During these 10 years of operation in Llanos 34 Block, we have built all the required infrastructure to produce and manage the fluids of the assets, including 10 production facilities, 24 kilometers of power grid, more than 45 kilometers of flowlines for fluid transfer, 136 kilometers of roads and a 42 kilometers oil pipeline. In December 2020, we connected the Tigana field in the Llanos 34 Block to the ODCA pipeline in, further reducing truck traffic, contributing to further reduce operational risk, costs and carbon emissions. As of the date of this annual report, outstanding investment commitments of US$17.4 million related to this block correspond to the drilling of 3 exploratory wells before November 10, 2021. Due to a private agreement with the partner in the block, the investment commitment incurred by us amounts to US$1.9 million at our working interest.
12.8 million. As of the date of this annual report, we had already drilled the three exploratory wells and are waiting for ANH’s approval to fulfill the investment commitment.
Our partner in the Llanos 34 Block is Parex,Verano Energy (a subsidiary of Parex), which has a 55% interest. See “—Our operations.” We operate in the block pursuant to an E&P Contract with the ANH. See “—Significant Agreements—Colombia—E&P Contracts—Llanos 34 Block E&P Contract.”
La Cuerva Block. We are the operator of, and have a 100% working interest in, the La Cuerva Block, which covers approximately 24,500 gross acres (99.1 sq. km). Average net oil production in 2018 was 606 bopd. We operate in the block pursuant to an E&P Contract with the ANH. On November 2, 2018 we executed a Sale Purchase Agreement with Perenco to sale the 100% working interest in the La Cuerva Block. Closing of the transaction is subject to customary regulatory approvals, which are expected to occur during 2019.
Yamú Block. We are the operator of, and have a 100% working interest in, the Yamú Block, which covers approximately 5,588 gross acres (22.6 sq. km). For the year ended December 31, 2018, our average net production was 375 bopd. On November 2, 2018 we executed a Sale Purchase Agreement with Perenco to sale the 100% working interest in the Yamú Block. Closing of the transaction is subject to customary regulatory approvals, which are expected to occur during 2019.
Llanos 32 Block. We have a 12.5% working interest in the Llanos 32 Block, as a result of our acquisition of an additional 2.5% interest on August 22, 2017.Block. The Llanos 32 Block covers approximately 57,00050,211 gross acres (230.7(203 sq. km)km.). ParexVerano Energy is the operator of this block and has aan 87.5% working interest. Since 2015, the operator focused on the commissioning of a gas facility on this block to produce natural gas and light crude oil from the Une formation and to facilitate shipment of processed gas south to the adjacent Llanos 34 Block. For the year ended December 31, 2018,2021, our average net production in the Llanos 32 Block was 306456 bopd. The remaining commitmentAs of the date of this annual report, outstanding investment commitments related to this block is to drill one exploratory well before August 2018 was already fulfilled. On February 19, 2019 the partiescorrespond to the Llanos 32 contract requested ANHdrilling of 5 exploratory wells before February 20, 2022. Due to grant an extension of one year to phase 2 of the subsequent exploratory program in order to drill an exploratory well amounting to US$ 4.7 million gross subject to ANH approval. We executed ana private agreement with Parex by which we obtained a 25% working interestthe partner in the remaining exploration areas ofblock, the block.
VIM-3 Block.On July 23, 2014 we were awarded an exploratory license during the 2014 Colombia Bidding Round, carried outinvestment commitment incurred by the ANH. We are entitledus amounts to operate the block, in which we have a 100% working interest. The VIM-3 Block is located in the Lower Magdalena Basin. Our winning bid consisted of committing to a Royalty X Factor of 3% and a minimum investment program of 200 sq. km of 2D seismic data acquisition and drilling one exploratory well, with a total estimated investment of US$22.3 million during the initial exploratory period ending February 2019. On June 21, 2017, the ANH approved our relinquishment of 79.15% of the VIM 3 Block area. The remaining area covers 48,950 acres and the commitments described above are not affected. On September 12, 2018, the ANH accepted our proposal to extend the first exploratory phase for an additional period ending May 12, 2019. Additionally, we requested the ANH to terminate the E&P Contract due to environmental restrictions in the block. These restrictions became apparent once the National Authority of Environmental Licenses (ANLA) issued the environmental license.9.2 million. As of the date of this annual report, the termination requestfive exploratory wells have already been drilled and ANH approval of the fulfillment of the investment commitment is under review and the remaining commitment amounts to US$22.3 million.
pending.
Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block association contract. Pacific Rubiales Energy is the operator of, and has a 100% working interest in, the Abanico Block, which covers an area of approximately 26,65825,658 gross acres (103 sq. km)km.). We do not maintain a direct working interest in the Abanico Block, but rather have a 10% economic interest in the net revenues from the block pursuant to a joint operating agreement initially entered into with Kappa Resources Colombia Limited (now Pacific, who subsequently assigned its participation interest to Cespa de Colombia S.A., who then assigned the interest to Explotaciones CMS Oil & Gas), Maral Finance Corporation and Getionar S.A.
Llanos 86 and Llanos 104 Blocks. We and Hocol (a subsidiary of Ecopetrol), each with fifty percent (50%) working interest executed an E&P contract over these blocks on July 11, 2019, as a result of the Permanent Competitive Process launched by ANH in 2019. We are the operator of these contracts that are in its exploratory phase 1 as of the date of this
54
annual report and cover approximately 530,309 gross acres (2,146 sq. km.). We have requested the Ministry of Interior to certify if there are indigenous communities present in the area and the Ministry confirmed the presence of such communities. Therefore, we conducted the due prior consultation process with the communities. On March 15, 2022 the prior consultation process concluded, and the contract entered into exploratory phase 1 in which the commitments are: acquisition of 3D seismic, reprocessing of 2D seismic and drilling of two exploratory wells for an estimated amount of US$9.5 million for Llanos 86 Block and US$8.4 million for Llanos 104 Block as of the date of this annual report.
Llanos 87 Block. GeoPark and Hocol, each with fifty percent (50%) working interest executed an E&P contract over this block on July 11, 2019, as a result of the Permanent Competitive Process launched by ANH in 2019. The Ministry of Interior certified the absence of indigenous communities in the area. We are the operator of this contract that is currently in exploratory phase 1 and covers approximately 107,624 gross acres (435 sq. km.). Phase 1 commitments are reprocessing of 3D seismic, drilling of four exploratory wells and acquisition of aero geophysics before January 18, 2023, with an estimated amount of US$13.2 million as of the date of this annual report.
Llanos 123 and Llanos 124 Blocks: GeoPark and Hocol, each with fifty percent (50%) working interest executed an E&P contract over these blocks on December 20, 2019, as a result of the Permanent Competitive Process launched by ANH in 2019. We are the operator of these contracts that covers approximately 115,956 gross acres (469 sq. km.). As of the date of this annual report, outstanding investment commitments of US$16.8 million related to these blocks correspond to (i) reprocessing 3D seismic, acquiring geochemistry and drilling of two exploratory wells for Llanos 123 Block with an estimated amount of US$6.8 million before January 14, 2024, and; (ii) the acquisition of 3D seismic, reprocessing of 3D seismic, acquisition of geochemistry and drilling of three exploratory wells for Llanos 124 Block with an estimated amount of US$10.0 million before January 14, 2024.
Llanos 94 Block. On July 24, 2019, the E&P contract was awarded to Parex Energy as a result of the Permanent Competitive Process launched by ANH in 2019. This contract is in its exploratory phase 1 and covers approximately 89,175 gross acres (360.8 sq. km.). We acquired a 50% working interest from Parex and obtained ANH’s approval to such transfer in May, 2020. As of the date of this annual report, outstanding investment commitments of US$10.9 million related to this block correspond to the acquisition of 3D seismic, reprocessing of 3D seismic and drilling of 3 exploratory wells before October 1, 2023.
CPO-5 Block. On December 26, 2008, the E&P Contract was executed between ONGC Videsh, as operator and the ANH as a result of the Competitive Process “Ronda Colombia 2008”. This contract covers approximately 490,825 gross acres (1,986 sq. km.). We hold a 30% working interest since the acquisition of Amerisur. As of the date of this annual report this contract is in exploratory phase 2 in which the pending commitment correspond to the acquisition, processing and interpretation of 230 sq. km. of 3D seismic for an amount of US$2.8 million before July 8, 2024. There are two commercial fields called Mariposa and Indico. Average net production in 2021 was 3,722 bopd and net reserves were 5.1 mmboe.
Magdalena Basin:
VIM-3 Block. On July 23, 2014, we were awarded an exploratory license during the 2014 Colombia Bidding Round, carried out by the ANH. The VIM-3 Block is located in the Lower Magdalena Basin. In 2018, we filed a request before the ANH to terminate the E&P Contract due to environmental restrictions in the block. These restrictions became apparent once the National Authority of Environmental Licenses issued the environmental license. As of the date of this annual report, the termination was approved by the ANH with a remaining commitment for an amount of US$9.3 million, which were transferred to CPO-5 Block in Colombia. As of the date of this annual report, the relinquishment of the Block is still pending.
Putumayo Basin:
Andaquies Block. We are the operator of and have a 100% working interest in the Andaquies Block, which covers approximately 114,879 gross acres (465 sq. km.). As of the date of this annual report the contract is in phase 3 of the exploration period. On February 14, 2020, we presented our withdrawal from the E&P Contract and requested the ANH
55
to approve the transfer of the pending commitments to the Llanos 32 Block. On February 20, 2020, the ANH approved the request. We and the ANH already began the process of relinquishment of the E&P Contract and its subsequent liquidation.
Coati Block. We are the operator of and have a 100% working interest in the Coati Block, which covers approximately 61,843 gross acres (250 sq. km.). As of the date of this annual report the contract is in phase 3 of the exploration period, which exploration commitment consists of the acquisition of 57 sq. km. of 3D seismic and 30 km. of 2D seismic, for an estimated amount of US$4.5 million. Furthermore, on September 2006, the former operator declared an Evaluation Area and presented an Evaluation Program in the southern part of the Block for the Temblon wells (Temblon Evaluation Program), which includes the completion and evaluation of the Coatí-1 well. Both, the phase 3 and the Temblon Evaluation Program, are currently suspended due to force majeure events (relating to prior consultations).
Mecaya Block. We are the operator of and have a 50% working interest in the Mecaya Block, which covers approximately 74,128 gross acres (300 sq. km.). Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this annual report, the contract is in unified phases 1 and 2 of the exploration period, which remaining exploration commitment consists of the acquisition of 52.2 sq. km. of 3D seismic for an amount of US$0.6 million. On December 2010, the former operator declared an evaluation area and presented an evaluation program for the Mecaya-1 well (Mecaya Evaluation Program). Both the unified phases 1 and 2 and the evaluation program are currently suspended due to force majeure events (relating to prior consultations).
Platanillo Block. We are the operator of and have a 100% working interest in the Platanillo Block, which covers approximately 27,300 gross acres (110 sq. km.). On September 11, 2009, we began the commercial exploitation of the Platanillo Block (Alea 1 and Platanillo 2 wells, began). Average net production in 2021 was 1,766 bopd and net reserves of 1.9 mmboe.
Putumayo 8 Block. We are the operator of and have a 50% working interest in the Putumayo 8 Block, which covers approximately 102,800 gross acres (416 sq. km.). Sierracol Energy is the owner of the remaining 50% working interest. The contract is in unified phases 1 and 2 of the exploration period. As of the date of this annual report, outstanding investment commitments of US$13.1 million related to this block correspond to the drilling of 3 exploratory wells and the acquisition of 112 sq. km. of 3D seismic before July 5, 2023.
Putumayo 9 Block. We are the operator of and have a 50% working interest in the Putumayo 9 Block, which covers approximately 121,453 gross acres (492 sq. km.). Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this annual report, the contract is in phase 1 of the exploration period and outstanding investment commitments of US$4.4 million related to this block correspond to drilling of two exploratory wells before October 14, 2020, and the acquisition of 126.25 sq. km. of 3D seismic. Phase 1 was suspended on June 25, 2019, due to the occurrence of a force majeure event consisting of the issuance of the Municipal Agreement No. 007 of Puerto Guzmán, which prohibits the hydrocarbon exploration and production activities in such municipality.
Putumayo 12 Block. We are the operator of and have a 60% working interest in the Putumayo 12 Block, which covers approximately 134,534 gross acres (544 sq. km.). Pluspetrol Colombia Corporation (“Pluspetrol”) is the owner of the remaining 40% working interest. As of the date of this annual report, the contract is in phase 1 of the exploration period, and outstanding investment commitments of US$14.4 million related to this block consist of the drilling of one exploratory well, the acquisition of 131 km. of 2D seismic, and the acquisition of geochemistry before November 29, 2021. On February 23, 2021, we requested the termination of the contract due to the occurrence of force majeure events related with judicial procedures initiated by ethnic communities.
Putumayo 14 Block. We are the operator of and have a 100% working interest in the Putumayo 14 Block, which covers approximately 114,560 gross acres (464 sq. km.). The contract is in phase 0, as the applicable prior consultation process must be completed. The Ministry of Interior certified the presence of two indigenous communities for the execution of the seismic commitment for phase 1. Prior consultations with the two ethnic communities are ongoing. Phase 1 commitments consist of the acquisition of 98 km. of 2D seismic and the drilling of one exploratory well for an estimated net amount of US$16.1 million as of the date of this annual report.
56
Putumayo 30 Block. We are the operator of and have a 100% working interest in the Putumayo 30 Block, which covers approximately 95,172 gross acres (385 sq. km.). On February 23, 2021, we submitted to the ANH our request to withdraw from to the E&P contract and transfer the remaining commitments to other E&P contracts. The ANH approved the request. The remaining investment was transferred to Llanos 34 Block and Platanillo Block. The contract is in process of termination as of the date of this annual report.
Putumayo 36 Block. We are the operator of and have a 50% working interest in the Putumayo 36 Block, which covers approximately 148,021 gross acres (599 sq. km.). Sierracol is the owner of the remaining 50% working interest. The contract is in preliminary phase, whereby applicable prior consultation processes must be completed. The Ministry of Interior certified the presence of one indigenous community for the execution of the seismic commitment for phase 1. As of the date of this annual report, the contract is in phase 0 as the applicable prior consultation process must be completed, and outstanding investment commitments of US$9.5 million related to this block consist of the acquisition of 105.6 sq. km. of 3D seismic and the drilling of two exploratory wells. Prior consultation has not been initiated with the ethnic community due to the restrictions that derive from the issuance of Municipal Agreement 007 of Puerto Guzmán. Preliminary phase is suspended due to the occurrence of force majeure events from April 1, 2020, to June 20, 2022.
Tacacho Block. We are the operator of and have a 50% working interest in the Tacacho Block, which covers approximately 589,009 gross acres (2,384 sq. km.). Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this annual report, the contract is in phase 1 of the exploration period, and outstanding investment commitments of US$1.2 million related to this block consist of the acquisition, processing and interpretation of 480 km. of 2D seismic. Phase 1 is suspended due to the occurrence of force majeure events related with social and public order conditions of the area as of the date of this annual report.
Terecay Block. We are the operator of and have a 50% working interest in the Terecay Block, which covers approximately 586,625 gross acres (2,374 sq. km.). Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this annual report, the contract is in phase 1 of the exploration period, and outstanding investment commitments of US$2.9 million related to this block consist of the acquisition, processing and interpretation of 476 km. of 2D seismic. Phase 1 is suspended due to the occurrence of force majeure events related with social and public order conditions of the area as of the date of this annual report.
As per farm-out agreement executed on November 21, 2018, Sierracol Energy shall carry us in certain exploration activities for the Mecaya, PUT-9, Tacacho and Terecay Contracts.
Operations in Chile
Our Chilean assets currently give us access to 808,000716,000 of gross exploratory and productive acres across 54 blocks in a large fully-operated land base across the Magallanes Basin, with existing reserves, production and cash flows.
Our Chilean blocks are located in the provinces of UltimaÚltima Esperanza, Magallanes and Tierra del Fuego in the Magallanes Basin, a proven oil and gas-producing area. As of December 31, 2018,2021, the Magallanes Basin accounted for all of Chile’s oil and gas production. Although this basin has been in production for over 60 years, we believe that it remains relatively underdeveloped.
Substantial technical data (seismic, geological, drilling and production information), developed by us and by ENAP, provides an informed base for new hydrocarbon exploration and development. Shut-in and abandoned fields may also have the potential to be put back in production by constructing new pipelines and plants. Our geophysical analyses suggest additional development potential in known fields and exploration potential in undrilled prospects and plays, including opportunities in the Springhill, Tertiary, Tobífera and Estratos con Favrella formations. The Springhill formation has historically been the source of production in the Fell Block, though the Estratos con Favrella shale formation is the principal source rock of the Magallanes Basin, and we believe it contains unconventional resource potential.
Highlights of the year ended December 31, 20182021, related to our operations in Chile included:
57
| Average net oil and gas production |
| Proved oil and gas reserves decreased by |
| Capital expenditures decreased by |
The map below shows the location of the blocks in Chile in which we have working interests.
58
The table below summarizes information about the blocks in Chile in which we have working interests as of and for the year ended December 31, 2018.2021.
| Block | Gross acres (thousand acres) | Working | Partners | Operator | Net proved | Production (boepd) | Basin | Concession expiration year | ||||||||||||||||||
| Fell | 367.8 | 100 | % | — | GeoPark | 6.8 | 2,708 | Magallanes | Exploitation: 2032 | |||||||||||||||||
| Tranquilo | 92.4 | 50 | %(4) | Pluspetrol
| GeoPark | — | — | Magallanes | Exploitation: 2043 | |||||||||||||||||
| Isla Norte | 97.7 | 60 | % | ENAP | GeoPark | — | — | Magallanes | Exploration: 2021 Exploitation: 2044 | |||||||||||||||||
| Campanario | 144.2 | 50 | % | ENAP | GeoPark | — | — | Magallanes | Exploration: 2021 Exploitation: 2045 | |||||||||||||||||
| Flamenco | 105.9 | 50 | % | ENAP | GeoPark | — | 14 | Magallanes | Exploration: 2021 Exploitation: 2044 | |||||||||||||||||
| | | | | | | | | | | | | | | | |
|
| Gross |
| |
| |
| |
| |
| |
| |
| |
| | acres | | | | | | | | Net proved | | | | | | |
| | (thousand | | Working | | | | | | reserves | | Production | | | | Concession |
Block | | acres) | | interest (1) | | Partners (2) | | Operator | | (mmboe) | | (boepd) | | Basin | | expiration year |
Fell |
| 367.8 |
| 100 | % | — |
| GeoPark |
| 4.2 |
| 2,397 |
| Magallanes |
| Exploitation: 2032 |
Isla Norte |
| 97.7 |
| 60 | % | ENAP |
| GeoPark |
| — |
| — |
| Magallanes |
| Exploration: 2023 |
| | | | | | | | | | | | | | |
| Exploitation: 2044 |
Campanario |
| 144.2 |
| 50 | % | ENAP |
| GeoPark |
| — |
| — |
| Magallanes |
| Exploration: 2023 |
| | | | | | | | | | | | | | |
| Exploitation: 2045 |
Flamenco |
| 105.9 |
| 50 | % | ENAP |
| GeoPark |
| — |
| — |
| Magallanes |
| Exploration: 2021 |
| | | | | | | | | | | | | | |
| Exploitation: 2044 |
| (1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in |
| (2) | Partners with working interests. |
Fell Block
In 2006, we became the operator and 100% interest owner of the Fell Block. When we first acquired an interest in the Fell Block in 2002, it had no material oil and gas production. Since then, we have completed more than 1,100 sq. kmkm. of 3D seismic surveys and drilled 117140 exploration and development wells. In the year ended December 31, 2018,2021, we produced an average of 2,7082,397 boepd, in the Fell Block, consisting of 29% oil.
87% gas.
The Fell Block has an area of approximately 368,000367,800 gross acres (1,488 sq. km)km.) and its center is located approximately 140 kmkm. northeast of the city of Punta Arenas. It is bordered on the north by the international border between Argentina and Chile and on the south by the Magellan Strait.
From 2006 through August 2011, we successfully explored and developed the Fell Block, which allowed us to transition approximately 84% of the Fell Block’s area from an exploration phase into an exploitation phase, which we expect will last through 2032. During the exploration phase, we exceeded the minimum work and investment commitment required under the Fell Block CEOP by more than 75 times. There are no minimum work and investment commitments under the Fell Block CEOP associated with the exploitation phase.
The Fell Block is located in the north-eastern part of the Magallanes Basin. The principal producing reservoir is composed of sandstones in the Springhill formation, at depths of 2,200 to 3,500 meters. Additional reservoirs have been discovered and put into production in the Fell Block—namely, Tobífera formation volcanoclastic rocks at depths of 2,900 to 3,600 meters, and Upper Tertiary and Upper Cretaceous sandstones, at depths of 700 to 2,000 meters.
Our geosciences team identified and developed an attractive inventory of prospects and drilling opportunities for both exploration and development in the Fell Block.
During 2018, we successfully drilled and completed the Jauke X-1 exploration well. The well is in production, and the gas is being sold to Methanex through a long-term gas contract. In addition, we continued to focus on maintaining production levels, and reducing production, operating costs and workover costs.
The Jauke gas field is part of the large Dicky geological structure in the Fell block and has the potential for multiple development drilling opportunities. Petrophysical analysis also indicates hydrocarbon potential in the shallower El Salto formation which will be tested in the future. Our 2019 work plan includes the drilling of an additional well.
The Fell Block also contains the Estratos con Favrella shale reservoir which we believe represents a high-potential, unconventional resource play for shale oil, as a broad area within Fell Block (1,000 sq. km)km.) which appears to be in the oil window for this play.
Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks)
In the first and second quarters of 2012, we entered into three CEOPs with ENAP and Chile granting us working interests in the Isla Norte, Campanario and Flamenco Blocks, located in the center-north of the Tierra del Fuego Province of Chile. We are the operator of all three of these blocks, with working interests of 60%, 50% and 50%, respectively. We believe that these three blocks, which collectively cover 347,700 gross acres (1,407 sq. km)km.) and are geologically contiguous to the Fell Block, represent strategic acreage with resource potential. We have committed to paying 100% of the required minimum investment under the CEOPs covering these blocks, in an aggregate amount of US$101.4 million through the end of the first exploratory periods for these blocks, which includes our covering of ENAP’s investment commitment corresponding to its working interest in the blocks.
Block.
Flamenco Block. We are the operator of, and have a 50% working interest in, the Flamenco Block, in partnership with ENAP. The block covers approximately 105,900 gross acres (428 sq. km)km.). In June 2013, we discovered a new oil and gas field in the block following the successful testing of the Chercán 1 well, the first well drilled by us in Tierra del Fuego. As
59
We have completed 100% ofall the committed 570 sq. km of 3D seismic surveys and the drilling activities for the first and second exploration periodperiods under the CEOP governing the Flamenco Block. In the year ended December 31, 2018, we produced an average of 14 boepd in the Flamenco Block.
On June 30, 2017, the Chilean Ministry accepted our proposal to extend the second exploratory period for an additional period of 18 months. AsWe opted out of the date of this annual report, US$2.1 million investment commitments related to this block (corresponding to one exploratory well) remain outstandingthird exploration period, and will be entirely assumed by us. On December 20, 2018, we proposed to extend the second exploratory period for an additional period of 18 months, ending November 7, 2020. Asas of the date of this annual report, the Chilean Ministryexploration phase in the Flamenco Block has not replied.
been concluded.
Isla Norte Block. We are the operator of and have a 60% working interest in partnership with ENAP in the Isla Norte Block, which covers approximately 97,650 gross acres (395 sq. km)km.). As of March 31, 2019, we had completed 100% of the committed 350 sq. km of 3D seismic surveys and drilled one exploratory well, which represents the first oil discovery within the block. As of the date of this annual report, we had completed 100% of the commitments of the first exploratory period and outstanding investment commitments of US$2.90.9 million related to this block correspond to twoone exploratory wells to be executed before May 7, 2019.
well of the second exploratory period.
Campanario Block. We are the operator of, and have a 50% working interest in, the Campanario Block, in partnership with ENAP. The block covers approximately 144,150 gross acres (583 sq. km)km.). As of March 31, 2019, we had completed 100% of the committed 578 sq. km of 3D seismic surveys and have also drilled five exploratory wells, including the Primavera Sur 1 well that marks the first discovery of an oil field on the Campanario Block in addition to one development well. As of the date of this annual report, we had completed 100% of the commitments of the first exploratory period and outstanding investment commitments of US$4.85.0 million related to this block correspond to threetwo exploratory wells to be executed before July 10, 2019.
Tranquilo Block. We completed a seismic program consisting of 163 sq. km of 3D seismic and 371 sq. km of 2D seismic survey work, and drilled four wells, including the Palos Quemados and Marcou Sur well. We discovered gas in the El Salto formation of the Palos Quemado well. At the Palos Quemados well, we completed a 22-week commercial feasibility test aimed at defining its productive potential. As the test was not conclusive, we were granted permission by the Chilean Ministry of Energy to extend the testing period for an additional six months. Upon such testing period, we kept 4 provisional protection areas, which enabled continued analysis of the area prior the declaration of its commercial viability for a period of 5 years. On January 17, 2013, we formally announced to the Chilean Ministry of Energy our decision not to proceed with the second exploratory periodperiod. The drilling campaign relating to the committed wells of Isla Norte and Campanario Blocks started in February 2020 but due to terminate the exploratory phaseCOVID-19 pandemic, the execution of the Tranquilo Block CEOP. Subsequently,2020 work plan was interrupted.
Therefore, in April 2020, January 2021, and July 2021, we relinquished all areas of the Tranquilo Block, except for a remaining area of 92,417 gross acres, for the exploitation of the Renoval, Marcou Sur, Estancia Maria Antonieta and Palos Quemados Fields, which we have identified as the areas with the most potential for prospects in the block. In November 2017, we proposedpresented to the Ministry of Energy to extendnotifications of declaration of force majeure, which were approved and we obtained an extension of the second exploratory period to declarefulfill the commerciality of discoveries in the areas of Palos Quemados, Maria Antonieta and Marcou Sur for an additional period of 24 months. In February 2018, the Ministry approved our proposal. In December 2018, we increased our working interest to 100%. The approvalcommitments of the agreement with Pluspetrol in connection withCampanario and Isla Norte Blocks until the first quarter of 2023.
During 2020 we fulfilled all the committed activities for the second exploration period under the CEOP governing the Flamenco Block, and we have outstanding investment commitment of US$5.9 million as of the date of this change is still under review byannual report, consisting of two exploratory wells before April 20, 2023, on the Ministry of Energy.
Campanario Block, and one exploratory well before February 19, 2023, on the Isla Norte Block.
Operations in Brazil
Our Brazilian assets currently give us access to 68,60061,400 of gross exploratory and productive acres across 76 blocks (6(5 exploratory blocks and the BCAM-40 Concession, which is in production phase) in an attractive oil and gas geography.
Highlights of the year ended December 31, 20182021 related to our operations in Brazil included:
| On March 1, 2021, the farm-out agreement to sell our 70% interest in REC-T-128 Block was signed. Closing of the transaction took place in May 2021, after receipt of the corresponding customary regulatory approvals. |
| ● | Average net oil and gas production |
| Proved oil and gas reserves decreased by 4% to 2.3 mmboe at year-end 2021, from 2.4 mmboe at year-end 2020 after producing 0.6 mmboe; and |
| ● | Capital expenditures decreased by |
60
The map below shows the location of our concessions in Brazil in which we have a current or future working interest, including the BCAM-40 Concession and the concessions from bidding rounds 11, 12, 13 and 14.interest:
| (1) |
61
The following table sets forth information as of December 31, 20182021 on our concessions in Brazil in which we have a current or future working interest, including the Manati Field and the concessions from bidding rounds 11, 12, 13 and 14.interest:
| Concession | Gross acres (thousand acres) | Working | Partners | Operator | Net proved reserves (mmboe) | Production (boepd) | Basin | Concession expiration year | ||||||||||||||||||
| REC-T 94 | 7.7 | 100 | % | — | GeoPark | — | — | Recôncavo | Exploration: 2020 Exploitation: 2047 | |||||||||||||||||
| POT-T 619 | 7.9 | 100 | % | — | GeoPark | — | — | Potiguar | Exploration: 2020 Exploitation: 2045 | |||||||||||||||||
| PN-T-597(2) | 188.7 | 100 | % | — | GeoPark | — | — | Parnaíba | — | |||||||||||||||||
| SEAL-T-268 | 7.8 | 100 | % | — | GeoPark | — | — | Sergipe Alagoas | Exploration: 2020 Exploitation: 2047 | |||||||||||||||||
| REC-T-128 | 7.6 | 70 | % | Geosol | GeoPark | — | — | Recôncavo | Exploration: 2019 Exploitation: 2045 | |||||||||||||||||
| POT-T-747 | 6.9 | 100 | %(3) | — | GeoPark | — | — | Potiguar | Exploration: 2018(4) Exploitation: 2045 | |||||||||||||||||
| POT-T-785 | 7.9 | 100 | %(3) | - | GeoPark | - | - | Potiguar | Exploration: 2023 Exploitation: 2050 | |||||||||||||||||
| Manati | 22.8 | 10 | % | Petrobras; Enauta; Brasoil | Petrobras | 3.0 | 2,925 | Camamu-Almada | Exploitation: 2029 | |||||||||||||||||
| | | | | | | | | | | | | | | | |
|
| Gross acres |
| |
| |
| |
| Net proved |
| |
| | | |
| | (thousand | | Working | | | | | | reserves | | Production | | | | Concession expiration |
Concession | | acres) | | interest(1) | | Partners | | Operator | | (mmboe) | | (boepd) | | Basin |
| year |
POT-T-785 |
| 7.9 |
| 70 | % | Petroil |
| GeoPark |
| — |
| — |
| Potiguar |
| Exploration: 2023 |
| | | | | | | | | | | | | | |
| Exploitation: 2050 |
REC-T 58 | | 7.8 | | 100 | % | — | | GeoPark | | — | | — | | Recôncavo | | Exploration: 2025 |
| | | | | | | | | | | | | | | | Exploitation:2052 |
REC-T 67 | | 7.7 | | 100 | % | — | | GeoPark | | — | | — | | Recôncavo | | Exploration: 2025 |
| | | | | | | | | | | | | | | | Exploitation:2052 |
REC-T 77 | | 7.7 | | 100 | % | — | | GeoPark | | — | | — | | Recôncavo | | Exploration: 2025 |
| | | | | | | | | | | | | | | | Exploitation:2052 |
POT-T 834 | | 7.5 | | 100 | % | — | | GeoPark | | — | | — | | Potiguar | | Exploration: 2025 |
| | | | | | | | | | | | | | | | Exploitation:2052 |
Manati (2) |
| 22.8 |
| 10 | % | Petrobras; Enauta; PetroRio |
| Petrobras |
| 2.3 |
| 1,919 |
| Camamu-Almada |
| Exploitation: 2029 |
| (1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in |
| (2) | On November 22, 2020, we signed an agreement to sell our |
Manati Field
As a result of the Rio das Contas acquisition, weWe have a 10% working interest in the BCAM-40 Concession, which originally included interestsan interest in the Manati Field, and the Camarão Norte Field, and which is located in the Camamu-Almada Basin. Petrobras is the operator of, and has a 35% working interest in, the BCAM-40 Concession, which covers approximately 22,784 gross acres (92.2 sq. km)km.). In addition to us, Petrobras’ partners in the block are BrasoilPetroRio S.A. and Enauta Energia S.A. (Enauta), with 10% and 45% working interests, respectively. Petrobras operates the BCAM-40 Concession pursuant to a concession agreement with the ANP, executed on August 6, 1998. See “—Significant Agreements—Brazil—Overview of concession agreements—BCAM-40 Concession Agreement.” In September 2009, Petrobras announced the relinquishment of BCAM-40’s exploration area within the concession to the ANP, except for the Manati Field and the Camarão Norte Field. In August 2018, Petrobras announced the relinquishment of the Camarão Norte Field.
The Manati Field is located 65 kmkm. south of Salvador, offshore at a water depth of 35 meters. The field was discovered in October 2000, and, in 2002, Petrobras declared the field commercially viable. Production began in January 2007. As of December 31, 2018,2021, 11 wells had been drilled in the Manati Field, 6 of which are productive and connected to a fixed production platform installed at a depth of 35 meters, located 9 kmkm. from the coast of the State of Bahia. From the platform, the gas flows by sea and land through a 125 kmkm. pipeline to the Estação Vandemir Ferreira or EVF gas treatment plant. The gas is sold to Petrobras up to a maximum volume as determined in the existing Petrobras Gas Sales Agreement (as defined below).
In July 2015,2020 we executed the 15th Amendment to the Petrobras Gas Sales Agreement in order to reflect the negotiations to mitigate the effects of the COVID-19 pandemic on the natural gas agents. Additionally, and in parallel a Term of Settlement of Outstanding Issues was executed to reflect the negotiations related to the take or pay agreement.
On November 22, 2020, we signed an amendmentagreement to sell our 10% non-operated working interest in the existingManati gas field to Gas Sales AgreementBridge for a total consideration of R$144.4 million (approximately $27 million as of the date of the agreement at the exchange rate of R$5.35 to US$1.00), including a fixed payment of R$124.4 million plus an earn-out of R$20.0 million, which is subject to obtaining certain regulatory approvals. The transaction was agreed with Petrobras that covers 100%an effective date of December 31, 2020 and is subject to certain conditions, including the acquisition by Gas Bridge of the remaining gas reserves90% working interest and operatorship of the Manati Field.
Also, in 2015, in order to improve the field gas recovery and production, Manati’s consortium built an onshore compression plant that started operating in August 2015. The compression plant involved capital expenditures of approximately US$3.7 million at our working interest and allowed us to classify all existing proved undeveloped reserves as proved developed.
Some environmental licenses related to operation of the Manati Field production system and natural gas pipeline are expired. However, the operator submitted, in a timely manner, the request for renewal of those licenses and as such this operation is not in default as long as the regulator does not state its final position on the renewal.
Round 11 Concessions
During ANP’s 11th Bid Round, held in May 2013, we were awarded 7 exploratory blocks, of which 2 were in the Reconcavo Basin in the state of Bahia and 5 were in the Potiguar Basin in the state of Rio Grande do Norte. The exploratory phase for these concessions is divided into two exploratory periods, the first of which lasts for three years and the second of which is non-obligatory and can last for up to two years.
In 2016, after fulfilling the committed exploratory commitments and further reevaluation of commercial potential, five exploratory blocks were relinquished to the ANP (REC T 85, POT T 620, POT T 663, POT T 664 and POT T 665).
REC-T 94 Concession
In the REC-T 94 we committed R$17.6 million (approximately US$ 4.5 million, at the December 31, 2018 exchange rate of R$3.9 to US$1.00) during the first exploratory period consisting of drilling two exploratory wells and 31 sq. km of 3D seismic surveys.
During the year 2014 we executed a 3D seismic survey. Seismic data interpretation in 2015 and 2016 defined two well locations, one of which was drilled in 2017. The estimated remaining commitment amounts to US$0.9 million.
POT-T 619 Concession
In the POT-T 619 Concession we committed investments of R$2.3 million (approximately US$0.6 million at the December 31, 2018 exchange rate of R$3.9 to US$1.00) during the first exploratory period, equivalent to 46 km of 2D seismic work.
During the year 2014 we executed a 2D seismic survey. Seismic data processing was concluded in 2015. After seismic interpretation, we decided to continue to the second exploratory period in September 2016, which lasts for two years with a commitment to drill one exploratory well. The well was drilled during 2018 and was abandoned. There is no pending commitment.
Round 12 Concessions
In November 2013, in the 12th Bid Round, the ANP awarded us two concessions (the PN-T-597 Concession in the Parnaíba Basin in the State of Maranhão and the SEAL-T-268 Concession in the Sergipe Alagoas Basin) in the State of Alagoas.
For more information, see “Item 3. Key information—D. Risk factors—Risks relating to our business—The PN-T-597 Concession Agreement in Brazil may not close.”
PN-T-597 Concession
The Parnaiba Basin, which covers an area of approximately 148 million gross acres (600,000 sq. km), is a basin with large underexplored areas.field. As of December 31, 2018, the basin had two fields in production in the basin.
In the PN-T-597 Concession we committed R$7.7 million (approximately US$2.0 million, at the December 31, 2018 exchange rate of R$3.9 to US$1.00) for the first exploratory period, equivalent to 180 km of 2D seismic.
The exploratory phase for this concession is divided into two exploratory periods. Given that Parnaiba Basin is considered as a “new frontier” area by the ANP, the first exploratory period lasts four years, and the second exploratory period, which is optional, can last for up to two years.
See “Item 3. Key Information—D. Risk factors—Risks relating to our business—The PN-T-597 may not close” and “—D. Risk factors—Risks relating to the countries in which we operate—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” for more information.
SEAL-T-268 Concession
In the SEAL-T-268 Concession we committed R$1.6 million (approximately US$0.4 million, at the December 31, 2018 exchange rate of R$3.9 to US$1.00) for the first exploratory period. The exploratory phase for this concession is divided into two exploratory periods, the first lasting three years, and the second, which is optional, can last for up to two years. During 2016, an electromagnetic survey acquisition of 70 stations and reprocessing of 58 km of vintage 2D seismic was performed and, after ANP approval of the extension of the first exploratory phase, we will fulfill part of the remaining committed work program that amounts to US$ 0.2 million.
Round 13 Concessions
During ANP’s 13th Bid Round held in October 2015, we were awarded four exploratory concessions, of which two were in the Potiguar Basin in the state of Rio Grande do Norte and two were in the Reconcavo Basin in the state of Bahia. The exploratory phase for these concessions is divided into two exploratory periods, the first of which lasts for three years and the second of which is non-obligatory and can last for up to two years.
POT-T-747 and POT-T-882
The POT-T-747 and POT-T-882 blocks are located in the Potiguar Basin and encompass an area of 14,829 acres (60 square km). Total commitment to the ANP was R$8.5 million (approximately US$2.2 million, at the December 31, 2018 exchange rate of R$3.9 to US$1.00) during the first exploratory period and is equivalent to acquiring 70 km of 2D seismic and drilling one well. During 2017 3D seismic was reprocessed and a well was drilled in the POT-T-747 block during 2018 and was abandoned. All the commitments related to POT-T-882 were fulfilled as of the date of this annual report. The estimated remaining commitment in the POT-T-747 block amounts to US$0.5 million.report, these conditions have not been met.
62
REC-T-128 Concession
REC-T-128 and REC-T-93
Both blocks are part of the Reconcavo Basin and have a combined area of 15,405 acres (62.3 square km). The block REC-T-128 was bid for in partnership with Geosol with a 70% working interest for us and 30% working interest for Geosol. The total commitment to the ANP was R$10.7 million (approximately US$2.71.9 million at the December 31, 20182021, exchange rate of R$3.95.60 to US$1.00) during the first exploratory period and consistsconsisted of acquiringacquisition of 9 km2sq. km. of 3D seismic, drilling of one well and performing geochemical analysis at two geological levels.
During 2016, regional interpretation studies were performed inIn July 2020, we initiated a farm-out process to sell our 70% interest. On March 1, 2021, the area. Partfarm-out agreement was signed and closing of the minimum exploratory program of Block REC-T-93 has been fulfilled and approved by ANP with the 3D regional seismic acquisition, which also covered Block REC T 94 (Round 11). During 2018, 3D reprocessing was performedtransaction took place in the REC-T-128 block and we also drilled the Praia dos Castelhanos 1 exploration well that will be completed and tested in the first half of 2019. As of December 31, 2018, the estimated remaining commitment in the REC-T-128 block amounts to US$2.2 million. This commitment was fulfilled in the first quarter of 2019.
Upon complete fulfillmentMay 2021, after receipt of the minimum exploratory work programcorresponding customary regulatory approvals. The total consideration of US$1.1 million was paid in 2021 and the accomplishmentcontingent payment of local content commitments, the POT-T-882 and REC-T-93 blocks were relinquishedup to US$0.7 million is still subject to the ANP in December 2018.
Round 14 Concessions
During ANP’s 14th Bid Round held in September 2017, we were awarded one exploratory concession, in the Potiguar Basin in the stateoccurrence of Rio Grande do Norte.
certain conditions to happen until August 2022.
POT-T-785 Concession
The POT-T-785 block covers an area of 7,875 acres in the Potiguar Basin, surrounded by producing fields operated by Petrobras. Total commitment to the ANP was R$1.2 million (US$0.30.2 million, at the December 31, 20182021, exchange rate of R$3.95.60 to US$1.00) during the first exploratory period and is equivalent to acquiring 4 km2sq. km. of 3D seismic and performing geochemical analysis before January 29, 2023. As of December 31, 2018,2021, the estimated remaining commitment in the POT-T-785 block amounts to US$0.1 million.
ANP’s First Open Acreage Bid Round
OperationsDuring ANP’s First Open Acreage Bid Round held in Peru
In October 2014,September 2019, we entered into an agreement to expand our footprint into Peru (our fifth country platformwere awarded four exploratory blocks, one in Latin America) through the acquisition of Morona Block in a joint venture with Petroperu.
Potiguar Basin (Block POT-T-834) and three on the Recôncavo Basin (Blocks REC-T-58, REC-T-67 and REC-T-77). The Morona Block has DeGolyer and MacNaughton certified net proved reserves of 18.5 mmboe asConcession Agreements were executed on February 2020. As of December 31, 2018, composed of 100% oil.
The map below shows2021, the location of the Morona Block in Peru.
The table below summarizes information about the block in Peru.
| Block | Gross acres (thousand acres) | Working interest(1) | Operator | Net proved reserves (mmboe) | Production (boepd) | Basin | Expiration concession year | |||||||||||||||||||||
| Morona | 1,881 | 75 | % | GeoPark | 18.5 | — | Marañon | Exploitation: 2039 (2) | ||||||||||||||||||||
Morona Block
The Morona Block covers an area of approximately 1,881 thousand gross acres (7,600 sq. km). More than 1 billion barrels of oil have been produced from the surrounding blocksestimated commitment in the Marañon Basin.
On October 1, 2014, we entered into an agreementblocks amounted to acquire a 75% working interest in the Morona Block in Northern Peru. As stated above, this agreement includes a work programUS$0.6 million to be executed by us. This program includes 3 phases, and we may decide whether to continue or not at the endbefore February 14, 2025.
63
The Morona Block contains the Situche Central oil field, which has been delineated by two wells (with short term tests of approximately 2,400 and 5,200 bopd of 35-36° API oil each) and by 3D seismic. In addition to the Situche Central field, the Morona Block has a large exploration potential with several high impact prospects and plays. The Morona Block includes geophysical surveys of 2,783 km (2D seismic) and 465 sq. km (3D seismic), and an operating field camp and logistics infrastructure. The area has undergone oil and gas exploration activities for the past 40 years, and there exist ongoing association agreements and cooperation projects with the local communities.
The expected work program and development plan for the Situche Central oil field is to be completed in three stages.
The goal of the initial two stages is to start production from the two wells already drilled in the field, in order to determine the most effective overall development plan and to begin to generate cash flow. These initial stages require an investment of approximately US$100 million to US$150 million and are expected to be completed in 2020. We have committed to carry Petroperu, by paying its portion of the required investment in these initial phases. In addition, we are required to cover any capital or operational expenditures of Petroperu associated with the project until December 31, 2020. We expect these expenditures to be substantially reimbursed by Petroperu from revenues associated to future sales. The beginning of such activities is subject to the approval of an environmental impact assessment by the Peruvian environmental authority.
In accordance with the agreement between us and Petroperu, commitments assumed by GeoPark are subject to certain economical and technical conditions being met.
The third stage, which will be initiated once production has been established, is expected to focus on carrying out the full development of the Situche Central field, including transportation infrastructure.
The exploratory program entails drilling one exploratory well. Exploratory program capital expenditures will be borne exclusively by us. Expected capital expenditures in 2019 for the Morona Block are mainly related to flexible pipeline installation, temporary access road, location conditioning and the Morona Camp dock revamping. These activities are subject to the approval of the Environmental Impact Study, which is under review by the local authority as of the date of this annual report. The approval of the Development Environmental Impact Study is expected by the end of the second quarter of 2019.
Initially we will hold a 75% working interest in the block. However, according to the terms of the agreement, Petroperu has the right to increase its working interest in the block up to 50%, subject to the recovery of our investments in the block by certain agreed factors.
See “Item 3. Key Information—D. Risk factors—Risks relating to our business—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” and “—We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities, including native communities, where our reserves are located.”
Operations in Argentina
The map below shows the location of the blocks in Argentina in which we have working interests as of December 31, 2018.2021.
| (1) |
| (2) | During May 2021, we initiated a process to |
| these blocks. Closing of the transaction took place on January 31, 2022, after the |
64
The table below summarizes information about the blocks in Argentina in which we have working interests asTable of December 31, 2018.Contents
| Block | Gross acres (thousand acres) | Working | Operator | Net proved reserves (mmboe) | Production (boepd) | Basin | Expiration concession year | |||||||||||||||||
| Puelen | 260.2 | 18 | % | Pluspetrol | — | — | Neuquén | Exploration: 2019 | ||||||||||||||||
| Sierra del Nevado | 1,399.4 | 18 | % | Pluspetrol | — | — | Neuquén | Exploration: 2019 | ||||||||||||||||
| Aguada Baguales | 44.0 | 100 | % | GeoPark | 3.0 | 968 | Neuquén | Exploitation: 2025 | ||||||||||||||||
| Puesto Touquet | 34.2 | 100 | % | GeoPark | 1.0 | 495 | Neuquén | Exploitation: 2027 | ||||||||||||||||
| El Porvenir | 58.9 | 100 | % | GeoPark | 1.0 | 372 | Neuquén | Exploitation: 2025 | ||||||||||||||||
| CN-V | 57.2 | 50 | % | Wintershall | — | — | Neuquén | Exploration: 2021 | ||||||||||||||||
| Los Parlamentos | 330.9 | 50 | % | YPF | — | — | Neuquén | Exploration: 2021 | ||||||||||||||||
| corresponding regulatory approvals. The table below summarizes information about the blocks in Argentina in which we have working interests as of and for the year ended December 31, 2021. |
| | | | | | | | | | | | | | |
|
| Gross |
| |
| |
| |
| |
| |
| |
| | acres | | | | | | Net proved | | | | | | |
| | (thousand | | Working | | | | reserves | | Production | | | | Expiration |
Block | | acres) | | interest (1) | | Operator | | (mmboe) | | (boepd) | | Basin | | concession year |
Puelen |
| 260.2 |
| 18 | % | Pluspetrol |
| — |
| — |
| Neuquén |
| In process of relinquishment |
Sierra del Nevado (2) |
| 1,399.4 |
| 18 | % | Pluspetrol |
| — |
| — |
| Neuquén |
| In process of relinquishment |
Aguada Baguales (3) |
| 44.0 |
| 100 | % | GeoPark |
| 1.4 |
| 1,876 |
| Neuquén |
| Exploitation: 2025 |
Puesto Touquet (3) |
| 34.2 |
| 100 | % | GeoPark |
| 0.3 |
| 135 |
| Neuquén |
| Exploitation: 2027 |
El Porvenir (3) |
| 58.9 |
| 100 | % | GeoPark |
| 0.6 |
| 125 |
| Neuquén |
| Exploitation: 2025 |
CN-V (4) |
| 57.2 |
| 50 | % | Wintershall |
| — |
| — |
| Neuquén |
| In process of relinquishment |
Los Parlamentos |
| 330.9 |
| 50 | % | YPF |
| — |
| — |
| Neuquén |
| Exploration: 2022 |
| (1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. |
| (2) | The block was in process of relinquishment as of December 31, 2021. Final approval was obtained on February 16, 2022. |
| (3) | In August 2021, our Board of Directors approved the decision to evaluate farm-out or divestment opportunities to sell our 100% working interest and operatorship in these blocks. Closing of the transaction took place on January 31, 2022, after the corresponding regulatory approvals. |
| (4) | The block was in process of relinquishment as of December 31, 2021. Final approval was obtained on March 8, 2022. |
Highlights of the year ended December 31, 20182021 related to our operations in Argentina included:
| ● | Average net oil and gas production |
| Proved oil and gas reserves |
| ● | Approval of our Board of Directors of the divestment of the Aguada Baguales, Puesto Touquet and El Porvenir Blocks in 2021, with closing of the transaction on January 31, 2022. |
Neuquén blocks
On March 27, 2018, we acquired a 100% working interest and operatorship of the Aguada Baguales, El Porvenir and Puesto Touquet Blocks, which are located in the Neuquén Basin, for a total consideration of US$52 million, less a working capital adjustment of US$3.1 million. The blocks include production facilities, such as hydrocarbons treatment, storage, and delivery infrastructure. Average net production in 2021 was 2,136 bopd and net reserves of 2.3 mmboe.
On January 31, 2022, we assigned to Oilstone Energía S.A. our 100% working interest and operatorship in Neuquén Blocks.
Los Parlamentos Block Farm-in Agreement
In June 2018, we acquiredannounced the acquisition of a 50% working interest in the Los Parlamentos exploratory block in partnership with YPF, the largest oil and gas producer in Argentina. In accordance with the partnership agreement, YPF assumed the operationship of the block and GeoParkwe assumed a commitment to fund its 50% working interest of onewhich includes two exploratory wellwells and additional 3D seismic, whichthat amounts to US$6 million at GeoPark’sour working interest, overfor the next three years.first exploratory period. Due to
65
COVID-19 pandemic, in April 2020, YPF submitted to the Ministry of Economy and Energy of Mendoza Province a request of 12 month suspension of the first exploratory period. This request was approved by the Province, then the first exploratory period will end on October 30, 2022.
2014 Mendoza Bidding Round
On August 20, 2014, the consortium of Pluspetrol and us was awarded two exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa Mendocina de Energía S.A. (“EMESA”).
The consortium consists of Pluspetrol (operator with a 72% working interest), EMESA (non-operator with a 10% working interest) and us (non-operator with an 18% working interest). In accordance with the terms of the bidding, all of the expenditures related to EMESA’s working interest will be carried by Pluspetrol and us proportionately to our respective working interests and will be recovered through EMESA’s participation in future potential production.
We have committed to a minimum aggregate investment of US$6.2 million for our working interest, which includesincluded the work program commitment on both blocks during the first three years of the exploratory period. As of December 31, 2018,2021, we fulfilled the remaining commitments in the Puelen and Sierra del Nevado blockBlocks and we are in process of relinquishing the Puelen Block. Final approval for the first exploratory period amount to between US$0.5 and US$1.0 million at our working interest. There is no pending commitment in the Puelen block.relinquishment of Sierra del Nevado Block was obtained on February 16, 2022.
CN-V Block Farm-in Agreement
On July 22, 2015, we signed a farm-in agreement with Wintershall for the CN-V Block in Argentina, which complements our existing acreage in the basin.Argentina. Wintershall is Germany’s largest oil and gas producer and a subsidiary of BASF Group. Under the agreement, we committed to operate during the exploratory phase and receive a 50% working interest in the CN-V Block in exchange for having to drill and fully fund two exploratory wells for a total of US$10 million.
The CN-V Block covers an area of approximately 57.2 thousand gross acres and is located in the Neuquén Basin in southern Argentina. The block has 3D seismic coverage of 180 sq. kmkm. and is adjacent to the producing Loma Alta Sur oil field, a region and play-type well known to our team. The block includes upside potential in the developing Vaca Muerta unconventional play. As of December 31, 2021, we fulfilled the commitments in the CN-V Block. Final approval for the relinquishment of CN-V Block was obtained on March 8, 2022.
During 2017,
66
Operations in Ecuador
The map below shows the location of the blocks in Ecuador in which we drilledhave working interests as of December 31, 2021.
The table below summarizes information about the blocks in Ecuador in which we have working interests as of December 31, 2021.
| | | | | | | | | | | | | | |
|
| Gross |
| |
| |
| |
| |
| |
| |
| | acres | | | | | | Net proved | | | | | | |
| | (thousand | | Working | | | | reserves | | Production | | | | Expiration |
Block | | acres) | | interest (1) | | Operator | | (mmboe) | | (boepd) | | Basin | | concession year |
Espejo |
| 15.7 |
| 50 | % | GeoPark |
| — |
| — |
| Oriente |
| Exploration: 2025 |
| | | | | | | | | | | | | | Exploitation: 2045 |
Perico |
| 17.7 |
| 50 | % | Frontera |
| — |
| — |
| Oriente |
| Exploration: 2025 |
| | | | | | | | | | | | | | Exploitation: 2045 |
| (1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. |
67
Highlights of the year ended December 31, 2021 related to our operations in Ecuador include:
| ● | Continuity in our operations without interruptions, despite the COVID-19 pandemic; |
| ● | The ongoing drilling of the Jandaya 1 exploration well in the Perico Block; |
| ● | 3D seismic acquisition of 60 sq km in the Espejo Block; |
| ● | Capital expenditures increased by 1,567% to US$5.0 million in 2021 from US$0.3 million in 2020. |
Espejo and Perico blocks
On May 22, 2019, we signed final participation contracts for the Espejo and Perico Blocks which were awarded to us in the Intracampos Bid Round held in Quito, Ecuador in April 2019. We are the operator of the Espejo Block with a 50% working interest and Frontera is the operator of the Perico Block with 50% working interest. We assumed a commitment of carrying out 3D seismic and drilling four exploration wells in the Espejo Block for an estimated amount of US$20.9 million during the first exploratory well, Rio Grande Oeste 1, which resultedperiod ending June 17, 2025 and drilling four exploratory wells in the discoveryPerico Block for an estimated amount of Rio Grande Oeste oil field. During 2018, we drilledUS$18.1 million during the secondfirst exploratory well, Rio Grande Este 1, which is under evaluation. With these investments GeoPark Argentina has fulfilled the initial commitment of US$10 million and the operation of the block was transferred to Wintershall.period ending June 16, 2025. As of the date of this annual report, we had drilled the estimated remaining commitmentfirst exploratory well in the CN-V block for the current exploratory period denominated “Field under evaluation”, ending on November 27, 2021, amounts to US$1.3 million at our working interest.
Perico Block.
Oil and natural gas reserves and production
Overview
We have achieved consistent growth in oil and gas reserves from our investment activities since 2006, when we began production in the Fell Block in Chile, followed by successful acquisition, exploration and development activities in other countries in which we have a presence, including Colombia, Brazil, Argentina, and Peru.
Our reserves
The following table sets forth our oil and natural gas net proved reserves as of December 31, 2018,2021, which is based on the D&M Reserves Report.
| Net proved reserves | ||||||||||||||||
| As of December 31, 2018 | ||||||||||||||||
| Oil (mmbbl) | Natural gas (bcf) | Total net | % Oil | |||||||||||||
| Net proved developed | ||||||||||||||||
| Colombia | 32.3 | 1.8 | 32.6 | 99 | % | |||||||||||
| Chile | 0.7 | 12.0 | 2.7 | 26 | % | |||||||||||
| Argentina | 2.0 | 6.2 | 3.1 | 65 | % | |||||||||||
| Brazil | 0.1 | 17.3 | 3.0 | 3 | % | |||||||||||
| Total net proved developed | 35.1 | 37.3 | 41.4 | 85 | % | |||||||||||
| Net proved undeveloped | ||||||||||||||||
| Colombia | 42.5 | 0.3 | 42.5 | 100 | % | |||||||||||
| Chile | 2.6 | 8.8 | 4.1 | 63 | % | |||||||||||
| Argentina | 1.4 | 3.2 | 1.9 | 74 | % | |||||||||||
| Peru | 18.5 | - | 18.5 | 100 | % | |||||||||||
| Total net proved undeveloped(2) | 65.0 | 12.3 | 67.0 | 97 | % | |||||||||||
| Total net proved (Colombia, Chile, Peru, Argentina and Brazil) | 100.1 | 49.6 | 108.4 | 92 | % | |||||||||||
| | | | | | | | | |
| | Net proved reserves | | ||||||
| | As of December 31, 2021 | | ||||||
| | | | | | Total net | | |
|
| | | | | | proved | | |
|
| | Oil | | Natural gas | | reserves | | |
|
|
| (mmbbl) |
| (bcf) |
| (mmboe)(1) |
| % Oil |
|
Net proved developed | |
| |
| |
| |
| |
Colombia |
| 47.8 |
| 1.2 |
| 48.0 |
| 100 | % |
Chile |
| 0.7 |
| 15.2 |
| 3.3 |
| 21 | % |
Brazil |
| — |
| 13.6 |
| 2.3 |
| — | % |
Argentina |
| 1.2 |
| 3.4 |
| 1.7 |
| 71 | % |
Total net proved developed |
| 49.7 |
| 33.4 |
| 55.3 |
| 90 | % |
|
|
|
|
|
|
|
|
| |
Net proved undeveloped |
|
|
|
|
|
|
|
| |
Colombia |
| 31.0 |
| — |
| 31.0 |
| 100 | % |
Chile |
| 0.6 |
| 1.5 |
| 0.9 |
| 67 | % |
Brazil |
| — |
| — |
| — |
| — | % |
Argentina | | 0.6 | | — | | 0.6 | | 100 | % |
Total net proved undeveloped (2) |
| 32.2 |
| 1.5 |
| 32.5 |
| 99 | % |
|
|
|
|
|
|
|
|
| |
Total net proved (Colombia, Chile, Brazil and Argentina) |
| 81.9 |
| 34.9 |
| 87.8 |
| 93 | % |
| (1) | We calculate one barrel of oil equivalent as six mcf of natural gas. |
| (2) | We plan to put 100% of our reported |
68
We had net proved reserves of 108.487.8 mmboe at December 31, 2018,2021, compared to net proved reserves of 95.7100.6 mmboe as of December 31, 2017.
2020.
The 13.3% increase13% decrease in net proved reserves in 2018,2021, not including annual production, is mainly attributable to:
| ● | Lower than expected performance of the existing wells in Colombia, Argentina and Chile resulting in an 8.9 mmboe decrease, 0.6 mmboe decrease and 0.6 mmboe decrease respectively. |
| ● | Revision of the type well associated with the incremental activity that reduced the proved undeveloped reserves in the Fell Block in Chile, resulting in a 0.6 mmboe decrease. |
| ● | Removal of proved undeveloped reserves mainly due to changes in previously adopted development plan in the Fell Block in Chile, resulting in a 0.9 mmboe decrease. |
This was partially offset by:
| Extensions and discoveries that resulted in an increase of |
This was partially offset by:
During the year ended December 31, 2018,2021, we had 12.816.2 mmboe of our proved undeveloped reserves from December 31, 20172020, converted to proved developed reserves due to development drilling in the Jacana and Tigana oil fields in the Llanos 34 Block. For further information relating to the reconciliation of our net proved reserves for the years ended December 31, 2018, 20172021, 2020 and 2016,2019, please see Table 5 included in Note 3738 (unaudited) to our Consolidated Financial Statements.
Internal controls over reserves estimation process
We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserves engineers in their estimationestimating process and who have knowledge of the specific properties under evaluation. Our Director of Exploration, Salvador Minniti,Operations, Rodolfo Martín Terrado, is primarily responsible for overseeing the preparation of our reserves estimates and for the internal control over our reserves estimation. He has more than 35over 20 years of industry experience as an E&P geologist, with broad experience in reserves assessment, fieldasset development exploration portfolio generation and management and acquisition and divestiture opportunities evaluation.operations See “Item 6. Directors, Senior Management and Employees—A. Directors and senior management.”
In order to ensure the quality and consistency of our reserves estimates and reserves disclosures, we maintain and comply with a reserves process that satisfies the following key control objectives:
| estimates are prepared using generally accepted practices and methodologies; |
| estimates are prepared objectively and free of bias; |
| estimates and changes therein are prepared on a timely basis; |
| estimates and changes therein are properly supported and approved; and |
| estimates and related disclosures are prepared in accordance with regulatory requirements. |
Throughout each fiscal year, our technical team meets with Independent Qualified Reserves Engineers, who are provided with full access to complete and accurate information pertaining to the properties to be evaluated and all applicable personnel. This independent assessment of the internally-generated reserves estimates is beneficial in ensuring that interpretations and judgments are reasonable and that the estimates are free of preparer and management bias.
69
Recognizing that reserves estimates are based on interpretations and judgments, differences between the proved reserves estimates prepared by us and those prepared by an Independent Qualified Reserves Engineer of 10% or less, in aggregate, are considered to be within the range of reasonable differences. Differences greater than 10% must be resolved in the technical meetings. Once differences are resolved, the independent Qualified Reserves Engineer sends a preliminary copy of the reserves report to be reviewed by Corporate Reserves team and the TechnicalExecutive Committee, integrated by the CEO, COO, CFO, Director of Operations and Directorsmanagers in charge of each country.the Geoscience, Operations, and Finance departments A final copy of the Reserves Report is sent by the Independent Qualified Reserve Engineer to be approved and signed by the Technical Committee and our CEO and CFO.Executive Committee. See “Item 6. Directors, Senior Management and Employees—C. Board Practices—Committees of our board of directors.”
Independent reserves engineers
Reserves estimates as of December 31, 20182021, for Colombia, Chile, Brazil Argentina and PeruArgentina included elsewhere in this annual report are based on the D&M Reserves Report, dated February 4, 201911, 2022, and effective as of December 31, 2018.2021. The D&M Reserves Report, a copy of which has been filed as an exhibit to this annual report, was prepared in accordance with SEC rules, regulations, definitions and guidelines at our request in order to estimate reserves and for the areas and period indicated therein.
DeGolyer and MacNaughton, a Delaware corporation with offices in Dallas, Houston, Moscow, Algiers, Astana and Buenos Aires has been providing consulting services to the oil and gas industry since 1936. The firm has more than 200 professionals, including engineers, geologists, geophysicists, petrophysicists and economists that are engaged in the appraisal of oil and gas properties, the evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer and MacNaughton restricts its activities exclusively to consultation and does not accept contingency fees, nor does it own operating interests in any oil, gas or mineral properties, or securities or notes of its clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.
The D&M Reserves Report covered 100% of our total reserves. In connection with the preparation of the D&M Reserves Report, DeGolyer and MacNaughton prepared its own estimates of our proved reserves. In the process of the reserves evaluation, DeGolyer and MacNaughton did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of DeGolyer and MacNaughton that brought into question the validity or sufficiency of any such information or data, DeGolyer and MacNaughton did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. DeGolyer and MacNaughton independently prepared reserves estimates to conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(2)4 10(a)(1)-(32) of Regulation S-X. DeGolyer and MacNaughton issued the D&M Reserves Report based upon its evaluation. D&M’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. The assumptions, data, methods and procedures used, including the percentage of our total reserves reviewed in connection with the preparation of the D&M Reserves Report were appropriate for the purpose served by such report, and DeGolyer and MacNaughton used all methods and procedures as it considered necessary under the circumstances to prepare such reports.
However, uncertainties are inherent in estimating quantities of reserves, including many factors beyond our and our independent reserves engineers’ control. Reserves engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserves estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, economic factors such as changes in product prices or development and production expenses, and regulatory factors, such as royalties, development and environmental permitting and concession terms, may require revision of such estimates. Our operations may also be affected by unanticipated changes in regulations concerning the oil
70
and gas industry in the countries in which we operate, which may impact our ability to recover the estimated reserves. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserves estimates.
Technology used in reserves estimation
According to SEC guidelines, proved reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with “reasonable certainty” to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
There are various generally accepted methodologies for estimating reserves including volumetrics, decline analysis, material balance, simulation models and analogies. Estimates may be prepared using either deterministic (single estimate) or probabilistic (range of possible outcomes and probability of occurrence) methods. The particular method chosen should be based on the evaluator’s professional judgment as being the most appropriate, given the geological nature of the property, the extent of its operating history and the quality of available information. It may be appropriate to employ several methods in reaching an estimate for the property.
Estimates must be prepared using all available information (open and cased hole logs, core analyses, geologic maps, seismic interpretation, production/injection data and pressure test analysis). Supporting data, such as working interest, royalties and operating costs, must be maintained and updated when such information materially changes.
Proved undeveloped reserves
As of December 31, 2018,2021, we had 67.032.5 mmboe in proved undeveloped reserves, an increasea decrease of 8.115.1 mmboe, or 14%32%, over our December 31, 20172020, proved undeveloped reserves of 58.947.6 mmboe. Changes for the year ended December 31 2018, include (i) an increase of 8.9 mmboe in Colombia due to the Tigana and Jacana appraisal wells, the Tigui field discovery in the Llanos 34 Block and the gas discovery of the Une Formation in the Llanos 32 Block.; (ii) an increase of 2.0 mmboe in Argentina due to the purchase of minerals in place related with the Aguada Baguales, El Porvenir and Puesto Touquet fields acquisitions during 2018; (iii) a decrease of 12.8 mmboe in Colombia due to the conversion of proved undeveloped reserves to proved developed reserves in the Llanos 34 Block; (iv) an increase of 8.2 mmboe in Peru due to revisions in the Morona Block; (v) an increase in Peru of 1.0 mmboe due to the impact of higher average oil prices in the Morona Block (vi) an increase of 8.2 mmboe due to the better than expected performance from existing wells from the Tigana and Jacana fields in the Llanos 34 Block in Colombia partially offset by a removal of 1.4 mmboe of proved undeveloped reserves related to a worse than expected performance in the Fell Block in Chile; (vii) an increase of 0.2 mmboe in Chile due to the Jauke field discovery in the Fell Block and (viii) a decrease in reserves of 6.3 mmboe in Colombia due to changes in a previously adopted development plan in Max, Tua, Chachalaca Sur, Tilo and Jacamar fields in the Llanos 34 Block. 2021, include:
| an increase of 2.5 mmboe in Colombia due to the Tigui appraisal wells in the Llanos 34 Block; |
| (ii) | an increase of 0.6 mmboe due to the Aguada Baguales field extension in Argentina; |
| (iii) | a decrease of 2.8 mmboe due to a lower than expected performance in Colombia (2.0 mmboe), Chile (0.7 mmboe) and Argentina (0.1 mmboe); |
| (iv) | an increase of 1.7 mmboe due to higher oil average prices in Chile and Colombia; |
| (v) | a decrease of 0.9 mmboe mainly due to changes in previously adopted development plan in the Fell Block in Chile; and |
| (vi) | a decrease in reserves of 16.2 mmboe in Colombia due to the conversion of proved undeveloped reserves to proved developed reserves in the Llanos 34 Block. |
Of our 67.032.5 mmboe of net proved undeveloped reserves, 42.531.0 mmboe (63%(95.4%), 4.10.9 mmboe (6%(2.8%), 1.90.6 mmboe (3%) and 18.5 mmboe (28%(1.8%) were located in Colombia, Chile and Argentina, and Peru, respectively.
71
During 2018,2021, we incurred approximately US$37.843.6 million in capital expenditures in Colombia to convert such proved undeveloped reserves to proved developed reserves.
No net proved undeveloped reserves were located in Brazil as of December 31, 2018.
2021.
The following table shows the evolution of total net proved undeveloped (“PUD”) reserves in the year ended December 31, 2018.2021.
| | | ||
Total Net Proved Undeveloped (“PUD”) Reserves at December 31, | | 47.6 | ||
(All amounts shown in mmboe) | | | ||
| | | ||
Plus: Extensions, discoveries and acquisitions: | | | ||
-Colombia | | 2.5 | ||
-Argentina | | 0.6 | ||
Less: PUD Reserves converted to proved developed reserves: | | | ||
-Colombia | | (16.2) | ||
Plus/less: PUD Reserves revisions and movement to/from other categories: | | | ||
-Colombia | | (0.6) | ||
-Chile | | (1.3) | ||
-Argentina | | (0.1) | ||
Total Net Proved Undeveloped (“PUD”) Reserves at December 31, | | 32.5 |
Production, revenues and price history
The following table sets forth certain information on our production of oil and natural gas in Colombia, Chile, Brazil and Argentina for each of the years ended December 31, 2018, 20172021, 2020 and 2016.2019.
Average daily production(1) | ||||||||||||||||||||||||||||||||||||||||||||
| As of December 31, | ||||||||||||||||||||||||||||||||||||||||||||
| 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||
| Colombia | Chile | Brazil | Argentina(4) | Colombia | Chile | Brazil | Argentina | Colombia | Chile | Brazil | ||||||||||||||||||||||||||||||||||
| Oil production | ||||||||||||||||||||||||||||||||||||||||||||
| Average crude oil production (bopd) | 28,421 | 782 | 42 | 1,202 | 21,718 | 1,000 | 42 | 4 | 15,536 | 1,380 | 39 | |||||||||||||||||||||||||||||||||
| Average sales price of crude oil (US$/bbl)(3) | 52.6 | 62.3 | 79.1 | 65.0 | 36.1 | 45.7 | 60.1 | 52.3 | 24.4 | 37.0 | 48.0 | |||||||||||||||||||||||||||||||||
| Natural Gas production | ||||||||||||||||||||||||||||||||||||||||||||
| Average natural gas production (mcfpd) | 740 | 11,640 | 17,300 | 3,796 | 414 | 11,317 | 17,209 | - | - | 14,964 | 17,346 | |||||||||||||||||||||||||||||||||
| Average sales price of natural gas (US$/mcf)(3) | 2.6 | 5.4 | 5.0 | 5.0 | 5.9 | 4.5 | 5.8 | - | - | 3.8 | 5.0 | |||||||||||||||||||||||||||||||||
| Oil and gas production cost | ||||||||||||||||||||||||||||||||||||||||||||
| Average operating cost (US$/boe) | 5.6 | 22.8 | 6.1 | 31.2 | 5.6 | 20.3 | 7.8 | 242.6 | 5.4 | 15.8 | 5.8 | |||||||||||||||||||||||||||||||||
| Average royalties and Other (US$/boe) | 6.3 | 1.6 | 2.9 | 7.5 | 3.2 | 1.4 | 3.2 | 10.0 | 1.4 | 1.1 | 2.8 | |||||||||||||||||||||||||||||||||
| Average production cost (US$/boe)(2) | 11.9 | 24.4 | 9.0 | 38.7 | 8.8 | 21.7 | 11.0 | 252.6 | 6.7 | 16.9 | 8.5 | |||||||||||||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Average daily production(1) | ||||||||||||||||||||||
| | As of December 31, | ||||||||||||||||||||||
| | 2021 |
| 2020 |
| 2019 | ||||||||||||||||||
|
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Colombia |
| Chile |
| Brazil | | Argentina |
Oil production |
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
| |
|
|
|
|
| |
|
Average crude oil production (bopd) |
| 30,920 | | 313 | | 26 | | 1,215 | | 33,039 | | 395 | | 62 | | 1,364 | | 32,127 | | 656 | | 57 | | 1,603 |
Average sales price of crude oil (US$/bbl) |
| 58.3 | | 38.0 | | 39.6 | | 42.0 | | 30.6 | | 38.0 | | 39.6 | | 42.0 | | 50.4 | | 56.2 | | 70.3 | | 53.1 |
Natural Gas production |
| | | | | | | | | | | | | | | | | | | | | | | |
Average natural gas production (mcfpd) |
| 1,374 | | 12,507 | | 11,357 | | 5,529 | | 1,133 | | 17,084 | | 8,220 | | 5,556 | | 1,063 | | 14,917 | | 12,806 | | 4,834 |
Average sales price of natural gas (US$/mcf) |
| 4.4 | | 3.4 | | 5.2 | | 2.7 | | 5.5 | | 2.7 | | 4.3 | | 2.3 | | 5.7 | | 4.2 | | 5.1 | | 3.4 |
Oil and gas production cost |
| | | | | | | | | | | | | | | | | | | | | | | |
Average operating cost (US$/boe) |
| 6.5 | | 12.3 | | 4.6 | | 20.8 | | 5.4 | | 8.2 | | 5.8 | | 19.8 | | 5.4 | | 17.7 | | 5.6 | | 26.7 |
Average royalties and Other (US$/boe) |
| 9.6 | | 0.9 | | 2.6 | | 6.1 | | 2.7 | | 0.6 | | 2.2 | | 4.8 | | 5.0 | | 1.1 | | 2.5 | | 6.5 |
Average production cost (US$/boe)(2) |
| 16.2 | | 13.2 | | 7.2 | | 26.9 | | 8.1 | | 8.8 | | 8.0 | | 24.5 | | 10.4 | | 18.9 | | 8.1 | | 33.2 |
| (1) | We present production figures net of interests due to others, but before deduction of royalties, as we believe that net production before royalties is more appropriate in light of our foreign operations and the attendant royalty regimes. |
| (2) | Calculated pursuant to FASB ASC 932. |
72
The following table sets forth certain information on our production of oil and natural gas by final product sold in Colombia, Chile, Brazil and Argentina for each of the years ended December 31, 2018, 20172021, 2020 and 2016.2019.
| 2018 | 2017 | 2016 | ||||||||||||||||||||||
| Oil | Gas | Oil | Gas | Oil | Gas | |||||||||||||||||||
| Mbbl | MMcf | Mbbl | MMcf | Mbbl | MMcf | |||||||||||||||||||
| Tigana oil field(1) | 4,748.0 | - | 2,767.0 | - | 1,871.5 | - | ||||||||||||||||||
| Jacana oil field(1) | 3,051.0 | - | 2,566.0 | - | 1,188.6 | - | ||||||||||||||||||
| Rest of Colombia | 1,590.0 | - | 1,870.0 | - | 2,113.2 | - | ||||||||||||||||||
| Chile | 280.0 | 3,703.0 | 347.0 | 3,745.0 | 502.8 | 5,293.0 | ||||||||||||||||||
| Brazil | 15.0 | 5,803.0 | 15.0 | 5,763.0 | 14.0 | 6,314.0 | ||||||||||||||||||
| Argentina | 470.0 | 1,071.0 | - | - | - | - | ||||||||||||||||||
| Total | 10,154.0 | 10,577.0 | 7,565.0 | 9,508.0 | 5,690.1 | 11,607.0 | ||||||||||||||||||
| | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 | ||||||
|
| Oil |
| Gas |
| Oil |
| Gas |
| Oil |
| Gas |
| | Mbbl | | MMcf | | Mbbl | | MMcf | | Mbbl | | MMcf |
Tigana oil field(1) |
| 3,670 | | — |
| 4,250 | | — |
| 5,205 | | — |
Jacana oil field(1) |
| 4,023 | | — |
| 4,152 | | — |
| 3,716 | | — |
Rest of Colombia |
| 2,747 | | 502 |
| 2,584 | | 413 |
| 1,657 | | 719 |
Chile |
| 100 | | 4,403 |
| 134 | | 6,175 |
| 188 | | 5,167 |
Brazil |
| 9 | | 3,796 |
| 7 | | 2,785 |
| 11 | | 4,279 |
Argentina |
| 434 | | 1,584 |
| 505 | | 1,525 |
| 565 | | 1,355 |
Total |
| 10,983 |
| 10,285 |
| 11,632 |
| 10,898 |
| 11,342 |
| 11,520 |
| (1) | The Tigana (discovered in 2013) and Jacana (discovered in 2015) oil fields in Colombia are separately included in the table above as those oil fields individually contain more than 15% of our total proved reserves as of each of the years indicated above. |
Drilling activities
The following table sets forth the exploratory wells we drilled as operators during the years ended December 31, 2018, 20172021, 2020 and 2016.2019.
Exploratory wells(1) | ||||||||||||||||||||||||||||||||||||||||||||
| 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||
| Colombia | Chile | Brazil | Argentina | Colombia | Chile | Brazil | Argentina | Colombia | Chile | Brazil | ||||||||||||||||||||||||||||||||||
| Productive(2) | ||||||||||||||||||||||||||||||||||||||||||||
| Gross | 9.0 | 1.0 | 1.0 | - | 5.0 | 1.0 | - | 1.0 | 3.0 | - | - | |||||||||||||||||||||||||||||||||
| Net | 4.1 | 1.0 | 0.7 | - | 2.3 | 1.0 | - | 0.5 | 1.4 | - | - | |||||||||||||||||||||||||||||||||
| Dry(3) | ||||||||||||||||||||||||||||||||||||||||||||
| Gross | 2.0 | - | 1.0 | - | 1.0 | - | 1.0 | - | - | - | - | |||||||||||||||||||||||||||||||||
| Net | 1.5 | - | 1.0 | - | 0.5 | - | 1.0 | - | - | - | - | |||||||||||||||||||||||||||||||||
| Total | ||||||||||||||||||||||||||||||||||||||||||||
| Gross | 11.0 | 1.0 | 2.0 | - | 6.0 | 1.0 | 1.0 | 1.0 | 3.0 | - | - | |||||||||||||||||||||||||||||||||
| Net | 5.6 | 1.0 | 1.7 | - | 2.8 | 1.0 | 1.0 | 0.5 | 1.4 | - | - | |||||||||||||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Exploratory wells(1) | ||||||||||||||||||||||
| | 2021 | | 2020 | | 2019 | ||||||||||||||||||
|
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Colombia |
| Chile |
| Brazil | | Argentina |
Productive(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Gross |
| 3.0 | | — | | — | | — |
| 1.0 | | — | | — | | — |
| 5.0 | | 1.0 | | 1.0 | | 1.0 |
Net |
| 1.9 | | — | | — | | — |
| 0.3 | | — | | — | | — |
| 2.1 | | 1.0 | | 0.7 | | 1.0 |
Dry(3) |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Gross |
| 3.0 | | — | | — | | — |
| 1.0 | | 1.0 | | — | | — |
| — | | — | | 1.0 | | 3.0 |
Net |
| 0.8 | | — | | — | | — |
| 0.3 | | 1.0 | | — | | — |
| — | | — | | 1.0 | | 0.9 |
Total |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Gross |
| 6.0 | | — | | — | | — |
| 2.0 | | 1.0 | | — | | — |
| 5.0 | | 1.0 | | 2.0 | | 4.0 |
Net |
| 2.7 | | — | | — | | — |
| 0.6 | | 1.0 | | — | | — |
| 2.1 | | 1.0 | | 1.7 | | 1.9 |
| (1) | Includes appraisal wells. |
| (2) | A productive well is an exploratory, development, or extension well that is not a dry well. |
| (3) | A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. |
73
The following table sets forth the development wells we drilled as operators during the years ended December 31, 2018, 20172021, 2020 and 2016.2019.
| Development wells | ||||||||||||||||||||||||||||||||||||||||||||
| 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||
| Colombia | Chile | Brazil | Argentina | Colombia | Chile | Brazil | Argentina | Colombia | Chile | Brazil | ||||||||||||||||||||||||||||||||||
| Productive(1) | ||||||||||||||||||||||||||||||||||||||||||||
| Gross | 16 | - | - | - | 17.0 | 1.0 | - | - | 3.0 | 1.0 | - | |||||||||||||||||||||||||||||||||
| Net | 7.2 | - | - | - | 7.7 | 1.0 | - | - | 1.4 | 1.0 | - | |||||||||||||||||||||||||||||||||
| Dry(2) | ||||||||||||||||||||||||||||||||||||||||||||
| Gross | - | - | - | - | 1.0 | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||
| Net | - | - | - | - | 0.5 | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||
| Total | ||||||||||||||||||||||||||||||||||||||||||||
| Gross | 16 | - | - | - | 18.0 | 1.0 | - | - | 3.0 | 1.0 | - | |||||||||||||||||||||||||||||||||
| Net | 7.2 | - | - | - | 8.2 | 1.0 | - | - | 1.4 | 1.0 | - | |||||||||||||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Development wells | ||||||||||||||||||||||
| | 2021 | | 2020 | | 2019 | ||||||||||||||||||
|
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Colombia |
| Chile |
| Brazil |
| Argentina |
Productive(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Gross |
| 24.0 | | — | | — | | — |
| 19.0 | | — | | — | | — |
| 21.0 | | 1.0 | | — | | — |
Net |
| 10.8 | | — | | — | | — |
| 8.6 | | — | | — | | — |
| 9.5 | | 1.0 | | — | | — |
Dry(2) |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Gross |
| — | | — | | — | | — |
| — | | — | | — | | — |
| 1.0 | | — | | — | | 2.0 |
Net |
| — | | — | | — | | — |
| — | | — | | — | | — |
| 0.5 | | — | | — | | 2.0 |
Total |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Gross |
| 24.0 | | — | | — | | — |
| 19.0 | | — | | — | | — |
| 22.0 | | 1.0 | | — | | 2.0 |
Net |
| 10.8 | | — | | — | | — |
| 8.6 | | — | | — | | — |
| 10.0 | | 1.0 | | — | | 2.0 |
| (1) | A productive well is an exploratory, development, or extension well that is not a dry well. |
| (2) | A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. |
Developed and undeveloped acreage
The following table sets forth certain information regarding our total gross and net developed and undeveloped acreage in Colombia, Chile, Brazil Argentina and PeruArgentina as of December 31, 2018.2021.
Acreage(1) | ||||||||||||||||||||
| Colombia | Chile | Peru | Brazil | Argentina | ||||||||||||||||
| (in thousands of acres) | ||||||||||||||||||||
| Total developed acreage | ||||||||||||||||||||
| Gross | 11.6 | 6.7 | 0.7 | 4.1 | 9.8 | |||||||||||||||
| Net | 5.6 | 6.7 | 0.5 | 0.4 | 9.8 | |||||||||||||||
| Total undeveloped acreage | ||||||||||||||||||||
| Gross | 233.3 | 801.3 | 1,880.3 | 253.2 | 1,844.1 | |||||||||||||||
| Net | 120.2 | 591.0 | 1,410.3 | 234.1 | 454.6 | |||||||||||||||
| Total developed and undeveloped acreage | ||||||||||||||||||||
| Gross | 244.9 | 808.0 | 1,881.0 | 257.3 | 1,853.9 | |||||||||||||||
| Net | 125.8 | 597.7 | 1,410.8 | 234.5 | 464.4 | |||||||||||||||
| | | | | | | | |
| | Acreage(1) | ||||||
|
| Colombia |
| Chile |
| Brazil |
| Argentina |
| | (in thousands of acres) | ||||||
Total developed acreage |
|
|
|
|
|
|
|
|
Gross |
| 23.1 |
| 5.4 |
| 4.1 | | 7.6 |
Net |
| 12.1 |
| 5.4 |
| 0.4 | | 7.6 |
Total undeveloped acreage |
|
|
| |
| | | |
Gross |
| 3,667.3 |
| 710.2 |
| 57.3 | | 2,177.2 |
Net |
| 1,921.8 |
| 546.1 |
| 38.1 | | 622.3 |
Total developed and undeveloped acreage |
| |
| |
| | | |
Gross |
| 3,690.4 |
| 715.6 |
| 61.4 | | 2,184.8 |
Net |
| 1,933.9 |
| 551.5 |
| 38.5 | | 629.9 |
| (1) | Developed acreage is defined as acreage assignable to productive wells. Undeveloped acreage is defined as acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether such acreage contains proved reserves. Net acreage based on our working interest. |
74
Productive wells
The following table sets forth our total gross and net productive wells as of February 28, 2019.2022. Productive wells consist of producing wells and wells capable of producing, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
Productive wells(1) | ||||||||||||||||||||
| Colombia | Chile | Brazil | Peru | Argentina | ||||||||||||||||
| Oil wells | ||||||||||||||||||||
| Gross | 117.0 | 47.0 | - | - | 167.0 | |||||||||||||||
| Net | 66.4 | 44.0 | - | - | 166.5 | |||||||||||||||
| Gas wells | ||||||||||||||||||||
| Gross | 2.0 | 50.0 | 6.0 | - | 30.0 | |||||||||||||||
| Net | 0.3 | 49.0 | 0.6 | - | 30.0 | |||||||||||||||
| | | | | | | | |
| | Productive wells(1) | ||||||
|
| Colombia |
| Chile |
| Brazil |
| Ecuador |
Oil wells |
|
|
|
|
|
|
|
|
Gross |
| 143.0 | | 9.0 |
| — |
| 1.0 |
Net |
| 73.3 | | 9.0 |
| — |
| 0.5 |
Gas wells |
| | | |
|
|
| |
Gross |
| 2.0 | | 12.0 |
| 6.0 |
| — |
Net |
| 0.3 | | 12.0 |
| 0.6 |
| — |
| (1) | Includes wells drilled by other operators, prior to our commencing operations, and wells drilled in blocks in which we are not the operator. A productive well is an exploratory, development, or extension well that is not a dry well. |
Present activities
As of February 28, 2022, we drilled ten wells, nine of them in Colombia and one in Ecuador adding approximately 8,217 bopd gross as follows:
Our average oil and gas production
| ● | Seven wells were drilled in the Llanos 34 Block in Colombia (Tigui 29, Tigui 10, Tigana Norte 36, Tigana Norte 37, Jacana 65, Jacana 63 and Guerere 1), adding approximately 2,754 bopd gross; |
| ● | One well was drilled in the CPO-5 Block in Colombia (Indico 4), adding approximately 4,200 bopd gross; |
| ● | One well was drilled in the Platanillo Block in Colombia (Platanillo Central 1), adding approximately 526 bopd gross; and |
| ● | One well was drilled in the Perico Block in Ecuador (Jandaya 1), adding approximately 737 bopd. |
Additionally, on March 28, 2022, we announced our second hydrocarbon discovery in 2022 in the first quarterPerico Block in Ecuador. The Tui 1 well was drilled and completed to a total depth of 2019 was 39,558 mboepd, with oil production of 34,358 mbopd and gas production of 5,200 mboepd. Of this total production, 81%, 7%, 6% and 6% were in Colombia, Chile, Argentina and Brazil, respectively.
In March 2019, we announced the entry into Ecuador through the acquisition10,975 feet. As of the Espejodate of this annual report the testing program is underway and Perico exploratory blocks inadditional production history will be required to determine stabilized flow rates of the Intracampos Bid Round in the Oriente Basin located in the north-eastern part of Ecuador. The blocks were awarded to the GeoPark and Frontera consortium (50% GeoPark, 50% Frontera) in the form of production sharing contracts. The final award is contingent upon regulatory approvalswell and the executionextent of the contracts is expected for the second quarter of 2019.
On April 1, 2019, we secured 4,000 bopd through a zero-premium three-way structure, with a minimum average price of US$45-US$55 per barrel and a maximum average price of US$79 per barrel, for the period commencing April 2019 to March 2020.
reservoir.
Marketing and delivery commitments
Colombia
Our production in Colombia consists primarily of crude oil. Sales for the year ended December 31, 2018 were made under a long term sales agreement with Trafigura.
During 2018, our oil sales were done at wellhead with the delivery point at the truck-loading station at each field. In Colombia, pipelines have minimum quality conditions for accesswhich is sold according to the system. Consequently, and because we are mid to heavy oil producers, loading to the pipeline system requires the use of diluents which are blended into our crude. Under the Trafigura Agreement, we followed agreed priorities for the volumes to be transported through the ODL Pipeline. For the period from January 1, 2018 to December 31, 2018, Trafigura bought 100% of our production. In 2018, we amended the Trafigura Agreement to include a fixed volume oil sale of 8,000 bopd to Trafigura from January to December 2019.
Our oil sales price formula isformulas based on market reference indices (Brent price, Vasconia and VasconiaOriente differential) and discounts that consider transportation costs and quality adjustments.
With the expiration of the obligation to sell all ofDuring 2021, our Colombian production to Trafigura, we have started diversifying our client base in Colombia, allocating sales were allocated on a competitive basis to leading industry participants, including traders and other producers. We continued to deliver at both at well-head and at various points in the Colombian pipeline system and via Ecuador for the Putumayo production.
Our sales strategy is aimed at securing the highest available pricing for our production while securing a reliable and safe execution.path to market. To that end, we focus on developing synergies and strategic partnerships with both clients and the national transport systems, in order to obtain a reduction in costs and increased revenues by making use of the best alternatives available. Such is the case of the implementation of an unloading facility at Jaguey Station in partnership with Oleoducto de Los Llanos (ODL) in 2015. This unloading facility is located 42 kmkm. away from the Llanos 34 blockBlock and
75
allowed for reduced trucking distance and associated costs. Additionally, during 20182019 we developedcompleted a project to connect the Llanos 34 fieldBlock to the ODL pipeline via a flowline, which will be operational byflowline. In the secondthird quarter of 2019, we started sending our Jacana production volumes via this flowline to the ODL pipeline, eliminating trucking for that portion of our production and allowing further cost efficiencies and increased operational reliability. In November 2020, the flowline was converted into the Oleoducto del Casanare (“ODCA”) receiving full authorization from the Ministry of Energy and Mines to operate as such, determining the regulated tariff and allowing the transportation on of third party crudes. In 2020 we also inaugurated an unloading facility in Jacana, allowing for volumes of other fields to be transported via the ODCA. At the end of 2020, we connected the Tigana field to ODCA, further reducing transport of our volumes via truck. During 2021, ODCA was a central piece of our crude transportation in Colombia, including volumes of Jacana, Tigana and other fields. During this year, we also entered into an agreement to connect the third party owned Cabrestero Block to ODCA which will allow us to transport third party crude once the connection is completed.
In the case of the Platanillo Block in the Putumayo Basin, we gather the crude via truck and flowlines to pump it towards Ecuador via the Oloeducto Binacional Amerisur (“OBA”). This pipeline is operated by us and our affiliates and connects us to the Ecuadorean pipeline system via RODA allowing us to sell our production FOB in Esmeraldas port in Ecuador. We hold transport contracts with RODA and SOTE for the transport, storage and loading of our crude in Ecuador.
If we were to lose any of our customers, the loss could temporarily delay production and sale of our oil in the corresponding block. However, given the wide availability of customers for Colombian crude, we believe we could identify a substitute customer to purchase the impacted production volumes.
volumes in a very short period of time.
Chile
Our customer base in Chile is limited in number and primarily consists of ENAP and Methanex. For the year ended December 31, 20182021, we sold 100% of our oil production in Chile to ENAP and 99%100% of our gas production to Methanex, with sales to ENAP and Methanex accounting for 3%1% and 3%2%, respectively, of our total revenues in the same period.
On April 21, 2017, we renewedWe have a long-lasting commercial relationship with ENAP and have been selling our crude to them for the past years. We have a sales agreement with ENAP. As part of this agreement,ENAP whereby. ENAP has committed to purchase our oil production in the Fell Block in the amounts that we produce, subject to the limitation of available storage capacity at the Gregorio Terminal. The sales agreement provides us with the option to interrupt sales to ENAP periodically if conditions in the export markets allow for more competitive price levels. While the agreement renews automatically on an annual basis, we typically revise the agreement every year to reflect changes in the global oil market and make certain adjustments based on ENAP’s expenses related to storage at the Gregorio Terminal. As of the date of this annual report, our sales agreement with ENAP is set to expire on December 31, 2022.
General commercial conditions of our contract with ENAP have remained stable over time. We deliver the oil we produce in the Fell Block to ENAP at the Gregorio Terminal, where ENAP assumes responsibility for the oil transferred. ENAP owns two refineries in Chile in the north central part of the country and must ship any oil from the Gregorio Terminal to these refineries unless it is consumed locally.
In March 2017, we executed a new gas supply agreement with Methanex effective from May 1, 2017, to December 31, 2026. Under the agreement, Methanex commits to purchase up to 400,000 SCM/d of gas produced by us. In 2018, dueDuring 2020, we executed an additional amendment to increase the decline in gas production, thepurchase commitment was reduced to 315,000 SCM/d. We also hold an option to deliver up to 15% above550,000 SCM/d. As of the date of this volume.
annual report we are negotiating an amendment to increase the purchase commitment up to 600,000 SCM/d.
We gather the gas we produce in several wells through our own flow lines and inject it into several gas pipelines owned by ENAP. The transportation of the gas we sell to Methanex through these pipelines is pursuant to a private contract between Methanex and ENAP. We do not own any natural gas pipelines for the transportation of natural gas.
If we were to lose any one of our key customers in Chile, the loss could temporarily delay production and sale of our oil and gas in Chile. For a discussion of the risks associated with the loss of key customers, See “Item 3. Key Information—D. Risk factors—Risks relating to our business—We sell almost all of our natural gas in Chile to a single customer, who has in
76
the past temporarily idled its principal facility” and “—We derive a significant portion of our revenues from sales to a few key customers.”
Brazil
Our production in Brazil consists of natural gas, condensate and condensatecrude oil. Natural gas production is sold through a long-term, extendable agreement with Petrobras, which provides for the delivery and transportation of the gas produced in the Manati Field to the EVF gas treatment plant in the State of Bahia. The contract is in effect until delivery of the maximum committed volume or June 2030, whichever occurs first. The contract allows for sales above the maximum committed volume if mutually agreed by both seller and buyer. The price for the gas is fixed inreais and is adjusted annually in accordance with the Brazilian inflation index. In July 2015, we signed an amendment to the existing Gas Sales Agreement with Petrobras that covers 100% of the remaining gas reserves in the Manati Field.
The Manati Field is developed via a PMNT-1 production platform, which is connected to the Estação Vandemir Ferreira, or EVF, gas treatment plant through an offshore and onshore pipeline with a capacity of 335.5 mmcfpd (9.5 mm3 per day). The existing pipeline connects the field’s platform to the EVF gas treatment plant, which is owned by the field’s current concession holders. During 2015, in order to improve the field gas recovery and production, Manatì’s consortium built an onshore compression plant that started operating in August 2015, which allowed us to classify all existing proved undeveloped reserves as proved developed as of December 31, 2016.
The BCAM-40 Concession, which includes the Manati Field, also benefits from the advantages of Petrobras’ size. As the largest onshore and offshore operator in Brazil, Petrobras has the ability to mobilize the resources necessary to support its activities in the concession.
The condensate produced in the Manati Field is subject to a condensate purchase agreement with Petrobras, pursuant to which Petrobras has committed to purchase all of our condensate production in the Manati Field, but only in the amounts that we produce, without any minimum or maximum deliverable commitment from us. The agreement is valid through December 31, 2019,2022 and can be renewed upon an amendment signed by Petrobras and the seller.
Peru
In Peru, oil production is generally traded on a free market basis and commercial conditions generally follow international markers, normally WTI and Brent. As per the Joint Operating Agreement executed with Petroperu, Petroperu has the first option to acquire oil produced by us in the Morona Block by matching any offer received by third parties regarding such production.
Future production in the Morona Block is expected to be transported through the existing North Peruvian Pipeline to be sold to the domestic or export markets at the Bayovar port. The North Peruvian Pipeline and the Bayovar port are owned and operated by Petroperu, and regulated and supervised by Osinergmin, the regulatory body in the hydrocarbons sector. Transportation rates are negotiated with Petroperu. However, if an agreement cannot be reached between Petroperu and us, transportation rates will be determined by Osinergmin. The North Peruvian pipeline transported an average of 22,000 bopd in the first 9 months of 2018. On November 27, 2018, crude shipments on the North Line of the North Peruvian Pipeline were interrupted due to a blockage by a local community which resulted in a spill. In February 27, 2019, the Peruvian government reached an agreement with the local community that allowed the repairs to be made and the pipeline to restart operations in March 2019. See “Item 3. Risk factors—Risks relating to our business—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.”
Argentina
AllSince 2018, we have been selling the gas produced in Argentina through local gas marketing companies to the residential, industrial and power generation segments. According to local practices, gas is sold in annual agreements going from May to Grupo Albanesi, a leadingApril of each year. There is an ample availability of buyers in the Argentine privately held conglomerate focused on the energygas market that offers natural gas and power supply and transport services to its customers.could purchase our gas. We have an annual agreement in effect from May 20182021 through April 2019. According to local practices, this agreement contains seasonal prices, splitting between winter and summer prices.2022.
OurThe oil sales in Argentina arewere diversified across clients and delivery points. 30%points: i) 72% of our productionthe oil produced in Argentina (2%(3% of the consolidated revenues) isrevenue) was sold locally in the Neuquén Province andNeuquen, delivered at well-head. The remaining 70% (3%well-head; ii) 19% of the oil produced in Argentina (1% of the consolidated revenues) isrevenue) was sold to major local Argentinean refineries, delivered via pipeline; and iii) 9% of the oil produced in Argentina was exported to different traders, delivered via vessels. We managed the counterparty credit risk associated to sales contracts by limiting payment terms offered to minimize the exposure.
Ecuador
Ecuador has a well-developed crude oil market with broad access to international markets and delivered through pipeline. As usualan extensive pipeline transportation system. Future production from our recently acquired blocks in Ecuador is expected to be sold at the Esmeraldas port and linked to international benchmarks, namely Brent or WTI and local market,crude differentials (Napo or Oriente). We expect to transport our production on the sales agreements are executed for short-term renewable periods from one to three months.Ecuadorean existing pipeline system which has available capacity and competitive tariffs.
Significant Agreements
Colombia
E&P Contracts
We have entered into E&P Contractscontracts granting us the right to explore and operate, as well as working interests in sixtwenty three blocks in Colombia. These E&P Contractscontracts are generally divided into two periods: (1) the exploration period, which may be subdivided into various exploration phases and (2) the exploitation period, determined on a per-area basis and beginning on the date we declare an area to be commercially viable. Commercial viability is determined upon the completion of a specified evaluation program or as otherwise agreed by the parties to the relevant E&P Contract. The exploitation period for an area may be extended until such time as such area is no longer commercially viable and certain other conditions are met.
77
Pursuant to our E&P Contracts,contracts, we are required, as are all oil and gas companies undertaking exploratory and production activities in Colombia, to pay a royalty to the Colombian government based on our production of hydrocarbons, as of the time a field begins to produce. Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties we must pay in connection with our production of light and medium oil are calculated on a field-by-field basis. See Note 32.133.1 to our Consolidated Financial Statements.
Additionally, in the event that an exploitation area has produced amounts in excess of an aggregate amount established in the E&P Contract governing such area, the ANH is entitled to receive a “windfall profit,”profit”, to be paid periodically, calculated pursuant to such E&P Contract.
In each of the exploration and exploitation periods, we are also obligated to pay the ANH a subsoil use fee. During the exploration period, this fee is scaled depending on the contracted acreage. During the exploitation period, the fee is assessed on the amount of hydrocarbons produced, multiplied by a specified dollar amount per barrel of oil produced or thousand cubic feet of gas produced. Further, the ANH has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the relevant E&P Contract.
contract.
Our E&P Contractscontracts are generally subject to early termination for a breach by the parties, a default declaration, application of any of the contract’s unilateral termination clauses, ANH regulation or 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. Pursuant to Colombian law, if certain conditions are met, the anticipated termination declared by the ANH may also result in a restriction on the ability to engage contracts with the Colombian government during a certain period of time.period. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—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 Contractscontracts, production sharing agreements and concession agreements are subject to early termination in certain circumstances.”
Eastern Llanos Basin:
Llanos 34 Block E&P Contract. Pursuant to an E&P Contractcontract between Unión Temporal Llanos 34 (a consortium between Ramshorn and Winchester Oil and Gas - now GeoPark Colombia SAS) and the ANH that became effective as of March 13, 2009 (“Llanos 34 Block E&P Contract”), Unión Temporal Llanos 34 was granted the right to explore and operate the Llanos 34 Block, and weWinchester Oil and Gas and Ramshorn were granted a 40% and a 60% working interest, respectively, in the Llanos 34 Block. We were also granted the right to operate the Llanos 34 Block. On December 16, 2009, Winchester Oil and Gas (now GeoPark Colombia) entered into a joint operating agreement with Ramshorn and P1 Energy with respect to our operations in the block. As of the date of this annual report, the members of the UnionUnión Temporal Llanos 34 are GeoPark Colombia SAS with 45%, and Parex Verano Limited with 55% working interest.
We are currently in anOn September 19, 2019, the additional exploration period (the contract provides for two optional exploratory phases of 18 months each, in which the operator carries out exploratory activities in order to retain areas to explore) of the Llanos 34 Block E&P Contract with an exploitation program in execution over certain areas.ended (the E&P contract provides a 1-year Evaluation Program after a discovery declaration). As of the date of this annual report, the Guaco Evaluation Program is still ongoing. The Llanos 34 Block E&P contract also provides for a six-year exploration period consisting of two three-year phases. It also provides for a 24-year exploitation period for each commercialproduction area, which beginsbeginning on the date on which such area is declared commercially viable.of a commercial declaration. The exploitation period may be extended for periods of up to 10 years at a time until such time as the area is no longer commercially viable andif certain conditions are met. We have presented evaluation programsmet and subject to ANH approval. As of the ANHdate of this annual report there are production areas for the Tilo Field. We presented the declaration of commerciality of Max, Túa, Tarotaro, Tigana, Jacana, Chachalaca, Tilo, Chiricoca and Chachalaca, respectively.
Jacamar fields.
Pursuant to the Llanos 34 Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Llanos 34 Block. See Note 32.133.1 to our Consolidated Financial Statements.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Llanos 34 Block E&P Contract. The ANH also has an additional economic right equivalent to 1% of production, net of royalties.
In accordance with the Llanos 34 Block E&P Contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to
78
ANH a share of the production net of royalties in accordance with an established formula. See Note 33.1 to our Consolidated Financial Statements.
Llanos 32 Block. We have a 12.5% working interest in the Llanos 32 Block. Verano Energy is the operator of this block and has an 87.5% working interest. On February 27, 2020, the ANH approved an additional extension of two years to phase 2 of the subsequent exploratory program.
Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block association contract. Pacific Rubiales Energy is the operator of, and has a 100% working interest in, the Abanico Block. We do not maintain a direct working interest in the Abanico Block, but rather have a 10% economic interest in the net revenues from the block pursuant to a joint operating agreement initially entered into with Kappa Resources Colombia Limited (now Pacific, who subsequently assigned its participation interest to Cespa de Colombia S.A., who then assigned the interest to Explotaciones CMS Oil & Gas), Maral Finance Corporation and Getionar S.A.
Llanos 86 and Llanos 104 Blocks. We and Hocol (a subsidiary of Ecopetrol), each with fifty percent (50%) working interest executed an E&P contract over these blocks on July 11, 2019, as a result of the Permanent Competitive Process launched by ANH on 2019. We are the operator of these contracts that are into exploratory phase 1 as of the date of this annual report. We have requested the Ministry of Interior to certify if there are indigenous communities present in the area and the Ministry confirmed the presence of such communities. Therefore, we conducted the due prior consultation process with the communities. On March 15, 2022, the contracts entered into exploratory phase 1.
Llanos 87 Block. GeoPark and Hocol, each with fifty percent (50%) working interest executed an E&P contract over this block on July 11, 2019, as a result of the Permanent Competitive Process launched by ANH in 2019. The Ministry of Interior certified the absence of indigenous communities in the area. We are the operator of this contract that is currently in exploratory phase 1.
Llanos 123 and Llanos 124 Blocks: GeoPark and Hocol, each with fifty percent (50%) working interest executed an E&P contract over these blocks on December 20, 2019, as a result of the Permanent Competitive Process launched by ANH in 2019. We are the operator of these contracts.
Llanos 94 Block. On July 24, 2019 the E&P contract was awarded to Parex Energy as a result of the Permanent Competitive Process launched by ANH in 2019. This contract is in its exploratory phase 1. We acquired a 50% working interest from Parex and obtained ANH’s approval to such transfer in May, 2020.
CPO-5 Block E&P Contract. On December 26, 2008, the E&P Contract was executed between ONGC Videsh, as operator and the ANH as a result of the Competitive Process “Ronda Colombia 2008”. We hold a 30% working interest since the acquisition of Amerisur. The contract is in phase 2 of the exploration period as of the date of this annual report. There are two existing commercial fields called Mariposa and Indico field. Indico was declared commercially viable on August 19, 2021.
Pursuant to the CPO-5 Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the CPO-5 Block.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the CPO-5 Block E&P Contract. The ANH also has an additional economic right equivalent to 23% of production, net of royalties.
In accordance with the CPO-5 Block E&P Contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula.
79
Magdalena Basin:
VIM-3 Block. On July 23, 2014, we were awarded an exploratory license during the 2014 Colombia Bidding Round, carried out by the ANH. The VIM-3 Block is located in the Lower Magdalena Basin. In 2018, we filed a request before the ANH to terminate the E&P Contract due to environmental restrictions in the block. These restrictions became apparent once the National Authority of Environmental Licenses issued the environmental license. As of the date of this annual report the relinquishment of the VIM-3 Block is subject to approval of ANH.
Putumayo Basin:
Andaquies BlockE&P Contract. We are the operator of and have a 100% working interest in the Andaquies. As of the date of this annual report the contract is in phase 3 of the exploration period. We and the ANH already began the process of relinquishment of the E&P Contract and its subsequent liquidation.
Coati Block E&P Contract. We are the operator of and have a 100% working interest in the Coati Block. The Coati Block is divided in two areas: an exploration area in phase 3 of the exploration period, suspended due to Force Majeure Events (Prior Consultations); and an evaluation area, declared on September 2006, by the former operator in the southern part of the Block for the Temblon wells (Temblon Evaluation Program), which includes the completion and evaluation of the Coatí-1 well.
Pursuant to the Coati Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Coati Block E&P Contract.
In accordance with the Coati Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Mecaya Block E&P Contract. We are the operator of and have a 50% working interest in the Mecaya Block. Sierracol Energy is the owner of the remaining 50% working interest in the contract. As of the date of this annual report, the contract is in unified phases 1 and 2 of the exploration period, and it is suspended due to Force Majeure Events (Prior Consultations).
Pursuant to the Mecaya Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Mecaya Block.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Mecaya Block E&P Contract.
In accordance with the Mecaya Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. See Note 32.1 to our Consolidated Financial Statements.
WinchesterPlatanillo Block E&P Contract. We are the operator of and Luna Stock Purchase Agreement
have a 100% working interest in the Platanillo Block. On September 11, 2009, we began the commercial exploitation.
Pursuant to the stock purchase agreement entered intoPlatanillo Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Platanillo Block.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Platanillo Block E&P Contract.
80
In accordance with the Platanillo Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Putumayo 8 Block E&P Contract. We are the operator of and have a 50% working interest in the Putumayo 8 Block. Sierracol Energy is the owner of the remaining 50% working interest. The contract is in unified phases 1 and 2 of the exploration period.
Pursuant to the Putumayo 8 Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 8 Block E&P Contract. The ANH also has an additional economic right equivalent to 2% of production, net of royalties.
In accordance with the Putumayo 8 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Putumayo 9 Block E&P Contract. We are the operator of and have a 50% working interest in the Putumayo 9 Block. Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this annual report, the contract is in phase 1 of the exploration period, which is suspended since June 25, 2019, due to the occurrence of a Force Majeure event (issuance of the Municipal Agreement which prohibits the execution of hydrocarbons exploration and production activities in Puerto Guzmán Municipality).
Pursuant to the Putumayo 9 Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 9 Block E&P Contract. The ANH also has an additional economic right equivalent to 18% of production, net of royalties.
In accordance with the Putumayo 9 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Putumayo 12 Block E&P Contract. We are the operator of and have a 60% working interest in the Putumayo 12 Block. Pluspetrol Colombia Corporation (“Pluspetrol”) is the owner of the remaining 40% working interest. The contract is in phase 1 of the exploration period. On February 10, 2012 (the “Winchester 23, 2021, we requested the termination of the contract due to the occurrence of force majeure events related with judicial procedures initiated by ethnic communities. As of the date of this annual report, the ANH is reviewing our termination request.
Pursuant to the Putumayo 12 Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Putumayo 12 Block.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 12 Block E&P Contract. The ANH also has an additional economic right equivalent to 29% of production, net of royalties.
In accordance with the Putumayo 12 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula.
81
Putumayo 14 Block E&P Contract. We are the operator of and have a 100% working interest in the Putumayo 14 Block. The contract is in phase 0, as the applicable prior consultation process must be completed.
Pursuant to the Putumayo 14 Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 14 Block E&P Contract. The ANH also has an additional economic right equivalent to 5% of production, net of royalties.
In accordance with the Putumayo 14 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Putumayo 30 Block E&P Contract. We are the operator of and have a 100% working interest in the Putumayo 30 Block. On February 23, 2021, we submitted to the ANH our request to withdraw from to the E&P contract and transfer the remaining commitments to other E&P contracts. We transferred our investment to the Llanos 34 E&P Contract and to the Platanillo E&P Contract and as of the date of this annual report we are in process of termination and relinquishment of the Putumayo 30 E&P Contract, subject to ANH approval.
Putumayo 36 Block E&P Contract. We are the operator of and have a 50% working interest in the Putumayo 36 Block. Sierracol is the owner of the remaining 50% working interest. The contract is in preliminary phase, which is suspended since April 1, 2020 due to the occurrence of a Force Majeure Event (issuance of the Municipal Agreement which prohibits the execution of hydrocarbons exploration and production activities in Puerto Guzmán Municipality).
Pursuant to the Putumayo 36 Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 36 Block E&P Contract, and the payment of 25% of the Economic Right for the use of the subsoil for institutional strengthening and Technology Transfer.
The ANH also has an additional economic right equivalent to 1% of production, net of royalties.
In accordance with the Putumayo 36 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Tacacho Block E&P Contract. We are the operator of and have a 50% working interest in the Tacacho Block. Sierracol Energy is the owner of the remaining 50% working interest. The contract is in phase 1 of the exploration period, which is currently suspended due to the occurrence of force majeure events related with social and public order conditions of the area.
Pursuant to the Tacacho Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Tacacho Block E&P Contract.
In accordance with the Tacacho Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula.
82
Terecay Block E&P Contract. We are the operator of and have a 50% working interest in the Terecay Block. Sierracol Energy is the owner of the remaining 50% working interest. The contract is in phase 1 of the exploration period, which is currently suspended due to the occurrence of force majeure events related with social and public order conditions of the area.
Pursuant to the Terecay Block E&P Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block.
Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Terecay Block E&P Contract.
In accordance with the Terecay Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Stock Purchase Agreement”), we agreed to pay the Sellers a total consideration of US$30.0 million, adjusted for working capital. Additionally, under the terms of the Winchester Stock Purchase Agreement, weAgreements
We are obligated to make certain paymentspay an overriding royalty of 4% and 2.5%, respectively, to the Sellersprevious owners of the Llanos 34 and CPO-5 Blocks, based on the production and sale of hydrocarbons discovered by exploration wells drilled after October 25, 2011. Oncein the maximum earn-out amount is reached, we payblocks. During 2021, the Sellers quarterlyGroup has accrued US$22.6 million in relation with these overriding royaltiesroyalty agreements. Furthermore, there are overriding royalty agreements in an amount equalplace from 1.2% to 4%8.5% of the net production in the Andaquies, Coati, Mecaya, PUT-8, PUT-9, Tacacho and Terecay Blocks. Since they were exploratory blocks with no production during 2021, these agreements had no impact on our net revenues from any new discoveries of oil. For the year ended December 31, 2018, we accrued and paid US$20.6million and US$19.1 million with regards to this agreement.
results.
Chile
CEOPs
Currently, we have fivefour CEOPs in effect with Chile, one for each of the blocks in which we operate, which grant us the right to explore and exploit hydrocarbons in these blocks, determine our working interests in the blocks and appoint the operator of the blocks. These CEOPs are divided into two phases: (1) an exploration phase, which is divided into two or more exploration periods, and which begins on the effectiveness date of the relevant CEOP, and (2) an exploitation phase, which is determined on a per-field basis, commencing on the date we declare a field to be commercially viable and ending with the term of the relevant CEOP. In order to transition from the exploration phase to an exploitation phase, we must declare a discovery of hydrocarbons to the Ministry of Energy. This is a unilateral declaration, which grants us the right to test a field for a limited period of time for commercial viability. If the field proves commercially viable, we must make a further unilateral declaration to the Ministry of Energy. In the exploration phase, we are obligated to fulfill a minimum work commitment, which generally includes the drilling of wells, the performance of 2D or 3D seismic surveys, minimum capital commitments and guaranties or letters of credit, as set forth in the relevant CEOP. We also have relinquishment obligations at the end of each period in the exploration phase in respect of those areas in which we have not made a declaration of discovery. We can also voluntarily relinquish areas in which we have not declared discoveries of hydrocarbons at any time, at no cost to us. In the exploitation phase, we generally do not face formal work commitments, other than the development plans we file with the Chilean Ministry of Energy for each field declared to be commercially viable.
Our CEOPs provide us with the right to receive a monthly remuneration from Chile, payable in petroleum and gas, based either on the amount of petroleum and gas production per field or according to Recovery Factor, which considers the ratio of hydrocarbon sales to total cost of production (capital expenditures plus operating expenses). Pursuant to Chilean law, the rights contained in a CEOP cannot be modified without consent of the parties.
Our CEOPs are subject to early termination in certain circumstances, which vary depending upon the phase of the CEOP. During the exploration phase, Chile may terminate a CEOP in circumstances including a failure by us to comply with minimum work commitments at the termination of any exploration period, or a failure to communicate our intention to proceed with the next exploration period 30 days prior to its termination, a failure to provide the Chilean Ministry of
83
Energy the performance bonds required under the CEOP, a voluntary relinquishment by us of all areas under the CEOP or a failure by us to meet the requirements to enter into the exploitation phase upon the termination of the exploration phase. In the exploitation phase, Chile may terminate a CEOP if we stop performing any of the substantial obligations assumed under the CEOP without cause and do not cure such nonperformance pursuant to the terms of the concession, following notice of breach from the Chilean Ministry of Energy. Additionally, Chile may terminate the CEOP due to force majeure circumstances (as defined in the relevant CEOP). If Chile terminates a CEOP in the exploitation phase, we must transfer to Chile, 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. Other than as provided in the relevant CEOP, Chile cannot unilaterally terminate a CEOP without due compensation. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—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 Contractscontracts, production sharing agreements and concession agreements are subject to early termination in certain circumstances.”
Fell Block CEOP. On November 5, 2002, we acquired a percentage of rights and interests of the CEOP for the Fell Block with Chile, or the Fell Block CEOP, and on May 10, 2006, we became the sole owners, with 100% of the rights and interest in the Fell Block CEOP. Chile had originally entered into a CEOP for the Fell Block with ENAP and Cordex Petroleum Inc., or Cordex, on April 29, 1997, which had an effective date of August 25, 1997. The Fell Block CEOP grants us the exclusive right to explore and exploit hydrocarbons in the Fell Block and has a term of 35 years, beginning on the effective date. The Fell Block CEOP provided for a 14-year exploration period, composed of numerous phases that ended in 2011, and an up-to-35-year exploitation phase for each field.
The Fell Block CEOP provides us with a right to receive a monthly retribution from Chile payable in petroleum and gas, based on the following per-field formula: 95% of the oil produced in the field, for production of up to 5,000 bopd, ring fenced by field, and 97% of gas produced in the field, for production of up to 882.9 mmcfpd. In the event that we exceed these levels of production, our monthly retribution from Chile will decrease based on a sliding scale set forth under the Fell Block CEOP to a maximum of 50% of the oil and 60% of the gas that we produce per field.
TDF Blocks CEOPs. After an international bidding process led by ENAP and the Chilean Ministry of Energy, in March and April, 2012, we, together with ENAP, signed 3 new CEOPs for the Isla Norte, Campanario and Flamenco Blocks, all of them located in Tierra del Fuego (“TDF”), Magallanes region. Our working interest is 60% in Isla Norte and 50% in Campanario and Flamenco Blocks. The CEOPs have a term of 32 years, with an initial exploration phase which last for 7up to 10 years, including a first exploration period of 3 years in which we are committed to developing several exploration activities including 1,500 square kilometerssq. km. of 3D seismic registration, and the drilling of 21 exploratory wells.
The hydrocarbon discoveries opened up an exploitation phase that lasts up to 3225 years. We discovered hydrocarbon fields in the 3 blocks, starting in 2013 in the Flamenco Block, and in 2014 in both Campanario and Isla Norte Blocks. The CEOPs provide us with a right to receive a remuneration payable by means of a fraction of the production sold, which in the TDF Blocks is based on a formula depending on the recovery of the total accumulated expenses incurred (capital expenditure plus operational expenditure plus administrative and general expenses). While the recovery factor is less than 1.0, the remuneration is 95% of the hydrocarbons produced, either oil or gas. If the recovery factor surpasses 1.0, a formula applies reducing gradually the remuneration fraction to a minimum of 75% when the recovery factor is 2.5 times the total accumulated expenses.
Neuquén Exploitation Concessions. After receiving authorization in March 27, 2018 from the Province of Neuquén under Provincial Decree 266/2018, we closed the acquisition of a 100% interest in the Aguada Baguales, El Porvenir and Puesto Touquet hydrocarbon exploitation concessions from Pluspetrol S.A., together with an ancillary transportation concession over a natural gas pipeline from Puesto Touquet to Plaza Huincul, all in the Neuquén Basin in Argentina. These concessions had been originally granted to Pluspetrol S.A. for a term of 25 years in 1990 (Aguada Baguales and El Porvenir Blocks) and 1992 (Puesto Touquet Block). In 2008, the Province of Neuquén granted a ten year extension of these concessions in consideration of an investment program which included development, exploration and environmental remediation programs and a payment of a cash bonus in proportion to the in-situ hydrocarbon reserves of the blocks. At least one year prior to the end of the current ten year extension period, we are entitled to request a further ten year extension to these concessions in consideration for continued investments, an incremental 3% royalty (resulting in an aggregate 18% royalty) and a cash bonus equal to 2% of the then existing in-situ reserves.
Under these concessions, we are entitled to the exclusive right to develop the entire acreage of the concessions, produce, freely dispose and market all hydrocarbons we lift under a royalty tax system.
LGI Termination Agreement
Pursuant to the sale and purchase agreement entered into on November 28, 2018 (the “LGI Termination Agreement”), we agreed to pay LGI a total consideration of up to US$126 million for its entire equity interest in Geopark Chile, Geopark TdF and Geopark Colombia Coöperatie U.A. The acquisition price includes a fixed payment of US$81 million paid at closing, plus two equal installments of US$15 million each, to be paid in June 2019 and June 2020, respectively, and three contingent payments of US$5 million each, which could accrue over the next three years, subject to certain production thresholds being exceeded in the Llanos 34 Block. As a consequence of the LGI Termination Agreement we have become sole shareholder of the entities referred to above. See “Item 7. Major Shareholders and Related Parties—B. Related Party Transactions—LGI Termination Agreement.”
expenses.
Brazil
Overview of concession agreements
The Brazilian oil and gas industry is governed mainly by the Brazilian Petroleum Law, which provides for the granting of concessions to operate petroleum and gas fields in Brazil, subject to oversight by the ANP. A concession agreement is divided into two phases: (1) exploration and (2) development and production. The exploration phase which is further divided into two subsequentconsists of one exploratory periods, the first of whichperiod that begins on the date of execution of the concession agreement, can last from three to eight years (subject to earlier termination upon the total return of the concession area or the declaration of commercial viability with respect to a given area), while the development and production phase, which begins for each field on the date a declaration of commercial viability is submitted to the ANP, can last up to 27 years. Upon each declaration of commercial viability, a
84
concessionaire must submit to the ANP a development plan for the field within 180 days. The concessions may be renewed for an additional period equal to their original term if renewal is requested with at least 12 months’ notice and provided that a default under the concession agreement has not occurred and is then continuing. Even if obligations have been fulfilled under the concession agreement and the renewal request was appropriately filed, renewal of the concession is subject to the discretion of the ANP.
The main terms and conditions of a concession agreement are set forth in Article 43 of the Brazilian Petroleum Law, and include: (1) definition of the concession area; (2) validity and terms for exploration and production activities; (3) conditions for the return of concession areas; (4) guarantees to be provided by the concessionaire to ensure compliance with the concession agreement, including required investments during each phase; (5) penalties in the event of noncompliance with the terms of the concession agreement; (6) procedures related to the assignment of the agreement; and (7) rules for the return and vacancy of areas, including removal of equipment and facilities and the return of assets. Assignments of participation interests in a concession are subject to the approval of the ANP, and the replacement of a performance guarantee is treated as an assignment.
The main rights of the concessionaires (including us in our concession agreements) are: (1) the exclusive right of drilling and production in the concession area; (2) the ownership of the hydrocarbons produced; (3) the right to sell the hydrocarbons produced; and (4) the right to export the hydrocarbons produced. However, a concession agreement set forth that, in the event of a risk of a fuel supply shortage in Brazil, the concessionaire must fulfill the needs of the domestic market. In order to ensure the domestic supply, the Brazilian Petroleum Law granted the ANP the power to control the export of oil, natural gas and oil products.
Among the main obligations of the concessionaire are: (1) the assumption of costs and risks related to the exploration and production of hydrocarbons, including responsibility for environmental damages; (2) compliance with the requirements relating to acquisition of assets and services from domestic suppliers; (3) compliance with the requirements relating to execution of the minimum exploration program proposed in the winning bid; (4) activities for the conservation of reservoirs; (5) periodic reporting to the ANP; (6) payments for government participation; and (7) responsibility for the costs associated with the deactivation and abandonment of the facilities in accordance with Brazilian law and best practices in the oil industry.
A concessionaire is required to pay to the Brazilian government the following:
| a license fee; |
| rent for the occupation or retention of areas; |
| a special participation fee; |
| royalties; and |
| taxes. |
Rental fees for the occupation and maintenance of the concession areas are payable annually. For purposes of calculating these fees, the ANP takes into consideration factors such as the location and size of the relevant concession, the sedimentary basin and the geological characteristics of the relevant concession.
A special participation fee is an extraordinary charge that concessionaires must pay in the event of obtaining high production volumes and/or profitability from oil fields, according to criteria established by applicable regulations, and is payable on a quarterly basis for each field from the date on which extraordinary production occurs. This participation fee, whenever due, varies between 0% and 40% of net revenues depending on (1) the volume of production and (2) whether the concession is onshore or in shallow water or deep water. Under the Brazilian Petroleum Law and applicable regulations issued by the ANP, the special participation fee is calculated based on the quarterly net revenues of each field, which
85
consist of gross revenues calculated using reference prices established by the ANP (reflecting international prices and the exchange rate for the period) less:
| royalties paid; |
| investment in exploration; |
| operational costs; and |
| depreciation adjustments and applicable taxes. |
The Brazilian Petroleum Law also requires that the concessionaire of onshore fields pay to the landowners a special participation fee that varies between 0.5% to 1.0% of the net operational income originated by the field production.
BCAM-40 Concession Agreement. On August 6, 1998, the ANP and Petrobras executed the concession agreement governing the BCAM-40 Concession, or the BCAM-40 Concession Agreement, following the first round of bidding, referred to as Bid Round Zero, under the regime established by the Brazilian Petroleum Law. The exploitation phase will end in November 2029. On September 11, 2009, Petrobras announced the termination of BCAM-40 Concession’s exploration phase and the return of the exploratory area of the concession to the ANP, except for the Manati Field and the Camarão Norte Field.
Under the BCAM-40 Concession Agreement, the ANP is entitled to a monthly royalty payment equal to 7.5% of the production of oil and natural gas in the concession area. In addition, in case the special participation fee of 10% shall be applicable for a field in any quarter of the calendar year, the concessionaire is obliged to make qualified research and development investments equivalent to one percent of the field’s gross revenue. Area retention payments are also applicable under the concession agreement. We acquired Rio das Contas’ 10% participation interest in the BCAM-40 Concession on March 31, 2014. On November 22, 2020, we signed an agreement to sell our 10% participation interest in the Manati Block subject to certain precedent conditions that as the date of this annual report have not been met.
Rounds 11, 12, 13 and 14 Concession Agreements.
Under the Rounds 11, 12, 13 and 14 Concession Agreements, the ANP is entitled to a monthly royalty corresponding to up to 10% of the production of oil and natural gas in the concession area, in addition to the special participation fee described above, the payment for the occupation of the concession area of approximately R$7,600 per year and the payment to the owners of the land of the concession equivalent to one percent of the oil and natural gas produced in the concession area.
During bidding, a work program offer is made in the form of work units and the ANP asks for a guarantee of a monetary amount proportional to the offered units. However, depending on the work performed by the operator, the actual work program investment might have a different value to the guaranteed value.
Overview of consortium agreements
A consortium agreement is a standard document describing consortium members’ respective percentages of participation and appointment of the operator. It generally provides for joint execution of oil and natural gas exploration, development and production activities in each of the concession areas. These agreements set forth the allocation of expenses for each of the parties with respect to their respective participation interests in the concession. The agreements are supplemented by joint operating agreements, which are private instruments that typically regulate the aggregation of funds, the sharing of costs, mitigation of operational risks, preemptive rights and the operator’s activities.
An important characteristic of the consortia for exploration and production of oil and natural gas that differs from other consortia (Article 278, paragraph 1, of the Brazilian Corporate Law) is the joint liability among consortium members as established in the Brazilian Petroleum Law (Article 38, item II).
86
BCAM-40 Consortium Agreement
On January 14, 2000, Petrobras, EnautaQueiroz Galvão Perfurações (now Enauta) and Petroserv entered into a consortium agreement, or the BCAM-40 Consortium Agreement, for the performance of the BCAM-40 Concession Agreement. Petrobras is the operator of the BCAM-40 concession, with a 35% participation interest. Enauta, BrasoilPetroRio and Rio das ContasGeoPark Brazil have a 45%, 10% and 10% participation interest, respectively. The BCAM-40 Consortium Agreement has a specified term of 40 years, terminating on January 14, 2040 and, at the time the obligations undertaken in the agreement are fully completed, the parties will have the right to terminate it. The BCAM-40 Concession consortium has also entered into a joint operating agreement, which sets out the rights and obligations of the parties in respect of the operations in the concession.
Petrobras Natural Gas Purchase Agreement
Enauta, GeoPark Brasil, BrasoilPetroRio and Petrobras are party to a natural gas purchase agreement providing for the sale of natural gas by Enauta, GeoPark Brasil and BrasoilPetroRio to Petrobras, in an amount of 812 billion cubic feet (“bcf”) over the term of agreement. The Petrobras Natural Gas Purchase Agreement is valid until the earlier of Petrobras’ receipt of this total contractual quantity or June 30, 2030. The agreement may not be fully or partially assigned except upon execution of an assignment agreement with the written consent of the other parties, which consent may not be unreasonably withheld provided that certain prerequisites have been met.
The agreement provides for the provision of “daily contractual quantities” to Petrobras peaking at 170.3 mmcfd in 2016 and progressively dropping until 2030. The parties may agree to lower volumes as dictated by Manati Field’s depletion. Pursuant to the agreement, the base price is denominated in reais and is adjusted annually for inflation pursuant to the general index of market prices (IGPM). Additionally, the gas price applicable on a given day is subject to reduction as a result of the gas quantity acquired by Petrobras above the volume of the annual TOP commitment (85% of the daily contracted quantity) in effect on such day. The Petrobras Natural Gas Purchase Agreement provides that all of the Manati Field’s daily production be sold to Petrobras.
Peru
Morona Block
On October 1, 2014,November 22, 2020, we entered intosigned an agreement with Petroperu to acquire ansell our 10% participation interest in and operate the MoronaManati Block located in Northern Peru. We will assume a 75% working interestsubject to certain conditions that as the date of the Morona Block, with Petroperu retaining a 25% working interest. On December 1, 2016, through Supreme Decree N° 031-2016-MEN the Peruvian government approved the amendment to the License Contract of Block 64 (Morona Block) appointing GeoPark as operator and holder of 75% of the Contract.
In Peru, there is a 5-20% sliding scale royalty rate, depending on production levels. Production less than 5,000 bopd is assessed at a royalty rate of 5%. For production between 5,000 and 100,000 bopd there is a linear sliding scale between 5% and 20%. Production over 100,000 bopd has a flat royalty of 20%.
See “Item 4. Information on the Company—B. Business Overview—Our operations—Operations in Peru—Morona Block.”
this annual report have not been met.
Argentina
Overview of exploration permits
Our exploration permits grant to us and our partners the exclusive right to explore for hydrocarbons and declare a commercial discovery within the acreage of our permits. Our exploration permits are made up of three subperiods, each lasting 3, 2 and 1 year(s), respectively, plus an extension period of up to 5 years.
We are bound to pursue specific minimum work or investment commitments during each of the subperiods of each exploration permit. Such exploration works are valued in work units assigned to each particular type of work under the applicable bidding conditions.
Work and investment programs for the permits are required to be assured by issuing a performance bond for the value of the committed work plan.
Under the terms of our exploration permits and concession agreements, we are entitled to our proportionate share of the hydrocarbons production lifted from each block. The Province of Mendoza’s state ownedstate-owned company, EMESA, has a 10% carried interest in each of the Puelen and Sierra del Nevado permits and any future exploitation concessions, while there is no governmental participation in the CN-V Block. During the term of our exploration permits, we are also required, under Argentine law, to pay a 15% royalty to the province on both oil and gas sales. In case we progress to an exploitation concession, the applicable royalty rate will reduce to a 12% royalty. We also pay annual surface rental fees established under Hydrocarbons Law 17,319 (“Hydrocarbons Law”) and Resolution 588/98 of the Argentine Secretariat of Energy and Decree 1454/2007, and certain landowner fees. We are in process of relinquishing the Puelen Block and already relinquished the CN-V and Sierra del Nevado Blocks as of the date of this annual report.
87
Our Argentine exploration permits have no change of control provisions, though any assignment of these concessions is subject to the prior authorization by the executive branch of the Province of Mendoza and rights of first refusal in favor of our partners and EMESA, in the case of the Puelen and Sierra del Nevado permits. Each of these permits or future concessions can be terminated for default in payment obligations and/or breach of material statutory or regulatory obligations. We are subject to the obligation to relinquish at least 50% of the acreage of each exploration permit at the end of each exploration subperiod. We may also voluntarily relinquish acreage to the provincial authorities.
Our Argentine exploration permits are governed by the laws of Argentina and the resolution of any disputes must be sought in the Mendoza Provincial Courts.
If and when we make a commercial discovery in one or more of our exploration permits, we will have the right to request and obtain an exploitation concession to produce hydrocarbons in the block for 25 years, with an optional extension of up to 10 years. We also receive the right to be granted a 35-year oil transport concession to build and make use of pipelines or other transport facilities beyond the boundaries of the concession.
Additionally, oil and gas producers in Argentina must grant a privilege to the domestic market to the detriment of the export market, including hydrocarbon export restrictions, domestic price controls, export duties and domestic market supplier obligations.
Neuquén Exploitation Concessions.
Pluspetrol Asset Purchase Agreement
Pursuant toAfter receiving authorization in March 27, 2018, from the APA thatProvince of Neuquén under Provincial Decree 266/2018, we entered into on December 18, 2017 with Pluspetrol, we agreed to acquireclosed the acquisition of a 100% working interest and operatorship ofin the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina forhydrocarbon exploitation concessions from Pluspetrol S.A., together with an ancillary transportation concession over a total consideration of $52 million. The blocks include estimated oil andnatural gas production of 2,700 boepd (70% light oil and 30% gas), 137,000 acres well-positionedpipeline from Puesto Touquet to Plaza Huincul, all in the Neuquén Basin in Argentina. These concessions had been originally granted to Pluspetrol S.A. for a term of 25 years in 1990 (Aguada Baguales and production facilities, includingEl Porvenir Blocks) and 1992 (Puesto Touquet Block). In 2008, the Province of Neuquén granted a ten year extension of these concessions in consideration of an investment program which included development, exploration and environmental remediation programs and a payment of a cash bonus in proportion to the in-situ hydrocarbon reserves of the blocks. At least one year prior to the end of the current ten year extension period, we are entitled to request a further ten year extension to these concessions in consideration for continued investments, an incremental 3% royalty (resulting in an aggregate 18% royalty) and a cash bonus equal to 2% of the then existing in-situ reserves.
Under these concessions, we are entitled to the exclusive right to develop the entire acreage of the concessions, produce, freely dispose and market all hydrocarbons treatment, storage,we lift under a royalty tax system.
During May 2021, we initiated a process to evaluate the farm-out/divestment opportunities for some of our Argentinian assets. As a consequence of this process, on November 3, 2021, we executed an agreement with Oilstone Energía S.A. for the assignment of 100% of our working interest and delivery infrastructure.
We paidoperatorship to Oilstone Energía S.A. in the consideration using proceedsAguada Baguales, El Porvenir and Puesto Touquet hydrocarbon exploitation concessions, together with an ancillary transportation concession over a natural gas pipeline from Puesto Touquet to Plaza Huincul. After receiving authorization from the offeringProvince of Neuquén under Provincial Decree 119/2022, on January 31, 2022, we completed the Notes due 2024. The acquisitionassignment of the blocks closed on March 27, 2018.
such concessions to Oilstone Energía S.A.
Title to properties
In each of the countries in which we operate, the state is the exclusive owner of all hydrocarbon resources located in such country and has full authority to determine the rights, royalties or compensation to be paid by private investors for the exploration or production of any hydrocarbon reserves. In Chile, the Republic of Chile grants such rights through a CEOP. In Colombia, the Republic of Colombia grants such rights through E&P Contractscontracts or contracts of association. In Argentina, the Argentine Republic grants such rights through exploitation concessions. In Brazil, the Federative Republic of Brazil grants such rights pursuant to concession agreements. See “Item 3. Key Information—D. Risk factors—Risks relating to the countries in which we operate—Oil and natural gas companies in Colombia, Chile, Brazil, Argentina, and PeruEcuador do not own any of the oil and natural gas reserves in such countries.” Other than as specified in this annual report,
88
we believe that we have satisfactory rights to exploit or benefit economically from the oil and gas reserves in the blocks in which we have an interest in accordance with standards generally accepted in the international oil and gas industry. Our CEOPs, E&P Contracts,contracts, contracts of association, exploitation concessions and concession agreements are subject to customary royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of or affect the carrying value of our interests. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—We are not, and may not be in the future, the sole owner or operator of all of our licensed areas and do not, and may not in the future, hold all of the working interests in certain 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,non-wholly owned, assets.”
Our customers
In Colombia, our primary customer is Trafigura,the oil and who represented 82%gas production was sold to three clients that concentrate 99% of the Colombian subsidiaries revenue (89% of our total revenuesconsolidated revenue) for the year ended December 31, 2018.2021. In Chile, our primary customers are ENAP and Methanex. As of December 31, 2018,2021, ENAP purchased all of our Chilean oil and condensate production and Methanex purchased almost all of our natural gas production in Chile, and represented 3%1% and 3%2%, respectively, of our total revenues for the year ended December 31, 2018.2021. In Brazil, all of our hydrocarbons in Manati are sold to Petrobras.Petrobras and represented 3% of our total revenue for the year ended December 31, 2021. In Argentina, all the gas produced is sold to Grupo Albanesisales are channelled thought local gas marketing companies and represented 1% of our total revenues. Ourrevenue. The oil productionsales in Argentina is split between local buyers in the Neuquén Province, delivered at well-head (2%were diversified across clients and delivery points: i) 72% of consolidated revenues) and major refineries, delivered through pipeline (3% of consolidated revenues). In Peru, our primary customers are local refineries (Petroperu or Repsol) or the export market. Petroperu, has the first option to acquire the oil produced in Argentina (3% of the consolidated revenue for the year ended December 31, 2021) was sold locally in Neuquen, delivered at well-head; ii) 19% of the oil produced in Argentina (1% of the consolidated revenue for the year ended December 31, 2021) was sold to major local Argentinean refineries, delivered via pipeline; and iii) 9% of the oil produced in Argentina was exported to different traders (less than 1% of the total consolidated revenue for the year ended December 31, 2021), delivered via vessels. We managed the counterparty credit risk associated to sales contracts by us inlimiting payment terms offered to minimize the Morona Block by matching any offer received by third parties regarding such production.
exposure.
Seasonality
Although there is some historical seasonality to the prices that we receive for our production, the impact of such seasonality has not been material. Seasonality has also not played a significant role in our ability to conduct our operations, including drilling and completion activities.
However, as the Morona Block is located in a remote area, the development of the project depends on significant infrastructure being built which can be impacted by seasonal weather patterns, including rain. Since there are no roads available in the surrounding area, logistics will be performed by helicopters or barges during specific seasons of the year.
We take such seasonality into account in planning for and conducting our operations, such that the impact on our overall business is not material.
Our competition
The oil and gas industry is competitive, and we may encounter strong competition from other independent operators and from major state-owned oil companies in acquiring and developing licenses in the countries where we operate or plan to operate.
Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful wells, sustained periods of volatility in financial and commodities markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—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 may also be affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill wells and conduct our operations.
89
Health, safety and environmental matters
General
Our operations are subjectcorporate HSE commitment governs our actions, in accordance with the legal framework, industry best practices and international standards in terms of socio-environmental performance. We work closely with our suppliers and contractors to various stringenttransfer the best HSE practices throughout our value chain and complex international, federal, stateextend our responsibility towards the environment, with binding contractual agreements, monthly safety and local environmental healthperformance evaluations, annual compliance evaluations and safety lawsthe construction of capacities and regulationscompetencies necessaries to be in line with our environmental commitment.
We have an environmental management and feasibility strategy that allows us to guarantee the development of plans and actions that ensure respect and protection of the environment in the countries in whichterritories where we operate. These laws
In each of the countries where we operate, we ensure compliance with applicable environmental requirements. All our operations have the environmental licenses and regulations govern matters includingpermits required under the emissionapplicable legislation, which are derived from the development of environmental studies with citizen participation for the definition of management measures and dischargeimpact mitigation.
Our Environmental Management System (EMS) certified under the ISO standard: 14001:2015 for our operations in Colombia, defines programs for the integral management of pollutants into the ground, air or water; the generation, storage, handling, usewater resources; solid and transportation of regulated materials;liquid waste management; atmospheric and human healthenergy emissions; biodiversity and safety. These lawsecosystem services and regulations may, among other things:
These lawstraining and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. Compliance with these laws can be costly. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.
Public interest inawareness regarding the protection of the environment continuesfor employees and suppliers. In addition, it defines the roles and responsibilities of the management regarding to increase. Drillingthe performance of our environmental issues.
Although we do not have a certified EMS in somecountries such as Ecuador, Chile and Argentina, we have implemented the main programs contemplated by our corporate environmental commitment.
Our corporate environmental commitment is mainly based on the management of the following issues:
Integral water management
We recognize water as a strategic resource and axis of sustainable development in the territories. For this reason, we implement initiatives and strategies for saving and efficient use of the resource, and we focus our efforts on seeking efficiencies in the operation and on reducing environmental impacts and conflicts associated with water management.
We have an integral water management program that allows us to monitor the information necessary to control its use and consumption, ensure compliance with our environmental permits and take the necessary measures to control the different activities where we use water.
All the waste waters generated in our operations is treated and disposed of in accordance with the environmental licenses.
In 2021 we did not use surface water sources in our permanent operations in Colombia and we did not carry out any type of dumping in surface water, to avoid any possible conflict with the other users of this resource.
Biodiversity
Through our management, we articulate our efforts to avoid, mitigate an eliminate any impact that may represent a material risk to the biodiversity of the environment in where we operate. We recognize the importance of the biodiversity in the areas has been opposed by certain communityof our interest since the planning of projects stage. This situation forces us to apply prevention criteria that guide the execution of our operational projects. In addition, we participate and environmental groupspromote programs related to the rehabilitation, restoration and in other areas, has been restricted.conservation of ecosystems through strategic alliances for the conservation of biodiversity.
90
Climate change
Our response to climate change and our contribution to achieve the goal of sustainable development number 13 of the United Nations is part of the strategy of minimize emissions of Greenhouse Gas (GHG) announced by us in November 2021, following the approval of our Board of Directors of the voluntary reduction voluntarily goals adopted by us:
| ● | 35-40% GHG emissions intensity reduction of Scope 1 and 2 emissions by or before 2025; |
| ● | 40-60% GHG emissions intensity reduction of Scope 1 and 2 emissions by 2025-2030; and |
| ● | Net zero Scope 1 and 2 emissions by or before 2050. |
These goals take into account the execution of some operational and environmental projects. The following projects are the most relevant for 2022 in Colombia:
| ● | The interconnection of the core Llanos 34 Block to Colombia’s national grid by 2022, a decisive near-term catalyst to improve carbon performance and operational reliability, while reducing cost of energy generation; |
| ● | Other initiatives underway in the Llanos 34 Block, including a solar photovoltaic plant expected to be operational by the end of 2022 plus subsoil and surface optimization projects; and |
| ● | Increased use of gas for energy generation plus subsoil and surface optimization projects in the Platanillo Block. |
Medium-term actions include small-scale hydropower projects, reforestation and afforestation initiatives, among others.
BothLonger-term actions may include carbon capture, use and storage projects and potential participation in carbon markets.
As of the date of this annual report we have other ongoing environmental initiatives to mention, such as:
| ● | In Colombia, we began the execution of an agreement with the Institute of Hydrology, Meteorology and Environmental Studies (IDEAM) for the strengthening and modernization of the hydrometeorological monitoring network of the Orinoquía, in the hydrographic zone of the Meta River, which will contribute to improving water management, comprehensive risk management and adaptation to climate change. |
| ● | We developed projects focused on the conservation and protection of ecosystems, implementing initiatives that contribute to the reduction of biodiversity loss, the promotion of conservation of the environment and the stability of ecosystems. |
| ● | In 2021 we renewed our commitment to the Putumayo Regional Agreement for Biodiversity and Development, which integrates efforts by the private sector and national and regional entities to preserve the biodiversity and connectivity of this region of the Amazon. This agreement currently has the participation of the National Association of Entrepreneurs of Colombia (ANDI), the Ministry of Environment and Sustainable Development, the National Authority for Environmental Licenses (ANLA), the National Natural Parks of Colombia, the Amazon Research Institute (SINCHI), the von Humboldt Biological Resources Research Institute, the Institute of Hydrology, Meteorology and Environmental Studies, IDEAM and the companies in the oil and gas industry that operates in Putumayo, Colombia. |
| ● | In Ecuador, in the canton of Shushufindi, province of Sucumbios, we developed, in coordination with the local and provincial government, a project for the recovery of plant cover in areas of watercourses and |
91
| estuaries with an ecosystem, landscape and watershed protection approach, in order to improve the natural balance and the biodiversity of the territory. |
| ● | We actively participated in initiatives led by national governments in the countries where we operate focused on reducing deforestation. In 2021, we contributed by planting more than 38,000 trees, as part of our environmental obligations and voluntary initiatives. |
Integral waste management and circular economy
Regarding the proper management of solid waste generated by our activities, we focus our management on the principles of reduce, reuse, recycle and recover. In this way we ensure the mitigation of environmental impacts, while complying with applicable regulations. In 2021, we define the circular economy as one of our material environmental aspects, so in 2022, we will work on define our strategy and roadmap on this issue.
Spill Management
In 2021, there were no recordable hydrocarbon spills (>1Bbl uncontained) in our operations andin Colombia. In corporate terms, we closed the combustionyear with an OBS of oil and natural gas-based products results in0.05 barrels spilled per million barrels produced, this indicator was 93% lower than that of the emission of greenhouse gases, which may contribute to global climate change. Climate change regulation has gained momentum in recent years internationally and at the federal, regional, state and local levels. On the international level, various nations have committed to reducing their greenhouse gas emissions pursuant to the Kyoto Protocol. The Kyoto Protocol was set to expire in 2012. In late 2011, an international climate change conference in Durban, South Africa resulted in, among other things, an agreement to negotiate a new climate change regime by 2015 that would aim to cover all major greenhouse gas emitters worldwide, including the U.S., and take effect byyear 2020. In November and December 2012, at an international meeting held in Doha, Qatar, the Kyoto Protocol was extended by amendment until 2020. In addition, the Durban agreement to develop the protocol’s successor by 2015 and implement it by 2020 was reinforced. We are committed to controlling the emission of greenhouse gases and implementing available technologies to reduce the impact caused by our operations. For example, during 2016 we began a migration plan to replace diesel with natural gas and electric generation.
Our HSE Management System
Our health, safety and environmental management plan is focused on undertaking realistic and practical programs based on recognized world practices. Our emphasis is on building key principles and company-wide ownership and then expanding programs as we continue growing. Our S.P.E.E.D. philosophy and our HSE Plan have been developed with reference to ISO 14001 for environmental management issues, ISO 45000 for occupational health and safety management issues, SA 8000 for social accountability and workers’ rights issues and applicable World Bank Standards.
general guidelines from international entities such as IOGP, IPIECA, IADC and ARPEL.
Our EnvironmentalHSE Policy
Our policy looks forwardseeks to meet or exceed safety and environmental regulations in the countries in which we operate. We believe that oil and gas can be produced in an environmentally-responsibleenvironmentally responsible manner with proper care, understanding and management. Within our S.P.E.E.D. philosophy we have a team that is exclusively focused on securing the environmental authorizations and permits for the projects we undertake. This professional and trained team, specialized in environmental issues, is also responsible for the achievement of the environmental standards set by our Board of Directors and for training and supporting our personnel. Our senior executives, personnel in the field, visitors and contractors have also received training in proper environmental management.
Our Healthhealth and Safety Policy
safety practices and outcomes
We continue looking for the bestto improve and update management tools to managestrengthen our health and safety policy. In 20182021 we startedreached several significant milestones, among which the implementationfollowing stand out:
| ● | In the Llanos 34 Block, three drill rigs completed two years without lost-time incidents. |
| ● | We maintain the Safeguard Certification from Bureau Veritas for our COVID-19 protocols in the Llanos 34 and Platanillo Blocks and our administrative offices in Bogotá. |
| ● | Our assets in Chile and Argentina, which maintained a constant operation throughout 2021, had no recordable people incidents. |
92
As of December 31, 2018, on2021, in the last 12-month basis,twelve months, our HSE development statistics workforce showsHS indicators were the following:
People injury. Indicators calculated per 1,000,000 hours worked:
| ● | Lost time injury rate (LTIF) of 0.40. |
| ● | Total recordable incident rate (TRIR) of 0.80. |
| ● | Zero fatal incidents in the operation. |
Vehicle incidents, calculated per 1,000,000 kilometres travelled:
| ● | Rate of recordable vehicular incidents (MVC) of 0.23. |
COVID-19 Pandemic
2020 brought an additional challenge to our work environment. The social and health emergency resulting from the COVID-19 pandemic made us rethink and reinforce operations from our health and safety practices. Our goal is to keep operations active under the premise that Lost Time Injury Frequency (LTIF) was 0.42 (out of every 1,000,000 worked hours), our Total Recordable Incident Rate (TRIR) was 1.25 (out of every 1,000,000 worked hours)employees, contractors and visitors are healthy. During 2021, we continued applying the practices implemented last year and we had no fatal incidents relatedimplemented some new practices:
| ● | Maintain a corporate crisis committee to lead and attend to the situation generated by the emergency. |
| ● | Continuous communications with official and truthful information regarding the disease, prevention measures and care. |
| ● | Implementation of bio-security protocols for COVID-19 that regulate and refer to the best practices for entry and permanence in operations. |
| ● | Implementation of screening tests for early detection of the disease, implemented before entering operational shifts. |
| ● | Implementation of a “bubble” strategy to maintain control of specific crews and reduce the exposure and accumulation of personnel in common areas of the operation. Likewise, this strategy helps us control the contacts of people who may be suspected of contagion, preventing the disease from spreading through different field activities. |
| ● | Reinforcement in occupational health plans and patient care in the field. |
| ● | Creation of shock plans and operational continuity to make operations viable in the face of the worst scenarios that could arise caused by the disease. |
| ● | Maintain administrative work from home. |
| ● | Permanent training on implementation of bio-security protocols. |
| ● | Encourage our employees and contractors to get vaccinated against COVID-19. As of the date of this annual report, a large proportion of our employees and contractors were vaccinated against COVID-19. |
During 2021, we maintain under control the COVID-19 infection rate and we can continue our operations in 2018.without interruptions.
93
In 2016, we subscribed to the International AssociationTable of Oil and Gas Producers in order to align our Management System and policies with the best international standards.Contents
Certain Bermuda law considerations
As a Bermuda exempted company, we and our Bermuda subsidiaries are subject to regulation in Bermuda. We have been designated by the BMABermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermuda dollar, and there are no restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda.
Under Bermuda’s law, “exempted” companiesBermuda or to pay dividends to United States residents who are companies formed for the purposeholders of conducting business outside Bermuda from a principal place of business in Bermuda. As exempted companies, we and our Bermuda subsidiaries may not, without a license or consent granted by the Minister of Finance of Bermuda, participate in certain business transactions, including transactions involving Bermuda landholding rights and the carrying on of business of any kind for which we or our Bermuda subsidiaries are not licensed in Bermuda.
common shares.
Insurance
We maintain insurance coverage of types and amounts that we believe to be customary and reasonable for companies of our size and with similar operations in the oil and gas industry. However, as is customary in the industry, we do not insure fully against all risks associated with our business, either because such insurance is not available or because premium costs are considered prohibitive.
Currently, our insurance program includes, among other things, construction, fire, vehicle, technical, umbrella liability, cyber security, director’s and officer’s liability and employer’s liability coverage. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. A loss not fully covered by insurance could have a materially adverse effect on our business, financial condition and results of operations. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—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.”
Industry and regulatory framework
Colombia
Regulation of the oil and gas industry
The ANH is responsible for managing all exploration landsacreage not subject to previously existing association contracts with Ecopetrol. TheTwo decades ago, the ANH began offering all undeveloped and unlicensed exploration areas in the country under concession-fashion Exploration and Production Contracts (“E&P Contractscontracts”) and Technical Evaluation Agreements, or TEAs,(or “TEAs”), which resulted in a significant increase in Colombian exploration activity and competition, according to the ANH. The ANH is also in charge of negotiating and executing contracts through “direct negotiation” mechanisms with attention to special conditions in the areas to be explored, however the ANH has not issued the regulation for such direct granting of contracts. The regulatory landscape in Colombia has recently changed. The regime for the ANH’s contracts is set forth in Agreement 008 of 2004 and Agreement 004 of 2012. AccordAgreement 008 of 2004 issued by the Directive Council of the ANH, as repealed and replaced by AccordAgreement 004 of 2012, sets forth the necessary steps for entering into E&P Contractscontracts with the ANH. This Agreement regulates E&P contracts entered into from May 4, 2012.2012 and onwards. E&P contracts entered into before that date are still regulated by Agreement 008 of 2004. Due to the oil price crisis of 2015, the ANH implemented transitory measures through Agreements 002, 003, 004 and 005 of 2015. On May 18, 2017, the ANH issued Agreement 002, which repealed and replaced Agreement 004 of 2012 and transitory measures adopted in 2014 and 2015. Agreement 002 of 2017 established rules for the allocation ofgranting hydrocarbon areas and adopted criteria for the exploration and exploitation of hydrocarbons owned by Colombia, including the selection of contractors, and management, execution, termination, liquidation, monitoring, control and supervision of corresponding contracts. Agreement 002 of 2017 regulates contracts entered into from May 18, 2017.2017 and onwards. E&P contracts entered into before that date are still regulated by the Agreements under which they were executed.
In 2020, and due to COVID-19 pandemic and the then-current oil low price scenario, the ANH issued Agreement 002 of 2020 with transitory relief measures such as term extensions for the exploratory phases, reduction of the amounts of the guarantees, among other measures. All of these measures are subject to the accomplishment of certain conditions, some of which are related to the average oil price for prior months. In 2021 ANH issued Agreement 010 of 2021 to enable the execution of pending investments in any free area in the map of available areas published by ANH. This will allow companies with E&P Contracts that have pending obligations (investments) to execute them in other areas.
94
Regulatory framework
Regulation of exploration and production activities
Pursuant to Colombian law, the state is the exclusive owner of all hydrocarbon resources located in Colombia and has full authority to determine the rights, royalties or compensation to be paid by private investors for the exploration or production of any hydrocarbon reserves. The Ministry of Mines and Energy is the authority responsible for creating national energy policy and regulating all activities related to the exploration and production of hydrocarbons in Colombia.
Decree Law 1056 of 1953 (Código de Petróleos), or the Petroleum Code, establishes the general procedures and requirements that must be completed by a private investor and disclosure procedures that need toshould be followedmet during the performance of these activities.
Exploration and production activities were governed by Decree 1895 of 1973 until September 2009. Decree Law 2310 of 1974 (as complemented by Decree 743 of 1975) governed the contracts and contracting processes carried out by Ecopetrol and the rules applicable to such contracts, and also provided that Ecopetrol was responsible for administering the hydrocarbons resources in the Country. Decree 2310 of 1974 was replaced by Decree Law 1760 of 2003, which restructured the hydrocarbons sector, but all agreements entered into by usEcopetrol prior to 2003 with other oil companies are still regulated by Decree 2310 of 1974.
By Decree Law 1760 of 2003, Ecopetrol was spun-off and the ANH was created. One of the main purposes of this decree was to treat Ecopetrol as another oil and gas company in the market and to transfer regulatory functions to the ANH as administrator of the nation’s hydrocarbons. This enabled Ecopetrol to differentiate its role and avoid it being party and judge to contractual matters.
Resolution 18-1495 of 2009, modified by Resolution 40048 of 2015, establishes a series of regulations regarding hydrocarbon exploration and exploitation. In the E&P Contracts,contracts, operators are afforded access to blocks by committing to perform an explorationexploratory work program. These E&P Contractscontracts provide companies with 100% of new production, less the participation of the ANH, which participation may differ for each E&P Contract and depends on the percentage that each company has offered to the ANH in order to be granted with a block, subject to an initial royalty payment of 8%applicable royalties and the payment of income taxes of 33%.revenue taxes. In addition, the Colombian government also introduced TEAs, in which companies that enter into TEAs are the only ones to have the right to explore, evaluate and select desirable exploration areas by executing seismic and /or drilling stratigraphic wells and to propose work commitments on those areas, and have a preemptive right to enter into an E&P Contract (Right to convert the TEA Contract into an E&P Contract), thereby providing companies with low-cost access to larger areas for preliminary evaluation prior to committing to broader exploration programs. A preemptive right is grantedUnder a TEA, the contractor commits to convertexclusively perform the TEA into an E&P Contract. Exploration activities can only be carried out by the TEA contractor.
committed exploration activities.
Pursuant to Colombian law, oil companies are obligatedobliged to pay royalties (a percentage of their production) to the ANH in kind or in money as per ANH’s instruction and pursuant to the E&P Contracts, companiescontracts. Companies must also pay the ANH an economic right called participating interest in the production, commonly known as “X factor” among other economic rights established in the E&P Contractscontracts (i.e. high price provision, technology transfer, use of the subsurface). Producing fields pay royalties in accordance with the applicable law at the time of the discovery.
Under the E&P contracts, ANH contractors also undertake obligations in favor of the communities located in the area of influence of the oil & gas projects, called “Proyectos en Beneficio de las Comunidades” or (PBC).
Additionally, in February 2019, the ANH published the Terms of Reference for the Permanent Competitive Bidding Process (PCBP) in which initially 20 blocks will bewere offered to interested qualified bidders. As a result of the first phase of this competitive process, we and Hocol S.A. (as a temporary union, which, under Colombian law, is allowed to act as a contractor in E&P contracts) executed three contracts with ANH on July 11, 2019, in the Llanos Basin as follows: LLA-86, LLA-87 and LLA-104. We are the operator of these three contracts. In the second phase of this competitive process, ANH offered more than 50 blocks and we and Hocol S.A., acting through a temporary union, executed two contracts with the ANH on December 20, 2019 in the Llanos Basin as follows: LLA-123 and LLA-124. We also operate these latter contracts. Additionally, we have requested ANH for the assignment of fifty percent interest in LLA-94 block, operated by Parex. During 2020, the ANH granted its approval for such transfer. This contract was awarded to Parex in the first phase of the PCBP. Furthermore, in 2020 the ANH continued with the third cycle of the PCBP. We were qualified as bidder in this third cycle. However, the areas offered during this cycle were not of interest of the Company and therefore, we did
95
not submit a bid. In 2022, ANH launched Ronda Colombia 2021 with similar terms of reference with the PCBP. The main change to the terms of reference was the inclusion of the Exclusivity Economic Value (EEV). The Economic Value of Exclusivity includes both the minimum amount required by the ANH and the additional amount eventually included in the proposal, and which should be offered by the initial offers and counteroffers to surpass the initial proposal and equalize or exceed the most favorable counteroffer presented in each round. EEV is represented in number of exploratory wells offered by a company to be drilled during the E&P contract’s exploratory phase of six years. The companies should at least offer 1 VEE (minimum accepted by ANH) and grant a stand-by letter of credit for 100% of the estimated value of the well as per ANH’s reference values. In the event the company does not comply with the offered EEV, the letter of credit will be enforced by ANH. ANH granted 30 areas in Ronda Colombia 2021 in which we did not participate.
Taxation
The Tax Statute and Law 9 of 1991 provide the primary features of the oil and gas industry’s tax and foreign exchange system in Colombia. Generally, national taxes under the general tax statute apply to all taxpayers, regardless of industry.
The main taxes currently in effect—after the December 2016 tax reform discussed below—effect are the income tax (40%(31% for 2017, 37% for 2018fiscal year 2021, 35% from fiscal year 2022 and 33% for 2019 onwards), sales or value added tax (19%), and the tax on financial transaction (0.4%).
Additional regional taxes also apply.apply with some special rules for the companies belonging to the oil and gas industry. Colombia has entered into a number of international tax treaties to avoid double taxation and prevent tax evasion in matters of income tax and net asset tax.
Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international investment regime, regulates foreign capital investment in Colombia. Resolution 8 of the board of the Colombian Central Bank, or the Exchange Statute, and its amendments contain provisions governing exchange operations. Articles 48 to 52 of Resolution 8 provide for a special exchange regime for the oil industry that removes the obligation of repayment to the foreign exchange market currency from foreign currency sales made by foreign oil companies.
Such companies may not acquire foreign currency in the exchange market under any circumstances and must reinstate in the foreign exchange market the capital required in order to meet expenses in Colombian legal currency. Companies can avoid participating in this special oil and gas exchange regime, however, by informing the Colombian Central Bank and Ministry of Mines and Energy, in which case they will be subject to the general exchange regime of Resolution 8 and may not be able to access the special exchange regime for a period of 10 years.
In December 2018, a new tax reform was enacted in Colombia. The legislation included significant changes in certain corporate income tax, statutory income tax and legal provisions. This tax reform became effective on January 1, 2019.
The legislation included the progressive reduction of the general corporate income tax rate, previously set at 40% for 2017 and 37% for 2018, as follows:
33% in 2019, 32% in 2020, 31% in 2021 and 30% in 2022 and onwards.
Other changes that affect the Group are the following:
An audit benefit was granted by the reform, establishing that tax returns for the 2019 and 2020 fiscal years showing a net income tax 30% or 20% higher, respectively, than the one declared in the previous year would be considered definitive 6 months or 12 months after they became due, also respectively, if there were no objections or requests from the tax authority.
Chile
Regulation of the oil and gas industry
Under the Chilean Constitution, the state is the exclusive owner of all mineral and fossil substances, including hydrocarbons, regardless of who owns the land on which the reserves are located. The exploration and exploitation of hydrocarbons may be carried out by the state, companies owned by the state or private entities through administrative concessions granted by the President of Chile by Supreme Decree or CEOPs executed by the Minister of Energy. Exploitation rights granted to private companies are subject to special taxes and/or royalty payments. The hydrocarbon exploration and exploitation industry is supervised by the Chilean Ministry of Energy.
In Chile, a participant is granted rights to explore and exploit certain assets under a CEOP. If a participant breaches certain obligations under a CEOP, the participant may lose the right to exploit certain areas or may be required to return all or a portion of the awarded areas to Chile with no right of compensation. Although the government of Chile cannot unilaterally modify the rights granted in the CEOP once it is signed, exploration and exploitation are nonetheless subject to significant government regulations, such as regulations concerning the environment, tort liability, health and safety and labor.
96
Regulatory framework
Regulation of exploration and production activities
Oil and gas exploration and development is governed by the Political Constitution of the Republic of Chile and Decree with Law Force No 2 of 1986 of the Ministry of Mines, which set forth the revised text of the Decree Law 1089 of 1975, on CEOPS. However, the right to explore and develop fields is granted for each area under a CEOP between Chile and the relevant contractors. The CEOP establishes the legal framework for hydrocarbon activities, including, among other things, minimum investment commitments, exploration and exploitation phase durations, compensation for the private company (either in cash or in kind) and the applicable tax regime. Accordingly, all the provisions governing the exploitation and development of our Chilean operations are contained in our CEOPs and the CEOPs constitute all the licenses that we need in order to own, operate, import and export any of the equipment used in our business and to conduct our gas and petroleum operations in Chile.
Under Chilean law, the surface landowners have no property rights over the minerals found under the surface of their land. Subsurface rights do not generate any surface rights, except the right to impose legal easements or rights of way. Easements or rights of way can be individually negotiated with individual surface land ownerslandowners or can be granted without the consent of the landowner through judicial process. Pursuant to the Chilean Code of Mines, a judge can permit a party to use an easement pending final adjudication and settlement of compensation for the affected landowner.
Taxation
With regard to indirect taxes onUnder the Chilean tax regime, hydrocarbon exploitation the general rule is that hydrocarbons are transferred to the contractor (its retribution under the CEOP), and those re-acquisitionsbenefits from the contractor performed by Chile or its enterprises, as well as their corresponding acts, contracts and documents, are tax exempt. In addition, hydrocarbon exports by the contractor are also tax exempt. With regard to income taxes, as provided by article 5 of Decree Law No. 1,089, the contractor is subject either to a single tax calculated on its retribution, equal to 50% of such retribution, or to the general income tax regimelegislation are established in the Income Tax Law (Decree Law No. 824 of 1974), in force at the time of the execution of the public deed which contains CEOPs, terms of which will be applicable and invariable throughout the duration of the contract. Income in Chile is subject to corporate tax on an accrual basis and has a current rate of 25.5% for fiscal year 2017. The applicable and invariable corporate income tax rates of our CEOPs range between 15% and 18.5%, as follows: the Fell Block is subject to a rate of 15%, the Tranquilo Block is subject to a rate of 17% and the Flamenco, Isla Norte and Campanario Blocks are subject to a rate of 18.5%each CEOP for the income accrued or received during 2012exploitation of each block. Thus, new tax reforms do not affect the current taxation for our subsidiaries in Chile.
Further, new tax reporting provisions were approved that requires new information to be reported for transfer pricing and 17% for the income accrued or received during 2013 and onward. Dividends or profits distributed to the foreign shareholders of the contractors are subject to 35% Additional Withholding Tax with aindirect transfer tax credit for the corporate income tax paid by the contractor. With regard to the value added tax, contractors may obtain as a refund the value added tax (which is 19% according to the Sales and Services Tax Law contained in Decree Law No. 825 of 1974) supported or paid on the import or purchase of goods or services used in connection with the exploration and exploitation activities. The applicable tax regime for each CEOP remains unchanged throughout the duration of the CEOP.
The Chilean Congress approved a reform to the income tax law in September 2014 which was amended in February 2016. Under this reform the income tax rate will increase from 20% in 2013 to: 21% in 2014, 22.5% in 2015, 24% in 2016, 25.5% in 2017 and 27% in 2018. The operating subsidiaries that we control in Chile, which are GeoPark TdF S.A., GeoPark Fell S.p.A. and GeoPark Magallanes Limitada, are not affected by the income tax reform mentioned since they are covered by the tax treatment established in the CEOPs. The above has been confirmed by the Chilean IRS through ruling N°2478/2016.
purposes.
Brazil
Regulation of the oil and gas industry
Article 177 of the Brazilian Federal Constitution of 1988 provides for the Federal Government’s monopoly over the prospecting and exploration of oil, natural gas resources and other fluid hydrocarbon deposits, as well as over the refining, importation, exportation and sea or pipeline transportation of crude oil and natural gas. Initially, paragraph one of article 177 barred the assignment or concession of any kind of involvement in the exploration of oil or natural gas deposits to private industry. On November 9, 1995, however, Constitutional Amendment Number 9 altered paragraph one of article 177 so as to allow private or state-owned companies to engage in the exploration and production of oil and natural gas, subject to the conditions to be set forth by legislation.
Regulatory framework
Pricing policy
Until the enactment of the Brazilian Petroleum Law, the Brazilian government regulated all aspects of the pricing of oil and oil products in Brazil, from the cost of oil imported for use in refineries to the price of refined oil products charged to the consumer. Under the rules adopted following the Brazilian Petroleum Law, the Brazilian government changed its price regulation policies. Under these regulations, the Brazilian government: (1) introduced a new methodology for determining the price of oil products designed to track prevailing international prices denominated in U.S. dollars, and (2) gradually eliminated controls on wholesale prices.
97
Concessions
In addition to opening the Brazilian oil and natural gas industry to private investment, the Brazilian Petroleum Law created new institutions, including the ANP, to regulate and control activities in the sector. As part of this mandate, the ANP is responsible for licensing concession rights for the exploration, development and production of oil and natural gas in Brazil’s sedimentary basins through a transparent and competitive bidding process. The ANP has conducted 1417 bidding rounds for exploration concessions from 1999 through 2017. Our PN-T-597 is still subject to the entry into the concession agreement. See “—Our operations—Operations2021, three open acreage bid rounds (the third in Brazil”course), 6th Production Sharing Bidding Round and “Item 3. Key information—D. Risk factors—Risks relating to our business—The PN-T-597 concession is subject to an injunction and may not close” for more information.
two Transfer of Right Surplus Bidding Round.
Taxation
The Brazilian Petroleum Law introduced significant modifications and benefits to the taxation of oil and natural gas activities. The main component of petroleum taxation is the government take, comprised of license fees, fees payable in connection with the occupation or title of areas, royalties and a special participation fee. The introduction of the Brazilian Petroleum Law presents certain tax benefits primarily with respect to indirect taxes. Such indirect taxes are very complex and can add significantly to project costs. Direct taxes are mainly corporate income tax and social contribution on net profit.
With the effectiveness of the Brazilian Petroleum Law and the regulations promulgated by the ANP, concessionaires are required to pay the Brazilian federal government the following:
| license fees; |
| rent for the occupation or retention of areas; |
| special participation fee; and |
| royalties on production. |
The minimum value of the license fees is established in the bidding rules for the concessions, and the amount is based on the assessment of the potential, as conducted by the ANP. The license fees must be paid upon the execution of the concession contract. Additionally, concessionaires are required to pay a rental fee to landowners varying from 0.5% to 1.0% of the respective hydrocarbon production.
The special participation fee is an extraordinary charge that concessionaires must pay in the event of obtaining high production volumes and/or profitability from oil fields, according to criteria established by applicable regulation, and is payable on a quarterly basis for each field from the date on which extraordinary production occurs. This participation rate, whenever due, may reach up to 40% of net revenues depending on (i) volume of production and (ii) whether the block is onshore, shallow water or deep water. Under the Brazilian Petroleum Law and applicable regulations issued by the ANP, the special participation fee is calculated based upon quarterly net revenues of each field, which consist of gross revenues calculated using reference prices published by the ANP (reflecting international prices and the exchange rate for the period) less: royalties paid; investment in exploration; operational costs; and depreciation adjustments and applicable taxes.
The ANP is responsible for determining monthly minimum prices for petroleum produced in concessions for purposes of royalties payable with respect to production. Royalties generally correspond to a percentage ranging between 5% and 10% applied to reference prices for oil or natural gas, as established in the relevant bidding guidelines (edital de licitação) and concession agreement. In determining the percentage of royalties applicable to a particular concession, the ANP takes into consideration, among other factors, the geological risks involved, and the production levels expected.
State VAT (ICMS)
ICMS is a state sales tax. This tax is due on the local sale of oil and gas, based on the sale price, including the ICMS itself.
98
For intrastate transactions (carried out by a seller and a buyer located in the same Brazilian state) or imports, the ICMS rate is determined by the legislation of the state where the sale is made and generally varies from 17% to 20%. Interstate transactions (carried out between a seller and buyer located in different Brazilian states), in turn, are subject to reduced rates of 4% (if the products are imported and not submitted to a manufacturing process or, in case of further manufacturing, if the resulting product has a minimum imported content of 40%), 7% or 12%, depending on the states involved. One exception is that, due to the immunity established by the Brazilian Federal Constitution, ICMS is not due on interstate crude oil transactions when destined to industrialization and commercialization. On the other hand, in case of consumables or fixed assets, the buyer must pay to the state where the buyer is located, the ICMS DIFAL, which is calculated based on the difference between the interstate rate and the buyer’s own internal ICMS rate.
ICMS is calculated under the noncumulative regime, and therefore some input transactions could result in tax credits (for example the acquisition of inputs and fixed assets directly used in the company’s activity).
Social contribution taxes on gross revenue (PIS and COFINS)
PIS and COFINS are social contribution taxes charged on gross revenues earned by a Brazilian Federal Revenue noncumulative regime of calculation.
Under the noncumulative regime, PIS and COFINS are generally charged at a combined nominal rate of 9.25% (1.65% PIS and 7.6% COFINS) on national revenues earned by a legal entity. In that case, certain business costs result in tax credits to offset PIS and COFINS liabilities (e.g., input and services acquisitions, expenses of depreciation and amortization of machinery, equipment and other fixed assets acquired to be directly used in the company’s activities). PIS and COFINS paid upon the importation of certain inputs, assets and services contracted that are destined to the company’s activity are also creditable. Although upstream industries are generally subject to this regime, it is not clear yet when this benefit is applied according to the stage of the field, (exploration or production).
Since July 1, 2015, taxpayers subject to the noncumulative regime must calculate PIS and COFINS over certain financial revenues, applying rates of 0.65% and 4%, respectively.
Federal Industrialization VAT (IPI) and Municipality VAT (ISS)
IPI is a non-cumulative tax and may be due on goods acquisitions by importation or national transactions. The IPI rate will be applied depending on the NCM classification of the product according to TIPI (Table of IPI). On the acquisition of local goods subject to IPI, such tax is included in the price of the good. Considering that O&G activity (upstream) is not subject to IPI taxation, the amount of the tax cannot be considered as a credit (even though IPI is under the non-cumulative regime applicable for IPI’s taxpayers), which means that this will be a cost for the legal entity acquirer. In relation to the importation, the importer of record will be considered as the taxpayer and will be obliged to pay the IPI due on the transaction. For the same aforementioned reasons for the O&G companies (upstream), this will be considered as cost when the importation is subject to IPI.
ISS is a cumulative tax which is due on provided services and imported services. Usually, regarding local transactions, such tax is included in the price of the service charged by the service provider. In relation to the import of service, the Brazilian entity contractor is responsible for the payment of the ISS, which means that, depending on contractual arrangement, the tax burden may be supported by the Brazilian contractor or the foreign service provider.
ISS tax rate may vary from 2% to 5% and will depend on the nature of service, as well as where the service provider is located (in general, some exceptions may apply).
Additionally, GeoPark Brazil was granted in 2018 a tax benefit issued by SUDENE (Northeastern Development Superintendence), by means of the Constitutive Act No. 0069/2018, which approved the tax incentive to reduce by 75% the Income Tax and Additions, calculated over the company exploration profits, based on Article 1 of the Provisory Measure 2,199-14 of August 24, 2001, in accordance with the requirements established by the Decree 6,539 of August 18, 2008.
99
The benefit will be valid for 10 years, starting from January 1, 2018, under the condition of modernizing the entire project on the SUDENE operating area, observing all provided legal conditions and requirements that includes compliance with labor and social law and with all environmental protection and control regulations, annual submission of a declaration of income and a restriction to the distribution to partners or shareholders of the tax amount which is not payed due to the tax exemption.
The noncompliance with the requirements provided constitutes a default of the beneficiary company in respect to SUDENE and shall be subject to the applicable penalties.
Peru
Regulation of the oil and gas industry
The hydrocarbons activities in Peru are mainly regulated by the General Hydrocarbons Law (Law 26,221), and several regulations enacted in order to develop the provisions included in such law.
According to the Hydrocarbons Law, oil and gas exploration and production activities are carried out under license or service contracts granted by the government. Under a license contract, the investor pays a royalty, whereas under a service contract, the government pays remuneration to the contractor. As stated by the Peruvian Constitution and the Organic Law for Hydrocarbons, a license contract does not imply a transfer or lease of property over the area of exploration or exploitation. By virtue of the license contract, the contractor acquires the authorization to explore or to exploit hydrocarbons in a determined area, and Perupetro (the entity that holds the Peruvian state interest) transfers the property right in the extracted hydrocarbons to the contractor, who must pay a royalty to the state.
Argentina
Regulatory framework
License and service contracts are approved by a supreme decree issued by the Peruvian Ministry of Economy and Finance, and the Peruvian Ministry of Energy and Mining, and can only be modified by a written agreement signed by the parties. Before initiating any negotiation, every oil and gas company must be duly qualified by Perupetro, in order to determine if it fulfills all the requirements needed to develop exploration and production activities under the contract form requirements mentioned above.
License and services agreements may be granted for just an exploitation stage -when a commercial discovery has been made- or for an exploration and exploitation stage –when such discovery has not been made yet. In this case, the exploration phase will last no more than 7 years, counted from the effective date of the contract (60 days after the signing date). This term can be divided into several periods as agreed in the contract, and all of them with a minimum work obligation that should be fulfilled by a contractor in order to access the next exploration period. The exploration phase will last until a declaration of commercial discovery is made by the contractor. The exploitation phase will last from the date of such declaration until 30 years from the date of the contract.
The Ministry of Energy and Mines may exceptionally authorize an extension of three years for the exploration stage, if the contractor has fulfilled with the minimum work program established in the contract, and also commits to fulfill an additional work program that justifies such extension. The contractor shall be responsible for providing the technical and economic resources required for the execution of the operations of this phase.
The Peruvian regulations also established the roles of the Peruvian government agencies that regulate, promote and supervise the oil and gas industry, including the Ministry of Energy and Mines, Perupetro and OSINERGMIN.
Taxation
The fiscal regime that applies in Peru to the oil and gas industry consists of a combination of corporate income tax, royalties and other levies.
In general terms, oil and gas companies are subject to the general corporate income tax regime that is stabilized in the applicable regime on the date of subscription of the original License Agreement (due to a tax stability contract); nevertheless, there are certain special tax provisions for the oil and gas sector (the approval of the new Organic Hydrocarbons Law is pending in order to encourage investments in license agreements that are already operating in Peru and to promote exploration; as well as defining what will be the treatment on VAT in hydrocarbon exploration projects). At the end of 2018, the Congress approved to extend the VAT refund to this type of projects to December 2019.
The stabilized income tax regime will only cover the activities of the License Agreement (exploration and/or exploitation activities), therefore, the related activities (i.e., activities related to oil and gas, but not carried out under the terms of the contract) and other activities (i.e., activities not related to oil and gas) will be governed by the income tax rules in force to date.
Resident companies (incorporated in Peru), are subject to income tax on their worldwide taxable income. Branches and permanent establishments of foreign companies that are located in Peru and non-resident entities are taxed on Peruvian source income only.
With respect to the Morona Agreement, in which we take part, the applicable income tax stabilized regime is from 1995, which is the year of subscription of the original License Agreement. The income tax rate in 1995 was 30% and there was no withholding income tax for dividends. Additionally, in 1995 it was stated that the income tax should not be lower than 2% of the net assets of the Company (the “Minimum Income Tax”). The Minimum Income Tax was later declared unconstitutional, which is why, even when there was a tax stability contract, the Minimum Income Tax has been understood as not applicable or enforceable.
Taxable income is generally computed by reducing gross revenue by cost of goods sold and all expenses necessary to produce the income or maintain the source of income. Certain types of revenue, however, must be computed as specified in the tax law and some expenses are not fully deductible for tax purposes. Business transactions must be recorded in legally authorized accounting records that are in full compliance with the International Accounting Standards (IAS). Contractors in a license or services contract for the exploration or exploitation of hydrocarbons (Peruvian corporations and branches) are entitled to keep their accounting records in foreign currency, but taxes must be paid in Peruvian Soles (“PEN”).
Any investments in a contract area that did not reach the commercial extraction stage and that were totally released, can be accumulated with the same type of investments made in another contract area that has reached the stage of commercial extraction.
These investments are amortized in accordance with the amortization method chosen by the contractor. If the contractor has entered into a single contract, the accumulated investments are charged as a loss against the results of the contract for the year of total release of the area for any contract that did not reach the commercial extraction stage, with the exception of investments consisting of buildings, power installations, camps, means of communication, equipment and other goods that the contractor keeps or recovers to use in the same operations or in other operations of a different nature.
The contractor determines the tax base and the amount of the tax, separately and for each contract. If the contractor carries out related activities or other activities, the contractor is obligated to determine the tax base and the amount of tax, separately, and for each activity. The corresponding tax is determined based on the income tax provisions that apply in each case (subject to the tax stability provisions for contract activities and based on the regular regime for the related activities or other activities). The total income tax amount that the contractor must pay is the sum of the amounts calculated for each contract, for both the related activities and for the other activities. The forms to be used for tax statements and payments are determined by the tax administration. If the contractor has more than one contract, it may offset the tax losses generated by one or more contracts against the profits resulting from other contracts or related activities. Moreover, the tax losses resulting from related activities may be offset against the profits from one or more contracts.
It is possible to choose the allocation of tax losses to one or more of the contracts or related activities that have generated the profits, provided that the losses are depleted or compensated to the limit of the profits available. This means that if there is another contract or related activity, the taxpayer can continue compensating tax losses until they are completely offset. A contractor with tax losses from one or more contracts or related activities may not offset them against profits generated by the other activities. Furthermore, in no case may tax losses generated by the other activities be offset against the profits resulting from the contracts or the related activities.
During the exploration phase, operators are exempt from import duties and other forms of taxation applicable to goods intended for exploration activities. Exemptions are withdrawn at the production phase, but exceptions are made in certain instances, and the operator may be entitled to temporarily import goods tax-free for a two-year period (“Temporary Import”). A temporary Import may be extended for additional one year periods for up to two times upon the request of an operator, approval of the Ministry of Energy and Mines and authorization of the Superintendencia Nacional de Aduanas y de Administracion Tributaria (Peruvian Customs Agency).
Several Legislative Decrees were published on September 13, 2018, introducing modifications to the Income Tax Law and the Tax Code.
Income Tax Law: These dispositions are effective since January 1, 2019.
Additionally, new transfer pricing rules were established: (i) the obligations to apply the benefit test is now only applicable to operations between related parties and no longer to operations with, towards or through tax havens; and (ii) the “cost+expense+mark up” structure to deduct the expenses for services between related parties will now only be applicable to low added value services, and not to entirety of services between related parties.
In addition, when applying the Comparable Uncontrolled Price (CUP) method to cross-border transactions involving commodities, the Legislative Decree establishes that the arm’s-length price for Peruvian income tax purposes must be determined by reference to a publicly quoted price. The actual pricing date or period of pricing dates should be used as a reference to determine the price for the transaction, as long as independent parties in comparable circumstances would have relied upon the same pricing date. The taxpayer needs to notify the SUNAT (i.e., Peruvian Tax Authority) of the actual pricing date or period of pricing dates used to determine the price for the transaction.
Legislative Decree 1424 extends the application of sub capitalization rules (maximum deductible interest determination) to unrelated parties.
Likewise, as of 2021, the interest generated in transactions with related or unrelated parties that exceeds 30% of EBITDA of the preceding year will not be deductible. Interest that is not deducted may be carried forward for up to four years.
On the other hand, this Legislative Decree introduces in the Income Tax Law scenarios in which Permanent Establishments are triggered.
Additionally, other provisions have been included in this Legislative Decree, for instance, that an indirect transfer of Peruvian shares will always be triggered if the amount paid for the shares of a non-resident entity that corresponds to the Peruvian shares is equivalent to or higher than 40,000 Tax Units (approximately US$ 50.3 million).
Tax Code:
In case of entities with a Board of Directors, that Board of Directors will be responsible of approving the tax planning of the entity. That obligation cannot be delegated. The Board of Directors must evaluate the tax planning strategies implemented up to September 14, 2018 in order to ratify or modify them. The term for ratify or modify them will end on March 29, 2019.
In May 2018, GeoPark Perú SAC applied for a VAT anticipated refund regime that will allow it to recover the tax paid until the first oil is produced. The regime is established by Legislative Decree 973, which demands a minimum investment of US$5.0 million, and a preoperative period of 2 years (which for Morona Block starts on December 2016).
Environmental Regulation
Before initiating any hydrocarbon activity (e.g. seismic exploration, drilling of exploration wells, etc.) the contractor must file and obtain an approval for an Environmental Impact Study (EIS), which is the most important permit related to HSE for any hydrocarbon project. This study includes technical, environmental and social evaluations of the project to be executed in order to define the activities that should be required for preventing, minimizing, mitigating and remediation of the possible negative environmental and social impacts that the hydrocarbon project may generate.
There are general environmental regulations for the protection of water, soils, air, endangered species, biodiversity, natural protected areas, etc. In addition, there are specific environmental regulations applicable to the hydrocarbon industry.
Argentina
Regulatory framework
From the 1920s to 1989, the Argentine public sector dominated the upstream segment of the Argentine oil and gas industry and the midstream and downstream segment of the business.
The Hydrocarbon Law No. 17,319 enacted in 1967 continues in force until today, subject to amendments introduced by the Deregulation Decrees and Laws No. 24,145, 26,197 and 27,007.
The Petroleum Deregulation Decrees (as defined below), with the limitations thereon introduced by the YPF expropriation law 26,741 (the “Hydrocarbons Sovereignty Act”) and its regulations also molds the current national hydrocarbons regulatory framework.
The Hydrocarbon Law No. 17,319 provided for the existence of a state-owned oil & gas company (originally, YPF) for whom private companies served as service contractors or joint venture partners. But it also provided for a concession & royalty system which in practice was not used until after the YPF privatization.
In 1989, Argentina enacted certain laws aimed at privatizing the majority of its state-owned companies and issued a series of presidential decrees (namely, Decrees No. 1055/89, 1212/89 and 1589/89 (the “Oil“Petroleum Deregulation Decrees”)), relating specifically to the deregulation of energy activities).activities. The OilPetroleum Deregulation Decrees eliminated restrictions on imports and exports of crude oil, deregulated the domestic oil industry, and effective January 1, 1991, the prices of oil and petroleum products were also deregulated. In 1992, Law No. 24,145, referred to as the Privatization Law, privatized YPF and provided for transfer of hydrocarbon reservoirs from the Argentine government to the provinces, subject to the existing rights of the holders of exploration permits and production concessions.
In October 2004, the Argentine Congress enacted Law No. 25,943, creating a new state-owned energy company,Energía Argentina S.A. (“ENARSA”). The corporate purpose of ENARSA was initially the exploration and exploitation of solid, liquid and gaseous hydrocarbons; the transport, storage, distribution, commercialization and industrialization of these products; as well as the transportation and distribution of natural gas, and the generation, transportation, distribution and sale of electricity. Moreover, Law No. 25,943 granted ENARSA all offshore areas located beyond 12 nautical miles from the coastline up to the outer boundary of the continental shelf that were vacant at the time of the effectiveness of this law (i.e. November 3, 2004). In 2014, all open acreage offshore exploration permits and exploitation concessions were conveyed to the National Energy Secretary (NSE) and all existing JV agreements entered into by ENARSA with private investors were conveyed by ENARSA to YPF in accordance with Section 30, New Hydrocarbons Act No. 27,007.
On May 3, 2012, the Argentine Congress passed the Hydrocarbons Sovereignty Act. This law declared achieving self-sufficiency in the supply of hydrocarbons, as well as in the exploitation, industrialization, transportation and sale of hydrocarbons, a national public interest and a priority for Argentina. In addition, the law expropriated 51% of the share capital of YPF, the largest Argentine oil company, from Repsol, the largest Spanish oil company.
On July 28, 2012, Presidential Decree 1277/2012, which regulated the Hydrocarbon Sovereignty Law, was released, creating a Strategic Planning and Coordination Committee for the National Hydrocarbon Investment Plan and vesting it with the power to set the sector’s reference prices and to develop investment plans for the country to increase production and reserves. The decree introduced important changes to the rules governing Argentina’s oil and gas industry, including the repeal of certain articles of Deregulation Decrees passed during 1989 relating to free marketability of hydrocarbons at
100
negotiated prices, the deregulation of the oil and gas industry, freedom to import and export hydrocarbons and the ability to keep proceeds from export sales in foreign bank accounts.
On January 4, 2016, immediately after the new nationalPresident Macri’s administration took office, the Strategic Planning and Coordination Committee for the National Hydrocarbon Investment Plan was dissolved by Presidential Decree 272/2015 was released. This Decree abrogated the provisions of the Presidential Decree 1277/2012 which had repealed the Deregulation Decrees. Thus, the Deregulation Decrees were reinstated.
2015.
Other measures have also beenwere taken by the new presidentialprevious administration aimed at reducing government intervention and reestablishing market forces in the oil & gas industry:
| Effective October 1, 2017, both domestic oil prices at the wellhead and gasoline prices at the dispenser were allowed to float freely, ending floor pricing schemes sheltering the oil producers during low oil times. |
| Also, effective October 22, 2018, Resolution 103/2018 established a new framework governing natural gas export authorization proceedings, including |
Despite the above mentioned efforts to establish free market conditions for hydrocarbons, after a sharp devaluation, on September 1, 2019, Emergency Decree 609/2019 was enacted (thereafter amended by Decree 69/2019) whereby all exporters of goods and services were required to bring to Argentina and clear through the Argentine Central Bank all proceeds from their exports within the timeframes provided by the Argentine Central Bank. Moreover, this Decree authorized the Argentine Central Bank to introduce foreign exchange restrictions. A number of Central Bank Communications ensued thereafter restricting the outflow of funds from Argentina, including the requirement to obtain the Central Bank's prior approval to access the local foreign exchange market for payment of profits and dividends to foreign shareholders.
Regarding the export regime, Argentina passed on September 3, 2018, Decree 793/2018, which established a 12% export duty on all exports of goods from Argentina until December 31, 2020, including hydrocarbons exports. Then, the Economic Emergency Law 27,541 enacted on December 21, 2019, reduced to 8% the maximum export duty authorized to be levied on hydrocarbon exports as provided under Decree 793/2018. Lastly, National Decree 488/2020 passed in May 2020, in response to the COVID-19 pandemic, abrogated oil export duties as long as the Brent benchmark quotes at US$45 or under and reduced the export duties to 8% for when the Brent benchmark quotes at US$60 or over. A prorated export duty formula was established for periods when the Brent benchmark quotes between US$45 and US$60.
Domain and Jurisdiction of hydrocarbons resources
After a constitutional reform enacted in 1994, eminent domain over hydrocarbon resources lying in the territory of a provincial state is now vested in such provincial state, while eminent domain over hydrocarbon resources lying offshore on the continental platform beyond the jurisdiction of the coastal provincial states is vested in the federal state
state.
Thus, oil and gas exploration permits and exploitation concessions are now granted by each provincial government. A majority of the existing concessions were granted by the federal government prior to the enactment of Law No.26,197No. 26,197 and were thereafter transferred to the provincial states.
Hydrocarbon Exports and Self Sufficiency
Self-Sufficiency
Achieving self-sufficiency has been an energy policy goal from the early days of the industry.
Section 6 of the Hydrocarbon Law No. 17,319 allows the National Executive Branch to authorize the export of hydrocarbons. At times when the domestic production of liquid hydrocarbons is insufficient to cover domestic needs, the delivery of the entire availability of such locally produced hydrocarbons to the domestic market shall be mandatory, with such exceptions as may be justified on technical grounds.
101
In turn, Section 3 of the Natural Gas Regulatory Framework 24,076 allows the National Executive Branch to authorize the export of natural gas. The granting of natural gas export permits is regulated in detail.
Supply privileges favouringfavoring the domestic market to the detriment of the export market, including hydrocarbon export restrictions, domestic price controls, price subsidies, export duties and domestic market supply obligations have been implemented several times.
In November 2020, National Decree 892/2020 approved a Plan for the Promotion of the Production of Argentine Natural Gas – Supply and Demand Scheme 2020-2024 whereby the National Government agreed to compensate natural gas producers for the share of the price of natural gas they auctioned that is not transferred to end-users according to the passthrough mechanism provided in their license terms. Three subsequent Rounds of natural gas supply auctions have been conducted since then by the National Secretary of Energy under which participating producers committed to inject natural gas volumes required to satisfy the demand of domestic market utilities in consideration for government monetary compensation and certain natural gas export allowances.
Regulation of exploration and production activities
New Hydrocarbon Act:
In October 31, 2014, the Argentine Republic Official Gazette published the text of Law No. 27,007, amending the Hydrocarbon Law No. 17,319.
The most relevant aspects of the new law are as follows:
| With regards to concessions, three types of concessions are provided, namely, conventional exploitation, unconventional exploitation, and exploitation in the continental shelf and territorial waters, establishing the respective terms for each type. |
| The terms for hydrocarbon transportation concessions were adjusted in order to comply with the exploitation concessions terms. |
| With regards to royalties, a maximum of 12% |
| The |
Regulation of transportation activities
Exploitation concessionaires have the exclusive right to obtain a transportation concession for the transport of oil and gas from the provincial states or the federal government, depending on the applicable jurisdiction. Such transportation concessions include storage, ports, pipelines and other fixed facilities necessary for the transportation of oil, gas and by-products. Transportation facilities with surplus capacity must transport third parties’ hydrocarbons on an open-access basis, for a fee which is the same for all users on similar terms. As a result of the privatizations of YPF and Gas del Estado, a few common carriers of crude oil and natural gas were chartered and continue to operate to date.
Effective February 8, 2019, to promote transportation capacity expansions, Decree 115/2019 allowed interested shippers to reserve transportation capacity in new or expanded pipelines through freely negotiated capacity reservation agreements.
102
Taxation
Exploitation concessionaires are subject to the general federal and provincial tax regime. The most relevant federal taxes are the income tax (30%(35%), and the value addedvalue-added tax (21%) and a tax on assets.. The most relevant provincial taxes are the turnover tax (3% on average) and stamp tax. Corporate income tax rate may range from 25% to 35% on bands of income that can be adjusted annually.
Ecuador
Regulatory framework
Petroleum Ownership and Regulation
Oil, gas, minerals and natural resources underground belong to the Republic of Ecuador, in accordance with the Ecuadorian Constitution. This is a primary concept in both the Constitution and the law. However, the State can allow private investment to explore and produce hydrocarbons under different types of contracts as provided under the law.
The Ministry of Energy and Non-Renewable Natural Resources is in charge of regulating and overseeing all hydrocarbon-related activities in the country, including exploration, production, transportation, refining and marketing. The Ministry has absorbed the functions and duties of the Secretariat of Hydrocarbons and, through the Vice-Ministry of Hydrocarbons, oversees awarding, executing and monitoring contracts with private companies for the exploration and production of hydrocarbons. On the other hand, the Agency for Regulation and Control of Energy and Non-Renewable Natural Resources (“ARCERNNR” for its Spanish acronym) has the legal duty to oversee, audit, collect levies and duties on operations, and conduct accounting control of all upstream and downstream hydrocarbon operations.
The Ministry of the Environment, Water and Ecological Transition of Ecuador (“MAATE” for its Spanish acronym) has the legal competence for granting environmental licenses for all oil and gas activities and to ensure such operations are conducted in compliance with environmental laws and regulations. The Ministry of the Environment is independent from the Ministry of Energy.
Petroleum Laws and Regulations
The Ecuadorian Constitution contains the main provisions, which stipulate that all hydrocarbons belong to the State of Ecuador, that the national oil company is EP PETROECUADOR (following the merger of Petroecuador EP and Petroamazonas EP completed in 2020) has preferential rights for oil exploration, production, transportation and sale, and that, in case a contract is executed with a private oil company, the State’s benefit must be more than that of the private company. The State’s benefit is understood as all taxes, production sharing and other economic benefits the State receives from oil production, while the company’s benefit is understood as all proceeds received from payment for the service of producing oil, or from the sales of its share of oil, less all amortization of investments, costs and taxes paid by the company.
The Hydrocarbons Law is the main body of law below the Ecuadorian Constitution and regulates the different types of contracts the government can enter into with international oil companies, as well as the rights, obligations and penalties for private companies. The main contracts that have been implemented in Ecuador from time to time are service contracts and fairly recently the production-sharing contracts (“PSC”). Under a service contract, the State of Ecuador pays a contractually agreed tariff per barrel. Under a PSC, the investing company receives a share of the oil produced which it can freely trade.
There are several regulations ranking below the Hydrocarbons Law that set further rules for all activities, including the regulation of hydrocarbon operations and special local rules on the accounting principles for each type of contract.
In addition to all the other generally applicable laws of the country, the Environmental Law, Labor Law (including local content in hiring of personnel) and Tax Law should be carefully considered.
103
Background for Contract types for Private Investment in Petroleum
During almost 50 years Ecuador has been producing oil, through two types of contracts: production-sharing contracts and service contracts. The government has imposed service contracts when the price of oil was high and production-sharing contracts when the price of oil was low. In 2010, a legal reform wasrequired all oil companies that were operating under the umbrella of production-sharing contracts to transform their contracts into service contracts.
Service contracts can be executed by the Ministry of Hydrocarbons for exploration blocks or for fields already in production (followed a 2021 reform to the Law of Hydrocarbons). In both cases, the contracting company receives a pre-agreed tariff that is usually negotiated considering the amount of the investment, existing reserves, production cost and an estimated reasonable profit for the company.
In July 2018, Executive Decree no. 449 reinstated the production-sharing type of contracts so called locally as Participation Contracts. On 2019, the Ministry of Energy executed several Participation Contracts for exploration and exploitation of hydrocarbons.
The contract term for a production-sharing contract is usually four years for exploration, extendable for two additional years, and 20 years for production, subject to an extension if reserves have been added and new investments are committed. As of the date of this annual report, we hold two production-sharing contracts with a 50% working interest in consortium with Frontera Energy (Espejo Block, operated, and non-operated Perico Block), which were awarded by the Ministry of Energy during the First Intracampos Bidding Round in April 2019.
As of the date of this annual report, after a reform to the Law of Hydrocarbons enacted in Argentina2021, oil companies can transform a service contract into a production sharing contract through a request to the Ministry of Energy and negotiating certain new terms and conditions applicable to the production-sharing contract.
Taxation
The guiding principle is that the government’s share will always be higher than the contracting company’s share. If the contracting company’s share is higher than 51%, it triggers a sovereignty margin adjustment in December 2017. The legislation included significant changes to certain corporate income tax and statutory income tax provisions, including rate reductions. Mostfavor of the tax provisions were effective asgovernment.
In a risk service contract, the government’s share comprises the oil sales price or the reference price for a specific month, less the tariff paid to the company and plus all applicable taxes. For this type of contract, the contracting company’s share is composed of the beginningtariff received from the government per barrel, less the amortization of fiscal year 2018.investments, operating costs and all applicable taxes and contributions paid in accordance with the law and the contract.
WithUnder a production-sharing contract, the government’s share is composed of the sales price or the reference price of the share of oil assigned to the government as per the contract, plus all taxes and contributions paid by the company. In this tax reform,type of contract, the corporate income tax, which was previously 35% hascontracting company’s share is the following rate schedule: higher of the sales price and the reference price of the company’s oil, less all amortization of investments, operating costs, transportation costs up to the port of Balao on the Pacific Coast and all taxes and contributions paid pursuant to the law and the contract.
104
Basically, the taxes are:
Other changes include the following:
Production Risk
For any type of contract to be entered into in Ecuador, the investing company has to take on all exploration and production risks and investments, as well as environmental responsibilities in accordance with its corresponding environmental obligations.
Furthermore, the investing company must strictly abide by all employment laws, in terms of legal requirements concerning the maximum number of foreign employees. Some contracts have allowed for arbitration as a dispute resolution mechanism; however, certain matters, such as taxes, cannot be submitted to arbitration. This is also true for certain termination provisions in the event of the investing company breaching the law (such as transfer of rights without consent). The reform to the Law of Hydrocarbons enacted in 2021 allows the entry into investment treaties with the Government of Ecuador, allowing to freeze tax incentives in consideration for investment commitments and expanding local employment.
| C. Organizational structure |
We are an exempted company incorporated pursuant to the laws of Bermuda. We operate and own our assets directly and indirectly through a number of subsidiaries. See an illustration of our corporate structure in Note 21 (“Subsidiary undertakings”) to our Consolidated Financial Statements. During 2017, we decided to incorporate a subsidiary in the United Kingdom (international investor centre) to conduct our businesses and financial decisions.
| D. Property, plant and equipment |
See “—B. Business Overview—Title to properties.”
ITEM 4A. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
| A. Operating results |
The following discussion of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and the notes thereto as well as the information presented under “Item 3. Key Information— A. Selected financial data.”
thereto.
The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including those set forth in “Item 3. Key Information—D. Risk factors” and “Forward-looking statements.”
105
Factors affecting our results of operations
We describe below the year-to-year comparisons of our historical results and the analysis of our financial condition. Our future results could differ materially from our historical results due to a variety of factors, including the following:
Discovery and exploitation of reserves
Our results of operations depend on our level of success in finding, acquiring (including through bidding rounds) or gaining access to oil and natural gas reserves. While we have geological reports evaluating certain proved, contingent and prospective resources in our blocks, there is no assurance that we will continue to be successful in the exploration, appraisal, development and commercial production of oil and natural gas. The calculation of our geological and petrophysical estimates is complex and imprecise, and it is possible that our future exploration will not result in additional discoveries, and, even if we are able to successfully make such discoveries, there is no certainty that the discoveries will be commercially viable to produce.
For the year ended December 31, 2018,2021, we made total capital expenditures of US$ 124.7129.3 million (US$97.0119.9 million, US$7.94.3 million, US$9.0 million, US$8.50.1 million and US$2.35.0 million in Colombia, Chile, Argentina Peru and Brazil,Ecuador, respectively), consisting of US$43.546.2 million related to exploration.
Oil prices werehave been volatile, particularly since the endstart of 2014.the COVID-19 pandemic and the armed conflict in Ukraine. In preparation for continued volatility and the prolonged effects of the COVID-19 pandemic, we have developed multiple scenarios for our 20192022 capital expenditure program. See “Item 4. Information on the Company –B.Company—B. Business Overview—20192022 Strategy and Outlook.”
Funding for our 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 such as the Trafigura Agreement, which is our offtake and prepayment agreement.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, which could harm our business outlook, investor confidence and our share price.
If oil prices average higher than the base budget price, we have the ability to allocate additional capital to more projects and increase its work and investment program and thereby further increase oil and gas production.
Our results of operations will be adversely affected in the event that our estimated oil and natural gas asset base does not result in additional reserves that may eventually be commercially developed. In addition, there can be no assurance that we will acquire new exploration blocks or gain access to exploration blocks that contain reserves. Unless we succeed in exploration and development activities, or acquire properties that contain new reserves, our anticipated reserves will continually decrease, which would have a material adverse effect on our business, results of operations and financial condition.
Oil and gas revenue and international prices
Our revenues are derived from the sale of our oil and natural gas production, as well as of condensate derived from the production of natural gas. The price realized for the oil we produce is generally linked to Brent or Vasconia.Brent. The price realized for the natural gas we produce in Chile is linked to the international price of methanol, which is settled in the international markets in US$. The market price of these commodities is subject to significant fluctuation and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors.
From January 1, 2014 to December 31, 2018, Brent spot prices ranged from a low of US$27.9 per barrel to a high of US$118.9 per barrel, Henry Hub natural gas average spot prices ranged from a low of US$1.7 per mmbtu to a high of US$6.0 per mmbtu, US Gulf methanol spot barge prices ranged from a low of US$250.0 per metric ton to a high of US$635.1 per metric ton. Furthermore, oil, natural gas and methanol prices do not necessarily fluctuate in direct relationship to each other.
As a consequence ofDuring 2020, the oil price crisis which started inmarket experienced a significant over-supply condition, mainly influenced by the second half of 2014 (WTI and Brent, the main international oil price benchmarks, fell more than 60% between October 2014 and February 2016), we took decisive steps in 2015 and 2016 to adapt to the new oil price environment. We reduced our capital expenditure program from US$238 million in 2014 to US$48 million in 2015 and US$39 million in 2016 and implemented significant cost reduction initiativesCOVID-19 pandemic, that resulted in productiona sharp drop in prices, with Brent falling from over US$50 per barrel at the beginning of March
106
2020 up to US$16 per barrel in late April 2020. During 2021, the crude demand recovery resulted in some improvements in the market conditions from the end of 2020 and operating costs being reduced by 49% (2016 versus 2014), and administrative expenses being reduced by 26% (2016 versus 2014), while increasing average production to approximately 22.4 mboepd and increasing our proved reserves to 73.6 mmboe.onwards.
In October 2016, we decided toWe manage part of our exposure to the volatile crude oil price using derivatives. For further information related to Commodity Risk Management Contracts, please see Note 8 to our Consolidated Financial Statements.
Additionally, the oil and gas we sell may be subject to certain discounts. For example, in Colombia, the realized oil price of oil we sell is based onlinked to either the Vasconia crude reference price, a marker broadly used in the Llanos Basin, or the Oriente crude reference price, a marker broadly used for crude sales in Esmeraldas, Ecuador, for the crude oil of the Putumayo Basin that is transported through Ecuador. In both basins, the reference price is then adjusted for certain marketing and quality discounts based on, among other things, API, viscosity, sulfur,sulphur content, delivery point and water content, as well as on certain transportation costs (including pipeline costs and trucking costs).transport costs.
In Chile, the price of oil we sell to ENAP is based on Dated Brent minus certain marketing and quality discounts.discounts such as, API, sulphur content and others. We have a long-term gas supply contract with Methanex. The price of the gas sold under this contract is determined based onby a formula that takes into account variousconsiders a basket of international methanol prices, of methanol, including US Gulf methanol spot barge prices, methanol spot Rotterdam prices and spot prices in Asia.European price indices. See “Item 3. Key Information—D. Risk factors—Risks relating to 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.”
In Brazil, prices for gas produced in the Manati Field are based on a long-term off-take contract with Petrobras. The price of gas sold under this contract is denominated inreais and is adjusted annually for inflation pursuant to the Brazilian General Market Price Index (Índice Geral de Preços—Mercado) (the “IGPM”). See Note 3 to our Consolidated Financial Statements.
In Argentina, the realized oil prices for our production in the Neuquén Basin follows the “Medanito” blend oil price reference, which has traditionally been linked to ICE Brent adjusted by certain marketing and quality discounts based on API, delivery point and transport costs. Between May and November 2018, Medanito crude prices were capped industry-wide between US$ 65 per barrel and US$ 70 per barrel. Since December 2018, domesticThough prices have reconnected tobeen regulated by the international benchmark.Government in the past, they are currently being determined by market-based formulas.
Gas sales in Argentina are carried out through annual contracts that go from May to April. The price of the gas sold under these contracts depends mainly on domestic supply and demand and regulation affecting the sector.
If the market prices of oil and methanol prices had fallen by 10% as compared to actual prices during the year, with all other variables held constant, and taking into accountconsidering the impact of the derivative contracts in place, post-tax profit for the year ended December 31, 2018 would have been lower by US$13.717.9 million (post-tax loss would have been higher by US$10.421.0 million in 2017)2020).
Production and operating costs
Our production and operating costs consist primarily of expenses associated with the production of oil and gas, the most significant of which are gas plant leasing, facilities and wells maintenance (including pulling works), labor costs, contractor and consultant fees, chemical analysis, royalties and products, among others. As commodity prices increase or decrease, our production costs may vary. We have historically not hedged our costs to protect against fluctuations.
Availability and reliability of infrastructure
Our business depends on the availability and reliability of operating and transportation infrastructure in the areas in which we operate. Prices and availability for equipment and infrastructure, and the maintenance thereof, affect our ability to make the investments necessary to operate our business, and thus our results of operations and financial condition. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—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.”
107
Production levels
Our oil and gas production levels are heavily influenced by our drilling results, our acquisitions and to oil and natural gas prices.
We expect that fluctuations in our financial condition and results of operations will be driven by the rate at which production volumes from our wells decline. As initial reservoir pressures are depleted, oil and gas production from a given well will decline over time. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—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.”
Contractual obligations
In order to protect our exploration and production rights in our licensed areas, we must make and declare discoveries within certain time periods specified in our various special contracts, E&P Contractscontracts and concession agreements. The costs to maintain or operate our licensed areas may fluctuate or increase significantly, and we may not be able to meet our commitments under these agreements on commercially reasonable terms or at all, which may force us to forfeit our interests in such areas. If we do not succeed in renewing these agreements, or in securing new ones, our ability to grow our business may be materially impaired. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Under the terms of some of our various CEOPs, E&P Contractscontracts, production sharing agreements and concession contracts and concession agreements, we are obligated to drill wells, declare any discoveries and file periodic reports in order 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 concessionedconcession areas.”
Acquisitions
As described above, part of our strategy is to acquire and consolidate assets in Latin America. We intend to continue to selectively acquire companies, producing properties and concessions. As with our historical acquisitions, any future acquisitions could make year-to-year comparisons of our results of operations difficult. We may also incur additional debt, issue equity securities or use other funding sources to fund future acquisitions. We generally incorporate our acquired business into our results of operations at or around the date of closing.
On January 16, 2020, we acquired the 100% share capital of Amerisur. Considering that Amerisur issues financial information monthly, we have considered the identified assets and liabilities as of December 31, 2019. If the purchase price allocation exercise had been carried out as of January 16, 2020, it would not have deferred significantly.
Functional and presentational currency
Our Consolidated Financial Statements are presented in US$, which is our presentationalpresentation currency. Items included in the financial information of each of our entities are measured using the currency of the primary economic environment in which the entity operates, or the functional currency, which is the US$ in each case, except for our Brazil operations, where the functional currency is thereal.
Geographical segment reporting
In the description of our results of operations that follow, our “Other” operations reflect our non-Colombian, non-Chilean, non-Argentine and non-Brazilian operations, primarily consisting of our corporate head office operations.
We divideAs of December 31, 2021, we divided our business into five geographical segments—Colombia, Chile, Brazil, Argentina, and Peru—Ecuador—that correspondcorresponded to our principal jurisdictions of operation. Activities not falling into these five geographical segments are reported under a separate corporate segment that primarily includes certain corporate administrative costs not attributable to another segment.
108
Description of principal line items
The following is a brief description of the principal line items of our consolidated statement of income.
Revenue
Revenue includes the sale of crude oil, condensate and natural gas net of value-added tax (“VAT”), and discounts related to the sale (such as API and mercury adjustments) and overriding royalties due to the ex-owners of oil and gas properties where the royalty arrangements represent a retained working interest in the property. Revenue from the sale of crude oil and gas is recognized when control has beenof the product is transferred to the purchasercustomer, which is generally when the product is physically transferred into a pipe or other delivery mechanism and if revenue can be measured reliablythe customer accepts the product. Consequently, the Group’s performance obligations are considered to relate only to the sale of crude oil and is expectedgas, with each barrel of crude oil equivalent considered to be received.
a separate performance obligation under the contractual arrangements in place.
Commodity risk management contracts
Includes realized and unrealized gains and losses arising from commodity risk management contracts.
Production and operating costs
Production and operating costs are recognized on the accrual basis of accounting. These costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals leasing and royalties are also included within this account. For a description of our production and operating costs, see “—Factors affecting our results of operations.”
Depreciation and write-off of unsuccessful efforts
Capitalized costs of proved oil and natural gas properties are depreciated on a licensed-area-by-licensed-area basis, using the unit of production method, based on commercial proved and probable reserves as calculated under the Petroleum Resources Management System methodology promulgated by the Society of Petroleum Engineers and the World Petroleum Council (the “PRMS”), which differs from SEC reporting guidelines pursuant to which certain information in the forepart of this annual report is presented. The calculation of the “unit of production” depreciation takes into account estimated future discovery and development costs. Changes in reserves and cost estimates are recognized prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content.
In particular, upon completion of the evaluation phase, a prospect is either transferred to oil and gas properties if it contains reserves or is charged to profit and loss in the period in which the determination is made. See “—Critical accounting policies and estimates—Oil and gas accounting.”
Geological and geophysical expenses
Geological and geophysical expenses are recognized on the accrual basis of accounting and consist of geosciences costs, including wages and salaries and share-based compensation not subject to capitalization, geological consultancy costs and costs relating to independent reservoir engineer studies.
Administrative expenses
Administrative expenses are recognized on the accrual basis of accounting and consist of corporate costs such as director fees and travel expenses, new project evaluations and back-office expenses principally comprised of wages and salaries, share-based compensation, consultant fees and other administrative costs, including certain costs relating to acquisitions.
Our administrative expenses for the year ended December 31, 2018 increased2021, decreased by US$10.03.5 million, or 24%7%, compared to the year ended December 31, 20172020, mainly due to staff cost reductions and higher staff costs resulting from increased scale ofallocation to joint operations. However, administrative costs may increase as a result of our Peruvian and Argentinian operations, other acquisitions, increased activity or the impact of appreciation of local currencies in the countries where we operate.
109
Selling expenses
Selling expenses are recognized on the accrual basis of accounting and consist primarily of transportation, storage costs and selling taxes.
Our selling expenses for the year ended December 31, 2021, increased by US$2.9 million, or 49%, compared to the year ended December 31, 2020, mainly due to the sales increase during the year and also to differences in accounting for different points of sale in Colombia. Sales at the wellhead have no selling costs associated but generate lower revenue whereas transportation costs for sales to other delivery points are accounted for as selling expenses.
Write-off of unsuccessful exploration efforts
Upon completion of the evaluation phase, the exploratory prospects are either transferred to oil and gas properties or charged to expense in the period in which the determination is made, depending whether they have discovered reserves or not. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is recoverable.
During 2021, we recognized write-off of unsuccessful exploration efforts of US$12.3 million (US$52.7 million in 2020). See Note 20 to our Consolidated Financial Statements.
Impairment of non-financial assets
Assets that are not subject to depreciation and/or amortization (such as exploration and evaluation assets) are tested annually for impairment. Assets that are subject to depreciation and/or amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.
An impairment loss is recognized for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value minus costs to sell and value in use.
During 20182021, we recognized a net reversalimpairment loss of US$4.3 million (US$133.9 million in 2020) that corresponded to: (1) an impairment lossesloss recognized in the Fell Block of US$5.017.6 million whiledue to the decline in 2017 we did not recognize or reverse any impairment lossesthe proved reserves estimation in 2021 and, in 2016 we recognized(2) a reversal of impairment lossesloss of US$5.7 million.13.3 million in the Aguada Baguales and El Porvenir Blocks in Argentina. See Note 3637 to our Consolidated Financial Statements.
Financial results
Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and liabilities, and foreign exchange gains and losses.
Profit or loss for the period attributable to owners of the Company
Profit or loss for the period attributable to owners of the Company consists of profit or losses for the year less non-controlling interest.
Critical accounting policies and estimates
We prepare our Consolidated Financial Statements in accordance with IFRS and the interpretations of the IFRS Interpretations Committee (“IFRIC”), as adopted by the IASB. The preparation of the financial statements requires us to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. We continually evaluate these estimates and assumptions based on the most recently available information, our own historical experience and various other assumptions that we believe to be reasonable under the circumstances. Since the use of estimates is an integral component of the financial reporting process, actual results could differ from those estimates.
An accounting policy is considered critical if it requires an accounting estimate to be made based on assumptions about matters that are highly uncertain at the time such estimate is made, and if different accounting estimates that reasonably could have been used, or changes in the accounting estimates that are reasonably likely to occur periodically, could materially impact the financial statements. We believe that the following accounting policies represent critical accounting policies as they involve a higher degree of judgment and complexity in their application and require us to make significant accounting estimates. The following descriptions of critical accounting policies and estimates should be read in conjunction with our Consolidated Financial Statements and the accompanying notes and other disclosures.
Business combinations
Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair market value of the assets acquired, equity instruments issued and liabilities incurred or assumed on the date of completion of the acquisition. Acquisition costs incurred are recognized directly in the consolidated statement of income. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair market values at the acquisition date. The excess of the cost of acquisitions over fair market value of a company’s share of the identifiable net assets acquired is recorded as goodwill. If the cost of the acquisition is less than a company’s share of the net assets acquired, the difference is recognized directly in the consolidated statement of income.
The determination of fair value of identifiable acquired assets and assumed liabilities means that we are to make estimates and use valuation techniques, including independent appraisers. The valuation assumptions underlying each of these valuation methods are based on available updated information, including discount rates, estimated cash flows, market risk rates and other data. As a result, the process of identification and the related determination of fair values require complex judgments and significant estimates.
Cash flow estimates for impairment assessments
Cash flow estimates for impairment assessments require assumptions about two primary elements: future prices and reserves. Estimates of future prices require significant judgments about highly uncertain future events. Historically, oil and natural gas prices have exhibited significant volatility. Our forecasts for oil and natural gas revenues are based on prices derived from future price forecasts among industry analysts, as well as our own assessments. Estimates of future cash flows are generally based on assumptions of long-term prices and operating and development costs.
The process of estimating reserves requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. The estimation of economically recoverable oil and natural gas reserves and related future net cash flows was performed based on the D&M Reserves Report. Such estimates incorporate many factors and assumptions including:
Our management believes these factors and assumptions are reasonable based on the information available at the time we prepare our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and natural gas prices and costs change.
For further information related to impairment of property, plant and equipment, please see Note 36 to our Consolidated Financial Statements.
Oil and gas accounting
Oil and gas exploration and production activities are accounted for in accordance with the successful efforts method on a field by field basis. We account for exploration and evaluation activities in accordance with IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing exploration and evaluation costs until such time as the economic viability of producing the underlying resources is determined. Costs incurred prior to obtaining legal rights to explore are expensed immediately to the consolidated statement of income.
Exploration and evaluation costs may include: license acquisition, geological and geophysical studies (i.e., seismic), direct labor costs and drilling costs of exploratory wells. No depreciation and/or amortization are charged during the exploration and evaluation phase. Upon completion of the evaluation phase, the prospects are either transferred to oil and gas properties or charged to expense in the period in which the determination is made, depending whether they have found reserves. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is recoverable. All field development costs are considered construction in progress until they are finished and capitalized within oil and gas properties, and are subject to depreciation once completed. Such costs may include the acquisition and installation of production facilities, development drilling costs (including dry holes, service wells and seismic surveys for development purposes), project-related engineering and the acquisition costs of rights and concessions related to proved properties.
Workovers of wells made to develop reserves and/or increase production are capitalized as development costs. Maintenance costs are charged to income when incurred.
Capitalized costs of proved oil and gas properties and production facilities and machinery are depreciated on a licensed area by licensed area basis, using the unit of production method, based on commercial proved and probable reserves. The calculation of the “unit of production” depreciation takes into account estimated future finding and development costs, and is based on current year-end un-escalated price levels. Changes in reserves and cost estimates are recognized prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content.
Oil and gas reserves for purposes of our Consolidated Financial Statements are determined in accordance with PRMS, and were estimated by DeGolyer and MacNaughton, independent reserves engineers.
Depreciation of the remaining property, plant and equipment assets (i.e., furniture and vehicles) not directly associated with oil and gas activities has been calculated by means of the straight line method by applying such annual rates as required to write-off their value at the end of their estimated useful lives. The useful lives range between three and 10 years.
Asset retirement obligations
Obligations related to the plugging and abandonment of wells once operations are terminated may result in the recognition of significant liabilities. We record the fair value of the liability for asset retirement obligations in the period in which the wells are drilled. When the liability is initially recognized, the cost is also capitalized by increasing the carrying amount of the related asset. Over time, the liability is accreted to its present value at each reporting date, and the capitalized cost is depreciated over the estimated useful life of the related asset. Estimating the future abandonment costs is difficult and requires management to make assumptions and judgments because most of the obligations will be settled after many years. Technologies and costs are constantly changing, as are political, environmental, health, safety and public relations considerations. Consequently, the timing and future cost of dismantling and abandonment are subject to significant modification. Any change in the variables underlying our assumptions and estimates can have a significant effect on the liability and the related capitalized asset and future charges related to the retirement obligations. The present value of future costs necessary for well plugging and abandonment is calculated for each area at the present value of the estimated future expenditure. The liability recognized is based upon estimated future abandonment costs, wells subject to abandonment, time to abandonment, and future inflation rates.
Share-based payments
We provide several equity-settled, share-based compensation plans to certain employees and third-party contractors, composed of payments in the form of share awards and stock options plans.
Fair value of the stock option plans for employee or contractor services received in exchange for the grant of the options is recognized as an expense. The total amount to be expensed over the vesting period, which is the period over which all specified vesting conditions are to be satisfied, is determined by reference to the fair value of the options granted calculated using the Geometric Brownian Motion method. Determining the total value of our share-based payments requires the use of highly subjective assumptions, including the expected life of the stock options, estimated forfeitures and the price volatility of the underlying shares. The assumptions used in calculating the fair value of share-based payment represent management’s best estimates, but these estimates involve inherent uncertainties and the application of management’s judgment.
Non-market vesting conditions are included in assumptions in respect of the number of options that are expected to vest. At each balance sheet date, we revise our estimates of the number of options that are expected to vest. We recognize the impact of the revision to original estimates, if any, in the consolidated statement of income, with a corresponding adjustment to equity.
The fair value of the share awards payments is determined at the grant date by reference of the market value of the shares and recognized as an expense over the vesting period.
When options are exercised, we issue new common shares. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium when the options are exercised.
Taxation
The computation of our income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution of tax positions taken by us, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome.
In addition, we have tax-loss carry-forwards in certain taxing jurisdictions that are available to offset against future taxable profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax losses can be utilized. Management judgment is exercised in assessing whether this is the case.
To the extent that actual outcomes differ from management’s estimates, taxation charges or credits may arise in future periods.
Contingencies
From time to time, we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, environmental and health & safety matters. For example, from time to time, the Company receives notices of environmental, health and safety violations. Based on what our Management currently knows, such claims are not expected to have a material impact on the financial statements.
Recent accounting pronouncements
See Note 2.1.1 to our Consolidated Financial Statements.
We have set up a project team by business unit which has reviewed each business unit’s leasing arrangements over the last year in light of the new lease accounting rules in IFRS 16.
As of December 31, 2018, we have non-cancellable operating lease commitments of US$ 69.9 million. Of these commitments, we expect to recognize right-of-use assets and lease liabilities, at nominal value, of approximately US$ 14.5 million on January 1, 2019. The remaining lease commitments, in accordance with IFRS 16, will be recognized on a straight-line basis as expense in the consolidated statement of income.
There will not be an impact on Adjusted EBITDA as a consequence of the adoption of this new standard.
Operating cash flows will increase and financing cash flows will decrease by approximately US$ 4 million, as repayment of the principal portion of the lease liabilities will be classified as cash flows from financing activities.
We have applied the standard from the mandatory adoption date of January 1, 2019. We intend to apply the simplified transition approach and as a result, will not restate comparative amounts for the year prior to first adoption.
Results of operations
The following discussion is of certain financial and operating data for the periods indicated. You should read this discussion in conjunction with our Consolidated Financial Statements and the accompanying notes.
In preparation for continued volatility, we have developed multiple scenarios for our 20192022 capital expenditure program. See “Item 4. Information on the Company –B. Business Overview—20192022 Strategy and Outlook.”
110
Year ended December 31, 20182021 compared to year ended December 31, 2017
2020
The following table summarizes certain of our financial and operating data for the years ended December 31, 20182021 and 2017.2020.
| For the year ended December 31, | ||||||||||||
| 2018 | 2017 | % Change from prior year | ||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||
| Revenue | ||||||||||||
| Net oil sales | 545,490 | 279,162 | 95 | % | ||||||||
| Net gas sales | 55,671 | 50,960 | 9 | % | ||||||||
| Revenue | 601,161 | 330,122 | 82 | % | ||||||||
| Commodity risk management contracts | 16,173 | (15,448 | ) | (205 | )% | |||||||
| Production and operating costs | (174,260 | ) | (98,987 | ) | 76 | % | ||||||
| Geological and geophysical expenses | (13,951 | ) | (7,694 | ) | 81 | % | ||||||
| Administrative expenses | (52,074 | ) | (42,054 | ) | 24 | % | ||||||
| Selling expenses | (4,023 | ) | (1,136 | ) | 254 | % | ||||||
| Depreciation | (92,240 | ) | (74,885 | ) | 23 | % | ||||||
| Write-off of unsuccessful exploration efforts | (26,389 | ) | (5,834 | ) | 352 | % | ||||||
| Impairment loss reversed for non-financial assets | 4,982 | - | 100 | % | ||||||||
| Other operating expense | (2,887 | ) | (5,088 | ) | (43 | )% | ||||||
| Operating profit | 256,492 | 78,996 | 225 | % | ||||||||
| Financial expenses | (39,321 | ) | (53,511 | ) | (27 | )% | ||||||
| Financial income | 3,059 | 2,016 | 52 | % | ||||||||
| Foreign exchange loss | (11,323 | ) | (2,193 | ) | 416 | % | ||||||
| Profit before income tax | 208,907 | 25,308 | 725 | % | ||||||||
| Income tax expense | (106,240 | ) | (43,145 | ) | 146 | % | ||||||
| Profit (Loss) for the year | 102,667 | (17,837 | ) | 676 | % | |||||||
| Non-controlling interest | 30,252 | 6,391 | 373 | % | ||||||||
| Profit (Loss) for the year attributable to owners of the Company | 72,415 | (24,228 | ) | 399 | % | |||||||
| Net production volumes | ||||||||||||
| Oil (mbbl)(2) | 11,113 | 8,309 | 34 | % | ||||||||
| Gas (mcf)(3) | 12,219 | 10,562 | 16 | % | ||||||||
| Total net production (mboe) | 13,150 | 10,069 | 31 | % | ||||||||
| Average net production (boepd) | 36,027 | 27,586 | 24 | % | ||||||||
| Average realized sales price | ||||||||||||
| Oil (US$ per bbl) | 53.0 | 36.6 | 46 | % | ||||||||
| Gas (US$ per mmcf) | 5.1 | 5.3 | (4 | )% | ||||||||
| Average unit costs per boe (US$) | ||||||||||||
| Operating cost | 8.2 | 7.4 | 11 | % | ||||||||
| Royalties and other | 5.8 | 3.0 | 93 | % | ||||||||
| Production costs(1) | 14.0 | 10.4 | 35 | % | ||||||||
| Geological and geophysical expenses | 1.1 | 0.8 | 38 | % | ||||||||
| Administrative expenses | 4.2 | 4.4 | -5 | % | ||||||||
| Selling expenses | 0.3 | 0.1 | 200 | % | ||||||||
| | | | | | | |
| | For the year ended December 31, |
| ||||
|
| |
| |
| % Change from |
|
| | 2021 | | 2020 | | prior year | |
| | (in thousands of US$, except for percentages) |
| ||||
| | | | | | | |
Revenue |
|
|
|
|
|
| |
Sale of crude oil |
| 647,559 |
| 359,640 |
| 80 | % |
Sale of gas |
| 40,984 |
| 34,052 |
| 20 | % |
Revenue |
| 688,543 |
| 393,692 |
| 75 | % |
Commodity risk management contracts |
| (109,191) |
| 8,081 |
| (1,451) | % |
Production and operating costs |
| (212,790) |
| (125,072) |
| 70 | % |
Geological and geophysical expenses |
| (7,891) |
| (14,951) |
| (47) | % |
Administrative expenses |
| (46,828) |
| (50,315) |
| (7) | % |
Selling expenses |
| (8,730) |
| (5,844) |
| 49 | % |
Depreciation |
| (88,969) |
| (118,073) |
| (25) | % |
Write-off of unsuccessful exploration efforts |
| (12,262) |
| (52,652) |
| (77) | % |
Impairment loss recognized for non-financial assets |
| (4,334) |
| (133,864) |
| (97) | % |
Other expenses |
| (11,739) |
| (11,665) |
| 1 | % |
Operating profit (loss) |
| 185,809 |
| (110,663) |
| (268) | % |
Financial expenses |
| (64,112) |
| (64,582) |
| (1) | % |
Financial income |
| 1,652 |
| 3,166 |
| (48) | % |
Foreign exchange profit (loss) |
| 5,049 |
| (13,008) |
| (139) | % |
Profit (loss) before income tax |
| 128,398 |
| (185,087) |
| (169) | % |
Income tax expense |
| (67,271) |
| (47,863) |
| 41 | % |
Profit (loss) for the year |
| 61,127 |
| (232,950) |
| (126) | % |
| | | | | | | |
Net production volumes |
|
|
|
|
|
| |
Oil (mbbl)(2) |
| 11,853 |
| 12,759 |
| (7) | % |
Gas (mcf)(3) |
| 11,230 |
| 11,709 |
| (4) | % |
Total net production (mboe) |
| 13,725 |
| 14,710 |
| (7) | % |
Average net production (boepd) |
| 37,602 |
| 40,192 |
| (6) | % |
Average realized sales price |
|
|
|
|
|
| |
Oil (US$ per bbl) |
| 58.3 |
| 31.2 |
| 87 | % |
Gas (US$ per mmcf) |
| 4.0 |
| 3.1 |
| 28 | % |
Average unit costs per boe (US$) |
| |
| |
|
| |
Operating cost |
| 7.6 |
| 6.5 |
| 17 | % |
Royalties |
| 8.6 |
| 2.6 |
| 231 | % |
Production costs(1) |
| 16.1 |
| 9.1 |
| 77 | % |
Geological and geophysical expenses |
| 0.6 |
| 1.1 |
| (45) | % |
Administrative expenses |
| 3.5 |
| 3.7 |
| (5) | % |
Selling expenses |
| 0.7 |
| 0.4 |
| 75 | % |
| (1) | Calculated pursuant to FASB ASC 932. |
| (2) | We present production figures before deduction of royalties, as we believe that net production before royalties is more appropriate in light of our foreign operations and the attendant royalty regimes. Oil production figures presented on page |
| (3) | Corresponds to production measured after separation but prior to compression, which is the measure we used to monitor business performance. Gas production presented on page |
111
The following table summarizes certain financial and operating data.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | ||||||||||||||||||||||||||||||||||||||||||||||||
| | For the year ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| | 2021 | | 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Ecuador |
| Other |
| Total |
| Colombia |
| Chile |
| Brazil |
| Argentina | | Peru | | Other |
| Total | ||||||||||||||||||||||||||||||||||||||||||||||||
| For the year ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2018 | 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Chile | Colombia | Brazil | Argentina | Peru | Other | Total | Chile | Colombia | Brazil | Other | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in thousands of US$) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
| (in thousands of US$) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Revenue | 37,359 | 497,870 | 30,053 | 35,879 | - | - | 601,161 | 32,738 | 263,076 | 34,238 | 70 | 330,122 |
| 618,268 | | 21,471 | | 20,109 | | 28,695 | | — | | — |
| 688,543 |
| 334,606 | | 21,704 | | 12,783 | | 24,599 | | — | | — |
| 393,692 | ||||||||||||||||||||||||||||||||||||
| Depreciation | (28,203 | ) | (42,721 | ) | (10,395 | ) | (10,640 | ) | (245 | ) | (36 | ) | (92,240 | ) | (23,730 | ) | (40,010 | ) | (10,809 | ) | (336 | ) | (74,885 | ) |
| (61,279) | | (14,275) | | (4,082) | | (9,130) | | (200) | | (3) |
| (88,969) |
| (63,687) | | (33,571) | | (3,732) | | (16,564) | | (401) | | (118) |
| (118,073) | ||||||||||||||||||||||||
Impairment and write-off | (12,670 | ) | (6,134 | ) | (2,020 | ) | (583 | ) | - | (21,407 | ) | (546 | ) | (1,625 | ) | (2,978 | ) | (685 | ) | (5,834 | ) |
| (7,827) | | (22,076) | | — | | 13,307 | | — | | — |
| (16,596) |
| (1,949) | | (132,134) | | (2,253) | | (16,205) | | (33,975) | | — |
| (186,516) | |||||||||||||||||||||||||||
Revenue
For the year ended December 31, 2018,2021, crude oil sales were our principal source of revenue, with 91%94% and 9%6% of our total revenue from crude oil and gas sales, respectively. The following chart shows the change in oil and natural gas sales from the year ended December 31, 20172020, to the year ended December 31, 2018.2021.
| | | | | ||||||||
| | For the year ended | ||||||||||
| | December 31, | ||||||||||
|
| 2021 |
| 2020 | ||||||||
| For the year ended December 31, | ||||||||||||
| 2018 | 2017 | |||||||||||
|
| (in thousands of US$) | ||||||||||
| Consolidated | (in thousands of US$) | | | | | |||||||
| Sale of crude oil | 545,490 | 279,162 |
| 647,559 |
| 359,640 | ||||||
| Sale of gas | 55,671 | 50,960 |
| 40,984 |
| 34,052 | ||||||
| Total | 601,161 | 330,122 |
| 688,543 |
| 393,692 | ||||||
| | | | | | | | | | ||||||||||||||||
| | Year ended December 31, | | Change from prior year |
| ||||||||||||||||||||
|
| 2021 |
| 2020 |
|
| | % |
| ||||||||||||||||
| Year ended December 31, | Change from prior year | ||||||||||||||||||||||||
| 2018 | 2017 | % | |||||||||||||||||||||||
| (in thousands of US$, except for percentages) | |||||||||||||||||||||||||
|
| (in thousands of US$, except for percentages) | | ||||||||||||||||||||||
| By country |
|
|
|
|
|
|
|
| | ||||||||||||||||
| Colombia | 497,870 | 263,076 | 234,794 | 89 | % |
| 618,268 |
| 334,606 |
| 283,662 |
| 85 | % | |||||||||||
| Chile | 37,359 | 32,738 | 4,621 | 14 | % |
| 21,471 |
| 21,704 |
| (233) |
| (1) | % | |||||||||||
| Brazil | 30,053 | 34,238 | (4,185 | ) | (12 | )% |
| 20,109 |
| 12,783 |
| 7,326 |
| 57 | % | ||||||||||
| Argentina | 35,879 | 70 | 35,809 | 51,156 | % |
| 28,695 |
| 24,599 |
| 4,096 |
| 17 | % | |||||||||||
| Total | 601,161 | 330,122 | 271,039 | 82 | % |
| 688,543 |
| 393,692 |
| 294,851 |
| 75 | % | |||||||||||
Revenue increased 82%75%, from US$330.1393.7 million for the year ended December 31, 20172020, to US$601.1688.5 million for the year ended December 31, 2018,2021, primarily as a result of higher realized prices and additional deliveries.prices. Sales of crude oil increased due to higher realized prices and higherpartially offset by lower sold volumes of 10.711.5 mmbbl in the year ended December 31, 20182021, compared to 7.912.0 mmbbl in the year ended December 31, 2017,2020, and resulted in net revenue of US$545.5647.6 million for the year ended December 31, 20182021, compared to US$279.2359.6 million for the year ended December 31, 2017.2020. In addition, sales of gas increased from US$51.034.1 million for the year ended December 31, 20172020, to US$55.741.0 million for the year ended December 31, 20182021, due to increased sales volumes, the addition of the acquired blocks in Argentina and higher realized prices.
prices partially offset by lower natural gas deliveries.
The increase in 20182021 net revenue of US$271.0294.9 million is mainly explained by:
| an increase of US$ |
112
| an increase of US$ |
Revenue attributable to our operations in Colombia for the year ended December 31, 20182021, was US$497.9618.3 million, compared to US$263.1334.6 million for the year ended December 31, 2017,2020, representing 83%90% and 80%85% of our total consolidated sales.sales, respectively. The increase is related to an increase in oil deliveries from 7.6 mmbbl to 10.0 mmbbl and an increase in the average realized price per barrel of crude oil from US$36.130.6 per barrel to US$52.658.3 per barrel, primarily due to higher reference international prices.
prices partially offset by a decrease in oil deliveries from 11.3 mmbbl to 10.9 mmbbl.
Revenue attributable to our operations in Chile for the year ended December 31, 20182021, was US$37.421.5 million, a 14% increase1% decrease from US$32.721.7 million for the year ended December 31, 2017,2020, principally due to (1) increaseda decrease in gas sales by US$1.4 million reflecting lower deliveries, partially offset by higher average realized prices from US$16.1 per boe for the year ended December 31, 2020 to US$20.7 per boe for the year ended December 31, 2021, and, (2) an increase in oil sales by US$1.2 million reflecting higher average realized prices per barrel of crude oil from US$45.7 per barrel for the year December 31, 2017 to US$62.338.0 per barrel for the year ended December 31, 20182020 to US$62.8 per barrel for the year ended December 31, 2021 (an increase of US$16.624.8 per barrel or a total of 36%65%), and (2) an increase in gas sales by US$3.1 million reflecting higher gas prices and higher deliveries, mainly as a result of the discovery of the Jauke gas field. This was partially offset by sales of crude oil of 0.2 mmbbl for the year ended December 31, 2018 compared to 0.3 mmbbl for the year ended December 31, 2017 (aa decrease of 20%) due to the decline in oil base production.deliveries from 0.13 mmbbl to 0.10 mmbbl. The contribution to our revenue during suchthe years ended December 31, 2021, and 2020 from our operations in Chile was 6%3.1% and 5.5%, respectively.
Revenue attributable to our operations in Brazil for the year ended December 31, 20182021, was US$30.020.1 million, a 12% decrease57% increase from US$34.212.8 million for the year ended December 31, 2017,2020, principally due to lowerhigher gas deliveries from 0.5 mmboe to 0.6 mmboe to respond to the higher gas demand in Brazil plus higher realized gas prices and deliveries.from US$25.6 per boe for the year ended December 31, 2020, to US$37.4 per boe for the year ended December 31, 2021. The contribution to our revenue from our operations in Brazil during the years ended December 31, 20182021 and 20172020, was 5% in each year.
2.9% and 3.2%, respectively.
Revenue attributable to our operations in Argentina primarily from the acquired blocks in Argentina, for the year ended December 31, 20182021, was US$ 35.928.7 million, representing 6% of our total consolidated sales. Thea 17% increase from US$24.6 million for the year ended December 31, 2020, primary due to (1) an increase in oil sales by US$7.3 million related to an increase in average realized priceprices per barrel of crude oil increased from US$52.342.0 per barrel for the year ended December 31, 2020, to US$65.056.4 per barrel.
barrel for the year ended December 31, 2021 (or a total of 34%), partially offset by a decrease in oil deliveries from 0.5 mmbbl to 0.4 mmbbl, and (2) an increase in gas sales by US$0.8 million reflecting higher gas prices due to local market conditions, plus higher deliveries. The contribution to our revenue from our operations in Argentina during the years ended December 31, 2021 and 2020 was 4.2% and 6.2%, respectively.
Production and operating costs
The following table summarizes our production and operating costs for the years ended December 31, 20182021 and 2017.2020.
| | | | | | | | ||||||||||||
| | For the year ended December 31, |
| ||||||||||||||||
|
| |
| |
| % Change |
| ||||||||||||
| | 2021 | | 2020 | | from prior year | | ||||||||||||
| For the year ended December 31, | |||||||||||||||||||
| 2018 | 2017 | % Change from prior year | |||||||||||||||||
| (in thousands of US$, except for percentages) | |||||||||||||||||||
| Consolidated (including Colombia, Chile, Argentina, Peru and Brazil) | |||||||||||||||||||
|
| (in thousands of US$, except for percentages) | | ||||||||||||||||
Consolidated (including Colombia, Chile, Brazil and Argentina) |
|
|
|
|
|
| | ||||||||||||
| Royalties | (71,836 | ) | (28,697 | ) | 150 | % |
| (113,023) |
| (35,875) |
| 215 | % | ||||||
| Staff costs | (18,603 | ) | (12,358 | ) | 51 | % |
| (16,994) |
| (15,217) |
| 12 | % | ||||||
| Operation and maintenance | (7,756 | ) | (3,116 | ) | 149 | % |
| (7,826) |
| (7,491) |
| 4 | % | ||||||
| Transportation costs | (2,628 | ) | (2,969 | ) | (11 | )% |
| (3,383) |
| (5,622) |
| (40) | % | ||||||
| Well and facilities maintenance | (20,262 | ) | (14,722 | ) | 38 | % |
| (17,989) |
| (15,039) |
| 20 | % | ||||||
| Consumables | (17,444 | ) | (11,902 | ) | 47 | % |
| (19,270) |
| (16,776) |
| 15 | % | ||||||
| Equipment rental | (9,317 | ) | (5,818 | ) | 60 | % |
| (8,127) |
| (8,570) |
| (5) | % | ||||||
| Other costs | (26,414 | ) | (19,405 | ) | 36 | % |
| (26,178) |
| (20,482) |
| 28 | % | ||||||
| Total | (174,260 | ) | (98,987 | ) | 76 | % |
| (212,790) |
| (125,072) |
| 70 | % | ||||||
113
| Year ended December 31, | ||||||||||||||||||||||||||||||||
| 2018 | 2017 | |||||||||||||||||||||||||||||||
| Chile | Brazil | Argentina | Colombia | Chile | Brazil | Argentina | Colombia | |||||||||||||||||||||||||
| By country | (in thousands of US$) | |||||||||||||||||||||||||||||||
| Royalties | (1,473 | ) | (2,820 | ) | (4,833 | ) | (62,710 | ) | (1,314 | ) | (3,134 | ) | (13 | ) | (24,236 | ) | ||||||||||||||||
| Staff costs | (6,521 | ) | (386 | ) | (3,167 | ) | (8,529 | ) | (5,582 | ) | (241 | ) | (190 | ) | (6,345 | ) | ||||||||||||||||
| Operation and maintenance | - | - | (2,877 | ) | (4,879 | ) | - | - | - | (3,116 | ) | |||||||||||||||||||||
| Transportation costs | (1,250 | ) | - | (120 | ) | (1,258 | ) | (1,211 | ) | - | (80 | ) | (1,678 | ) | ||||||||||||||||||
| Well and facilities maintenance | (4,095 | ) | (1,286 | ) | (6,044 | ) | (8,837 | ) | (3,817 | ) | (2,982 | ) | - | (7,923 | ) | |||||||||||||||||
| Consumables | (1,712 | ) | - | (1,018 | ) | (14,714 | ) | (1,680 | ) | - | (12 | ) | (10,209 | ) | ||||||||||||||||||
| Equipment rental | (287 | ) | - | (1,269 | ) | (7,761 | ) | (59 | ) | - | (53 | ) | (5,706 | ) | ||||||||||||||||||
| Other costs | (6,561 | ) | (4,293 | ) | (5,715 | ) | (9,845 | ) | (7,336 | ) | (4,380 | ) | 10 | (7,700 | ) | |||||||||||||||||
| Total | (21,899 | ) | (8,785 | ) | (25,043 | ) | (118,533 | ) | (20,999 | ) | (10,737 | ) | (338 | ) | (66,913 | ) | ||||||||||||||||
| | | | | | | | | | | | | | | | |
| | Year ended December 31, | ||||||||||||||
| | 2021 | | 2020 | ||||||||||||
|
| Colombia |
| Chile |
| Argentina |
| Brazil |
| Colombia |
| Chile |
| Argentina |
| Brazil |
|
| (in thousands of US$) | ||||||||||||||
By country | | | | | | | | | | | | | | | | |
Royalties |
| (106,341) | | (770) | | (4,270) | | (1,642) |
| (30,453) | | (753) | | (3,620) | | (1,049) |
Staff costs |
| (9,490) | | (3,590) | | (3,909) | | (5) |
| (11,684) | | (3,188) | | (165) | | (180) |
Operation and maintenance |
| (4,813) | | — | | (3,013) | | — |
| (2,538) | | — | | (4,885) | | (68) |
Transportation costs |
| (2,606) | | (691) | | (86) | | — |
| (4,889) | | (638) | | (95) | | — |
Well and facilities maintenance |
| (13,118) | | (2,162) | | (1,842) | | (867) |
| (8,694) | | (1,607) | | (3,536) | | (1,202) |
Consumables |
| (17,022) | | (1,151) | | (1,097) | | — |
| (14,587) | | (1,050) | | (1,096) | | (43) |
Equipment rental |
| (6,682) | | (608) | | (837) | | — |
| (6,834) | | (516) | | (903) | | (317) |
Other costs |
| (18,312) | | (2,078) | | (3,706) | | (2,082) |
| (12,640) | | (2,492) | | (4,333) | | (1,017) |
Total |
| (178,384) |
| (11,050) |
| (18,760) |
| (4,596) |
| (92,319) |
| (10,244) |
| (18,633) |
| (3,876) |
Consolidated production and operating costs increased 76%70%, from US$99.0125.1 million for the year ended December 31, 20172020, to US$174.3212.8 million for the year ended December 31, 2018,2021, primarily due to the new operationhigher cash royalties as a result of the blocks in Argentina, higher royalties paid in cash, in line with increased production and a higher royalty rate in Colombia, and increased operating costs related to higher sales volumes.
international prices.
Production and operating costs in Colombia increased 77%by 93%, to US$118.5178.4 million for the year ended December 31, 2018,2021, as compared to US$66.992.3 million for the year ended December 31, 2017,2020, primarily due to higher royalties of US$38.575.9 million, in line with increased production, a higher royalty rate and higher oil prices. In addition, operating costs per boeprices and due to incremental maintenance and well intervention activities in Colombia remained at US$5.6 per boe for the year ended December 31, 2018.
Llanos 34 Block.
Production and operating costs in Chile increased by 4%8% to US$21.911.1 million due to higher staffwell intervention and maintenance activities that were suspended in the comparative period due to the lower oil price environment. Operating costs expenses and pulling campaign. Costs per boe increased to US$22.8 per boe from US$20.312.3 per boe in 2017. In the year ended December 31, 2018, the revenue mix for Chile was 46.6% oil and 53.4% gas, whereas for the same period2021 from US$8.2 per boe in 2017 it was 48.5% oil and 51.5% gas.
2020.
Production and operating costs in Brazil decreasedincreased by 18%19%, to US$8.84.6 million for the year ended December 31, 2018,2021, as compared to the year ended December 31, 2017,2020, mainly resulting from non-recurring maintenance costs in Manati Field. Operatinghigher royalties due to higher realized prices and gas deliveries. However, operating costs per boe decreased to US$6.14.6 for the year ended December 31, 20182021, from US$7.85.8 per boe for the year ended December 31, 2017.
2020.
Production and operating costs in Argentina amountedincreased by 1%, to US$25.018.8 million for the year ended December 31, 2018, mainly resulting from the operation of the blocks we acquired in Neuquén. Operating costs per boe amounted2021, as compared to US$31.2 for the year ended December 31, 2018.
Geological and geophysical expenses
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2018 | 2017 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | (6,288 | ) | (2,231 | ) | (4,057 | ) | 182 | % | ||||||||
| Chile | (733 | ) | (858 | ) | 125 | (15 | )% | |||||||||
| Brazil | (827 | ) | (1,007 | ) | 180 | (18 | )% | |||||||||
| Argentina | (1,694 | ) | (22 | ) | (1,672 | ) | 7,600 | % | ||||||||
| Other | (4,409 | ) | (3,576 | ) | (833 | ) | 23 | % | ||||||||
| Total | (13,951 | ) | (7,694 | ) | (6,257 | ) | 81 | % | ||||||||
Geological and geophysical expenses increased 81%, from US$7.718.6 million for the year ended December 31, 20172020, mainly due to higher operating costs per boe partially offset by lower oil deliveries. Operating costs per boe increased to US$14.020.8 for the year ended December 31, 2021, from US$19.8 per boe for the year ended December 31, 2020.
Geological and geophysical expenses
| | | | | | | | | |
| | Year ended December 31, | | Change from prior year |
| ||||
|
| 2021 |
| 2020 |
|
|
| % |
|
|
| (in thousands of US$, except for percentages) | | ||||||
Colombia |
| (3,450) |
| (10,544) |
| 7,094 |
| (67) | % |
Chile |
| (74) |
| (134) |
| 60 |
| (45) | % |
Brazil |
| — |
| (464) |
| 464 |
| (100) | % |
Argentina |
| (998) |
| (694) |
| (304) |
| 44 | % |
Other |
| (3,369) |
| (3,115) |
| (254) |
| 8 | % |
Total |
| (7,891) |
| (14,951) |
| 7,060 |
| (47) | % |
Geological and geophysical expenses decreased by 47%, from US$15.0 million for the year ended December 31, 2018, primarily as the result of lower allocation2020, to capitalized projects in Colombia due to: (i) decreased exploratory drilling activity levels totalling US$4.1 million, (ii) the new operation of the blocks in Argentina which increased US$1.7 million and (iii) a higher level of activities in Peru for an amount of US$0.5 million.
Administrative costs
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2018 | 2017 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | (24,910 | ) | (17,567 | ) | (7,343 | ) | 42 | % | ||||||||
| Chile | (5,671 | ) | (6,331 | ) | 660 | (10 | )% | |||||||||
| Brazil | (2,628 | ) | (2,444 | ) | (184 | ) | 8 | % | ||||||||
| Argentina | (2,847 | ) | (2,057 | ) | (790 | ) | 38 | % | ||||||||
| Other | (16,018 | ) | (13,655 | ) | (2,363 | ) | 17 | % | ||||||||
| Total | (52,074 | ) | (42,054 | ) | (10,020 | ) | 24 | % | ||||||||
Administrative costs increased 24%, from US$42.17.9 million for the year ended December 31, 20172021, primarily as the result of cost reduction initiatives and higher allocations to capitalized projects, as a result of the exploratory activities that were suspended in the comparative period due to the lower oil price environment.
114
Administrative costs
| | | | | | | | | |
| | Year ended December 31, | | Change from prior year |
| ||||
|
| 2021 |
| 2020 |
| |
| % |
|
|
| (in thousands of US$, except for percentages) | | ||||||
Colombia |
| (20,441) |
| (24,710) |
| 4,269 |
| (17) | % |
Chile |
| (1,694) |
| (2,968) |
| 1,274 |
| (43) | % |
Brazil |
| (1,349) |
| (1,485) |
| 136 |
| (9) | % |
Argentina |
| (4,787) |
| (2,449) |
| (2,338) |
| 95 | % |
Other |
| (18,557) |
| (18,703) |
| 146 |
| (1) | % |
Total |
| (46,828) |
| (50,315) |
| 3,487 |
| (7) | % |
Administrative costs decreased by 7%, from US$52.150.3 million for the year ended December 31, 2018, mainly due2020, to higher consultant fees and travel expenses for an amount of US$3.3 million, higher staff costs for an amount of US$2.7 million and higher other expenses related to our growth strategy and new business.
Selling expenses
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2018 | 2017 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | (1,028 | ) | (250 | ) | (778 | ) | 311 | % | ||||||||
| Chile | (533 | ) | (688 | ) | 155 | (23 | )% | |||||||||
| Argentina | (2,462 | ) | (198 | ) | (2,264 | ) | 1143 | % | ||||||||
| Total | (4,023 | ) | (1,136 | ) | (2,887 | ) | 254 | % | ||||||||
Selling expenses increased 254%, from US$1.1 million for year ended December 31, 2017 to US$4.046.8 million for the year ended December 31, 2018,2021, primarily as the result of cost reduction initiatives and higher allocation to joint operations. This reduction was partially offset by an increase in consultant fees and communication and IT costs related to projects that were postponed in the previous year due to the COVID-19 pandemic.
Selling expenses
| | | | | | | | | |
| | Year ended December 31, | | Change from prior year |
| ||||
|
| 2021 |
| 2020 |
| |
| % |
|
| | (in thousands of US$, except for percentages) |
| ||||||
Colombia |
| (7,033) |
| (4,488) |
| (2,545) |
| 57 | % |
Chile |
| (318) |
| (295) |
| (23) |
| 8 | % |
Brazil | | — | | (14) | | 14 | | (100) | % |
Argentina |
| (1,379) |
| (1,047) |
| (332) |
| 32 | % |
Total |
| (8,730) |
| (5,844) |
| (2,886) |
| 49 | % |
Selling expenses increased by 49%, from US$5.8 million for year ended December 31, 2020, to US$8.7 million for the year ended December 31, 2021, primarily due to the sales increase during 2021, and also to differences in accounting for different points of sale in Colombia. Sales at the wellhead have no selling costs associated but generate lower revenue whereas transportation costs andfor sales to other delivery points are accounted for as selling taxes in the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina.
expenses.
Commodity risk management contracts
We recorded a profitloss of US$16.2109.2 million related to commodity risk management contracts for the year ended December 31, 20182021, and a lossprofit of US$15.48.1 million for the year ended December 31, 2017. Realized losses reflect cash settled transactions2020.
Consolidated commodity risk management contracts refer to two different components, a realized and an unrealized losses reflect non-cash changes between the contract values and the forward Brent oil curve.
Depreciation
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2018 | 2017 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | (42,721 | ) | (40,010 | ) | (2,711 | ) | 7 | % | ||||||||
| Chile | (28,203 | ) | (23,730 | ) | (4,473 | ) | 19 | % | ||||||||
| Brazil | (10,395 | ) | (10,809 | ) | 414 | (4 | )% | |||||||||
| Argentina | (10,640 | ) | (159 | ) | (10,481 | ) | 66 | % | ||||||||
| Other | (281 | ) | (177 | ) | (104 | ) | 59 | % | ||||||||
| Total | (92,240 | ) | (74,885 | ) | (17,355 | ) | 23 | % | ||||||||
Depreciation charges increased by 23% fromportion. The realized loss of US$74.9109.7 million for the year ended December 31, 20172021, compared to a US$92.221.1 million gain for the year ended December 31, 2020, reflected Brent oil prices and commodity risk management contracts settled during the respective periods. The unrealized gain was US$0.5 million for the year ended December 31, 2018, mainly2021, compared to US$13.0 million loss for the year ended December 31, 2020. Unrealized results are generated from changes in the forward Brent oil price curve.
115
Depreciation
| | | | | | | | | |
| | Year ended December 31, | | Change from prior year |
| ||||
|
| 2021 |
| 2020 |
| |
| % |
|
| | (in thousands of US$, except for percentages) |
| ||||||
Colombia |
| (61,279) |
| (63,687) |
| 2,408 |
| (4) | % |
Chile |
| (14,275) |
| (33,571) |
| 19,296 |
| (57) | % |
Brazil |
| (4,082) |
| (3,732) |
| (350) |
| 9 | % |
Argentina |
| (9,130) |
| (16,564) |
| 7,434 |
| (45) | % |
Other |
| (203) |
| (519) |
| 316 |
| (61) | % |
Total |
| (88,969) |
| (118,073) |
| 29,104 |
| (25) | % |
Depreciation charges decreased by 25% from US$118.1 million for the year ended December 31, 2020, to US$89.0 million for the year ended December 31, 2021, primarily due to a decrease in the new operationdepreciation cost per boe in Chile as a consequence of the impairment losses recognized in the Fell Block in 2020 and the property, plant and equipment related to the blocks in Argentina and increased volumes. However, depreciation costs per boe decreased from US$7.9 to US$7.1 per boe due to drilling successes and increased reservesthat were reclassified as held for sale in Colombia.
August 2021.
Operating profit (loss)
| | | | | | | | | | ||||||||||||||||
| | Year ended December 31, | | Change from prior year |
| ||||||||||||||||||||
|
| 2021 |
| 2020 |
| |
| % |
| ||||||||||||||||
| Year ended December 31, | Change from prior year | ||||||||||||||||||||||||
| 2018 | 2017 | % | |||||||||||||||||||||||
| (in thousands of US$, except for percentages) | |||||||||||||||||||||||||
| | (in thousands of US$, except for percentages) |
| ||||||||||||||||||||||
| Colombia | 309,357 | 116,290 | 193,067 | 166 | % |
| 228,983 |
| 144,806 |
| 84,177 |
| 58 | % | |||||||||||
| Chile | (29,139 | ) | (19,675 | ) | (9,464 | ) | 48 | % |
| (29,160) |
| (158,619) |
| 129,459 |
| (82) | % | ||||||||
| Brazil | 4,370 | 4,434 | (64 | ) | (1 | )% |
| 9,502 |
| 1,215 |
| 8,287 |
| 682 | % | ||||||||||
| Argentina | (6,739 | ) | (3,430 | ) | (3,309 | ) | 96 | % |
| (567) |
| (32,595) |
| 32,028 |
| (98) | % | ||||||||
| Other | (21,357 | ) | (18,623 | ) | (2,734 | ) | 15 | % |
| (22,949) |
| (65,470) |
| 42,521 |
| (65) | % | ||||||||
| Total | 256,492 | 78,996 | 177,496 | 225 | % |
| 185,809 |
| (110,663) |
| 296,472 |
| (268) | % | |||||||||||
We recorded an operating profit of US$256.5185.8 million for the year ended December 31, 2018, a 225% improvement from the2021, compared to an operating profitloss of US$79.0110.7 million for the year ended December 31, 2017, primarily due to an increase in revenue and other gains,2020, as a result of the reasons described above.
In 2018,2021, we recorded a write-off of unsuccessful exploration efforts of US$26.412.3 million that corresponded to ninetwo unsuccessful exploratory wells four wells drilled in Colombia (Tiple, Llanos 34 andthe Llanos 32 Blocks), two wells drilledBlock in Brazil (POT-T-747 and POT-T-619 Blocks) and three wells drilled in Argentina (Puelen Block). The charge also included the write-off of a well andColombia, other exploration costs incurred in the Fell Block in Chile, an exploratory well drilled in previous years in the CPO-5 Block in Colombia and other exploration costs incurred in previous years in the VIM-3PUT-30 Block and POT-T-882 and REC-T-93 Blocks,in Colombia for which no additional work would be performed. This was partially offset by
Additionally, during 2021, we recognized a gain on non-cash impairments reversalnet impairment loss of non-financial assets amounting to US$5.0 million. This amount comprised: (i) US$11.54.3 million gainthat corresponded to: (1) an impairment loss recognized in Colombia, resulting from an improved oil price environment and the known fair value less costsFell Block of disposal of the La Cuerva and Yamu Blocks; and (ii) US$6.517.6 million impairment loss due to the terminationdecline in the proved reserves estimation and, (2) a reversal of impairment loss of US$13.3 million in the Aguada Baguales and El Porvenir Blocks in Argentina due to the known market price of the sales agreement forblocks in the TdF’s blocks, with no renovation in place ascontext of the date of this annual report.
transaction described in Note 36.3.1 to our Consolidated Financial Statements. For further information see Note 37 to our Consolidated Financial Statements.
Financial costsresults
Financial costs decreased 30%Net financial results increased 2% to US$36.362.5 million for the year ended December 31, 20182021, as compared to US$51.561.4 million for the year ended December 31, 2017,2020, mainly due toresulting from a one-time costs on the cancellation of 2020 Notes for an amountcost of US$17.66.3 million recognizedassociated with the strategic deleveraging process executed in 2017.April 2021 that resulted in significant debt reduction with extended maturities and lower costs of debt.
Foreign exchange loss
gain (loss)
Foreign exchange variation increased fromwas a loss of US$2.213.0 million for the year ended December 31, 20172020, compared to a lossgain of US$11.35.0 million for the year ended December 31, 2018,2021. The loss of 2020 mainly duecorresponds to the depreciationrealized loss on
116
currency risk management contracts of US$9.4 million resulting from derivative financial instruments to manage our future exposure to local currency fluctuations with respect to income tax balances in the 2017 and 2018 period. Foreign exchange differences are mainly generated from changes in the value of the Brazilianreal over the U.S. Dollar-denominated debt incurred at the local subsidiary level, where the functional currency is the Brazilian real.
Colombia.
Profit (loss)before income tax
| | | | | | | | | |
| | Year ended December 31, | | Change from prior year |
| ||||
|
| 2021 |
| 2020 |
| |
| % |
|
| | (in thousands of US$, except for percentages) |
| ||||||
Colombia |
| 210,472 |
| 112,158 |
| 98,314 |
| 88 | % |
Chile |
| (30,284) |
| (159,855) |
| 129,571 |
| (81) | % |
Brazil |
| 8,714 |
| (2,956) |
| 11,670 |
| (395) | % |
Argentina |
| (2,865) |
| (32,277) |
| 29,412 |
| (91) | % |
Other |
| (57,639) |
| (102,157) |
| 44,518 |
| (44) | % |
Total |
| 128,398 |
| (185,087) |
| 313,485 |
| (169) | % |
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2018 | 2017 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | 305,409 | 113,028 | 192,381 | 170 | % | |||||||||||
| Chile | (40,545 | ) | (32,801 | ) | (7,744 | ) | 24 | % | ||||||||
| Brazil | (6,632 | ) | (2,529 | ) | (4,103 | ) | 162 | % | ||||||||
| Argentina | (13,737 | ) | (4,845 | ) | (8,892 | ) | 184 | % | ||||||||
| Other | (35,588 | ) | (47,545 | ) | 11,957 | (25 | )% | |||||||||
| Total | 208,907 | 25,308 | 183,599 | 725 | % | |||||||||||
For the year ended December 31, 2018,2021, we recorded a profit before income tax of US$208.9128.4 million, compared to a profitloss of US$25.3185.1 million for the year ended December 31, 2017,2020, primarily due to profits recorded in our Colombian operations.
the reasons mentioned above.
Income tax expense
| | | | | | | | | | ||||||||||||||||
| | Year ended December 31, | | Change from prior year |
| ||||||||||||||||||||
|
| 2021 |
| 2020 |
| |
| % |
| ||||||||||||||||
| Year ended December 31, | Change from prior year | ||||||||||||||||||||||||
| 2018 | 2017 | % | |||||||||||||||||||||||
| (in thousands of US$, except for percentages) | |||||||||||||||||||||||||
| | (in thousands of US$, except for percentages) |
| ||||||||||||||||||||||
| Colombia | (119,730 | ) | (45,406 | ) | (74,324 | ) | 164 | % |
| (61,074) |
| (41,079) |
| (19,995) |
| 49 | % | ||||||||
| Chile | 6,090 | 856 | 5,234 | 611 | % |
| (4,865) |
| 12,604 |
| (17,469) |
| (139) | % | |||||||||||
| Brazil | 1,762 | 36 | 1,726 | 4,794 | % |
| 2,700 |
| (11,151) |
| 13,851 |
| (124) | % | |||||||||||
| Argentina | 5,752 | - | 5,752 | 100 | % |
| (4,032) |
| (240) |
| (3,792) |
| 1,580 | % | |||||||||||
| Other | (114 | ) | 1,369 | (1,483 | ) | (108 | )% |
| — |
| (7,997) |
| 7,997 |
| (100) | % | |||||||||
| Total | (106,240 | ) | (43,145 | ) | (63,095 | ) | 146 | % |
| (67,271) |
| (47,863) |
| (19,408) |
| 41 | % | ||||||||
Our effective tax rate was 51%52% for the year ended December 31, 2018,2021, compared to 170%(26)% in 2017.2020. The decreaseincrease in the effective tax rate was primarily due to an increasethe generation of profit during 2021. The 2020 income tax expense included the write-down of the deferred income tax asset in profits recorded in our Colombian operations as comparedPeru due to the decision to retire from the Morona Block (US$8.4 million), the write-down of a portion of tax losses and other countriesdeferred income tax assets in Chile, Brazil and Argentina in which there was insufficient evidence of future taxable profits to offset them in accordance with the incorporation of the Argentine operations.
expected future cash-flows at year-end (US$24.2 million), and tax losses from non-taxable jurisdictions or where no deferred income tax benefit is recognized.
Profit (loss) for the year
| | | | | | | | | | ||||||||||||||||
| | Year ended December 31, | | Change from prior year |
| ||||||||||||||||||||
|
| 2021 |
| 2020 |
| |
| % |
| ||||||||||||||||
| Year ended December 31, | Change from prior year | ||||||||||||||||||||||||
| 2018 | 2017 | % | |||||||||||||||||||||||
| (in thousands of US$, except for percentages) | |||||||||||||||||||||||||
| | (in thousands of US$, except for percentages) |
| ||||||||||||||||||||||
| Colombia | 185,679 | 67,622 | 118,057 | 175 | % |
| 149,398 |
| 71,079 |
| 78,319 |
| 110 | % | |||||||||||
| Chile | (34,455 | ) | (31,945 | ) | (2,510 | ) | 8 | % |
| (35,149) |
| (147,251) |
| 112,102 |
| (76) | % | ||||||||
| Brazil | (4,870 | ) | (2,493 | ) | (2,377 | ) | 95 | % |
| 11,414 |
| (14,107) |
| 25,521 |
| (181) | % | ||||||||
| Argentina | (7,985 | ) | (4,845 | ) | (3,140 | ) | 65 | % |
| (6,897) |
| (32,517) |
| 25,620 |
| (79) | % | ||||||||
| Other | (35,702 | ) | (46,176 | ) | 10,474 | (23 | )% |
| (57,639) |
| (110,154) |
| 52,515 |
| (48) | % | |||||||||
| Total | 102,667 | (17,837 | ) | 120,504 | (676 | )% |
| 61,127 |
| (232,950) |
| 294,077 |
| (126) | % | ||||||||||
For the year ended December 31, 2018,2021, we recorded a net profit of US$102.761.1 million as a result of the reasons described above.
Profit for the year attributable to owners of the Company
Profit for the year attributable to owners of the Company increased by 399% to US$72.4 million,above, compared to a net loss for the year ended December 31, 2017 of US$24.2 million for the reasons described above. Profit attributable to non-controlling interest increased by 373% to US$30.3233.0 million for the year ended December 31, 2018 as2020.
117
Year ended December 31, 2020 compared to year ended December 31, 2019
For a profitdiscussion of US$6.4 millionthe results of our operations for the year ended December 31, 2017. In November 2018, we acquired all of LGI’s equity interest in GeoPark’s Chilean and Colombian subsidiaries.
Year ended December 31, 2017 compared to year ended December 31, 2016
The following table summarizes certain of our financial and operating data for the years ended December 31, 2017 and 2016.
| For the year ended December 31, | ||||||||||||
| 2017 | 2016 | % Change from prior year | ||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||
| Revenue | ||||||||||||
| Net oil sales | 279,162 | 145,193 | 92 | % | ||||||||
| Net gas sales | 50,960 | 47,477 | 7 | % | ||||||||
| Revenue | 330,122 | 192,670 | 71 | % | ||||||||
| Commodity risk management contracts | (15,448 | ) | (2,554 | ) | 505 | % | ||||||
| Production and operating costs | (98,987 | ) | (67,235 | ) | 47 | % | ||||||
| Geological and geophysical expenses | (7,694 | ) | (10,282 | ) | (25 | )% | ||||||
| Administrative expenses | (42,054 | ) | (34,170 | ) | 23 | % | ||||||
| Selling expenses | (1,136 | ) | (4,222 | ) | (73 | )% | ||||||
| Depreciation | (74,885 | ) | (75,774 | ) | (1 | )% | ||||||
| Write-off of unsuccessful exploration efforts | (5,834 | ) | (31,366 | ) | (81 | )% | ||||||
| Impairment loss reversed for non-financial assets | - | 5,664 | (100 | )% | ||||||||
| Other operating expense | (5,088 | ) | (1,344 | ) | 279 | % | ||||||
| Operating profit (loss) | 78,996 | (28,613 | ) | (376 | )% | |||||||
| Financial costs | (51,495 | ) | (34,101 | ) | 51 | % | ||||||
| Foreign exchange (loss) gain | (2,193 | ) | 13,872 | (116 | )% | |||||||
| Profit (Loss) before income tax | 25,308 | (48,842 | ) | (152 | )% | |||||||
| Income tax expense | (43,145 | ) | (11,804 | ) | 266 | % | ||||||
| Loss for the year | (17,837 | ) | (60,646 | ) | (71 | )% | ||||||
| Non-controlling interest | 6,391 | (11,554 | ) | (155 | )% | |||||||
| Loss for the year attributable to owners of the Company | (24,228 | ) | (49,092 | ) | (51 | )% | ||||||
| Net production volumes | ||||||||||||
| Oil (mbbl)(2) | 8,309 | 6,189 | 34 | % | ||||||||
| Gas (mcf)(3) | 10,562 | 11,911 | (11 | )% | ||||||||
| Total net production (mboe) | 10,069 | 8,174 | 23 | % | ||||||||
| Average net production (boepd) | 27,586 | 22,394 | 23 | % | ||||||||
| Average realized sales price | ||||||||||||
| Oil (US$ per bbl) | 36.6 | 25.6 | 43 | % | ||||||||
| Gas (US$ per mmcf) | 5.3 | 4.5 | 18 | % | ||||||||
| Average unit costs per boe (US$) | ||||||||||||
| Operating cost | 7.4 | 7.3 | 1 | % | ||||||||
| Royalties and other | 3.0 | 1.5 | 100 | % | ||||||||
| Production costs(1) | 10.4 | 8.8 | 18 | % | ||||||||
| Geological and geophysical expenses | 0.8 | 1.3 | (38 | )% | ||||||||
| Administrative expenses | 4.4 | 4.5 | (2 | )% | ||||||||
| Selling expenses | 0.1 | 0.6 | (83 | )% | ||||||||
The following table summarizes certain financial and operating data.
| For the year ended December 31, | ||||||||||||||||||||||||||||||||||||||||
| 2017 | 2016 | |||||||||||||||||||||||||||||||||||||||
| Chile | Colombia | Brazil | Other | Total | Chile | Colombia | Brazil | Other | Total | |||||||||||||||||||||||||||||||
| (in thousands of US$) | ||||||||||||||||||||||||||||||||||||||||
| Revenue | 32,738 | 263,076 | 34,238 | 70 | 330,122 | 36,723 | 126,228 | 29,719 | - | 192,670 | ||||||||||||||||||||||||||||||
| Depreciation | (23,730 | ) | (40,010 | ) | (10,809 | ) | (336 | ) | (74,885 | ) | (31,355 | ) | (31,148 | ) | (12,974 | ) | (297 | ) | (75,774 | ) | ||||||||||||||||||||
| Impairment and write-off | (546 | ) | (1,625 | ) | (2,978 | ) | (685 | ) | (5,834 | ) | (19,389 | ) | (1,730 | ) | (4,583 | ) | - | (25,702 | ) | |||||||||||||||||||||
Revenue
For the year ended December 31, 2017, crude oil sales were our principal source of revenue, with 85% and 15% of our total revenue from crude oil and gas sales, respectively. The following chart shows the change in oil and natural gas sales from the year ended December 31, 2016 to the year ended December 31, 2017.
| For the year ended December 31, | ||||||||
| 2017 | 2016 | |||||||
| Consolidated | (in thousands of US$) | |||||||
| Sale of crude oil | 279,162 | 145,193 | ||||||
| Sale of gas | 50,960 | 47,477 | ||||||
| Total | 330,122 | 192,670 | ||||||
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2017 | 2016 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| By country | ||||||||||||||||
| Colombia | 263,076 | 126,228 | 136,848 | 108 | % | |||||||||||
| Chile | 32,738 | 36,723 | (3,985 | ) | (11 | )% | ||||||||||
| Brazil | 34,238 | 29,719 | 4,519 | 15 | % | |||||||||||
| Other | 70 | - | 70 | 100 | % | |||||||||||
| Total | 330,122 | 192,670 | 137,452 | 71 | % | |||||||||||
Revenue increased 71%, from US$192.7 million for the year ended December 31, 2016 to US$330.1 million for the year ended December 31, 2017, primarily as a result of higher oil revenues. Sales of crude oil increased due to higher realized prices and higher sold volumes of 7.9 mmbbl in the year ended December 31, 2017 compared to 5.9 mmbbl in the year ended December 31, 2016, and resulted in net revenue of US$279.2 million for the year ended December 31, 2017 compared to US$145.2 million for the year ended December 31, 2016. In addition, sales of gas increased from US$47.5 million for the year ended December 31, 2016 to US$51.0 million for the year ended December 31, 2017 due to increased sales volumes and higher realized prices.
The increase in 2017 net revenue of US$137.5 million is mainly explained by:
all of which was due principally to higher oil and gas prices, as further described below.
Revenue attributable to our operations in Colombia for the year ended December 31, 2017 was US$263.1 million, compared to US$126.2 million for the year ended December 31, 2016, representing 80% and 66% of our total consolidated sales. The increase is related to an increase in oil deliveries from 5.4 mmbbl to 7.6 mmbbl and an increase in the average realized price per barrel of crude oil from US$24.4 per barrel to US$36.1 per barrel, primarily due to higher reference international prices.
Revenue attributable to our operations in Chile for the year ended December 31, 2017 was US$32.7 million, a 11% decrease from US$36.7 million for the year ended December 31, 2016, principally due to (1) decreased sales of crude oil of 0.3 mmbbl for the year ended December 31, 2017 compared to 0.5 mmbbl for the year ended December 31, 2016 (a decrease of 40%) due to the decline in oil base production, (2) a decrease in gas sales by US$1.1 million, due to decreased gas production levels as compared to the previous year. This was partially offset by increased average realized prices per barrel of crude oil from US$37.0 per barrel for the year December 31, 2016 to US$45.7 per barrel for the year ended December 31, 2017 (an increase of US$8.7 per barrel or a total of 24%). The increase in the average realized price per barrel was attributable to higher international reference prices. The contribution to our revenue during such years from our operations in Chile was 10% and 19%, respectively.
Revenue attributable to our operations in Brazil for the year ended December 31, 2017 was US$34.2 million, a 15% increase from US$29.7 million for the year ended December 31, 2016, principally due to higher gas prices. The contribution to our revenue from our operations in Brazil during the years ended December 31, 2017 and 2016 was 10% and 15%, respectively.
Production and operating costs
The following table summarizes our production and operating costs for the years ended December 31, 2017 and 2016.
| For the year ended December 31, | ||||||||||||
| 2017 | 2016 | % Change from prior year | ||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||
| Consolidated (including Colombia, Chile, Argentina, Peru and Brazil) | ||||||||||||
| Royalties | (28,697 | ) | (11,497 | ) | 150 | % | ||||||
| Staff costs | (15,474 | ) | (10,859 | ) | 42 | % | ||||||
| Transportation costs | (2,969 | ) | (2,281 | ) | 30 | % | ||||||
| Well and facilities maintenance | (14,722 | ) | (13,160 | ) | 12 | % | ||||||
| Consumables | (11,902 | ) | (8,283 | ) | 44 | % | ||||||
| Equipment rental | (5,818 | ) | (3,868 | ) | 50 | % | ||||||
| Other costs | (19,405 | ) | (17,287 | ) | 12 | % | ||||||
| Total | (98,987 | ) | (67,235 | ) | 47 | % | ||||||
| Year ended December 31, | ||||||||||||||||||||||||
| 2017 | 2016 | |||||||||||||||||||||||
| Chile | Brazil | Colombia | Chile | Brazil | Colombia | |||||||||||||||||||
| By country | (in thousands of US$) | |||||||||||||||||||||||
| Royalties | (1,314 | ) | (3,134 | ) | (24,236 | ) | (1,495 | ) | (2,721 | ) | (7,281 | ) | ||||||||||||
| Staff costs | (5,582 | ) | (241 | ) | (9,461 | ) | (5,866 | ) | (85 | ) | (5,530 | ) | ||||||||||||
| Transportation costs | (1,211 | ) | - | (1,678 | ) | (1,170 | ) | - | (1,111 | ) | ||||||||||||||
| Well and facilities maintenance | (3,817 | ) | (2,982 | ) | (7,923 | ) | (6,122 | ) | (1,419 | ) | (5,619 | ) | ||||||||||||
| Consumables | (1,680 | ) | - | (10,209 | ) | (1,405 | ) | - | (6,878 | ) | ||||||||||||||
| Equipment rental | (59 | ) | - | (5,706 | ) | (42 | ) | - | (3,826 | ) | ||||||||||||||
| Other costs | (7,336 | ) | (4,380 | ) | (7,700 | ) | (6,069 | ) | (4,234 | ) | (6,362 | ) | ||||||||||||
| Total | (20,999 | ) | (10,737 | ) | (66,913 | ) | (22,169 | ) | (8,459 | ) | (36,607 | ) | ||||||||||||
Consolidated production and operating costs increased 47%, from US$67.2 million for the year ended December 31, 2016 to US$99.0 million for the year ended December 31, 2017, primarily due to higher royalties paid in cash, in line with increased production (the Jacana oil field accumulated more than 5 mmbbl during the year ended December 31, 2017, triggering a higher royalty rate in Colombia), and higher oil prices, and increased operating costs related to higher sales volumes.
Production and operating costs in Colombia increased 83%, to US$66.9 million for the year ended December 31, 2017, as compared to US$36.6 million for the year ended December 31, 2016, primarily due to (i) higher royalties of US$17.0 million, in line with increased production (the Jacana oil field accumulated more than 5 mmbbl during the year ended December 31, 2017, triggering a higher royalty rate in Colombia) and higher oil prices, and (ii) increased costs associated with higher production and the reopening of the Cuerva and Yamu Blocks, which are mature fields with higher operating costs than the Llanos 34 Block. In addition, operating costs per boe in Colombia increased to US$5.6 per boe for the year ended December 31, 2017 from US$5.4 per boe for the year ended December 31, 2016.
Production and operating costs in Chile decreased by 5% to US$21.0 million due to lower oil and gas production levels. Costs per boe increased to US$20.3 per boe from US$15.8 per boe in 2016. In the year ended December 31, 2017, the revenue mix for Chile was 48.5% oil and 51.5% gas, whereas for the same period in 2016 it was 51.1% oil and 48.9% gas.
Production and operating costs in Brazil increased by 27%, to US$10.7 million for the year ended December 31, 2017, as2020 compared to the year ended December 31, 2016, mainly resulting from non-recurring maintenance costs2019, please refer to “Item 5.—A. Operating Results—Results of Operations for the Year Ended December 31, 2020 compared to the year ended December 31, 2019” in Manati Field. Operating costs per boe increased to US$7.8our Annual Report on Form 20-F for the year ended December 31, 2017 from US$5.8 per boe for the year ended December 31, 2016.2020.
Geological and geophysical expenses
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2017 | 2016 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | (2,231 | ) | (4,296 | ) | 2,065 | (48 | )% | |||||||||
| Chile | (858 | ) | (1,671 | ) | 813 | (49 | )% | |||||||||
| Brazil | (1,007 | ) | (1,053 | ) | 46 | (4 | )% | |||||||||
| Other | (3,598 | ) | (3,262 | ) | (336 | ) | 10 | % | ||||||||
| Total | (7,694 | ) | (10,282 | ) | 2,588 | (25 | )% | |||||||||
Geological and geophysical expenses decreased 25%, from US$10.3 million for the year ended December 31, 2016 to US$7.7 million for the year ended December 31, 2017, primarily as the result of higher allocation to capitalized projects due to increased drilling activity levels.
Administrative costs
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2017 | 2016 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | (17,567 | ) | (14,715 | ) | (2,852 | ) | 19 | % | ||||||||
| Chile | (6,331 | ) | (7,153 | ) | 822 | (11 | )% | |||||||||
| Brazil | (2,444 | ) | (3,085 | ) | 641 | (21 | )% | |||||||||
| Other | (15,712 | ) | (9,217 | ) | (6,495 | ) | 70 | % | ||||||||
| Total | (42,054 | ) | (34,170 | ) | (7,884 | ) | 23 | % | ||||||||
Administrative costs increased 23%, from US$34.2 million for the year ended December 31, 2016 to US$42.1 million for the year ended December 31, 2017, mainly due to higher staff costs and consulting fees resulting from an increased scale of operations.
Selling expenses
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2017 | 2016 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | (250 | ) | (2,830 | ) | 2,580 | (91 | )% | |||||||||
| Chile | (688 | ) | (994 | ) | 306 | (31 | )% | |||||||||
| Brazil | - | (20 | ) | 20 | (100 | )% | ||||||||||
| Other | (198 | ) | (378 | ) | 180 | (48 | )% | |||||||||
| Total | (1,136 | ) | (4,222 | ) | 3,086 | (73 | )% | |||||||||
Selling expenses decreased 73%, from US$4.2 million for year ended December 31, 2016 to US$1.1 million for the year ended December 31, 2017, primarily due to the Trafigura offtake agreement as sales occur at the wellhead in our Colombian operations, which are recorded as a discount to the oil price.
Commodity risk management contracts
We recorded a loss of US$15.4 million related to commodity risk management contracts for the year ended December 31, 2017. Realized losses reflect cash settled transactions and unrealized losses reflect non-cash changes between the contract values and the forward Brent oil curve.
Depreciation
Depreciation charges decreased by 1% from US$75.8 million for the year ended December 31, 2016 to US$74.9 million for the year ended December 31, 2017, mainly due to lower production levels in Chile and Brazil. and lower depreciation costs per barrel in Colombia. Depreciation costs per boe decreased from US$9.9 to US$7.9 per boe.
Operating profit (loss)
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2017 | 2016 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | 116,290 | 31,464 | 84,826 | 270 | % | |||||||||||
| Chile | (19,675 | ) | (44,969 | ) | 25,294 | (56 | )% | |||||||||
| Brazil | 4,434 | (644 | ) | 5,078 | (789 | )% | ||||||||||
| Other | (22,053 | ) | (14,464 | ) | (7,589 | ) | 52 | % | ||||||||
| Total | 78,996 | (28,613 | ) | 107,609 | (376 | )% | ||||||||||
We recorded an operating profit of US$79.0 million for the year ended December 31, 2017, a 376% improvement from the operating loss of US$28.6 million for the year ended December 31, 2016, primarily due to an increase in revenue and other gains and a decrease in certain expenses and depreciation, as described above. In 2016, we recorded a gain on non-cash impairments reversal of non-financial assets amounting to US$5.7 million in Colombia, resulting from an improved oil price environment and improvements in cost structure.
Financial costs
Financial costs increased 51% to US$51.5 million for the year ended December 31, 2017 as compared to US$34.1 million for the year ended December 31, 2016, mainly due to one-time costs on the cancellation of 2020 Notes for an amount of US$17.6 million.
Foreign exchange (loss) gain
Foreign exchange variation decreased from a gain of US$13.9 million for the year ended December 31, 2016 compared to a loss of US$2.2 million for the year ended December 31, 2017, mainly due to the appreciation of the Brazilianreal in the 2016 period and its depreciation in the 2017 period. Foreign exchange differences are mainly generated from changes in the value of the Brazilianreal over the U.S. Dollar-denominated debt incurred at the local subsidiary level, where the functional currency is the Brazilian real.
Profit (Loss) before income tax
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2017 | 2016 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | 113,028 | 25,845 | 87,183 | 337 | % | |||||||||||
| Chile | (32,801 | ) | (58,017 | ) | 25,216 | (43 | )% | |||||||||
| Brazil | (2,529 | ) | 8,762 | (11,291 | ) | (129 | )% | |||||||||
| Other | (52,390 | ) | (25,432 | ) | (26,958 | ) | 106 | % | ||||||||
| Total | 25,308 | (48,842 | ) | 74,150 | (152 | )% | ||||||||||
For the year ended December 31, 2017, we recorded a profit before income tax of US$25.3 million, compared to a loss of US$48.8 million for the year ended December 31, 2016, primarily due to profits recorded in our Colombian operations.
Income tax (expense)
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2017 | 2016 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | (45,406 | ) | (11,969 | ) | (33,437 | ) | 279 | % | ||||||||
| Chile | 856 | 2,155 | (1,299 | ) | (60 | )% | ||||||||||
| Brazil | 36 | (2,764 | ) | 2,800 | (101 | )% | ||||||||||
| Other | 1,369 | 774 | 595 | 77 | % | |||||||||||
| Total | (43,145 | ) | (11,804 | ) | (31,341 | ) | 266 | % | ||||||||
Income tax expense increased 266%, from US$11.8 million for the year ended December 31, 2016 to US$43.1 million for the year ended December 31, 2017, as a result of higher profits in Colombia.
Loss for the year
| Year ended December 31, | Change from prior year | |||||||||||||||
| 2017 | 2016 | % | ||||||||||||||
| (in thousands of US$, except for percentages) | ||||||||||||||||
| Colombia | 67,622 | 13,876 | 53,746 | 387 | % | |||||||||||
| Chile | (31,945 | ) | (55,862 | ) | 23,917 | (43 | )% | |||||||||
| Brazil | (2,493 | ) | 5,998 | (8,491 | ) | (142 | )% | |||||||||
| Other | (51,021 | ) | (24,658 | ) | (26,363 | ) | 107 | % | ||||||||
| Total | (17,837 | ) | (60,646 | ) | 42,809 | (71 | )% | |||||||||
For the year ended December 31, 2017, we recorded a net loss of US$17.8 million as a result of the reasons described above.
Loss for the year attributable to owners of the Company
Loss for the year attributable to owners of the Company decreased by 51% to US$24.2 million, compared to a loss for the year ended December 31, 2016 of US$49.1 million for the reasons described above. Profit attributable to non-controlling interest increased by 155% to US$6.4 million for the year ended December 31, 2017 as compared to a loss of US$11.6 million for the year ended December 31, 2016.
| B. Liquidity and capital resources |
Overview
Our financial condition and liquidity isare and will continue to be influenced by a variety of factors, including:
| changes in oil and natural gas prices and our ability to generate cash flows from our operations; |
| our capital expenditure requirements; |
| the level of our outstanding indebtedness and the interest we are obligated to pay on this indebtedness; and |
| changes in exchange rates which will impact our generation of cash flows from operations when measured in US$ |
We continually evaluate additional alternatives to further improve our capital structure by increasing our cash balances and/or reducing or refinancing a portion of our indebtedness. These alternatives include various strategic initiatives and potential asset sales as well as potential public or private equity or debt financings. If additional funds are obtained by issuing equity securities, our existing stockholders could be diluted. We can give no assurances that we will be able to sell any of our assets or to obtain additional financing on terms acceptable to us, or at all.
Our principal sources of liquidity have historically been contributed shareholder equity, debt financings and cash generated by our operations. We have also in the past entered into offtake and prepayment agreements.
SinceBetween 2005 to 2018,and 2021, we have raised approximately US$200 million in equity offerings at the holding company level and nearly US$11.5 billion through debt arrangements with multilateral agencies such as the IFC, gas prepayment facilities with Methanex, international bond issuances and bank financings, described further below, which have been used to fund our capital expenditures program and acquisitions and to increase our liquidity.
In February 2014, we commenced trading on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over-allotment option granted to and exercised by the underwriters, through the issuance of 13,999,700 common shares.
In September 2017, we issued US$425.0 million aggregate principal amount of senior notes due 2024. The Notes due 2024 mature on September 21, 2024 and bear interest at a fixed rate of 6.50% and a yield of 6.50% per year. Interest on the Notes due 2024 is payable semi-annually in arrears on March 21 and September 21 of each year. The Indenture governing our Notes due 2024 contains incurrence-based limitations on the amount of indebtedness we can incur. This limits our capacity to incur additional indebtedness, other than permitted debt, as specified in the indenture governing the Notes due 2024. The net proceeds from the Notes due 2024 were used by us (i) to make a capital contribution to our wholly-owned subsidiary, GeoPark Latin America Limited Agencia, en Chile, providing it with sufficient funds to fully repay the Notes due 2020 and to pay any related fees and expenses, including a call premium, and (ii) for general corporate purposes, including capital expenditures, such as the acquisition of the Aguada Baguales, El Porvenir and Puesto Touquet blocksBlocks in the Neuquén Basin in Argentina, and to repay existing indebtedness, including the Itaú loan in Brazil.
In January 2020, we issued US$350.0 million aggregate principal amount of senior notes due 2027. The Notes due 2027 mature on January 17, 2027, and bear interest at a fixed rate of 5.50% and a yield of 5.625% per year. Interest on the
118
Notes due 2027 is payable semi-annually in arrears on January 17 and July 17 of each year. The Indenture governing our Notes due 2027 contains incurrence-based limitations on the amount of indebtedness we can incur. This limits our capacity to incur additional indebtedness, other than permitted debt, as specified in the indenture governing the Notes due 2027. The net proceeds from the Notes were used by us (i) to make an intercompany loan to our wholly-owned subsidiary, GeoPark Colombia S.A.S., providing it with sufficient funds to pay the total consideration for the acquisition of Amerisur (see Note 36.1 to our Consolidated Financial Statements) and to pay any related fees and expenses, and (ii) for general corporate purposes.
In April 2021, we executed a series of transactions that included a successful tender to purchase US$255.0 million of the 2024 Notes that was funded with a combination of cash in hand and a US$150.0 million new issuance from the reopening of the 2027 Notes. The new notes offering, and the tender offer closed on April 23, 2021, and April 26, 2021, respectively.
The tender total consideration included the tender offer consideration of US$1,000 for each US$1,000 principal amount of the 2024 Notes plus the early tender payment of US$50 for each US$1,000 principal amount of the 2024 Notes. The tender also included a consent solicitation to align the covenants of the 2024 Notes to those of the 2027 Notes.
In May 2021, GeoPark Colombia S.A.S. executed a loan agreement with Bancolombia for Colombian Pesos 35.0 billion (equivalent to US$9.4 million at the moment of the loan execution) to finance working capital requirements in Colombia. The interest rate was the IBR index (interest rate of reference for short-term loans in Colombia) plus 1.6% per annum, and interests were payable monthly. The loan was set to mature in May 2022, but in August 2021, GeoPark Colombia S.A.S. fully prepaid the loan, with no additional cost.
In July 2021, GeoPark Colombia S.A.S. executed a loan agreement with Itau Bank for Colombian Pesos 37.7 billion (equivalent to US$10.0 million at the moment of the loan execution) to finance working capital requirements in Colombia. The interest rate was 5.38% per annum, and interests were payable monthly. The loan was set to mature in January 2022 but in October 2021, GeoPark Colombia S.A.S. fully prepaid the loan, with no additional cost.
On October 7, 2021, GeoPark Colombia S.A.S. signed a loan agreement with Banco BTG Pactual S.A. which provides GeoPark with access to up to US$20.0 million until October 7, 2022. The agreement establishes an interest rate of 4.50% per annum and a commitment fee of 1.95% per annum with respect to any undrawn amount. As of the date of this annual report, GeoPark Colombia S.A.S. has not withdrawn any amount from this loan.
On October 8, 2021, our Colombian subsidiaries entered into an offtake and prepayment agreement with Shell Western Supply and Trading Limited (“Shell”), one of their key customers. The prepayment agreement provides GeoPark with access to up to US$15.0 million in the form of prepaid future oil sales and has a twelve months availability period. Funds committed by Shell will be made available to GeoPark upon request and will be repaid by GeoPark, through future oil deliveries over the year after funds are disbursed. As of the date of this annual report, GeoPark has not withdrawn any amount from this prepayment agreement.
In September 2021, GeoPark was included in the S&P Global BMI Index and sub-indexes, including the S&P Emerging BMI, the S&P Colombia BMI, the S&P Latin America BMI, and the S&P Global BMI Energy, among others.
We believe that our current operations and 20192022 capital expenditures program can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline due to unforeseen events, including delivery restrictions or a protracted downturn in oil and gas prices, we would examine measures such as further capital expenditure program reductions, pre-saleoil prepayment agreements, disposition of assets, or issuance of equity, among others. We believe the liquidity and capital resource alternatives available to us will be adequate to fund our operations and provide flexibility until oil prices and industry conditions improve. This includes supporting our capital expenditure program, payment of debt services and dividends and any amount that may ultimately be paid in connection with commitments and contingencies. See “Item 4. Information on the Company—B. Business Overview—2022 Strategy and Outlook.”
119
Capital expenditures
In the past, we have funded our capital expenditures with proceeds from equity offerings, credit facilities, debt issuances and pre-sale agreements, as well as through cash generated from our operations. We expect to incur substantial expenses and capital expenditures as we develop our oil and natural gas prospects and acquire additional assets. See “Item 4. Information on the Company –B. Business Overview—20192022 Strategy and Outlook.”
Outlook”.
In the year ended December 31, 2018,2021, we madehad total capital expenditures, related to purchase of property, plant and equipment, of US$124.7129.3 million (US$97.0119.9 million, US$8.04.3 million, US$9.0 million, US$8.50.1 million and US$2.35.0 million in Colombia, Chile, Argentina Peru and Brazil,Ecuador, respectively).
In the year ended December 31, 2017,2020, we madehad total capital expenditures, related to purchase of property, plant and equipment, of US$105.675.3 million (US$80.061.6 million, US$10.211.9 million, US$8.20.7 million, US$3.60.4 million, US$0.4 million and US$3.60.3 million in Colombia, Chile, Argentina, Peru, Brazil and Brazil,Ecuador, respectively).
Cash flows
The following table sets forth our cash flows for the periods indicated:
| | | | | | | ||||||||||||
|
| Year ended December 31, | ||||||||||||||||
| | 2021 | | 2020 | | 2019 | ||||||||||||
| Year ended December 31, | ||||||||||||||||||
| 2018 | 2017 | 2016 | ||||||||||||||||
| (in thousands of US$) | ||||||||||||||||||
| Cash flows provided by (used in) | ||||||||||||||||||
| | (in thousands of US$) | ||||||||||||||||
Cash flows from (used in) |
|
|
|
|
|
| ||||||||||||
| Operating activities | 256,206 | 142,158 | 82,884 |
| 216,777 |
| 168,699 |
| 235,429 | |||||||||
| Investing activities | (164,594 | ) | (105,604 | ) | (39,306 | ) |
| (126,558) |
| (347,633) |
| (119,250) | ||||||
| Financing activities | (97,641 | ) | 23,968 | (51,136 | ) |
| (190,442) |
| 271,145 |
| (132,460) | |||||||
| Net (decrease) increase in cash and cash equivalents | (6,029 | ) | 60,522 | (7,558 | ) |
| (100,223) |
| 92,211 |
| (16,281) | |||||||
Cash flows provided byfrom operating activities
For the year ended December 31, 2018,2021, cash provided byflows from operating activities waswere US$256.2216.8 million, an 80%a 28% increase from US$142.2168.7 million for the year ended December 31, 2017,2020, mainly resulting from the increase in revenues of oil reflecting higher oil and gas prices and deliveries in 2018 as compared to 2017, net of increased income2021, partially offset by the cash taxes paid predominantly from Colombia for an amount of US$60.8 million.
payments made during 2021.
For the year ended December 31, 2017,2020, cash provided byflows from operating activities waswere US$142.2168.7 million, a 72% increase28% decrease from US$82.9235.4 million for the year ended December 31, 2016,2019, mainly resulting from the increasedecrease in revenues of oil reflecting lower oil and gas prices in 2017 as compared to 2016, net of a US$15.6 million advance payment paid in December 2017 to Pluspetrol, as a security deposit related to2020, partially offset by the recently announced acquisition of Aguada Baguales, El Porvenir and Puesto Touquet blocks in Neuquén Basin in Argentina.cost reduction initiatives carried during 2020.
Cash flows used in investing activities
For the year ended December 31, 2018,2021, cash flows used in investing activities waswere US$164.6126.6 million, a 56% increasean 64% decrease from US$105.6347.6 million for the year ended December 31, 2017.2020. This increase was related todecrease is primarily explained by the acquisition of the blocksfact that we did not acquire any business in Argentina for2021 (US$272.3 million in 2020) partially offset by an amountincrease of US$48.954.0 million andin capital expenditures related to development, appraisalthe purchase of property, plant and exploration activities.equipment.
For the year ended December 31, 2017,2020, cash flows used in investing activities waswere US$105.6347.6 million, a 169%192% increase from US$39.3119.3 million for the year ended December 31, 2016.2019. This increase was primarily related to higher capital expendituresthe acquisition of Amerisur for US$272.3 million in Colombia, Chile, Argentina and Peru in 2017 as compared to 2016.
January 2020.
Cash flows (used in) from financing activities
Cash fromflows used in financing activities waswere US$24.0190.4 million for the year ended December 31, 2017,2021, compared to US$51.1271.1 million from financing activities for the year ended December 31, 2020. This decrease was principally related to the execution of a series of transactions that included a successful tender to purchase US$255.0 million of the 2024
120
Notes that was funded with a combination of cash in hand and a US$150.0 million new issuance from the reopening of the 2027 Notes.
Cash flows from financing activities were US$271.1 million for the year ended December 31, 2020, compared to US$132.5 million used in financing activities for the year ended December 31, 2016.2019. This changeincrease was principally related to the net proceeds from the issuance of 2024the 2027 Notes of US$418.3342.5 million offset by principal paidand a decrease in the shares repurchase payments of US$355.0 million related to the payment of 2020 Notes and the prepayment of the Itaú loan.
Cash from financing activities was US$97.6 million for the year ended December 31, 2018, compared to US$24.0 million used in financing activities for the year ended December 31, 2017. This increase was principally related to acquisition of the LGI non-controlling interest in Colombia and Chile’s equity interest for which we paid US$81.067.3 million. In addition, we paid US$8.0 million for dividends to LGI prior to the acquisition and used US$1.8 million to purchase our own equity securities during 2018.
Indebtedness
As of December 31, 20182021, and 2017,2020, we had total outstanding indebtedness of US$447.0674.1 million and US$426.2784.6 million, respectively, as set forth in the table below.
| As of December 31, | ||||||||
| 2018 | 2017 | |||||||
| (in thousands of US$) | ||||||||
| Bond GeoPark Limited (Notes due 2024) | 426,993 | 426,124 | ||||||
| BCI Loans (1) | 3 | 80 | ||||||
| Banco Santander | 20,006 | - | ||||||
| Total | 447,002 | 426,204 | ||||||
Our material outstanding indebtedness as of December 31, 2018 is described below.
Notes due 2024
General
On September 21, 2017, we issued US$425.0 million aggregate principal amount of senior notes due 2024. The Notes due 2024 mature on September 21, 2024 and bear interest at a fixed rate of 6.50% and a yield of 6.50% per year. Interest on the Notes due 2024 is payable semi-annually in arrears on March 21 and September 21 of each year.
Ranking
The Notes due 2024 constitute senior unsubordinated obligations of GeoPark Limited, and are guaranteed by Geopark Chile S.A., Geopark Colombia Coöperatie U.A. (the “Guarantors”). The Notes due 2024 rank equally in right of payment with all existing and future senior obligations of GeoPark Limited and the Guarantors (except those obligations preferred by operation of law, including without limitation labor and tax claims); rank senior in right of payment to all existing and future subordinated indebtedness of GeoPark Limited and the Guarantors; and rank effectively junior to any secured obligations of GeoPark Limited, the Guarantors and their respective subsidiaries to the extent of the value of the collateral securing such obligations.
Optional redemption
We may, at our option, redeem all or part of the Notes due 2024, at the redemption prices, expressed as percentages of principal amount, set forth below, plus accrued and unpaid interest thereon (including additional amounts), if any, to the applicable redemption date, if redeemed during the 12-month period beginning on September 21 of the years indicated below:
| Year | Percentage | |||
| 2021 | 103.250 | % | ||
| 2022 | 101.625 | % | ||
| 2023 and after | 100.000 | % | ||
Change of control
Upon the occurrence of certain events constituting a change of control, we are required to make an offer to repurchase all outstanding Notes due 2024, at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts payable in respect thereof) thereon to the date of purchase. If holders of not less than 90% in aggregate principal amount of the outstanding Notes due 2024 validly tender and do not withdraw such notes and we repurchase all such notes, we may redeem the Notes due 2024 that remain outstanding following such purchase at a price in cash equal to 101% of the principal amount thereof plus accrued and unpaid interest to but excluding the date of such redemption.
Covenants
The Notes due 2024 contain customary covenants, which include, among others, limitations on the incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), incurrence of liens, guarantees of additional indebtedness, the ability of certain subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging in certain businesses and merger or consolidation with or into another company.
In the event the Notes due 2024 receive investment-grade ratings from at least two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch, and no default has occurred or is continuing under the indenture governing the Notes due 2024, certain of these restrictions, including, among others, the limitations on incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), the ability of certain subsidiaries to pay dividends, asset sales and certain transactions with affiliates will no longer be applicable.
The indenture governing our Notes due 2024 includes incurrence test covenants that provide, among other things, that, the net debt to EBITDA ratio should not exceed (i) 3.50 until September 21, 2019, (ii) 3.25 from September 21, 2019 to September 21, 2021, and (iii) 3.00 thereafter until maturity, and the EBITDA to interest ratio should exceed (i) 2.00 until September 21, 2019, (ii) 2.25 from September 21, 2019 to September 21, 2021 and (iii) 2.50 thereafter until maturity. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit our capacity to incur additional indebtedness, as specified in the indenture governing the Notes due 2024, other than certain categories of permitted debt. We must test incurrence covenants before incurring additional debt or performing certain corporate actions including but not limited to making dividend payments, restricted payments and others (in each case with certain specific exceptions).
Events of default
Events of default under the indenture governing the Notes due 2024 include: the nonpayment of principal when due; default in the payment of interest, which continues for a period of 30 days; failure to make an offer to purchase and thereafter accept tendered notes following the occurrence of a change of control or as required by certain covenants in the indenture governing the Notes due 2024; cross payment default relating to debt with a principal amount of US$30.0 million or more, and cross-acceleration default following a judgment for US$30.0 million or more; bankruptcy and insolvency events; and invalidity or denial or disaffirmation of a guarantee of the notes. The occurrence of an event of default would permit or require the principal of and accrued interest on the Notes due 2024 to become or to be declared due and payable.
| | | | |
|
| As of December 31, | ||
| | 2021 | | 2020 |
| | (in thousands of US$) | ||
2024 Notes |
| 171,880 |
| 428,737 |
2027 Notes |
| 499,893 |
| 352,113 |
Banco Santander |
|
| 3,736 | |
Total | 674,092 | 784,586 | ||
Our material outstanding indebtedness is described below.
Notes due 2024 and 2027
General
On September 21, 2017, we issued US$425.0 million aggregate principal amount of senior notes due 2024. The Notes due 2024 mature on September 21, 2024, and bear interest at a fixed rate of 6.50% and a yield of 6.50% per year. Interest on the Notes due 2024 is payable semi-annually in arrears on March 21 and September 21 of each year.
On January 17, 2020, we issued US$350.0 million aggregate principal amount of senior notes due 2027. The Notes due 2027 mature on January 17, 2027 and bear interest at a fixed rate of 5.50% per year and a yield to maturity of 5.625%. Interest on the Notes due 2027 is payable semi-annually in arrears on January 17 and July 17 of each year.
In April 2021, the Company executed a series of transactions that included a successful tender to purchase US$255.0 million of the 2024 Notes that was funded with a combination of cash in hand and a US$150.0 million new issuance from the reopening of the 2027 Notes. The new notes offering, and the tender offer closed on April 23, 2021, and April 26, 2021, respectively.
The tender total consideration included the tender offer consideration of US$1,000 for each US$1,000 principal amount of the 2024 Notes plus the early tender payment of US$50 for each US$1,000 principal amount of the 2024 Notes. The tender also included a consent solicitation to align the covenants of the 2024 Notes to those of the 2027 Notes.
The reopening of the 2027 Notes was priced above par at 101.875%, representing a yield to maturity of 5.117%. The debt issuance cost for this transaction amounted to US$2.0 million. The Notes were offered in a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act, and outside the United States to non-U.S. persons in accordance with Regulation S under the Securities Act. The Notes are fully and unconditionally guaranteed jointly and severally by GeoPark Chile SpA and GeoPark Colombia S.A.S.
After these transactions, we reduced our total indebtedness nominal amount in US$105.0 million and improved our financial profile by extending our debt maturities. The current outstanding nominal amount of the 2024 Notes and 2027 Notes is US$170.0 million and US$500.0 million respectively. We recorded a loss of US$6.3 within Financial expenses for the year ended December 31, 2021 as a consequence of these transactions.
121
Ranking
The Notes due 2024 and 2027 constitute senior unsubordinated obligations of GeoPark Limited and are guaranteed by GeoPark Chile and GeoPark Colombia (the “Guarantors”). The Notes due 2024 and 2027 rank equally in right of payment with all existing and future senior obligations of GeoPark Limited and the Guarantors (except those obligations preferred by operation of law, including without limitation labor and tax claims); rank senior in right of payment to all existing and future subordinated indebtedness of GeoPark Limited and the Guarantors; and rank effectively junior to any secured obligations of GeoPark Limited, the Guarantors and their respective subsidiaries to the extent of the value of the collateral securing such obligations.
Optional redemption
We may, at our option, redeem all or part of the Notes due 2024, at the redemption prices, expressed as percentages of principal amount, set forth below, plus accrued and unpaid interest thereon (including additional amounts), if any, to the applicable redemption date, if redeemed during the 12-month period beginning on September 21 of the years indicated below:
| | | |
Year |
| Percentage |
|
2021 | | 103.250 | % |
2022 | | 101.625 | % |
2023 and after |
| 100.000 | % |
We may, at our option, redeem all or part of the Notes due 2027, at the redemption prices, expressed as percentages of principal amount, set forth below, plus accrued and unpaid interest thereon (including additional amounts), if any, to the applicable redemption date, if redeemed during the 12-month period beginning on January 17 of the years indicated below:
| | | |
Year |
| Percentage |
|
2024 | | 102.750 | % |
2025 | | 101.375 | % |
2026 and after |
| 100.000 | % |
Change of control
Upon the occurrence of certain events constituting a change of control, we are required to make an offer to repurchase all outstanding Notes due 2024 and 2027, at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts payable in respect thereof) thereon to the date of purchase. If holders of not less than 90% in aggregate principal amount of the outstanding Notes due 2024 and 2027 validly tender and do not withdraw such notes and we repurchase all such notes, we may redeem the Notes due 2024 and 2027 that remain outstanding following such purchase at a price in cash equal to 101% of the principal amount thereof plus accrued and unpaid interest to but excluding the date of such redemption.
Covenants
The Notes due 2024 and 2027 contain customary covenants, which include, among others, limitations on the incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), incurrence of liens, guarantees of additional indebtedness, the ability of certain subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging in certain businesses and merger or consolidation with or into another company.
In the event the Notes due 2024 and 2027 receive investment-grade ratings from at least two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch, and no default has occurred or is continuing under the indentures governing the Notes due 2024 and 2027, certain of these restrictions, including, among others, the limitations on incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), the
122
ability of certain subsidiaries to pay dividends, asset sales and certain transactions with affiliates will no longer be applicable.
The indenture governing our Notes includes certain tests that must be satisfied before incurring additional debt, as well as other matters, and which provide among other things, that the net debt to EBITDA ratio should not exceed 3.25 and the EBITDA to interest ratio should exceed 2.5. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit our capacity to incur additional indebtedness, as specified in the indenture governing the Notes, other than certain categories of permitted debt. We must test incurrence covenants before incurring additional debt or performing certain corporate actions including but not limited to making dividend payments, restricted payments and others (in each case with certain specific exceptions).
Events of default
Events of default under the indentures governing the Notes due 2024 and 2027 include: the nonpayment of principal when due; default in the payment of interest, which continues for a period of 30 days; failure to make an offer to purchase and thereafter accept tendered notes following the occurrence of a change of control or as required by certain covenants in the indentures governing the Notes due 2024 and 2027; cross payment default relating to debt with a principal amount of US$40.0 million or more, and cross-acceleration default following a judgment for US$40.0 million or more; bankruptcy and insolvency events; and invalidity or denial or disaffirmation of a guarantee of the notes. The occurrence of an event of default would permit or require the principal of and accrued interest on the Notes due 2024 and 2027 to become or to be declared due and payable.
Banco Santander
In October 2018, we executed a loan agreement with Banco Santander for Brazilian Real R$77.6 million (equivalent to US$20.0 million at the moment of the loan execution) to repay an existing US$-denominated intercompany loan. The interest rate applicable to this loan is the CDI plus 2.25% per annum. CDI represents the average rate of all inter-bank overnight transactions in Brazil. In September 2020, we executed the refinancing of the outstanding principal for Brazilian Real R$19.4 million (equivalent to US$3.4 million at the moment of the refinancing execution), to be paid in three installments in October 2021, April 2022 and October 2022.
Other Agreements
In June 2020, our Colombian subsidiary executed an offtake and prepayment agreement with Trafigura, one of its customers. The prepayment agreement provided us with access to up to US$75 million in the form of prepaid future oil sales. The availability period for the prepayment agreement expired on August 10, 2021. We did not withdraw any amount from this prepayment agreement.
Off-balance sheet arrangements
We did not have any off-balance sheet arrangements as of December 31, 2021, or as of December 31, 2020.
C. Research and development, patents and licenses, etc.
See “Item 4. Information on the Company——B. Business Overview” and “Item 4. Information on the Company—B. Business Overview—Title to properties.”
D. Trend information
For a discussion of Trend information, see “—A. Operating Results—Factors affecting our results of operations” and “Item 4. Information on the Company—B. Business Overview—2022 Strategy and Outlook.”
123
E. Critical accounting policies and estimates
We prepare our Consolidated Financial Statements in accordance with IFRS and the interpretations of the IFRS Interpretations Committee (“IFRIC”), as issued by the IASB. The preparation of the financial statements requires us to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. We continually evaluate these estimates and assumptions based on the most recently available information, our own historical experience and various other assumptions that we believe to be reasonable under the circumstances. Since the use of estimates is an integral component of the financial reporting process, actual results could differ from those estimates.
An accounting policy is considered critical if it requires an accounting estimate to be made based on assumptions about matters that are highly uncertain at the time such estimate is made, and if different accounting estimates that reasonably could have been used, or changes in the accounting estimates that are reasonably likely to occur periodically, could materially impact the financial statements. We believe that the following accounting policies represent critical accounting policies as they involve a higher degree of judgment and complexity in their application and require us to make significant accounting estimates. The following descriptions of critical accounting policies and estimates should be read in conjunction with our Consolidated Financial Statements and the accompanying notes and other disclosures.
Reserves estimates
The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. The estimation of economically recoverable oil and natural gas reserves and related future net cash flows was performed based on the Reserve Report as of December 31, 2021 prepared by DeGolyer and MacNaughton, an independent international consultancy to the oil and gas industry based in Dallas, Texas, in line with the principles contained in the Society of Petroleum Engineers (SPE) and the Petroleum Resources Management Reporting System (PRMS) framework. It incorporates many factors and assumptions including:
| ● | expected reservoir characteristics based on geological, geophysical and
|
| ● | future production rates based on historical performance and |
| ● | future oil
The tender total consideration included the tender offer consideration of US$ 1,000 for each US$ 1,000 principal amount of the 2024 Notes plus an early tender payment of US$ 50 for each US$ 1,000 principal amount of the 2024 Notes. The tender also included a consent solicitation to align the covenants of the 2024 Notes to those of the 2027 Notes. F-52 The reopening of the 2027 Notes was priced above par at 101.875%, representing a yield to maturity of 5.117%. The debt issuance cost for this transaction amounted to US$ 2,019,000. The Notes were offered in a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act, and outside the United States to non-U.S. persons in accordance with Regulation S under the
After these transactions, the Company reduced its total indebtedness nominal amount by US$ 105,000,000 and improved its financial profile by extending its debt maturities. The The
In May 2021, GeoPark Colombia S.A.S. executed a loan agreement with Bancolombia for Colombian Pesos 35,000,000,000 (equivalent to US$ 9,388,000 at the In July 2021, GeoPark Colombia S.A.S. executed a loan agreement with Itau Bank for Colombian Pesos 37,653,000,000 (equivalent to US$ 9,973,000 at the moment of the loan execution) to finance working capital requirements in Colombia as a consequence of the demonstrations and road blockades across the country that affected logistics and supply chains during May and June. The interest rate was 5.38% per annum, the original maturity was on January 3, 2022 and interests were payable monthly. In October 2021, GeoPark optionally prepaid the full amount of the loan, with no additional cost. As of the date of these Consolidated Financial Statements, the Group has available credit lines for F-53 Note 28 Leases The Consolidated Statement of Financial Position shows the following amounts relating to leases:
The Consolidated Statement of Income shows the following amounts relating to leases:
The table below summarizes the amounts of Right-of-use assets recognized and the movements during the reporting years:
The table below summarizes the amounts of Lease liabilities recognized and the movements during the reporting years:
F-54 Note 29 Provisions and other long-term liabilities
The provision for asset retirement obligation relates to the estimation of future disbursements related to the abandonment and decommissioning of oil and gas wells (see Note 4). Deferred income relates to government grants and other contributions Other includes the provision for an environmental contingency in the United Kingdom and other environmental obligations in Colombia and Peru. On January 8, 2020, Amerisur announced that it had received a copy of a claim form issued in the High Court of England and Wales (the “Court”) by Leigh Day solicitors on behalf of a group of claimants (the “Claimants”) described as members of a farming community in the department of Putumayo in Colombia. The F-55 Note 30 Trade and other payables
The average credit period (expressed as creditor days) during the year ended December 31, The fair value of these short-term financial instruments is not individually determined as the carrying amount is a reasonable approximation of fair value. Note
The Group has established different stock awards programs and other share-based payment plans to incentivize the Directors, senior management and employees, enabling them to benefit from the increased market capitalization of the Company. During 2018, GeoPark announced the 2018 Equity Incentive Plan (the “Plan”) to motivate and reward those employees, directors, consultants and advisors of the Group to perform at the highest level and to further the best interests of the Company and its shareholders. This Plan is designed as a master plan, with a 10-year term, and embraces all equity incentive programs that the Company decides to implement throughout such term. The maximum number of Shares available for issuance under the Plan is 5,000,000 Shares.
During
F-56
VCP has been classified as an equity-settled plan. not achieved to execute this program. Details of these costs and the characteristics of the different stock awards programs and other share-based payments are described in the following table and explanations:
The awards that are forfeited correspond to employees that had left the Group before vesting date. Note
The Group has interests in joint operations, which are engaged in the exploration of hydrocarbons in Colombia, Chile,
F-57 The following amounts represent the Group’s share in the assets, liabilities and results of the joint operations which have been recognized in the Consolidated Statement of Financial Position and Statement of Income:
F-58
F-59
Capital commitments are disclosed in Note Note 33 Commitments
In Colombia, royalties on production are payable to the Colombian Government and are determined on a field-by-field basis using
The production royalty rate depends on the crude quality. When the API is lower than 15°, the payment is reduced to the 75% of the total calculation.
When the accumulated production of each field, including the royalties’ volume, exceeds 5,000,000 of barrels and the WTI price exceeds F-60
Additionally,
Terecay Blocks. Since they are exploratory blocks with no production during 2021, these agreements had no impact on the Group’s results. In Chile, royalties are payable to the Chilean Government. In the Fell Block, royalties are calculated at 5% of crude oil production and 3% of gas production. In the Flamenco Block, Campanario Block and Isla Norte Block, royalties are calculated at 5% of gas and oil production. In Brazil, the Brazilian National Petroleum, Natural Gas and Biofuels Agency (ANP) is responsible for determining monthly minimum prices for petroleum produced in concessions for purposes of royalties payable with respect to production. Royalties generally correspond to a percentage ranging between 5% and 10% applied to reference prices for oil or natural gas, as established in the relevant bidding guidelines (edital de licitação) and concession agreement. In determining the percentage of royalties applicable to a concession, the ANP takes into consideration, among other factors, the geological risks involved and the production levels expected. In the Manati Block, royalties are calculated at 7.5% of gas production. In Argentina, crude oil and gas production accrues royalties payable to the Provinces of Mendoza and Neuquen equivalent to 15% on estimated value at well head of those products. This value is equivalent to final sales price less transport, storage and treatment costs.
33.2.1 Colombia The future investment commitments assumed by GeoPark, at its working interest, are up to:
F-61
33.2.2 Chile The remaining investment commitment to be assumed 100% by GeoPark for the second exploratory phase in the Campanario and Isla Norte Blocks are up to:
As of December 31, 2021, the Group has established guarantees for its total commitments. 33.2.3 Brazil The future investment commitments assumed by GeoPark are up to:
The investment commitment in the Los Parlamentos Block (50% working interest) for the first exploratory period, ending on October 30, F-62 33.2.5 Ecuador The investment commitments assumed by GeoPark, at its 50% working interest, in the Espejo and Perico Blocks during the first exploratory period are up to:
Note
Controlling interest The main shareholders of GeoPark Limited, a company registered in Bermuda, as of December 31,
F-63 Balances outstanding and transactions with related parties
There have been no other transactions with the Board of Directors, Executive officers, significant shareholders or other related parties during the year besides the intercompany transactions which have been eliminated in the Consolidated Financial Statements, the normal remuneration of Board of Directors and other benefits informed in Note 11. Note 35 Auditors Fees
Fees are shown net of VAT and other associated tax charges. Non-audit services fees relate to consultancy and other services. Note
36.1 Acquisition of Amerisur Resources Plc On
F-64
Ecuador named Oleoducto Binacional Amerisur (“OBA”). GeoPark
transaction date. In accordance with the acquisition method of accounting, the acquisition cost was allocated to the underlying assets acquired and liabilities assumed based primarily upon their estimated fair values at the date of acquisition. An income approach (being the net present value of expected future cash flows) was adopted to determine the fair values of the mineral interest. Estimates of expected future cash flows reflect estimates of projected future revenues, production costs and capital expenditures based on our business model. The excess of acquisition cost, if any, over the net identifiable assets acquired represents goodwill. The following table summarizes the combined consideration paid for the acquired
Since the acquisition date, Amerisur contributed revenue of US$ 42,855,000 and net loss of US$ 5,523,000 within the Consolidated Statement of Income for the year ended December 31, 2020. 36.2 Brazil 36.2.1 Manati Block On November 22, 2020, GeoPark signed an agreement to sell its F-65 36.2.2 REC-T-128 Block
transaction took place in May 2021, after the corresponding customary regulatory approvals.
36.3.1 Aguada Baguales, El Porvenir and Puesto Touquet Blocks
On November 3, 2021, GeoPark signed a sale and purchase and assignment agreement for a total consideration of US$ 16,000,000, subject to working capital adjustments. GeoPark has collected an advance payment of US$ 1,600,000. The closing of the transaction took place on January 31, 2022, after the corresponding regulatory approvals and GeoPark received the remaining outstanding payment. As
36.4 Peru 36.4.1 Morona Block On July 15, 2020, GeoPark notified its irrevocable decision to retire from the non-producing Morona Block (Block 64) in Peru, due to extended force majeure, which allows for the termination of the license contract. On April 6, 2021, the final agreement with Petroperu was signed and, on May 31, 2021, the joint operation agreement was terminated. On September 28, 2021, the supreme decree approving the assignment was issued by the Peruvian Government, and the public deed corresponding to that assignment was finally executed by GeoPark
During 2020, the
Note 37 Impairment test on Property, plant and equipment During 2021, the crude oil demand recovery resulted in
F-66 The Management of the Group considers as
As a consequence of the evaluation, the following amounts of impairment loss were
With regard to the assessment of value in use for the identified CGUs subject to impairment indicators, Management believes that there are no reasonably possible changes in any of the above key assumptions that would cause the carrying value of the CGUs to materially exceed its recoverable amount. F-67 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The following information is presented in accordance with ASC No. 932 “Extractive Activities -Activities- Oil and Gas”, as amended by ASU 2010 - 03 “Oil and Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010 in order to align the current estimation and disclosure requirements with the requirements set in the SEC final rules and interpretations, published on December 31, December 2008. This information includes the Group’s oil and gas production activities carried out in Colombia, Chile, Brazil, Argentina and Peru.each country.
Table 1 - Costs incurred in exploration, property acquisitions and development(a)
The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended as ofDecember 31, December 2018, 20172021, 2020 and 2016.2019. The acquisition of properties includes the cost of acquisition of proved or unproved oil and gas properties. Exploration costs include geological and geophysical costs, costs necessary for retaining undeveloped properties, drilling costs and exploratory wells equipment. Development costs include drilling costs and equipment for developmental wells, the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves.
| Amounts in US$ '000 | Colombia | Chile | Brazil | Argentina | Peru | Total | ||||||||||||||||||||||||||||
| Year ended 31 December 2018 | ||||||||||||||||||||||||||||||||||
| | | | | | | | | | | ||||||||||||||||||||||||
Amounts in US$‘000 | | Colombia | | Chile | | Brazil | | Argentina | | Total | ||||||||||||||||||||||||
Year ended December 31, 2021 | |
| |
| |
| |
| |
| ||||||||||||||||||||||||
| Acquisition of properties | |
| |
| |
| |
| |
| ||||||||||||||||||||||||
| Proved | - | - | - | 54,541 | - | 54,541 | | 0 | | 0 | | 0 | | 0 | | 0 | ||||||||||||||||||
| Unproved | - | - | - | - | - | - | | 0 | | 0 | | 0 | | 0 | | 0 | ||||||||||||||||||
| Total property acquisition | - | - | - | 54,541 | - | 54,541 | | 0 | | 0 | | 0 | | 0 | | 0 | ||||||||||||||||||
| Exploration | 34,242 | 6,221 | 3,217 | 9,383 | 1,269 | 54,332 | | 40,828 | | 3,940 | | 3 | | 998 | | 45,769 | ||||||||||||||||||
| Development | 65,174 | 3,033 | (2,220 | ) | 1,836 | 8,385 | 76,208 | |||||||||||||||||||||||||||
Development (a) | | 81,310 | | 1,900 | | (2,212) | | 2 | | 81,000 | ||||||||||||||||||||||||
| Total costs incurred | 99,416 | 9,254 | 997 | 11,219 | 9,654 | 130,540 | | 122,138 | | 5,840 | | (2,209) | | 1,000 | | 126,769 | ||||||||||||||||||
| Amounts in US$ '000 | Colombia | Chile | Brazil | Argentina | Peru | Total | ||||||||||||||||||||||||||||
| Year ended 31 December 2017 | ||||||||||||||||||||||||||||||||||
| | | | | | | | | | | ||||||||||||||||||||||||
Amounts in US$‘000 | | Colombia | | Chile | | Brazil | | Argentina | | Total | ||||||||||||||||||||||||
Year ended December 31, 2020 | |
| |
| |
| |
| |
| ||||||||||||||||||||||||
| Acquisition of properties | |
| |
| |
| |
| |
| ||||||||||||||||||||||||
| Proved | - | - | - | - | - | - | | 202,913 | | 0 | | 0 | | 0 | | 202,913 | ||||||||||||||||||
| Unproved | - | - | - | - | - | - | | 73,310 | | 0 | | 0 | | 0 | | 73,310 | ||||||||||||||||||
| Total property acquisition | - | - | - | - | - | - | | 276,223 | | 0 | | 0 | | 0 | | 276,223 | ||||||||||||||||||
| Exploration | 37,017 | 3,283 | 5,207 | 8,080 | 743 | 54,330 | | 19,142 | | 9,447 | | 668 | | 694 | | 29,951 | ||||||||||||||||||
| Development | 49,268 | 10,231 | 1,210 | 167 | 14,074 | 74,950 | ||||||||||||||||||||||||||||
Development (a) | | 51,793 | | 3,580 | | 412 | | (3,855) | | 51,930 | ||||||||||||||||||||||||
| Total costs incurred | 86,285 | 13,514 | 6,417 | 8,247 | 14,817 | 129,280 | | 70,935 | | 13,027 | | 1,080 | | (3,161) | | 81,881 | ||||||||||||||||||
| Amounts in US$ '000 | Colombia | Chile | Brazil | Argentina | Peru | Total | ||||||||||||||||||||||||||||||
| Year ended 31 December 2016 | ||||||||||||||||||||||||||||||||||||
| | | | | | | | | | | | | ||||||||||||||||||||||||
Amounts in US$‘000 | | Colombia | | Chile | | Brazil | | Argentina | | Peru | | Total | ||||||||||||||||||||||||
Year ended December 31, 2019 | |
| |
| |
| |
| |
| |
| ||||||||||||||||||||||||
| Acquisition of properties | | | | | | | | | | | |
| ||||||||||||||||||||||||
| Proved | - | - | - | - | - | - | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | ||||||||||||||||||
| Unproved | - | - | - | - | - | - | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | ||||||||||||||||||
| Total property acquisition | - | - | - | - | - | - | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | ||||||||||||||||||
| Exploration | 15,233 | 5,519 | 2,555 | 1,894 | - | 25,201 | | 22,008 | | 8,483 | | 5,219 | | 4,116 | | 0 | | 39,826 | ||||||||||||||||||
| Development | 12,500 | 4,566 | 191 | - | - | 17,257 | ||||||||||||||||||||||||||||||
Development (a) | | 68,818 | | 2,611 | | 143 | | 25,109 | | 14,408 | | 111,089 | ||||||||||||||||||||||||
| Total costs incurred | 27,733 | 10,085 | 2,746 | 1,894 | - | 42,458 | | 90,826 | | 11,094 | | 5,362 | | 29,225 | | 14,408 | | 150,915 | ||||||||||||||||||
| (a) | Includes the effect of change in estimate of assets retirement obligations. |
F-68
(a)Includes capitalized amounts related to asset retirement obligations.Table of Contents
Note
37 Supplemental information on oil and gas activities (unaudited – continued)
Table 2 - Capitalized costs related to oil and gas producing activities
The following table presents the capitalized costs as atof December 31, December 2018, 20172021, 2020 and 2016,2019, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.
| Amounts in US$ '000 | Colombia | Chile | Brazil | Argentina | Total | |||||||||||||||
| At 31 December 2018 | ||||||||||||||||||||
| Proved properties(a) | ||||||||||||||||||||
| Equipment, camps and other facilities | 83,023 | 81,459 | 5,154 | 2,458 | 172,094 | |||||||||||||||
| Mineral interest and wells | 189,514 | 400,338 | 63,574 | 64,084 | 717,510 | |||||||||||||||
| Other uncompleted projects(b) | 24,061 | 12,233 | - | 1,836 | 38,130 | |||||||||||||||
| Unproved properties | 1,676 | 41,162 | 7,073 | 10,081 | 59,992 | |||||||||||||||
| Gross capitalized costs | 298,274 | 535,192 | 75,801 | 78,459 | 987,726 | |||||||||||||||
| Accumulated depreciation | (122,479 | ) | (281,062 | ) | (43,158 | ) | (16,363 | ) | (463,062 | ) | ||||||||||
| Total net capitalized costs | 175,795 | 254,130 | 32,643 | 62,096 | 524,664 | |||||||||||||||
| | | | | | | | | | |
Amounts in US$‘000 | | Colombia | | Chile | | Brazil | | Argentina | | Total |
As of December 31, 2021 | |
| |
| |
| |
| |
|
Proved properties (a) | |
| |
| |
| |
| |
|
Equipment, camps and other facilities | | 125,078 | | 72,766 | | 3,333 | | — | | 201,177 |
Mineral interest and wells | | 580,931 | | 334,993 | | 42,008 | | — | | 957,932 |
Other uncompleted projects | | 26,136 | | 818 | | 250 | | — | | 27,204 |
Unproved properties (b) | | 94,419 | | — | | 271 | | — | | 94,690 |
Gross capitalized costs | | 826,564 | | 408,577 | | 45,862 | | 0 | | 1,281,003 |
Accumulated depreciation | | (282,616) | | (358,417) | | (38,741) | | — | | (679,774) |
Total net capitalized costs | | 543,948 | | 50,160 | | 7,121 | | 0 | | 601,229 |
| (a) |
| (b) | Do not include Ecuador capitalized costs. |
| | | | | | | | | | |
Amounts in US$‘000 | | Colombia | | Chile | | Brazil | | Argentina | | Total |
As of December 31, 2020 | |
| |
| |
| |
| |
|
Proved properties (a) | |
| |
| |
| |
| |
|
Equipment, camps and other facilities | | 115,577 | | 74,363 | | 3,580 | | 4,309 | | 197,829 |
Mineral interest and wells | | 511,040 | | 348,366 | | 47,729 | | 61,482 | | 968,617 |
Other uncompleted projects (b) | | 13,048 | | 2,158 | | 245 | | 26 | | 15,477 |
Unproved properties (c) | | 77,388 | | 0 | | 432 | | 0 | | 77,820 |
Gross capitalized costs | | 717,053 | | 424,887 | | 51,986 | | 65,817 | | 1,259,743 |
Accumulated depreciation | | (228,929) | | (345,611) | | (38,273) | | (45,619) | | (658,432) |
Total net capitalized costs | | 488,124 | | 79,276 | | 13,713 | | 20,198 | | 601,311 |
| (a) | Includes capitalized amounts related to asset retirement obligations, impairment loss in Chile, Argentina and Brazil for US$ |
| (b) | Do not include Peru capitalized costs. |
| Amounts in US$ '000 | Colombia | Chile | Brazil | Argentina | Total | |||||||||||||||
| At 31 December 2017 | ||||||||||||||||||||
| Proved properties(a) | ||||||||||||||||||||
| Equipment, camps and other facilities | 69,906 | 80,611 | 6,036 | 843 | 157,396 | |||||||||||||||
| Mineral interest and wells | 291,050 | 397,031 | 77,264 | 11,159 | 776,504 | |||||||||||||||
| Other uncompleted projects(b) | 11,290 | 12,508 | 70 | 48 | 23,916 | |||||||||||||||
| Unproved properties | 4,106 | 49,702 | 7,585 | 2,975 | 64,368 | |||||||||||||||
| Gross capitalized costs | 376,352 | 539,852 | 90,955 | 15,025 | 1,022,184 | |||||||||||||||
| Accumulated depreciation | (228,793 | ) | (253,764 | ) | (39,509 | ) | (5,700 | ) | (527,766 | ) | ||||||||||
| Total net capitalized costs | 147,559 | 286,088 | 51,446 | 9,325 | 494,418 | |||||||||||||||
| (c) | Do not include |
| Amounts in US$ '000 | Colombia | Chile | Brazil | Argentina | Total | |||||||||||||||
| At 31 December 2016 | ||||||||||||||||||||
| Proved properties(a) | ||||||||||||||||||||
| Equipment, camps and other facilities | 46,785 | 80,611 | 4,174 | 843 | 132,413 | |||||||||||||||
| Mineral interest and wells | 230,100 | 380,037 | 77,255 | 4,849 | 692,241 | |||||||||||||||
| Other uncompleted projects | 12,534 | 18,274 | 2,082 | 36 | 32,926 | |||||||||||||||
| Unproved properties | 4,503 | 48,908 | 6,468 | 1,894 | 61,773 | |||||||||||||||
| Gross capitalized costs | 293,922 | 527,830 | 89,979 | 7,622 | 919,353 | |||||||||||||||
| Accumulated depreciation | (190,025 | ) | (230,917 | ) | (29,803 | ) | (5,692 | ) | (456,437 | ) | ||||||||||
| Total net capitalized costs | 103,897 | 296,913 | 60,176 | 1,930 | 462,916 | |||||||||||||||
| | | | | | | | | | |
Amounts in US$‘000 | | Colombia | | Chile | | Brazil | | Argentina | | Total |
As of December 31, 2019 | |
| |
| |
| |
| |
|
Proved properties (a) | |
| |
| |
| |
| |
|
Equipment, camps and other facilities | | 79,999 | | 84,069 | | 4,615 | | 3,824 | | 172,507 |
Mineral interest and wells | | 282,973 | | 402,392 | | 64,179 | | 81,393 | | 830,937 |
Other uncompleted projects (b) | | 19,754 | | 11,984 | | 209 | | 765 | | 32,712 |
Unproved properties | | 567 | | 45,681 | | 1,788 | | 0 | | 48,036 |
Gross capitalized costs | | 383,293 | | 544,126 | | 70,791 | | 85,982 | | 1,084,192 |
Accumulated depreciation | | (172,207) | | (313,379) | | (46,370) | | (30,897) | | (562,853) |
Total net capitalized costs | | 211,086 | | 230,747 | | 24,421 | | 55,085 | | 521,339 |
| (a) | Includes capitalized amounts related to asset retirement obligations, |
| (b) | Do not include Peru capitalized costs. |
F-73 F-69
Note
Table 3 - Results of operations for oil and gas producing activities
The breakdown of results of the operations shown below summarizes revenues and expenses directly associated with oil and gas producing activities for the years ended December 31, December 2018, 20172021, 2020 and 2016.2019. Income tax for the years presented was calculated utilizing the statutory tax rates.
| Amounts in US$ '000 | Colombia | Chile | Brazil | Argentina | Total | |||||||||||||||||||||||||
| Year ended 31 December 2018 | ||||||||||||||||||||||||||||||
| | | | | | | | | | | ||||||||||||||||||||
Amounts in US$‘000 | | Colombia | | Chile | | Brazil | | Argentina | | Total | ||||||||||||||||||||
Year ended December 31, 2021 | |
| |
| |
| |
| |
| ||||||||||||||||||||
| Revenue | 497,870 | 37,359 | 30,053 | 35,879 | 601,161 | | 618,268 | | 21,471 | | 20,109 | | 28,695 | | 688,543 | |||||||||||||||
| Production costs, excluding depreciation | | | | | | | | | | | ||||||||||||||||||||
| Operating costs | (55,823 | ) | (20,426 | ) | (5,965 | ) | (20,210 | ) | (102,424 | ) | | (72,043) | | (10,280) | | (2,954) | | (14,490) | | (99,767) | ||||||||||
| Royalties | (62,710 | ) | (1,473 | ) | (2,820 | ) | (4,833 | ) | (71,836 | ) | | (106,341) | | (770) | | (1,642) | | (4,270) | | (113,023) | ||||||||||
| Total production costs | (118,533 | ) | (21,899 | ) | (8,785 | ) | (25,043 | ) | (174,260 | ) | | (178,384) | | (11,050) | | (4,596) | | (18,760) | | (212,790) | ||||||||||
| Exploration expenses(a) | (23,953 | ) | (6,855 | ) | (2,846 | ) | (2,277 | ) | (35,931 | ) | | (11,276) | | (4,509) | | — | | (998) | | (16,783) | ||||||||||
| Accretion expense(b) | (892 | ) | (1,105 | ) | (918 | ) | (508 | ) | (3,423 | ) | | (576) | | (1,319) | | (535) | | (710) | | (3,140) | ||||||||||
| Impairment loss reversal for non-financial assets | 11,531 | (6,549 | ) | - | - | 4,982 | ||||||||||||||||||||||||
Impairment loss for non-financial assets | | 0 | | (17,641) | | 0 | | 13,307 | | (4,334) | ||||||||||||||||||||
| Depreciation, depletion and amortization | (41,850 | ) | (27,298 | ) | (10,278 | ) | (10,662 | ) | (90,088 | ) | | (54,588) | | (12,806) | | (2,933) | | (8,152) | | (78,479) | ||||||||||
| Results of operations before income tax | 324,173 | (26,347 | ) | 7,226 | (2,611 | ) | 302,441 | | 373,444 | | (25,854) | | 12,045 | | 13,382 | | 373,017 | |||||||||||||
| Income tax benefit (expense) | (119,944 | ) | 3,952 | (2,457 | ) | 783 | (117,666 | ) | ||||||||||||||||||||||
Income tax (expense) benefit | | (115,989) | | 3,878 | | (4,095) | | (4,684) | | (120,890) | ||||||||||||||||||||
| Results of oil and gas operations | 204,229 | (22,395 | ) | 4,769 | (1,828 | ) | 184,775 | | 257,455 | | (21,976) | | 7,950 | | 8,698 | | 252,127 | |||||||||||||
| Amounts in US$ '000 | Colombia | Chile | Brazil | Argentina | Total | |||||||||||||||||||||||||
| Year ended 31 December 2017 | ||||||||||||||||||||||||||||||
| | | | | | | | | | | ||||||||||||||||||||
Amounts in US$‘000 | | Colombia | | Chile | | Brazil | | Argentina | | Total | ||||||||||||||||||||
Year ended December 31, 2020 | |
| |
| |
| |
| |
| ||||||||||||||||||||
| Revenue | 263,076 | 32,738 | 34,238 | 70 | 330,122 | | 334,606 | | 21,704 | | 12,783 | | 24,599 | | 393,692 | |||||||||||||||
| Production costs, excluding depreciation | | | | | | | | | | | ||||||||||||||||||||
| Operating costs | (42,677 | ) | (19,685 | ) | (7,603 | ) | (325 | ) | (70,290 | ) | | (61,866) | | (9,491) | | (2,827) | | (15,013) | | (89,197) | ||||||||||
| Royalties | (24,236 | ) | (1,314 | ) | (3,134 | ) | (13 | ) | (28,697 | ) | | (30,453) | | (753) | | (1,049) | | (3,620) | | (35,875) | ||||||||||
| Total production costs | (66,913 | ) | (20,999 | ) | (10,737 | ) | (338 | ) | (98,987 | ) | | (92,319) | | (10,244) | | (3,876) | | (18,633) | | (125,072) | ||||||||||
| Exploration expenses(a) | (3,856 | ) | (1,404 | ) | (3,985 | ) | (707 | ) | (9,952 | ) | | (12,493) | | (50,301) | | (1,000) | | (694) | | (64,488) | ||||||||||
| Accretion expense(b) | (855 | ) | (994 | ) | (930 | ) | - | (2,779 | ) | | (670) | | (1,358) | | (867) | | (1,381) | | (4,276) | |||||||||||
Impairment loss for non-financial assets | | 0 | | (81,967) | | (1,717) | | (16,205) | | (99,889) | ||||||||||||||||||||
| Depreciation, depletion and amortization | (38,721 | ) | (22,705 | ) | (10,659 | ) | (8 | ) | (72,093 | ) | | (56,720) | | (32,233) | | (2,488) | | (14,723) | | (106,164) | ||||||||||
| Results of operations before income tax | 152,731 | (13,364 | ) | 7,927 | (983 | ) | 146,311 | | 172,404 | | (154,399) | | 2,835 | | (27,037) | | (6,197) | |||||||||||||
| Income tax benefit (expense) | (61,161 | ) | 2,005 | (2,695 | ) | 344 | (61,507 | ) | ||||||||||||||||||||||
Income tax (expense) benefit | | (55,169) | | 23,160 | | (964) | | 8,111 | | (24,862) | ||||||||||||||||||||
| Results of oil and gas operations | 91,570 | (11,359 | ) | 5,232 | (639 | ) | 84,804 | | 117,235 | | (131,239) | | 1,871 | | (18,926) | | (31,059) | |||||||||||||
| | | | | | | | | | |
Amounts in US$‘000 | | Colombia | | Chile | | Brazil | | Argentina | | Total |
Year ended December 31, 2019 | |
| |
| |
| |
| |
|
Revenue | | 538,917 | | 32,336 | | 23,049 | | 34,605 | | 628,907 |
Production costs, excluding depreciation | | | | | | | | | | |
Operating costs | | (60,545) | | (18,608) | | (4,098) | | (21,137) | | (104,388) |
Royalties | | (56,399) | | (1,181) | | (1,855) | | (5,141) | | (64,576) |
Total production costs | | (116,944) | | (19,789) | | (5,953) | | (26,278) | | (168,964) |
Exploration expenses (a) | | (10,921) | | (126) | | (6,152) | | (13,947) | | (31,146) |
Accretion expense (b) | | (813) | | (1,283) | | (832) | | (722) | | (3,650) |
Impairment loss for non-financial assets | | 0 | | 0 | | 0 | | (7,559) | | (7,559) |
Depreciation, depletion and amortization | | (44,906) | | (34,344) | | (6,200) | | (14,534) | | (99,984) |
Results of operations before income tax | | 365,333 | | (23,206) | | 3,912 | | (28,435) | | 317,604 |
Income tax (expense) benefit | | (120,560) | | 3,481 | | (1,330) | | 8,531 | | (109,878) |
Results of oil and gas operations | | 244,773 | | (19,725) | | 2,582 | | (19,904) | | 207,726 |
F-74
Note
| (a) |
Table 3 - Results of operations for oil and gas producing activities (continued)
| Amounts in US$ '000 | Colombia | Chile | Brazil | Argentina | Total | |||||||||||||||
| Year ended 31 December 2016 | ||||||||||||||||||||
| Revenue | 126,228 | 36,723 | 29,719 | - | 192,670 | |||||||||||||||
| Production costs, excluding depreciation | ||||||||||||||||||||
| Operating costs | (29,326 | ) | (20,674 | ) | (5,738 | ) | - | (55,738 | ) | |||||||||||
| Royalties | (7,281 | ) | (1,495 | ) | (2,721 | ) | - | (11,497 | ) | |||||||||||
| Total production costs | (36,607 | ) | (22,169 | ) | (8,459 | ) | - | (67,235 | ) | |||||||||||
| Exploration expenses(a) | (11,690 | ) | (21,060 | ) | (5,636 | ) | - | (38,386 | ) | |||||||||||
| Accretion expense(b) | (459 | ) | (897 | ) | (1,198 | ) | - | (2,554 | ) | |||||||||||
| Impairment loss reversal for non-financial assets | 5,664 | - | - | - | 5,664 | |||||||||||||||
| Depreciation, depletion and amortization | (29,439 | ) | (29,890 | ) | (12,785 | ) | - | (72,114 | ) | |||||||||||
| Results of operations before income tax | 53,697 | (37,293 | ) | 1,641 | - | 18,045 | ||||||||||||||
| Income tax benefit (expense) | (21,479 | ) | 5,594 | (558 | ) | - | (16,443 | ) | ||||||||||||
| Results of oil and gas operations | 32,218 | (31,699 | ) | 1,083 | - | 1,602 | ||||||||||||||
| Do not include Peru and Ecuador costs. |
| (b) | Represents accretion of ARO and other environmental liabilities. |
F-70
Table 4 - Reserve quantity information
Estimated oil and gas reserves
Proved reserves represent estimated quantities of oil (including crude oil and condensate) and natural gas, which available geological and engineering data demonstrates with reasonable certainty to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The choice of method or combination of methods employed in the analysis of each reservoir was determined by the stage of development, quality and reliability of basic data, and production history.
The Group believes that its estimates of remaining proved recoverable oil and gas reserve volumes are reasonable and such estimates have been prepared in accordance with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008.
The Group estimates its reserves at least once a year. The Group’s reserves estimation as of December 31, December2021, 2020, 2019 and 2018 2017 and 2016 was based on the DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”). DeGolyer and MacNaughton prepared its proved oil and natural gas reserve estimates in accordance with Rule 4-10 of Regulation S–X, promulgated by the SEC, and in accordance with the oil and gas reserves disclosure provisions of ASC 932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities - Oil and Gas (formerly SFAS no. 69 Disclosures about Oil and Gas Producing Activities).
F-75
Note
Table 4 - Reserve quantity information (continued)
Reserves engineering is a subjective process of estimation of hydrocarbon accumulation, which cannot be exactly measured, and the reserve estimation depends on the quality of available information and the interpretation and judgement of the engineers and geologists. Therefore, the reserves estimations, as well as future production profiles, are often different than the quantities of hydrocarbons which are finally recovered. The accuracy of such estimations depends, in general, on the assumptions on which they are based.
The estimated GeoPark net proved reserves for the properties evaluated as of December 31, December2021, 2020, 2019 and 2018 2017 and 2016 are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):
| As of 31 December 2018 | As of 31 December 2017 | As of 31 December 2016 | ||||||||||||||||||||||
| Oil and condensate (Mbbl) | Natural gas (MMcf) | Oil and condensate (Mbbl) | Natural gas (MMcf) | Oil and condensate (Mbbl) | Natural gas (MMcf) | |||||||||||||||||||
| Net proved developed | ||||||||||||||||||||||||
| Colombia(a) | 32,326.0 | 1,763.0 | 21,101.0 | - | 9,502.0 | - | ||||||||||||||||||
| Chile(b) | 696.0 | 11,944.0 | 720.0 | 8,688.0 | 547.0 | 6,610.0 | ||||||||||||||||||
| Brazil(c) | 55.0 | 17,339.0 | 76.0 | 23,821.0 | 72.0 | 29,525.0 | ||||||||||||||||||
| Argentina(d) | 2,058.0 | 6,207.0 | - | - | - | - | ||||||||||||||||||
| Peru(e) | - | - | 9,502.0 | - | 9,316.0 | - | ||||||||||||||||||
| Total consolidated | 35,135.0 | 37,253 | 31,399.0 | 32,509.0 | 19,437.0 | 36,135.0 | ||||||||||||||||||
| Net proved undeveloped | ||||||||||||||||||||||||
| Colombia(f) | 42,449.0 | 359.0 | 44,398.0 | - | 27,838.0 | - | ||||||||||||||||||
| Chile(g) | 2,622.0 | 8,823.0 | 3,423.0 | 11,329.0 | 6,052.0 | 29,690.0 | ||||||||||||||||||
| Argentina(h) | 1,440.0 | 3,174.0 | - | - | - | - | ||||||||||||||||||
| Peru(e) | 18,460.0 | - | 9,215.0 | - | 9,305.0 | - | ||||||||||||||||||
| Total consolidated | 64,971.0 | 12,356.0 | 57,036.0 | 11,329.0 | 43,195.0 | 29,690.0 | ||||||||||||||||||
| Total proved reserves | 100,106.0 | 49,609.0 | 88,435.0 | 43,838.0 | 62,632.0 | 65,825.0 | ||||||||||||||||||
| | | | | | | | | | | | | | | | |
| | As of December 31, 2021 | | As of December 31, 2020 | | As of December 31, 2019 | | As of December 31, 2018 | ||||||||
| | Oil and | | | | Oil and | | | | Oil and | | | | Oil and | | |
| | condensate | | Natural gas | | condensate | | Natural gas | | condensate | | Natural gas | | condensate | | Natural gas |
|
| (Mbbl) |
| (MMcf) |
| (Mbbl) |
| (MMcf) |
| (Mbbl) |
| (MMcf) |
| (Mbbl) |
| (MMcf) |
Net proved developed | |
| |
| |
| |
| |
| |
| |
| |
|
Colombia (a) | | 47,766 | | 1,207 | | 43,817 | | 1,695 | | 39,397 | | 2,319 | | 32,326 | | 1,763 |
Chile (b) | | 755 | | 15,196 | | 798 | | 19,054 | | 898 | | 14,406 | | 696 | | 11,944 |
Brazil (c) | | 43 | | 13,601 | | 34 | | 13,927 | | 48 | | 14,872 | | 55 | | 17,339 |
Argentina (d) | | 1,186 | | 3,379 | | 1,685 | | 5,599 | | 1,658 | | 5,785 | | 2,058 | | 6,207 |
Total consolidated | | 49,750 | | 33,383 | | 46,334 | | 40,275 | | 42,001 | | 37,382 | | 35,135 | | 37,253 |
| | | | | | | | | | | | | | | | |
Net proved undeveloped | |
| |
| |
| |
| |
| |
| |
| | |
Colombia (e) | | 31,019 | | 0 | | 45,240 | | 0 | | 51,212 | | 0 | | 42,449 | | 359 |
Chile (b) | | 575 | | 1,563 | | 1,229 | | 5,661 | | 2,809 | | 6,413 | | 2,622 | | 8,823 |
Argentina (f) | | 603 | | 0 | | 104 | | 0 | | 1,370 | | 450 | | 1,440 | | 3,174 |
Peru (g) | | 0 | | 0 | | 0 | | 0 | | 19,210 | | 0 | | 18,460 | | 0 |
Total consolidated | | 32,197 | | 1,563 | | 46,573 | | 5,661 | | 74,601 | | 6,863 | | 64,971 | | 12,356 |
| | | | | | | | | | | | | | | | |
Total proved reserves | | 81,947 | | 34,946 | | 92,907 | | 45,936 | | 116,602 | | 44,245 | | 100,106 | | 49,609 |
| (a) | Llanos 34 Block, CPO-5 Block, Llanos 32 Block and Platanillo Block account for 88%, 8%, 2% and 2% (Llanos 34 Block, CPO-5 Block, Llanos 32 Block and Platanillo Block account for 86%, 8%, 3% and 3% in 2020, Llanos 34 |
F-71
| Block and Llanos 32 Block account for 97% and 3% in 2019, and Llanos 34 Block, La Cuerva Block, Yamu Block and Llanos 32 Block account for 96%, 1.5%, 1.5% and 1% |
| (b) | Fell Block accounts for 100% |
| (c) | BCAM-40 Block accounts for 100% of the reserves. |
| (d) | Aguada Baguales Block, Puesto Touquet Block, and El Porvenir Block account for 45%, 21% and 33% (Aguada Baguales Block, Puesto Touquet Block, and El Porvenir Block account for 50%, 26% and 24% in 2020, 49%, 30% and 21% in 2019 and 48%, 33% and 19% in 2018) of the proved developed reserves, respectively. |
| (e) |
| Llanos 32 Block, CPO-5 Block and Platanillo Block account 88%, 5%, 5% and 3% (Llanos 34 Block, Llanos 32 Block and CPO-5 Block account 91%, 5% and 4% in 2020, Llanos 34 Block and Llanos 32 Block account 96% and 4% in 2019, and Llanos 34 Block, La Cuerva Block and Yamu Block account for 97%, 2% and 1% |
| (f) | Aguada Baguales Block |
| Aguada Baguales Block and El Porvenir Block account for 75% and 25% in 2018) of the proved undeveloped reserves, respectively. |
Note
| (g) |
Table 5 - Net proved reserves of oil, condensate and natural gas
Net proved reserves (developed and undeveloped) of oil and condensate:
| Thousands of barrels | Colombia | Chile | Brazil | Argentina | Peru | Total | ||||||||||||||||||
| Reserves as of 31 December 2015 | 30,423.3 | 5,953.8 | 120.0 | - | - | 36,497.1 | ||||||||||||||||||
| Increase (decrease) attributable to: | ||||||||||||||||||||||||
| Revisions(a) | 5,779.0 | 1,148.0 | (34.0 | ) | - | - | 6,893.0 | |||||||||||||||||
| Extensions and discoveries(b) | 6,311.0 | - | - | - | - | 6,311.0 | ||||||||||||||||||
| Purchase of Minerals in place(c) | - | - | - | - | 18,621.0 | 18,621.0 | ||||||||||||||||||
| Production | (5,173.3 | ) | (502.8 | ) | (14.0 | ) | - | - | (5,690.1 | ) | ||||||||||||||
| Reserves as of 31 December 2016 | 37,340.0 | 6,599.0 | 72.0 | - | 18,621.0 | 62,632.0 | ||||||||||||||||||
| Increase (decrease) attributable to: | ||||||||||||||||||||||||
| Revisions(d) | 6,315.0 | (2,109.0 | ) | 19.0 | - | 96.0 | 4,321.0 | |||||||||||||||||
| Extensions and discoveries(e) | 29,047.0 | - | - | - | - | 29,047.0 | ||||||||||||||||||
| Production | (7,203.0 | ) | (347.0 | ) | (15.0 | ) | - | - | (7,565.0 | ) | ||||||||||||||
| Reserves as of 31 December 2017 | 65,499.0 | 4,143.0 | 76.0 | - | 18,717.0 | 88,435.0 | ||||||||||||||||||
| Increase (decrease) attributable to: | ||||||||||||||||||||||||
| Revisions(f) | 9,826.0 | (586.0 | ) | (6.0 | ) | - | (257.0 | ) | 8,977.0 | |||||||||||||||
| Extensions and discoveries(g) | 8,839.0 | 41.0 | - | - | - | 8,880.0 | ||||||||||||||||||
| Purchase of Minerals in place(h) | - | - | - | 3,968.0 | - | 3,968.0 | ||||||||||||||||||
| Production | (9,389.0 | ) | (280.0 | ) | (15.0 | ) | (470.0 | ) | - | (10,154.0 | ) | |||||||||||||
| Reserves as of 31 December 2018 | 74,775.0 | 3,318.0 | 55.0 | 3,498.0 | 18,460.0 | 100,106.0 | ||||||||||||||||||
| | | | | | | | | | | | |
Thousands of barrels | | Colombia | | Chile | | Brazil | | Argentina | | Peru | | Total |
Reserves as of December 31, 2018 | | 74,775 | | 3,318 | | 55 | | 3,498 | | 18,460 | | 100,106 |
Increase (decrease) attributable to: | |
| |
| |
| |
| |
| |
|
Revisions (a) | | 18,341 | | 541 | | 4 | | 95 | | 750 | | 19,731 |
Extensions and discoveries (b) | | 8,071 | | 36 | | 0 | | 0 | | 0 | | 8,107 |
Production | | (10,578) | | (188) | | (11) | | (565) | | 0 | | (11,342) |
Reserves as of December 31, 2019 | | 90,609 | | 3,707 | | 48 | | 3,028 | | 19,210 | | 116,602 |
Increase (decrease) attributable to: | |
| |
| |
| |
| |
| | |
Revisions (c) | | (1,964) | | (1,825) | | (7) | | (734) | | 0 | | (4,530) |
Extensions and discoveries (d) | | 4,545 | | 279 | | 0 | | 0 | | 0 | | 4,824 |
Purchase or (Disposal) of Minerals in place (e) | | 6,853 | | 0 | | 0 | | 0 | | (19,210) | | (12,357) |
Production | | (10,986) | | (134) | | (7) | | (505) | | 0 | | (11,632) |
Reserves as of December 31, 2020 | | 89,057 | | 2,027 | | 34 | | 1,789 | | 0 | | 92,907 |
Increase (decrease) attributable to: | |
| |
| |
| |
| |
| | |
Revisions (f) | | (3,207) | | (597) | | 18 | | (169) | | — | | (3,955) |
Extensions and discoveries (g) | | 3,375 | | — | | — | | 603 | | — | | 3,978 |
Production | | (10,440) | | (100) | | (9) | | (434) | | — | | (10,983) |
Reserves as of December 31, 2021 | | 78,785 | | 1,330 | | 43 | | 1,789 | | 0 | | 81,947 |
| (a) | For the year ended December 31, |
- A technical revision of the expected results of future wells in the Jacana and Tigana Fields that led to an increase in reserves of 12.3 mmbbl.
- Better than expected performance from existing wells resulting in anthat increase of 9 mmbbl, of which 8 mmbbl was from the Tigana, Jacana and other minor fields in the Llanos 34 Block, and 1 mmbbl was from the Fell Block in Chile.
- Such increase was partially offset by lower average oil prices impacting the La Cuerva and Yamu Blocksproved developed reserves, mostly originated in Colombia resulting in a 2 mmbbl decrease.
- Better than expected performance from existing wells,(6.3 mmbbl) from the Tigana and Jacana fields in the Llanos 34 Block, resultingBlock. There were also minor increments in an increaseArgentina (0.4 mmbbl) originated in better performance of 3.8 mmbbl.the Aguada Baguales Field wells; and in Chile (0.3 mmbbl) mostly in the Yagan Norte, Konawentru, Alakaluf and Yagan Fields.
- The impactAn updated geological model for the Situche Field in the Morona Block originated a new estimation of higher averagethe proved original oil prices resulting in a 2.5 mmbbl and 0.4 mmbbl increase inplace volumes that increased the proved undevelop reserves fromof the blocks in Colombia and Chile, respectively.block by 0.7 mmbbl.
- Such increase was partially offset by a decrease in reserves mainly related to a change in a previously adopted development plan in the Fell Block in Chile, resulting in a 2.4 mmbbl decrease.
- Better than expected performance from existing wells, from the Tigana and Jacana fields in the Llanos 34 Block, resulting in an increase of 15.4 mmbbl.
- The impact of higherlower average oil prices resultingresulted in a 0.7 mmbbl, 1.00.3 mmbbl and 0.3 mmbbl increasedecrease in reserves from the blocks in Colombia Peru and Chile,Argentina, respectively.
- Such increase wasThere were also better well types considered for the Kiuaku, Loij and Konawentru Field that originated a minor increment of 0.2 mmbbl partially offsetcompensated by a decreasereduction of 0.04 mmbbl in reserves mainly relatedArgentina Challaco Field condensate due to a change in a previously adopted development plan in Max, Tua, Chachalaca Sur, Tilo, and Jacamar fields in the Llanos 34 Block, resulting in a 6.3 mmbbl decrease. Also, lower than expected performance from existing wells in Fell Block, resulted in a 0.8 mmbbl decrease. Finally, revisions in Peru resulted in a 1.3 mmbbl decrease.an unsuccessful well.
F-72
(b) | In Colombia, the extensions and discoveries are primary due to the Tigana and Jacana fields appraisal wells and the |
( c) | For the year ended December 31, 2020, the Group’s oil and condensate proved reserves were revised downward by 4.5 mmbbl. The primary factors leading to the |
Noteabove were:
- Lower average oil prices resulted in a 4.2 mmbbl, 1.1 mmbbl and 0.3 mmbbl decrease in reserves from the blocks in Colombia, Argentina and Chile, respectively.
Table 5 - NetA reduction of 1.6 mmbbl in Chile due to the revision of the type well in the Kiaku and Loij fields and a reduction in Argentina of 0.2 mmbbl, associated to the revision of the type of well in the Aguada Baguales fields.
- Lower than expected performance from the existing wells in Colombia that reduced the proved developed reserves from the Jacana, Tigana and Tigui fields (2.8 mmbbl).
- Such decrease was partially offset by a better performance of proved undeveloped reserves in Colombia (5.1 mmbbl) originated by a new estimation of original oil in place and better type wells considered in the Jacana and Tigana fields. In addition, the proved developed reserves increased in the Aguada Baguales Block in Argentina (0.5 mmbbl) and the Konawentru and Guanaco Fields in Chile of 0.1 mmbbl due to better performance of the existing wells.
- Lower than expected performance from the existing wells that reduced the proved developed reserves in Colombia (8.9 mmbbl), in Argentina (0.3 mmbbl), and in Chile (0.3 mmbbl).
- A decrease of 0.6 mmbbl in Chile due to a change in a previously adopted development plan in the Fell Block.
- Such decrease was partially offset by a higher average oil condensateprices resulted in a 5.7 mmbbl, 0.1 mmbbl and natural gas (continued)0.3 mmbbl increase in reserves from the blocks in Colombia, Argentina and Chile, respectively.
Net proved reserves (developed and undeveloped) of natural gas:
| Millions of cubic feet | Colombia | Chile | Brazil | Argentina | Total | |||||||||||||||
| Reserves as of 31 December 2015 | - | 36,515.0 | 36,158.0 | - | 72,673.0 | |||||||||||||||
| Increase (decrease) attributable to: | ||||||||||||||||||||
| Revisions(a) | - | 5,078.0 | (319.0 | ) | - | 4,759.0 | ||||||||||||||
| Production | - | (5,293.0 | ) | (6,314.0 | ) | - | (11,607.0 | ) | ||||||||||||
| Reserves as of 31 December 2016 | - | 36,300.0 | 29,525.0 | - | 65,825.0 | |||||||||||||||
| Increase (decrease) attributable to: | ||||||||||||||||||||
| Revisions(b) | - | (13,725.0 | ) | 59.0 | - | (13,666.0 | ) | |||||||||||||
| Extensions and discoveries(c) | - | 1,187.0 | - | - | 1,187.0 | |||||||||||||||
| Production | - | (3,745.0 | ) | (5,763.0 | ) | - | (9,508.0 | ) | ||||||||||||
| Reserves as of 31 December 2017 | - | 20,017.0 | 23,821.0 | - | 43,838.0 | |||||||||||||||
| Increase (decrease) attributable to: | ||||||||||||||||||||
| Revisions(d) | - | 544.0 | (679.0 | ) | - | (135.0 | ) | |||||||||||||
| Extensions and discoveries(e) | 2,122.0 | 3,909.0 | - | - | 6,031.0 | |||||||||||||||
| Purchase of Minerals in place(f) | - | - | - | 10,452.0 | 10,452.0 | |||||||||||||||
| Production | - | (3,703.0 | ) | (5,803.0 | ) | (1,071.0 | ) | (10,577.0 | ) | |||||||||||
| Reserves as of 31 December 2018 | 2,122.0 | 20,767.0 | 17,339.0 | 9,381.0 | 49,609.0 | |||||||||||||||
| | | | | | | | | | |
Millions of cubic feet | | Colombia | | Chile | | Brazil | | Argentina | | Total |
Reserves as of December 31, 2018 | | 2,122 | | 20,767 | | 17,339 | | 9,381 | | 49,609 |
Increase (decrease) attributable to: | |
| |
| |
| |
| | |
Revisions (a) | | 621 | | (167) | | 1,812 | | (1,791) | | 475 |
Extensions and discoveries (b) | | 295 | | 5,386 | | 0 | | 0 | | 5,681 |
Production | | (719) | | (5,167) | | (4,279) | | (1,355) | | (11,520) |
Reserves as of December 31, 2019 | | 2,319 | | 20,819 | | 14,872 | | 6,235 | | 44,245 |
Increase (decrease) attributable to: | |
| |
| |
| |
| | |
Revisions (c) | | (211) | | (385) | | 1,840 | | 889 | | 2,133 |
Extensions and discoveries (d) | | 0 | | 10,456 | | 0 | | 0 | | 10,456 |
Production | | (413) | | (6,175) | | (2,785) | | (1,525) | | (10,898) |
Reserves as of December 31, 2020 | | 1,695 | | 24,715 | | 13,927 | | 5,599 | | 45,936 |
Increase (decrease) attributable to: | |
| | | |
| |
| | |
Revisions (e) | | 14 | | (3,553) | | 3,470 | | (636) | | (705) |
Production | | (502) | | (4,403) | | (3,796) | | (1,584) | | (10,285) |
Reserves as of December 31, 2021 | | 1,207 | | 16,759 | | 13,601 | | 3,379 | | 34,946 |
| (a) | For the year ended December 31, |
- RemovalAn increase of proved undevelopeddeveloped reserves due to changesbetter performance of existing wells in previously adopted development planChile (2.2 billion cubic feet) mostly associated to the Pampa Larga, Ache and Monte Aymond Fields; in Brazil (1.8 billion cubic feet) in the Fell Block in ChileManati Field; Colombia (0.6 billion cubic feet) due to a better performance of the Tigana and unsuccessful proved undeveloped executionsJacana Fields; and Argentina (0.1 billion cubic feet) mostly associated to a better performance of wells in the Fell Block in Chile (totalling 21.3 billion cubic feet).Aguada Baguales Field.
F-73
- The above was partially offset by an increase of 6.8 billion cubic feet due to a better performance in the proved developed producing reserves in the Fell Block in Chile and the impact of higher average prices that resulted in an increase of 0.8 billion cubic feet.
- Removal of proved undeveloped reserves due to changes in previously adopted development plan in the Fell Block in Chile and lower than expected performance from existing wellsfor the proved undeveloped reserves in Chile (2.4 billion cubic feet) mostly associated to the increase of water production in Ache Field; and Argentina (1.3 billion cubic feet) associated to an unsuccessful well drilled in the Fell Block in Chile (totalling 2.0 billion cubic feet).Challaco Bajo Field.
- Lower than expected performance from existing wells in BCAM-40 Block, resultingaverage prices resulted in a decrease of 0.7 billion cubic feet.
- The above was partially offset by higher average prices that resulted in an increase of 2.50.5 billion cubic feet reduction in the Fell Blockgas proved developed reserves in Chile.Argentina.
| (b) | The extensions and discoveries are primary due to the Jauke Field discovery in the Fell Block, in Chile, and the gas discovery of the Une Formation in the Azogue field in the Llanos 32 Block, in Colombia. |
| (c) |
- An increase of proved developed reserves due to better performance of existing wells in Chile (7.9 billion cubic feet) mostly associated to the Jauke and Ache Fields, in Brazil (3.0 billion cubic feet) associated to new gas sales plateau in 2021 and forward which leads to better than expected performance of the Manati Field and in Argentina (1.9 billion cubic feet) due to better performance of the Puesto Touquet and El Porvenir Blocks.
- The above was partially offset by lower than expected performance of proved undeveloped reserves in Chile (5.8 billion cubic feet) due to revisions of the type of well in the Pampa Larga Field.
- Lower average prices resulted in a decrease of 2.5 billion cubic feet, 1.2 billion cubic feet and 1.2 billion cubic feet reduction in gas reserves in Chile, Brazil and Argentina, respectively.
| (d) |
| (e) | For the year ended December 31, 2021, the Group’s proved natural gas reserves were revised downward by 0.7 billion cubic feet. This was the combined effect of: |
- A decrease of proved developed reserves due to lower performance of existing wells in Argentina (1.6 billion cubic feet) and in Chile (2.7 billion cubic feet) partially offset by better than expected performance in the Manati Field in Brazil (2.5 billion cubic feet).
- A decrease of 3.4 billion cubic feet in Chile due to the revision of the type well associated with the incremental activity that reduced the proved undeveloped reserves.
- A decrease of 1.5 billion cubic feet in Chile due to a change in a previously adopted development plan in the Fell Block.
-Such decrease was partially offset by higher average prices which resulted in an increase of 4.0 billion cubic feet, 1 billion cubic feet and 1 billion cubic feet in Chile, Brazil, and Argentina, respectively.
Revisions refer to changes in interpretation of discovered accumulations and some technical and logistical needs in the area obliged to modify the timing and development plan of certain fields under appraisal and development phases.
Note
Table 6 - Standardized measure of discounted future net cash flows related to proved oil and gas reserves
The following table discloses estimated future net cash flows from future production of proved developed and undeveloped reserves of crude oil, condensate and natural gas. As prescribed by SEC Modernization of Oil and Gas Reporting rules and ASC 932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities – Oil and Gas (formerly SFAS no. 69 Disclosures about Oil and Gas Producing Activities), such future net cash flows were estimated using the average first day-of-the-month price during the 12-month period for 2018, 20172021, 2020 and 20162019 and using a 10%annual discount factor. Future development and abandonment costs include estimated drilling costs, development and exploitation installations and abandonment costs. These future development costs were estimated based on evaluations made by the Group. The future income tax was calculated by applying the statutory tax rates in effect in the respective countries in which we have interests, as of the date this supplementary information was filed.
This standardized measure is not intended to be and should not be interpreted as an estimate of the market value of the Group’s reserves. The purpose of this information is to give standardized data to help the users of the financial statements to compare different companies and make certain projections. It is important to point out that this information does not include, among other items, the effect of future changes in prices, costs and tax rates, which past experience indicates that are likely to occur, as well as the effect of future cash flows from reserves which have not yet been classified as proved reserves, of a discount factor more representative of the value of money over the lapse of time and of the risks inherent to the production of oil and gas. These future changes may have a significant impact on the future net cash flows disclosed
F-74
below. For all these reasons, this information does not necessarily indicate the perception the Group has on the discounted future net cash flows derived from the reserves of hydrocarbons.
| | | | | | | | | | | | |
Amounts in US$‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Peru |
| Total |
As of December 31, 2021 | |
| |
| |
| |
| |
| |
|
Future cash inflows | | 4,381,191 | | 136,152 | | 89,208 | | 109,678 | | 0 | | 4,716,229 |
Future production costs | | (1,715,554) | | (69,067) | | (34,930) | | (61,660) | | 0 | | (1,881,211) |
Future development costs | | (197,461) | | (40,339) | | (1,955) | | (49,200) | | 0 | | (288,955) |
Future income taxes | | (754,205) | | 0 | | (3,449) | | (2,947) | | 0 | | (760,601) |
Undiscounted future net cash flows | | 1,713,971 | | 26,746 | | 48,874 | | (4,129) | | 0 | | 1,785,462 |
10% annual discount | | (496,150) | | 6,121 | | (7,171) | | 4,471 | | 0 | | (492,729) |
Standardized measure of discounted future net cash flows | | 1,217,821 | | 32,867 | | 41,703 | | 342 | | 0 | | 1,292,733 |
As of December 31, 2020 | |
| |
| |
| |
| |
| | |
Future cash inflows | | 2,561,947 | | 130,200 | | 68,857 | | 83,125 | | 0 | | 2,844,129 |
Future production costs | | (850,029) | | (82,290) | | (36,254) | | (65,536) | | 0 | | (1,034,109) |
Future development costs | | (197,859) | | (28,620) | | (2,355) | | (24,640) | | 0 | | (253,474) |
Future income taxes | | (409,276) | | 0 | | (327) | | 0 | | 0 | | (409,603) |
Undiscounted future net cash flows | | 1,104,783 | | 19,290 | | 29,921 | | (7,051) | | 0 | | 1,146,943 |
10% annual discount | | (345,550) | | (2,258) | | (4,543) | | 7,032 | | 0 | | (345,319) |
Standardized measure of discounted future net cash flows | | 759,233 | | 17,032 | | 25,378 | | (19) | | 0 | | 801,624 |
As of December 31, 2019 | |
| |
| |
| |
| |
| | |
Future cash inflows | | 4,323,914 | | 294,202 | | 86,191 | | 187,064 | | 1,255,239 | | 6,146,610 |
Future production costs | | (1,159,621) | | (104,688) | | (32,608) | | (118,797) | | (512,607) | | (1,928,321) |
Future development costs | | (276,804) | | (35,420) | | (2,166) | | (49,595) | | (278,388) | | (642,373) |
Future income taxes | | (858,700) | | (5,594) | | (1,409) | | (2,251) | | (143,416) | | (1,011,370) |
Undiscounted future net cash flows | | 2,028,789 | | 148,500 | | 50,008 | | 16,421 | | 320,828 | | 2,564,546 |
10% annual discount | | (715,217) | | (44,277) | | (6,626) | | (5,080) | | (199,611) | | (970,811) |
Standardized measure of discounted future net cash flows | | 1,313,572 | | 104,223 | | 43,382 | | 11,341 | | 121,217 | | 1,593,735 |
F-75
Note
| Amounts in US$ '000 | Colombia | Chile | Brazil | Argentina | Peru | Total | ||||||||||||||||||
| At 31 December 2018 | ||||||||||||||||||||||||
| Future cash inflows | 4,059,619 | 317,437 | 102,104 | 277,429 | 1,352,159 | 6,108,748 | ||||||||||||||||||
| Future production costs | (983,782 | ) | (156,724 | ) | (49,255 | ) | (173,053 | ) | (441,801 | ) | (1,804,615 | ) | ||||||||||||
| Future development costs | (207,630 | ) | (39,360 | ) | (3,752 | ) | (54,400 | ) | (293,468 | ) | (598,610 | ) | ||||||||||||
| Future income taxes | (848,519 | ) | (2,515 | ) | (2,231 | ) | (6,610 | ) | (189,922 | ) | (1,049,797 | ) | ||||||||||||
| Undiscounted future net cash flows | 2,019,688 | 118,838 | 46,866 | 43,366 | 426,968 | 2,655,726 | ||||||||||||||||||
| 10% annual discount | (640,625 | ) | (29,008 | ) | (5,317 | ) | (8,499 | ) | (188,435 | ) | (871,884 | ) | ||||||||||||
| Standardized measure of discounted future net cash flows | 1,379,063 | 89,830 | 41,549 | 34,867 | 238,533 | 1,783,842 | ||||||||||||||||||
| At 31 December 2017 | ||||||||||||||||||||||||
| Future cash inflows | 2,434,954 | 284,711 | 157,527 | - | 1,047,540 | 3,924,732 | ||||||||||||||||||
| Future production costs | (531,751 | ) | (131,788 | ) | (56,311 | ) | - | (466,110 | ) | (1,185,960 | ) | |||||||||||||
| Future development costs | (187,414 | ) | (57,690 | ) | (7,524 | ) | - | (235,920 | ) | (488,548 | ) | |||||||||||||
| Future income taxes | (558,226 | ) | (656 | ) | (10,442 | ) | - | (107,294 | ) | (676,618 | ) | |||||||||||||
| Undiscounted future net cash flows | 1,157,563 | 94,577 | 83,250 | - | 238,216 | 1,573,606 | ||||||||||||||||||
| 10% annual discount | (343,561 | ) | (19,338 | ) | (13,293 | ) | - | (147,682 | ) | (523,874 | ) | |||||||||||||
| Standardized measure of discounted future net cash flows | 814,002 | 75,239 | 69,957 | - | 90,534 | 1,049,732 | ||||||||||||||||||
| At 31 December 2016 | ||||||||||||||||||||||||
| Future cash inflows | 873,771 | 394,993 | 200,713 | - | 941,463 | 2,410,940 | ||||||||||||||||||
| Future production costs | (229,593 | ) | (186,700 | ) | (74,116 | ) | - | (497,187 | ) | (987,596 | ) | |||||||||||||
| Future development costs | (69,996 | ) | (149,785 | ) | (16,352 | ) | - | (234,328 | ) | (470,461 | ) | |||||||||||||
| Future income taxes | (191,096 | ) | (8,344 | ) | (21,041 | ) | - | (69,698 | ) | (290,179 | ) | |||||||||||||
| Undiscounted future net cash flows | 383,086 | 50,164 | 89,204 | - | 140,250 | 662,704 | ||||||||||||||||||
| 10% annual discount | (113,584 | ) | (14,709 | ) | (15,688 | ) | - | (109,321 | ) | (253,302 | ) | |||||||||||||
| Standardized measure of discounted future net cash flows | 269,502 | 35,455 | 73,516 | - | 30,929 | 409,402 | ||||||||||||||||||
Note
Table 7 - Changes in the standardized measure of discounted future net cash flows from proved reserves
| Amounts in US$ '000 | Colombia | Chile | Brazil | Argentina | Peru | Total | ||||||||||||||||||||||||||||||
| Present value at 31 December 2015 | 300,097 | 68,155 | 72,316 | - | - | 440,568 | ||||||||||||||||||||||||||||||
| Sales of hydrocarbon, net of production costs | (91,163 | ) | (15,127 | ) | (20,945 | ) | - | - | (127,235 | ) | ||||||||||||||||||||||||||
| Net changes in sales price and production costs | (171,131 | ) | (16,854 | ) | 16,366 | - | - | (171,619 | ) | |||||||||||||||||||||||||||
| Changes in estimated future development costs | 14,941 | (49,763 | ) | 542 | - | - | (34,280 | ) | ||||||||||||||||||||||||||||
| Extensions and discoveries less related costs | 76,641 | - | - | - | - | 76,641 | ||||||||||||||||||||||||||||||
| Development costs incurred | 17,302 | 9,417 | 2,214 | - | - | 28,933 | ||||||||||||||||||||||||||||||
| Revisions of previous quantity estimates | 70,180 | 22,765 | (1,872 | ) | - | - | 91,073 | |||||||||||||||||||||||||||||
| Purchase of Minerals in place | - | - | - | - | 30,929 | 30,929 | ||||||||||||||||||||||||||||||
| Net changes in income taxes | 3,030 | 8,256 | (4,020 | ) | - | - | 7,266 | |||||||||||||||||||||||||||||
| Accretion of discount | 49,605 | 8,606 | 8,915 | - | - | 67,126 | ||||||||||||||||||||||||||||||
| Present value at 31 December 2016 | 269,502 | 35,455 | 73,516 | - | 30,929 | 409,402 | ||||||||||||||||||||||||||||||
| | | | | | | | | | | | | ||||||||||||||||||||||||
Amounts in US$‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Peru |
| Total | ||||||||||||||||||||||||
Present value as of December 31, 2018 | | 1,379,063 | | 89,830 | | 41,549 | | 34,867 | | 238,533 | | 1,783,842 | ||||||||||||||||||||||||
| Sales of hydrocarbon, net of production costs | (198,631 | ) | (14,251 | ) | (26,979 | ) | - | - | (239,861 | ) | | (411,528) | | (14,284) | | (17,289) | | (13,280) | | 0 | | (456,381) | ||||||||||||||
| Net changes in sales price and production costs | 289,199 | 26,928 | (3,000 | ) | - | 69,962 | 383,089 | | (299,642) | | 12,799 | | 6,923 | | (20,694) | | (48,823) | | (349,437) | |||||||||||||||||
| Changes in estimated future development costs | (124,053 | ) | 79,078 | 8,385 | - | (9,725 | ) | (46,315 | ) | | (268,377) | | (22,163) | | 1,165 | | 573 | | (175,248) | | (464,050) | |||||||||||||||
| Extensions and discoveries less related costs | 49,574 | - | - | - | - | 49,574 | | 182,857 | | 17,300 | | 0 | | 0 | | 0 | | 200,157 | ||||||||||||||||||
| Development costs incurred | 67,571 | 7,146 | - | - | - | 74,717 | | 69,694 | | 4,023 | | 445 | | 4,325 | | 0 | | 78,487 | ||||||||||||||||||
| Revisions of previous quantity estimates | 673,622 | (69,594 | ) | 603 | - | 1,133 | 605,764 | | 415,349 | | 9,508 | | 5,482 | | (2,358) | | 11,992 | | 439,973 | |||||||||||||||||
| Net changes in income taxes | (258,842 | ) | 6,097 | 7,976 | - | (11,828 | ) | (256,597 | ) | | 23,398 | | (2,025) | | 729 | | 3,760 | | 51,917 | | 77,779 | |||||||||||||||
| Accretion of discount | 46,060 | 4,380 | 9,456 | - | 10,063 | 69,959 | | 222,758 | | 9,235 | | 4,378 | | 4,148 | | 42,846 | | 283,365 | ||||||||||||||||||
| Present value at 31 December 2017 | 814,002 | 75,239 | 69,957 | - | 90,534 | 1,049,732 | ||||||||||||||||||||||||||||||
Present value as of December 31, 2019 | | 1,313,572 | | 104,223 | | 43,382 | | 11,341 | | 121,217 | | 1,593,735 | ||||||||||||||||||||||||
| Sales of hydrocarbon, net of production costs | (380,829 | ) | (18,923 | ) | (24,781 | ) | (21,243 | ) | - | (445,776 | ) | | (221,620) | | (12,803) | | 8,080 | | (10,454) | | 0 | | (236,797) | |||||||||||||
| Net changes in sales price and production costs | 397,064 | 16,093 | (15,170 | ) | - | 191,288 | 589,275 | | (975,716) | | (117,895) | | (14,580) | | (113) | | 0 | | (1,108,304) | |||||||||||||||||
| Changes in estimated future development costs | (18,632 | ) | 413 | (1,426 | ) | - | 9,611 | (10,034 | ) | | 514,317 | | 20,870 | | (19,606) | | (2,587) | | 0 | | 512,994 | |||||||||||||||
| Extensions and discoveries less related costs | 271,933 | 12,323 | - | - | - | 284,256 | | 59,898 | | 13,914 | | 0 | | 0 | | 0 | | 73,812 | ||||||||||||||||||
| Development costs incurred | 85,880 | 2,980 | - | 737 | - | 89,597 | | 69,694 | | 10,743 | | 394 | | 445 | | 0 | | 81,276 | ||||||||||||||||||
| Revisions of previous quantity estimates | 257,540 | (4,517 | ) | (1,879 | ) | - | (7,098 | ) | 244,046 | | (27,190) | | (13,002) | | 3,519 | | (10) | | 0 | | (36,683) | |||||||||||||||
| Purchase of Minerals in place | - | - | - | 55,373 | - | 55,373 | ||||||||||||||||||||||||||||||
Purchase or (Disposals) of Minerals in place | | 90,315 | | 0 | | 0 | | 0 | | (121,217) | | (30,902) | ||||||||||||||||||||||||
| Net changes in income taxes | (185,118 | ) | (1,368 | ) | 6,808 | - | (65,585 | ) | (245,263 | ) | | (281,264) | | 0 | | (290) | | 0 | | 0 | | (281,554) | ||||||||||||||
| Accretion of discount | 137,223 | 7,590 | 8,040 | - | 19,783 | 172,636 | | 217,227 | | 10,982 | | 4,479 | | 1,359 | | 0 | | 234,047 | ||||||||||||||||||
| Present value at 31 December 2018 | 1,379,063 | 89,830 | 41,549 | 34,867 | 238,533 | 1,783,842 | ||||||||||||||||||||||||||||||
Present value as of December 31, 2020 | | 759,233 | | 17,032 | | 25,378 | | (19) | | 0 | | 801,624 | ||||||||||||||||||||||||
Sales of hydrocarbon, net of production costs | | (516,844) | | (11,520) | | (15,677) | | (16,855) | | 0 | | (560,896) | ||||||||||||||||||||||||
Net changes in sales price and production costs | | 924,875 | | 64,048 | | 19,393 | | (3,145) | | 0 | | 1,005,171 | ||||||||||||||||||||||||
Changes in estimated future development costs | | 96,364 | | (18,731) | | 861 | | 20,674 | | 0 | | 99,168 | ||||||||||||||||||||||||
Extensions and discoveries less related costs | | 80,933 | | 0 | | 0 | | (1,020) | | 0 | | 79,913 | ||||||||||||||||||||||||
Development costs incurred | | 87,877 | | 4,111 | | 0 | | 0 | | 0 | | 91,988 | ||||||||||||||||||||||||
Revisions of previous quantity estimates | | (76,850) | | (23,776) | | 11,957 | | 465 | | 0 | | (88,204) | ||||||||||||||||||||||||
Net changes in income taxes | | (254,618) | | 0 | | (2,780) | | 244 | | 0 | | (257,154) | ||||||||||||||||||||||||
Accretion of discount | | 116,851 | | 1,703 | | 2,571 | | (2) | | 0 | | 121,123 | ||||||||||||||||||||||||
Present value as of December 31, 2021 | | 1,217,821 | | 32,867 | | 41,703 | | 342 | | 0 | | 1,292,733 | ||||||||||||||||||||||||
F-76