UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER PURSUANT TO RULE 13a-16 OR 15d-16 UNDER THE SECURITIES EXCHANGE ACT OF 1934
For the month of March 2022
Commission File Number: 001-36298
GeoPark Limited
(Exact name of registrant as specified in its charter)
Calle 94 N° 11-30 8° piso
Bogota, Colombia
(Address of principal executive office)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
Form 20-F | X |
| Form 40-F |
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):
Yes |
| No | X |
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):
Yes |
| No | X |
GEOPARK LIMITED
TABLE OF CONTENTS
ITEM
1. | GeoPark Limited Consolidated Financial Statements as of and for the year ended December 31, 2021 |
Item 1
GEOPARK LIMITED
CONSOLIDATED
FINANCIAL STATEMENTS
As of and for the year ended December 31, 2021
| |
| |
2 | Reports of Independent Registered Public Accounting Firms |
5 | Consolidated Statement of Income |
6 | Consolidated Statement of Comprehensive Income |
7 | Consolidated Statement of Financial Position |
8 | Consolidated Statement of Changes in Equity |
9 | Consolidated Statement of Cash Flow |
10 | Notes to the Consolidated Financial Statements |
| |
| |
| |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of
GeoPark Limited
Opinion on the Financial Statements
We have audited the accompanying consolidated statements of financial position of GeoPark Limited (the Company) as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, changes in equity and cash flow for the years then ended and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results of its operations and its cash flows for the years then ended, in conformity with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Effect of estimated proved and probable oil and gas reserves on the depreciation of property, plant and equipment
Description of the Matter
At December 31, 2021, the carrying value of the Company’s property, plant and equipment was $614 million and depreciation expense was $81.1 million for the year then ended. As discussed in Note 2.11 the proved and probable reserves are used by the Company in the successful efforts method of accounting for its oil and gas properties. Under such method oil and gas properties are depreciated using the unit-of-production method based on commercial proved and probable oil and gas reserves, as estimated by a third-party petroleum engineering firm. Proved and probable oil and gas reserves estimates are based on geological, geophysical and engineering assessments of expected reservoir characteristics, future production rates based on historical performance and expected future operating and investment activities. Estimating reserves also requires the selection of inputs, including future oil and gas prices and quality differentials, future development and operating costs and tax rates by jurisdiction, among others.
2
Auditing the Company’s depreciation calculations is complex because of the use of the work of a third-party petroleum engineering firm and the evaluation of management’s determination of the inputs described above used by the engineers in estimating commercial proved and probable oil and gas reserves. Also, the assumptions used by management are subject to changes due to future events and conditions, and evaluating them requires significant auditor judgement.
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s internal controls over its process to calculate depreciation expense, including management’s controls over proved and probable oil and gas reserves’ estimation process.
To test the depreciation of property, plant and equipment our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal reservoir engineers primarily responsible for overseeing the preparation of the reserve estimates by the third-party petroleum engineering firm hired by the Company. In addition, we evaluated the completeness and accuracy of the financial data and inputs used in estimating proved and probable oil and gas reserves and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management’s development plan by assessing consistency of the development projections with the Company’s drill plan and the availability of capital to develop such plan. We also tested the mathematical accuracy of the depreciation computations of property, plant and equipment, including comparing the proved and probable oil and gas reserve amounts used in the calculations to the Reserve Reports prepared by the third-party petroleum engineering firm.
/s/ PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.
Member of Ernst & Young Global
We have served as the Company’s auditor since 2020.
Buenos Aires, Argentina
March 8, 2022
3
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of GeoPark Limited
Opinion on the Financial Statements
We have audited the consolidated statements of income, of comprehensive income and of cash flows of GeoPark Limited and its subsidiaries (the “Company”) for the year ended December 31, 2019, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of the Company for the year ended December 31, 2019 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.
Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.
/s/ PRICE WATERHOUSE & CO. S.R.L.
(Partner) |
/s/ Hernan Pablo Rodriguez Cancelo Araujo
Autonomous City of Buenos Aires, Argentina
March 31, 2020
We served as the Company's auditor from 2009 to 2020
4
CONSOLIDATED STATEMENT OF INCOME
| | | | | | | | |
Amounts in US$´000 |
| Note |
| 2021 |
| 2020 |
| 2019 |
REVENUE |
| 7 |
| 688,543 |
| 393,692 |
| 628,907 |
Commodity risk management contracts (loss) gain |
| 8 |
| (109,191) |
| 8,081 |
| (22,523) |
Production and operating costs |
| 9 |
| (212,790) |
| (125,072) |
| (168,964) |
Geological and geophysical expenses |
| 12 |
| (7,891) |
| (14,951) |
| (18,593) |
Administrative expenses |
| 13 |
| (46,828) |
| (50,315) |
| (60,818) |
Selling expenses |
| 14 |
| (8,730) |
| (5,844) |
| (14,113) |
Depreciation |
| | | (88,969) |
| (118,073) |
| (105,532) |
Write-off of unsuccessful exploration efforts |
| 20 |
| (12,262) |
| (52,652) |
| (18,290) |
Impairment loss for non-financial assets, net |
| 20‑37 |
| (4,334) |
| (133,864) |
| (7,559) |
Other expenses |
| | | (11,739) |
| (11,665) |
| (1,840) |
OPERATING PROFIT (LOSS) |
| | | 185,809 |
| (110,663) |
| 210,675 |
Financial expenses |
| 15 |
| (64,112) |
| (64,582) |
| (41,070) |
Financial income |
| 15 |
| 1,652 |
| 3,166 |
| 2,360 |
Foreign exchange gain (loss) |
| 15 |
| 5,049 |
| (13,008) |
| (2,446) |
PROFIT (LOSS) BEFORE INCOME TAX |
| | | 128,398 |
| (185,087) |
| 169,519 |
Income tax expense |
| 17 |
| (67,271) |
| (47,863) |
| (111,762) |
PROFIT (LOSS) FOR THE YEAR |
| | | 61,127 |
| (232,950) |
| 57,757 |
Earnings (Losses) per share (in US$). Basic |
| 19 |
| 1.00 |
| (3.84) |
| 0.96 |
Earnings (Losses) per share (in US$). Diluted |
| 19 |
| 0.99 |
| (3.84) |
| 0.92 |
The notes on pages 10 to 81 are an integral part of these Consolidated Financial Statements.
5
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
| | | | | | |
Amounts in US$´000 |
| 2021 |
| 2020 |
| 2019 |
Profit (Loss) for the year |
| 61,127 |
| (232,950) |
| 57,757 |
Other comprehensive income: |
|
|
|
|
|
|
Items that may be subsequently reclassified to profit or loss |
|
|
|
|
|
|
Currency translation differences |
| (1,438) |
| (8,449) |
| (1,498) |
(Loss) Gain on cash flow hedges | | — | | (6,770) | | 6,770 |
Income tax benefit (expense) relating to cash flow hedges | | — | | 2,166 | | (2,166) |
Other comprehensive (loss) profit for the year |
| (1,438) |
| (13,053) |
| 3,106 |
| | | | | | |
Total comprehensive profit (loss) for the year |
| 59,689 |
| (246,003) |
| 60,863 |
The notes on pages 10 to 81 are an integral part of these Consolidated Financial Statements.
6
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
| | | | | | ��� |
Amounts in US$´000 |
| Note |
| 2021 |
| 2020 |
ASSETS | | | | | | |
NON-CURRENT ASSETS | | | | | | |
Property, plant and equipment |
| 20 |
| 614,047 |
| 614,665 |
Right-of-use assets | | 28 | | 21,014 | | 21,402 |
Prepayments and other receivables |
| 22 |
| 148 |
| 1,060 |
Other financial assets |
| 25 |
| 13,883 |
| 13,364 |
Deferred income tax asset |
| 18 |
| 14,072 |
| 18,168 |
TOTAL NON-CURRENT ASSETS |
|
|
| 663,164 |
| 668,659 |
CURRENT ASSETS |
|
|
|
|
|
|
Inventories |
| 23 |
| 10,915 |
| 13,326 |
Trade receivables |
| 24 |
| 70,531 |
| 46,918 |
Prepayments and other receivables |
| 22 |
| 22,650 |
| 27,263 |
Derivative financial instrument assets |
| 25 |
| 126 |
| 1,013 |
Other financial assets |
| 25 |
| 864 |
| 28 |
Cash and cash equivalents |
| 25 |
| 100,604 |
| 201,907 |
Assets held for sale |
| 36 |
| 26,887 |
| 1,152 |
TOTAL CURRENT ASSETS |
|
|
| 232,577 |
| 291,607 |
TOTAL ASSETS |
|
|
| 895,741 |
| 960,266 |
EQUITY |
|
|
|
|
|
|
Equity attributable to owners of the Company |
|
|
|
|
|
|
Share capital |
| 26.1 |
| 60 |
| 61 |
Share premium |
| | | 169,220 |
| 179,399 |
Reserves |
| | | 83,554 |
| 92,216 |
Accumulated losses |
| | | (314,779) |
| (380,866) |
TOTAL EQUITY |
|
|
| (61,945) |
| (109,190) |
LIABILITIES |
|
|
|
|
|
|
NON-CURRENT LIABILITIES |
|
|
|
|
|
|
Borrowings |
| 27 |
| 656,176 |
| 766,897 |
Lease liabilities | | 28 | | 12,513 | | 11,457 |
Provisions and other long-term liabilities |
| 29 |
| 62,848 |
| 82,370 |
Deferred income tax liability |
| 18 |
| 20,947 |
| 7,190 |
Trade and other payables |
| 30 |
| 1,540 |
| 4,886 |
TOTAL NON-CURRENT LIABILITIES |
|
|
| 754,024 |
| 872,800 |
CURRENT LIABILITIES |
|
|
|
|
|
|
Borrowings |
| 27 |
| 17,916 |
| 17,689 |
Lease liabilities | | 28 | | 8,231 | | 10,890 |
Derivative financial instrument liabilities |
| 25 |
| 20,757 |
| 15,094 |
Current income tax liabilities |
| | | 8,801 |
| 52,775 |
Trade and other payables |
| 30 |
| 127,513 |
| 100,156 |
Liabilities associated with assets held for sale |
| 36 |
| 20,444 |
| 52 |
TOTAL CURRENT LIABILITIES |
|
|
| 203,662 |
| 196,656 |
TOTAL LIABILITIES |
|
|
| 957,686 |
| 1,069,456 |
TOTAL EQUITY AND LIABILITIES |
|
|
| 895,741 |
| 960,266 |
The notes on pages 10 to 81 are an integral part of these Consolidated Financial Statements.
7
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
| | | | | | | | | | | | |
| | Attributable to owners of the Company | | | ||||||||
| | | | | | | | | | (Accumulated | | |
| | | | | | | | | | Losses) | | |
| | Share | | Share | | Other | | Translation | | Retained | | |
Amount in US$‘000 |
| Capital |
| Premium |
| Reserve |
| Reserve |
| Earnings |
| Total |
Equity as of January 1, 2019 | | 60 |
| 237,840 |
| 114,131 |
| (2,322) |
| (206,688) | | 143,021 |
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |
Profit for the year |
| — |
| — |
| — |
| — |
| 57,757 |
| 57,757 |
Other comprehensive profit (loss) for the year |
| — |
| — |
| 4,604 |
| (1,498) |
| — |
| 3,106 |
Total Comprehensive profit (loss) for the year 2019 |
| — |
| — |
| 4,604 |
| (1,498) |
| 57,757 |
| 60,863 |
Transactions with owners: |
|
|
|
|
|
|
|
|
|
|
| |
Share-based payment (Note 31) |
| 3 |
| 7,144 |
| — |
| — |
| (4,430) |
| 2,717 |
Repurchase of shares (Note 26.1) | | (4) |
| (71,268) |
| — |
| — |
| — |
| (71,272) |
Cash distribution (Note 26.2) | | — |
| — |
| (2,444) |
| — |
| — |
| (2,444) |
Total 2019 |
| (1) |
| (64,124) |
| (2,444) |
| — |
| (4,430) |
| (70,999) |
Balances as of December 31, 2019 |
| 59 |
| 173,716 |
| 116,291 |
| (3,820) |
| (153,361) |
| 132,885 |
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |
Loss for the year |
| — |
| — |
| — |
| — |
| (232,950) |
| (232,950) |
Other comprehensive loss for the year |
| — |
| — |
| (4,604) |
| (8,449) |
| — |
| (13,053) |
Total Comprehensive loss for the year 2020 |
| — |
| — |
| (4,604) |
| (8,449) |
| (232,950) |
| (246,003) |
Transactions with owners: |
|
|
|
|
|
|
|
|
|
|
| |
Share-based payment (a) (Note 31) |
| 2 |
| 7,349 |
| — |
| — |
| 5,445 |
| 12,796 |
Repurchase of shares (Note 26.1) |
| (1) |
| (4,008) |
| — |
| — |
| — |
| (4,009) |
Cash distribution (Note 26.2) | | — |
| — |
| (4,859) |
| — |
| — |
| (4,859) |
Stock distribution (Note 26.3) |
| 1 | | 2,342 | | (2,343) | | — | | — | | — |
Total 2020 |
| 2 |
| 5,683 |
| (7,202) |
| — |
| 5,445 |
| 3,928 |
Balances as of December 31, 2020 |
| 61 |
| 179,399 |
| 104,485 |
| (12,269) |
| (380,866) |
| (109,190) |
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |
Profit for the year |
| — |
| — |
| — |
| — |
| 61,127 |
| 61,127 |
Other comprehensive loss for the year |
| — |
| — |
| — |
| (1,438) |
| — |
| (1,438) |
Total Comprehensive (loss) profit for the year 2021 |
| — |
| — |
| — |
| (1,438) |
| 61,127 |
| 59,689 |
Transactions with owners: |
|
|
|
|
|
|
|
|
|
|
| |
Share-based payment (Note 31) |
| — |
| 1,661 |
| — |
| — |
| 4,960 |
| 6,621 |
Repurchase of shares (Note 26.1) |
| (1) |
| (11,840) |
| — |
| — |
| — |
| (11,841) |
Cash distribution (Note 26.2) | | — |
| — |
| (7,224) |
| — |
| — |
| (7,224) |
Total 2021 |
| (1) |
| (10,179) |
| (7,224) |
| — |
| 4,960 |
| (12,444) |
Balances as of December 31, 2021 |
| 60 |
| 169,220 |
| 97,261 |
| (13,707) |
| (314,779) |
| (61,945) |
(a) | Includes issuance of shares to certain employees as part of their 2019 bonus compensation of US$ 4,352,000. |
The notes on pages 10 to 81 are an integral part of these Consolidated Financial Statements.
8
CONSOLIDATED STATEMENT OF CASH FLOW
| | | | | | | | |
Amounts in US$‘000 |
| Note |
| 2021 |
| 2020 |
| 2019 |
Cash flows from operating activities |
|
|
|
|
|
|
|
|
Profit (Loss) for the year | | |
| 61,127 |
| (232,950) |
| 57,757 |
Adjustments for: |
|
|
|
|
|
|
|
|
Income tax expense |
| 17 |
| 67,271 |
| 47,863 |
| 111,762 |
Depreciation | | |
| 88,969 |
| 118,073 |
| 105,532 |
Loss on disposal of property, plant and equipment | | |
| 787 |
| 417 |
| 143 |
Impairment loss for non-financial assets |
| 20‑37 |
| 4,334 |
| 133,864 |
| 7,559 |
Write-off of unsuccessful exploration efforts |
| 20 |
| 12,262 |
| 52,652 |
| 18,290 |
Accrual of borrowing’s interests | | |
| 44,378 |
| 48,690 |
| 29,573 |
Borrowings cancellation costs | | 15 | | 6,308 |
| — |
| — |
Amortization of other long-term liabilities |
| 29 |
| (223) |
| (387) |
| (429) |
Unwinding of long-term liabilities |
| 15 |
| 5,079 |
| 5,894 |
| 4,560 |
Accrual of share-based payment | | |
| 6,621 |
| 8,444 |
| 2,717 |
Foreign exchange (gain) loss | | 15 |
| (5,049) |
| 3,594 |
| 5,289 |
Unrealized (gain) loss on commodity risk management contracts |
| 8 |
| (463) |
| 12,978 |
| 26,411 |
Income tax paid | | |
| (65,273) |
| (25,193) |
| (88,638) |
Changes in working capital |
| 5 |
| (9,351) |
| (5,240) |
| (45,097) |
Cash flows from operating activities – net | | |
| 216,777 |
| 168,699 |
| 235,429 |
Cash flows from investing activities |
|
|
|
|
|
|
|
|
Purchase of property, plant and equipment | | |
| (129,258) |
| (75,298) |
| (126,316) |
Acquisition of business, net of cash acquired |
| 36.1 |
| — |
| (272,335) |
| — |
Proceeds from disposal of long-term assets |
| 36.2-36.3 |
| 2,700 |
| — |
| 7,066 |
Cash flows used in investing activities – net | | |
| (126,558) |
| (347,633) |
| (119,250) |
Cash flows from financing activities |
|
|
|
|
|
|
|
|
Proceeds from borrowings | | 5 |
| 172,174 |
| 350,000 |
| — |
Debt issuance costs paid |
| 5 | | (2,019) |
| (7,507) |
| — |
Principal paid | | 5 |
| (274,934) |
| (3,575) |
| (9,790) |
Interest paid | | 5 |
| (42,592) |
| (37,594) |
| (29,099) |
Borrowings cancellation costs paid | | 5 | | (12,908) |
| — |
| — |
Lease payments | | 5 |
| (7,518) |
| (9,380) |
| (4,855) |
Repurchase of shares | | 26.1 |
| (11,841) |
| (4,009) |
| (71,272) |
Cash distribution | | 26.2 | | (7,224) | | (4,859) | | (2,444) |
Payments for transactions with former non-controlling interest |
| |
| (3,580) |
| (11,931) |
| (15,000) |
Cash flows (used in) from financing activities – net | | |
| (190,442) |
| 271,145 |
| (132,460) |
Net increase (decrease) in cash and cash equivalents | | |
| (100,223) |
| 92,211 |
| (16,281) |
| | |
| | | | | |
Cash and cash equivalents at January 1 | | |
| 201,907 |
| 111,180 |
| 127,727 |
Currency translation differences | | |
| (1,080) |
| (1,484) |
| (266) |
Cash and cash equivalents at the end of the year | | | | 100,604 |
| 201,907 |
| 111,180 |
| | | | | | | | |
Ending Cash and cash equivalents are specified as follows: |
|
|
|
|
|
|
|
|
Cash in bank and bank deposits | | |
| 100,587 |
| 201,884 |
| 111,159 |
Cash in hand | | |
| 17 |
| 23 |
| 21 |
Cash and cash equivalents | | |
| 100,604 |
| 201,907 |
| 111,180 |
The notes on pages 10 to 81 are an integral part of these Consolidated Financial Statements.
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 General Information
GeoPark Limited (the “Company”) is a company incorporated under the law of Bermuda. The Registered Office address is Clarendon House, 2 Church Street, Hamilton HM11, Bermuda.
The principal activities of the Company and its subsidiaries (the “Group” or “GeoPark”) are exploration, development and production for oil and gas reserves in Colombia, Chile, Brazil, Argentina and Ecuador.
These Consolidated Financial Statements were authorized for issue by the Board of Directors on March 8, 2022.
1.1 Overview
The 2019 coronavirus (“COVID-19”) outbreak was first reported near the end of 2019 in Wuhan, China. Since then, the virus has spread worldwide. On March 11, 2020, the World Health Organization declared the COVID-19 outbreak to be a pandemic. 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. 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.
Note 2 Summary of significant accounting policies
The principal accounting policies applied in the preparation of these Consolidated Financial Statements are set out below. These policies have been consistently applied to the years presented, unless otherwise stated.
2.1 Basis of preparation
The Consolidated Financial Statements of GeoPark Limited have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”), under the historical cost basis, except for the following: certain financial assets and liabilities (including derivative instruments) measured at fair value, and assets held for sale – measured at fair value less costs to sell.
The Consolidated Financial Statements are presented in thousands of United States Dollars (US$’000) and all values are rounded to the nearest thousand (US$’000), except in the footnotes and where otherwise indicated.
The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group’s accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the Consolidated Financial Statements are disclosed in this note under the title “Accounting estimates and assumptions”.
All the information included in these Consolidated Financial Statements corresponds to the Group, except where otherwise indicated.
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Note 2 Summary of significant accounting policies (continued)
2.1 Basis of preparation (continued)
2.1.1 Changes in accounting policy and disclosure
2.1.1.1 New and amended standards and interpretations
The Group applied for the first-time certain standards and amendments, which are effective for annual periods beginning on or after January 1, 2021. The Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective.
Interest Rate Benchmark Reform – Phase 2: Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16
The amendments provide temporary relief that address the financial reporting effects when an interbank offered rate (IBOR) is replaced with an alternative nearly risk-free interest rate (RFR). The amendments include the following practical expedients:
● | A practical expedient to require contractual changes, or changes to cash flows that are directly required by the reform, to be treated as changes to a floating interest rate, equivalent to a movement in a market rate of interest |
● | Permit changes required by IBOR reform to be made to hedge designations and hedge documentation without the hedging relationship being discontinued |
● | Provide temporary relief to entities from having to meet the separately identifiable requirement when an RFR instrument is designated as a hedge of a risk component |
These amendments had no impact on the Consolidated Financial Statements of the Group.
COVID-19-Related Rent Concessions beyond June 30, 2021 Amendments to IFRS 16
On May 28, 2020, the IASB issued COVID-19-Related Rent Concessions - amendment to IFRS 16 Leases. The amendment provides relief to lessees from applying IFRS 16 guidance on lease modification accounting for rent concessions arising as a direct consequence of the COVID-19 pandemic. As a practical expedient, a lessee may elect not to assess whether a COVID-19 related rent concession from a lessor is a lease modification. A lessee that makes this election accounts for any change in lease payments resulting from the COVID-19 related rent concession the same way it would account for the change under IFRS 16, if the change were not a lease modification.
The amendment was intended to apply until June 30, 2021, but as the impact of the COVID-19 pandemic continued, on March 31, 2021, the IASB extended the period of application of the practical expedient to June 30, 2022. The amendment applies to annual reporting periods beginning on or after April 1, 2021. This amendment had no impact on the Consolidated Financial Statements of the Group.
2.2 Going concern
The Directors regularly monitor the Group’s cash position and liquidity risks throughout the year to ensure that it has sufficient funds to meet forecast operational and investment funding requirements. Sensitivities are run to reflect latest expectations of expenditures, oil and gas prices and other factors to enable the Group to manage the risk of any funding short falls and/or potential debt covenant breaches.
Considering the performance of the operations, the Group’s cash position of US$ 100,604,000, the liability management and debt reduction executed in April 2021 (see Note 27), the oil hedge strategy to mitigate the price risk exposure within the next twelve months, and the fact that 97% of its total indebtedness as of December 31, 2021 matures in 2024 or 2027, the Directors have formed a judgement, at the time of approving the Consolidated Financial Statements, that there is a reasonable expectation that the Group has adequate resources to meet all its obligations for the foreseeable future. For this reason, the Directors have continued to adopt the going concern basis in preparing the Consolidated Financial Statements.
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Note 2 Summary of significant accounting policies (continued)
2.3 Consolidation
Subsidiaries are all entities (including structured entities) over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases.
Intercompany transactions, balances and unrealized gains on transactions between the Group and its subsidiaries are eliminated. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Amounts reported in the financial statements of subsidiaries have been adjusted where necessary to ensure consistency with the accounting policies adopted by the Group.
2.4 Segment reporting
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Committee. This committee is integrated by the CEO, COO, CFO and managers in charge of the Geoscience, Operations, Legal and Corporate Governance, People and Sustainability departments. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments based on these reports.
2.5 Foreign currency translation
2.5.1 Functional and presentation currency
The Consolidated Financial Statements are presented in US Dollars, which is the Group’s presentation currency.
Items included in the Consolidated Financial Statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates (the “functional currency”). The functional currency of Group companies incorporated in Colombia, Chile, Argentina and Ecuador is the US Dollar, meanwhile for the Group´s Brazilian company the functional currency is the local currency, which is the Brazilian Real.
2.5.2 Transactions and balances
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in the Consolidated Statement of Income.
The results and financial position of foreign operations that have a functional currency different from the presentation currency are translated into the presentation currency as follows: assets and liabilities are translated at the closing rate, and income and expenses are translated at average exchange rates. All resulting exchange differences are recognized in Other comprehensive income.
2.6 Joint arrangements
Under IFRS 11, investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. The Group has assessed the nature of its joint arrangements and determined them to be joint operations. The Group combines its share in the joint operations individual assets, liabilities, results and cash flows on a line-by-line basis with similar items in its Consolidated Financial Statements.
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Note 2 Summary of significant accounting policies (continued)
2.7 Business combinations
Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, which is measured at the acquisition date fair value, and the amount of any non-controlling interests in the acquiree. For each business combination, the Group elects whether to measure the non-controlling interests in the acquiree at fair value or at the proportionate share of the acquiree’s identifiable net assets. Acquisition-related costs are expensed as incurred and included in administrative expenses.
The Group determines that it has acquired a business when the acquired set of activities and assets include an input and a substantive process that together significantly contribute to the ability to create outputs. The acquired process is considered substantive if it is critical to the ability to continue producing outputs, and the inputs acquired include an organized workforce with the necessary skills, knowledge, or experience to perform that process or it significantly contributes to the ability to continue producing outputs and is considered unique or scarce or cannot be replaced without significant cost, effort, or delay in the ability to continue producing outputs.
When the Group acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree.
Any contingent consideration to be transferred by the acquirer will be recognized at fair value at the acquisition date. Contingent consideration classified as equity is not remeasured and its subsequent settlement is accounted for within equity. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9 Financial Instruments, is measured at fair value with the changes in fair value recognized in the statement of profit or loss in accordance with IFRS 9. Other contingent consideration that is not within the scope of IFRS 9 is measured at fair value at each reporting date with changes in fair value recognized in profit or loss.
Goodwill is initially measured at cost (being the excess of the aggregate of the consideration transferred and the amount recognized for non-controlling interests and any previous interest held over the net identifiable assets acquired and liabilities assumed). If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the Group re-assesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognized at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognized in profit or loss.
Revenue from the sale of crude oil and gas is recognized at the point in time when control of the product is transferred to the customer, which is generally when the product is physically transferred into a pipe or other delivery mechanism and the customer accepts the product. Consequently, the Group’s performance obligations are considered to relate only to the sale of crude oil and gas, with each barrel of crude oil equivalent considered to be a separate performance obligation under the contractual arrangements in place.
The Group’s sales of crude oil are priced based on market prices. The sales price is linked to US dollar denominated crude oil international benchmarks, such as Brent, adjusted for certain marketing and quality discounts based on, among other things, American Petroleum Institute (“API”) gravity, viscosity, sulphur content, delivery point and transport costs. The Group’s sales of natural gas are priced based on long-term Gas Supply contracts with customers.
Revenue is shown net of VAT, discounts related to the sale 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. See Note 33.1.
2.9 Production and operating costs
Production and operating costs are recognized in the Consolidated Statement of Income 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, and royalties are also included within this account.
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Note 2 Summary of significant accounting policies (continued)
2.10 Financial results
Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and liabilities, and foreign exchange gains and losses. The Group has capitalized the borrowing cost directly attributable to wells and facilities identified as qualifying assets. Qualifying assets are assets that necessarily take a substantial period of time to get ready for their intended use or sale. The capitalization rate used to determine the amount of borrowing costs to be capitalized is the weighted average interest rate applicable to the Group’s general borrowings, which was 6.90% at year-end 2019. No amounts were capitalized during the year (nil in 2020 and US$ 367,000 in 2019).
2.11 Property, plant and equipment
Property, plant and equipment are stated at historical cost less depreciation and impairment charges, if applicable. Historical cost includes expenditure that is directly attributable to the acquisition of the items; including provisions for asset retirement obligation.
Oil and gas exploration and production activities are accounted for in accordance with the successful efforts method on a field by field basis. The Group accounts 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 (exploration costs) 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.
A charge of US$ 12,262,000 has been recognized in the Consolidated Statement of Income within Write-off of unsuccessful exploration efforts (US$ 52,652,000 in 2020 and US$ 18,290,000 in 2019). See Note 20.
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 the Consolidated Statement of Income when incurred.
Capitalized costs of proved oil and gas properties and production facilities and machinery are depreciated on a licensed area by the licensed area basis, using the unit of production method, based on commercial proved and probable oil and gas reserves. The calculation of the “unit of production” depreciation considers estimated future finding and development costs and is based on current year-end unescalated 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.
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 3 years and 10 years.
Depreciation is allocated in the Consolidated Statement of Income as a separate line to better follow the performance of the business.
An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated recoverable amount (see Impairment of non-financial assets in Note 2.13).
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Note 2 Summary of significant accounting policies (continued)
2.12 Provisions and other long-term liabilities
Provisions for asset retirement obligations and other environmental liabilities, deferred income, restructuring obligations and legal claims are recognized when the Group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and the amount has been reliably estimated. Restructuring provisions, if any, comprise lease termination penalties and employee services termination payments.
Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to the passage of time is recognized as financial expense.
2.12.1 Asset Retirement Obligation
The Group records the fair value of the liability for asset retirement obligations in the period in which the wells are drilled. When the liability is initially recorded, the Group capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value at each reporting period, and the capitalized cost is depreciated over the estimated useful life of the related asset. According to interpretations and the application of current legislation, and on the basis of the changes in technology and the variations in the costs of restoration necessary to protect the environment, the Group has considered it appropriate to periodically re-evaluate future costs of well-capping. The effects of this recalculation are included in the Consolidated Financial Statements in the period in which this recalculation is determined and reflected as an adjustment to the provision and the corresponding property, plant and equipment asset.
2.12.2 Deferred Income
Government grants and other contributions relating to the purchase of property, plant and equipment are included in non-current liabilities as deferred income and they are credited to the Consolidated Statement of Income over the expected lives of the related assets. Grants from the government are recognized at their fair value where there is a reasonable assurance that the grant will be received and the Group will comply with all attached conditions.
2.13 Impairment of non-financial assets
Assets that are not subject to depreciation and/or amortization 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 excess of the asset’s carrying amount over its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units), generally a licensed area. Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment at each reporting date.
No asset should be kept as an exploration and evaluation asset for a period of more than three years, except if it can be clearly demonstrated that the carrying value of the investment will be recoverable.
During 2021, net impairment loss was recognized for US$ 4,334,000 (US$ 133,864,000 and US$ 7,559,000 in 2020 and 2019, respectively). See Note 37. The write-offs are detailed in Note 20.
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Note 2 Summary of significant accounting policies (continued)
2.14 Lease contracts
The Group assesses at contract inception whether a contract is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.
2.14.1 Right-of-use assets
The Group recognises right-of-use assets at the commencement date of the lease. Right of use assets are measured at cost, less any accumulated depreciation and impairment losses, an adjusted for any measurement of lease liabilities.
The cost of right-of-use assets comprise the following:
● | the amount of the initial measurement of lease liability, |
● | any lease payments made at or before the commencement date less any lease incentives received, |
● | any initial direct costs, and |
● | restoration costs. |
The Group leases various offices, facilities, machinery and equipment. Lease contracts are typically made for fixed periods of 1 to 7 years but may have extension options. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. Right-of-use assets are depreciated on a straight-line basis over the shorter of the lease term and the estimated useful lives of the assets.
If ownership of the leased asset transfers to the Group at the end of the lease term or the cost reflects the exercise of a purchase option, depreciation is calculated using the estimated useful life of the asset. The right-of-use assets are also subject to impairment.
2.14.2 Lease liabilities
At the commencement date of the lease, the Group recognises lease liabilities measured at the present value of lease payments to be made over the lease term. Lease liabilities include the net present value of the following lease payments:
● | fixed payments, less any lease incentives receivable, |
● | variable lease payments that are based on an index or a rate, |
● | amounts expected to be payable by the lessee under residual value guarantees, |
● | the exercise price of a purchase option if the lessee is reasonably certain to exercise that option, and |
● | payments of penalties for terminating the lease, if the lease term reflects the lessee exercising that option. |
In calculating the present value, the lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the Group’s incremental borrowing rate is used, being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions. After the commencement date, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the lease payments (e.g., changes to future payments resulting from a change in an index or rate used to determine such lease payments) or a change in the assessment of an option to purchase the underlying asset.
2.14.3 Short-term leases and leases of low-value assets
The Group applies the short-term lease recognition exemption to its short-term leases of machinery and equipment (i.e., those leases that have a lease term of 12 months or less from the commencement date and do not contain a purchase option). It also applies the lease of low-value assets recognition exemption to leases of IT equipment and small items of office furniture that are considered to be low value. Lease payments on short-term leases and leases of low-value assets are recognized as expense on a straight-line basis over the lease term.
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Note 2 Summary of significant accounting policies (continued)
2.15 Inventories
Inventories comprise crude oil and materials.
Crude oil is measured at the lower of cost and net realizable value. Materials are measured at the lower of cost and recoverable amount. The cost of materials and consumables is calculated at acquisition price with the addition of transportation and similar costs. Cost is determined using the first-in, first-out (FIFO) method.
2.16 Current and deferred income tax
The tax expense for the year comprises current and deferred income tax. Income tax is recognized in the Consolidated Statement of Income.
The current income tax charge is calculated on the basis of the tax laws enacted or substantially enacted at the financial statements date in the countries where the Company’s subsidiaries operate and generate taxable income. The computation of the income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution of tax positions taken by the Group, 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.
Deferred income tax is recognized, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Consolidated Financial Statements. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted as of the financial statements date and are expected to apply when the related deferred income tax asset is realized, or the deferred income tax liability is settled.
In addition, the Group has tax-loss carry-forwards in certain tax jurisdictions that are available to be offset against future taxable profit. However, deferred income 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.
Deferred income tax liabilities are provided on taxable temporary differences arising from investments in subsidiaries and joint arrangements, except for deferred income tax liability where the timing of the reversal of the temporary difference is controlled by the Group and it is probable that the temporary difference will not reverse in the foreseeable future. The Group is able to control the timing of dividends from its subsidiaries and hence does not expect taxable profit. Hence deferred income tax is recognized in respect of the retained earnings of overseas subsidiaries only if at the date of the Consolidated Financial Statements, dividends have been accrued as receivable or a binding agreement to distribute past earnings in future has been entered into by the subsidiary. As mentioned above the Group does not expect that the temporary differences will revert in the foreseeable future.
Deferred income tax balances are provided in full, with no discounting.
2.17 Non-current assets or disposal groups held for sale
Non-current assets or disposal groups are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through continuing use and a sale is considered highly probable. They are measured at the lower of their carrying amount and fair value less costs to sell, except for assets such as deferred tax assets, assets arising from employee benefits, financial assets and investment property that are carried at fair value and contractual rights under insurance contracts, which are specifically exempt from this requirement.
An impairment loss is recognized for any initial or subsequent write-down of the asset or disposal group to fair value less costs to sell. A gain is recognized for any subsequent increases in fair value less costs to sell of an asset or disposal group, but not in excess of any cumulative impairment loss previously recognized. A gain or loss not previously recognized by the date of the sale of the non-current asset or disposal group is recognized at the date of derecognition.
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Note 2 Summary of significant accounting policies (continued)
2.17 Non-current assets or disposal groups held for sale (continued)
Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they are classified as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognized.
Non-current assets classified as held for sale and the assets of a disposal group classified as held for sale are presented separately from the other assets in the Consolidated Statement of Financial Position. The liabilities of a disposal group classified as held for sale are presented separately from other liabilities in the Consolidated Statement of Financial Position.
2.18 Financial assets
Financial assets are divided into the following categories: amortized cost; financial assets at fair value through profit or loss and fair value through other comprehensive income. The classification depends on the Group’s business model for managing the financial assets and the contractual terms of the cash flows. The Group reclassifies debt investments when and only when its business model for managing those assets changes.
All financial assets not at fair value through profit or loss are initially recognized at fair value, plus transaction costs. Transaction costs of financial assets carried at fair value through profit or loss, if any, are expensed to profit or loss.
Derecognition of financial assets occurs when the rights to receive cash flows from the investments expire or are transferred and substantially all of the risks and rewards of ownership have been transferred. An assessment for impairment is undertaken at each balance sheet date.
Interest and other cash flows resulting from holding financial assets are recognized in the Consolidated Statement of Income when receivable, regardless of how the related carrying amount of financial assets is measured.
Amortized cost are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are included in current assets, except for maturities greater than twelve months after the balance sheet date. These are classified as non-current assets. These financial assets comprise trade and other receivables and cash and cash equivalents in the Consolidated Statement of Financial Position. They arise when the Group provides money, goods or services directly to a debtor with no intention of trading the receivables. These financial assets are subsequently measured at amortized cost using the effective interest method, less provision for impairment, if applicable.
Any change in their value through impairment or reversal of impairment is recognized in the Consolidated Statement of Income. All of the Group’s financial assets are classified as amortized cost.
2.19 Other financial assets
Non-current other financial assets include contributions made for environmental obligations according to a Colombian and Brazilian government request and are restricted for those purposes.
Current other financial assets include short-term investments with original maturities up to twelve months and over three months.
2.20 Impairment of financial assets
The Group assesses on a forward-looking basis the expected credit losses associated with its debt instruments. The impairment methodology applied depends on whether there has been a significant increase in credit risk. For trade receivables, the Group applies the simplified approach permitted by IFRS 9, which requires expected lifetime losses to be recognized from initial recognition of the receivables.
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Note 2 Summary of significant accounting policies (continued)
2.21 Cash and cash equivalents
Cash and cash equivalents includes cash in hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value, and bank overdrafts. Bank overdrafts, if any, are shown within borrowings in the current liabilities section of the Consolidated Statement of Financial Position.
2.22 Trade and other payables
Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of the business from suppliers. Accounts payable are classified as current liabilities if payment is due within one year or less (or in the normal operating cycle of the business if longer). If not, they are presented as non-current liabilities.
Trade payables are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method.
2.23 Derivatives and hedging activities
Derivative financial instruments are recognized in the Consolidated Statement of Financial Position as assets or liabilities and initially and subsequently measured at fair value. They are presented as current assets or liabilities if they are expected to be settled within 12 months after the end of the reporting period.
The mark-to-market fair value of the Group's outstanding derivative instruments is based on independently provided market rates and determined using standard valuation techniques, including the impact of counterparty credit risk and are within level 2 of the fair value hierarchy.
2.23.1 Cash flow hedges that qualify for hedge accounting
The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognized in Other Reserve within Equity. The gain or loss relating to the ineffective portion is recognized immediately in the Consolidated Statement of Income.
When forward contracts are used to hedge forecast transactions, the Group designates the change in fair value of the forward contract as the hedging instrument. Gains or losses relating to the effective portion of the change in the fair value of the forward contracts are recognized in Other Reserve within Equity.
Where the hedged item subsequently results in the recognition of a non-financial asset, both the deferred hedging gains and losses and the deferred time value of the option contracts or deferred forward points, if any, are included within the initial cost of the asset.
When a hedging instrument expires, or is sold or terminated, or when a hedge no longer meets the criteria for hedge accounting, any cumulative deferred gain or loss and deferred costs of hedging in Equity at that time remains in Equity until the forecast transaction occurs, resulting in the recognition of a non-financial asset. When the forecast transaction is no longer expected to occur, the cumulative gain or loss and deferred costs of hedging that were reported in Equity are immediately reclassified to the Consolidated Statement of Income.
For more information about derivatives designated as cash flow hedges please refer to Note 3 Currency risk.
2.23.2 Other Derivatives
Certain derivative instruments do not qualify for hedge accounting. Changes in the fair value of any derivative instrument that does not qualify for hedge accounting are recognized immediately in the Consolidated Statement of Income.
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Note 2 Summary of significant accounting policies (continued)
2.23.2 Other Derivatives (continued)
For more information about derivatives related to commodity risk management please refer to Note 8 and for more information about derivatives related to currency risk management please refer to Note 15.
2.24 Borrowings
Borrowings are obligations to pay cash and are recognized when the Group becomes a party to the contractual provisions of the instrument.
Borrowings are recognized initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortized cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognized in the Consolidated Statement of Income over the period of the borrowings using the effective interest method.
Direct issue costs are charged to the Consolidated Statement of Income on an accrual basis using the effective interest method.
2.25 Share capital
Equity comprises the following:
● | "Share capital" representing the nominal value of equity shares. |
● | "Share premium" representing the excess over nominal value of the fair value of consideration received for equity shares, net of expenses of the share issuance. |
● | "Other reserve" representing: |
- | the difference between the proceeds from the transaction with non-controlling interests received against the book value of the shares acquired in the Chilean and Colombian subsidiaries, and |
- | the changes in the fair value of the effective portion of derivatives designated as cash flow hedges. |
● | "Translation reserve" representing the differences arising from translation of investments in overseas subsidiaries. |
● | "(Accumulated losses) Retained earnings" representing: |
- | accumulated earnings and losses, and |
- | the equity element attributable to shares granted according to IFRS 2 but not issued at year end. |
2.26 Share-based payment
The Group operates a number of equity-settled share-based compensation plans comprising share awards payments to employees and other third-party contractors. Share-based payment transactions are measured in accordance with IFRS 2.
Fair value of the stock option plan for employee or contractors 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 is determined by reference to the fair value of the options granted calculated using the Geometric Brownian Motion method.
Non-market vesting conditions are included in assumptions about the number of options that are expected to vest. At each reporting date, the entity revises its estimates of the number of options that are expected to vest. It recognizes 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 to the market value of the shares and recognized as an expense over the vesting period. When the awards are exercised, the Company issues new 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.
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Note 3 Financial Instruments-risk management
The Group is exposed through its operations to the following financial risks:
● | Currency risk |
● | Price risk |
● | Credit risk– concentration |
● | Funding and liquidity risk |
● | Interest rate risk |
● | Capital risk management |
The policy for managing these risks is set by the Board of Directors. Certain risks are managed centrally, while others are managed locally following guidelines communicated from the corporate department. The policy for each of the above risks is described in more detail below.
Currency risk
In Colombia, Chile, Argentina and Ecuador the functional currency is the US Dollar. The fluctuation of the local currencies of these countries against the US Dollar, except for Ecuador where the local currency is the US Dollar, does not impact the loans, costs and revenue held in US Dollars; but it does impact the balances denominated in local currencies. Such is the case of the prepaid taxes.
In Colombian, Chilean and Argentinean subsidiaries most of the balances are denominated in US Dollars, and since it is the functional currency of the subsidiaries, there is no exposure to currency fluctuation except from receivables or payables originated in local currency mainly corresponding to VAT and income tax.
The Group minimises the local currency positions in Colombia, Chile and Argentina by seeking to balance local and foreign currency assets and liabilities. However, tax receivables (VAT) seldom match with local currency liabilities. Therefore, the Group maintains a net exposure to them, except for what it is described below.
Since December 2018, GeoPark decided to manage its future exposure to local currency fluctuation with respect to income tax balances in Colombia. Consequently, the Group entered into derivative financial instruments with local banks in Colombia in December 2018 and 2019, in order to anticipate any currency fluctuation with respect to income taxes to be paid during the first half of the following year. As of December 31, 2021 and 2020, there are no currency risk management contracts in place. The Group’s derivatives are accounted for as non-hedge derivatives and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the results of the periods in which they occur. See the impact in the Consolidated Statement of Income in Note 15.
Most of the Group's assets held in those countries are associated with oil and gas productive assets. Those assets, even in the local markets, are generally settled in US Dollar equivalents.
During 2021, the Colombian Peso devalued by 16% (5% and 1% in 2020 and 2019, respectively), the Chilean Peso devalued by 19% (revalued by 5% in 2020 and devalued by 8% in 2019) and the Argentine Peso devalued by 22% (41% and 59% in 2020 and 2019, respectively), all against the US Dollar.
If the Colombian Peso, the Chilean Peso and the Argentine Peso had each devalued an additional 10% against the US dollar, with all other variables held constant, post-tax profit for the year would have been higher by US$ 9,070,000 (post-tax loss would have been lower by US$ 9,057,000 in 2020 and post-tax profit would have been lower by US$ 645,000 in 2019).
In Brazil, the functional currency is the local currency, which is the Brazilian Real. The fluctuation of the US Dollars against the Brazilian Real does not impact the loans, costs and revenues held in Brazilian Real; but it does impact the balances denominated in US Dollars. Such is the case of the provision for asset retirement obligation and the lease liabilities. The exchange loss generated by the Brazilian subsidiary during 2021 amounted to US$ 498,000 (US$ 4,205,000 in 2020 and US$ 664,000 in 2019).
21
Note 3 Financial Instruments-risk management (continued)
Currency risk (continued)
During 2021, the Brazilian Real devalued by 7% against the US Dollar (29% and 17% in 2020 and 2019, respectively). If the Brazilian Real had devalued an additional 10% against the US dollar, with all other variables held constant, post-tax profit for the year would have been lower by US$ 780,000 (post-tax loss would have been higher by US$ 909,000 in 2020 and post-tax profit would have been lower by US$ 927,000 in 2019).
As currency rate changes between the US Dollar and the local currencies, the Group recognizes gains and losses in the Consolidated Statement of Income.
In relation to the cash consideration, of British Pound Sterling (“GBP”) 241,682,496, payable for the acquisition of Amerisur Resources Plc, GeoPark was exposed to fluctuations of the GBP as of December 31, 2019. Consequently, the Group decided to manage this exposure by entering into a “Deal Contingent Forward” with a UK Bank, in order to anticipate any currency fluctuation. This forward contract was accounted for as a cash flow hedge as of December 31, 2019 and therefore the effective portion of the changes in its fair value was recognized in Other Reserve within Equity. On January 16, 2020, GeoPark removed that amount from the cash flow hedge reserve and included it directly in the initial cost of the acquired business. See Note 36.1.
Price risk
The realized oil price for the Group is linked to US dollar denominated crude oil international benchmarks. The market price of this commodity is subject to significant volatility and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil, the geopolitical landscape, armed conflicts, the economic conditions and a variety of additional factors. The main factors affecting realized prices for gas sales vary across countries with some closely linked to international references while others are more domestically driven.
In Colombia, the realized oil price is linked 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, sulphur content, delivery point and transport costs.
In Chile, the oil price is based on Dated Brent minus certain marketing and quality discounts such as, API, sulphur content and others.
GeoPark has signed a long-term Gas Supply Contract with Methanex in Chile. The price of the gas sold under this contract is determined by a formula that considers a basket of international methanol prices, including US and European price indices.
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 in Brazilian Real and is adjusted annually for inflation pursuant to the Brazilian General Market Price Index (Indice Geral de Preços do Mercado), or IGPM.
In Argentina, the realized oil prices for the production in the Neuquen 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. Though prices have been regulated by the Argentine 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. See Note 36.3.1.
22
Note 3 Financial Instruments-risk management (continued)
Price risk (continued)
If oil and methanol prices had fallen by 10% compared to actual prices during the year, with all other variables held constant, considering the impact of the derivative contracts in place, post-tax profit for the year would have been lower by US$ 17,899,000 (post-tax loss would have been higher by US$ 21,014,000 in 2020 and post-tax profit would have been lower by US$ 38,340,000 in 2019).
GeoPark manages part of the exposure to crude oil price volatility using derivatives. The Group considers these derivative contracts to be an effective manner of properly managing commodity price risk. The price risk management activities mainly employ combinations of options and key parameters are based on forecasted production and budget price levels. GeoPark has also obtained credit lines from industry leading counterparties to minimize the potential cash exposure of the derivative contracts (see Note 8).
Credit risk– concentration
The Group’s credit risk relates mainly to accounts receivable where the credit risks correspond to the recognized values of commodities sold. GeoPark considers that there is no significant risk associated to the Group’s major customers and hedging counterparties.
In Colombia, GeoPark allocates its sales on a competitive basis to industry leading participants including traders and other producers. During 2021, the oil and gas production was sold to three clients which concentrate 99% of the Colombian subsidiaries’ revenue, accounting for 89% of the consolidated revenue (98% of the Colombian subsidiaries’ revenue, accounting for 83% of the consolidated revenue in 2020). Delivery points include wellhead and other locations on the Colombian pipeline system for the Llanos Basin production. The Putumayo Basin production is delivered to clients FOB in Esmeraldas, Ecuador, and to the Colombian pipeline system in case of contingencies in Ecuador that affect the transport through the Ecuadorian pipeline system. The outstanding contracts for Colombian production extend through 2023. GeoPark manages its counterparty credit risk associated to sales contracts by including, in certain contracts, early payment conditions to minimize the exposure.
In Chile, the oil production is sold to ENAP, the State-owned oil and gas company (1% of the consolidated revenue in 2021, 1% in 2020 and 2% in 2019), and the gas production is sold to the local subsidiary of Methanex, a Canadian public company (2% of the consolidated revenue in 2021, 4% in 2020 and 3% in 2019).
In Brazil, all the hydrocarbons from Manati Field are sold to Petrobras, the State-owned company, which is the operator of the Manati Field (3% of the consolidated revenue in 2021, 3% in 2020 and 4% in 2019). The crude oil production from the Recôncavo Basin during 2020 and 2019 (representing less than a 1% of the consolidated revenue) was sold to local customers in the states of Bahia and Espirito Santo and to Petrobras.
In Argentina, the gas sales were channelled thought local gas marketing companies. GeoPark used to have annual agreements for gas sales from May through April. Gas sales in Argentina account for 1% of the consolidated revenues in each year.
The oil sales in Argentina were diversified across clients and delivery points: i) 72% of the oil produced in Argentina (3% of the consolidated revenue) was sold locally in Neuquen, delivered at well-head; ii) 19% of the oil produced in Argentina (1% of the consolidated revenue) was sold to major local Argentinean refineries, delivered via pipeline; and iii) 9% of the oil produced in Argentina was exported to different traders and delivered via vessels. GeoPark managed the counterparty credit risk associated to sales contracts by limiting payment terms offered to minimize the exposure.
The forementioned companies all have a good credit standing and despite the concentration of the credit risk, the Directors do not consider there to be a significant collection risk.
GeoPark executes oil prices hedges via over-the-counter derivatives. Should oil prices drop, the Group could stand to collect from its counterparties under the derivative contracts. The Group’s hedging counterparties are leading financial institutions and trading companies, therefore the Directors do not consider there to be a significant collection risk. See disclosure in Notes 8 and 25.
23
Note 3 Financial Instruments-risk management (continued)
Funding and Liquidity risk
In the past, the Group has been able to raise capital through different sources of funding including equity, strategic partnerships and financial debt.
The Group is positioned at the end of 2021 with a cash balance of US$ 100,604,000 and 97% of its total indebtedness matures in 2024 or 2027. In addition, the Group has a large portfolio of attractive and largely discretional projects - both oil and gas - in multiple countries with 39,300 boepd in production at year end. This scale and positioning permit the Group to protect its financial condition and selectively allocate capital to the optimal projects subject to prevailing macroeconomic conditions.
The Indentures governing the Company Notes 2024 and 2027 include incurrence test covenants related to compliance with certain thresholds of Net Debt to Adjusted EBITDA ratio and Adjusted EBITDA to Interest ratio. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit the Group’s capacity to incur additional indebtedness, as specified in the indentures governing the Notes. As of the date of these Consolidated Financial Statements, the Group is in compliance with all the indentures’ provisions and covenants.
The most significant funding transactions executed during the last three years include:
In January 2020, the Company successfully placed US$ 350,000,000 Notes. These Notes were priced at 99.285% and carry a coupon of 5.50% per annum (yield 5.625% per annum). Final maturity of the Notes will be January 17, 2027. The net proceeds from the Notes were used by the Group to pay the total consideration for the acquisition of Amerisur (see Note 36.1) and to pay any related fees and expenses, and for general corporate purposes.
In June 2020, GeoPark Colombia S.A.S. executed an offtake and prepayment agreement with Trafigura. The prepayment agreement provided GeoPark with access to up to US$ 75,000,000 in the form of prepaid future oil sales. The availability period for the prepayment agreement expired on August 10, 2021. GeoPark did not withdraw any amount from this prepayment agreement.
In April 2021, the Company executed a series of transactions that included a successful tender offer to purchase US$ 255,000,000 of the 2024 Notes that was funded with a combination of cash in hand and a US$ 150,000,000 new issuance from the reopening 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%.
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 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, the original maturity was on May 14, 2022 and interests were payable monthly. In August 2021, GeoPark optionally prepaid the full amount of the loan, with no additional cost.
In July 2021, GeoPark Colombia S.A.S. executed a loan agreement with Itau Bank for Colombian Pesos 37,653,000,000 (equivalent to US$ 9,973,000 at the moment of the loan execution) to finance working capital requirements in Colombia. 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.
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$ 20,000,000 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 these Consolidated Financial Statements, GeoPark has not withdrawn any amount from this loan agreement.
24
Note 3 Financial Instruments-risk management (continued)
Funding and Liquidity risk (continued)
On October 8, 2021, the 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$ 15,000,000 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 these Consolidated Financial Statements, GeoPark has not withdrawn any amount from this prepayment agreement.
The Group’s interest rate risk arises from long-term borrowings issued at variable rates, which expose the Group to interest rate risk.
The Group does not face interest rate risk on its US$ 170,000,000 and US$ 500,000,000 Notes which carry fixed rate coupons of 6.50% and 5.50% per annum, respectively. Consequently, the accruals and interest payments are not substantially affected by the market interest rate changes.
As of December 31, 2021, the outstanding borrowing affected by a variable rate amounted to US$ 2,319,000, representing 0.3% of total borrowings. It corresponds to a loan from Banco Santander taken by the Brazilian subsidiary that has a floating interest rate based on CDI (Interbank certificate of deposit), which represents the average rate of all inter-bank overnight transactions in Brazil. GeoPark considers that there is no significant risk associated to interest rate based on the current exposure to variable rates.
Capital risk management
The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital.
Consistent with others in the industry, the Group monitors capital on the basis of the gearing ratio. This ratio is calculated as net debt divided by total capital. Net debt is calculated as total borrowings (including ‘current and non-current borrowings’ as shown in the Consolidated Statement of Financial Position) less cash and cash equivalents. Total capital is calculated as ‘equity’ as shown in the Consolidated Statement of Financial Position plus net debt.
The Group’s strategy is to keep the gearing ratio within a 60% to 80% range, in normal market conditions. Due to the market conditions prevailing since 2020, the gearing ratio at year-end is above such range.
The gearing ratios as of December 31, 2021 and 2020 were as follows:
| | | | | |
Amounts in US$‘000 |
| 2021 |
| 2020 |
|
Net Debt |
| 573,488 |
| 582,679 | |
Total Equity |
| (61,945) |
| (109,190) | |
Total Capital |
| 511,543 |
| 473,489 | |
Gearing Ratio |
| 112 | % | 123 | % |
25
Note 4 Accounting estimates and assumptions
Estimates and assumptions are used in preparing financial statements. Although these estimates are based on management’s best knowledge of current events and actions, actual results may differ. Estimates and judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.
The key estimates and assumptions used in these Consolidated Financial Statements are noted below:
● | 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:
o | expected reservoir characteristics based on geological, geophysical and engineering assessments; |
o | future production rates based on historical performance and expected future operating and investment activities; |
o | future oil and gas prices and quality differentials; |
o | assumed effects of regulation by governmental agencies; |
o | tax rates by jurisdiction; and |
o | future development and operating costs. |
Management believes these factors and assumptions are reasonable based on the information available to them at the time of preparing the 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 gas prices and costs change.
Such changes may impact the Group’s reported financial position and results, which include: (a) the carrying value of exploration and evaluation assets; oil and gas properties and other property, plant and equipment; may be affected due to changes in estimated future cash flows, (b) depreciation and amortization charges in the Consolidated Statement of Income may change where such charges are determined using the unit of production method, or where the useful life of the related assets change, (c) provisions for abandonment may require revision -where changes to reserves estimates affect expectations about when such activities will occur and the associated cost of these activities- and, (d) the recognition and carrying value of deferred income tax assets may change due to changes in the judgements regarding the existence of such assets and in estimates of the likely recovery of such assets.
● | Cash flow estimates for impairment assessments of non-financial assets 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 gas prices have exhibited significant volatility. The Group’s forecasts for oil and gas revenues are based on prices derived from future price forecasts amongst industry analysts and internal assessments. Estimates of future cash flows are generally based on assumptions of long-term prices and operating and development costs. Given the significant assumptions required and the possibility that actual conditions may differ, management considers the assessment of impairment to be a critical accounting estimate (see Note 37). |
26
Note 4 Accounting estimates and assumptions (continued)
● | The Group adopted the successful efforts method of accounting. The Management of the Group makes assessments and estimates regarding whether an exploration and evaluation asset should continue to be carried forward as such when insufficient information exists. This assessment is made on a quarterly basis considering the advice from qualified experts. |
The application of the Group’s accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely from future either exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and resources is, in itself, an estimation process that involves varying degrees of uncertainty depending on how the resources are classified. These estimates directly impact when the Group defers exploration and evaluation expenditure. The deferral policy requires management to make certain estimates and assumptions about future events and circumstances, in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available. If, after expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, the relevant capitalized amount is written-off in the Consolidated Statement of Income in the period when the new information becomes available.
● | Oil and gas assets held in property plant and equipment are mainly depreciated on a unit of production (“UOP”) basis at a rate calculated by reference to proven and probable reserves and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce those reserves, the cost of the wells and future production facilities. This results in a depreciation charge proportional to the depletion of the anticipated remaining production from the block. |
The life of each item, which is assessed at least annually, has regard to both its physical life limitations and present assessments of economically recoverable reserves of the block at which the asset is located. These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The calculation of the UOP rate of depreciation will be impacted to the extent that actual production in the future is different from current forecast production based on total proved reserves, or future capital expenditure estimates change. Changes to proved reserves could arise due to changes in the factors or assumptions used in estimating reserves, including: (a) the effect on proved reserves of differences between actual commodity prices and commodity price assumptions and (b) unforeseen operational issues.
● | Obligations related to the abandonment of wells once operations are terminated may result in the recognition of significant obligations. Estimating the future abandonment costs is difficult and requires management to make estimates and judgments because most of the obligations are many years in the future. Technologies and costs are constantly changing as well as political, environmental, safety and public relations considerations. The Group has adopted the following criterion for recognizing well plugging and abandonment related costs: 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 liabilities recognized are based upon estimated future abandonment costs, wells subject to abandonment, time to abandonment, and future inflation rates. |
The expected timing, extent and amount of expenditure may also change, for example, in response to changes in oil and gas reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are made in determining the provision for decommissioning. As a result, there could be significant adjustments to the provisions established which would affect future financial results.
The provision at reporting date represents management’s best estimate of the present value of the future abandonment costs required.
27
Note 4 Accounting estimates and assumptions (continued)
● | From time to time, the Group may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, tax, environmental, safety and health matters. For example, from time to time, the Group receives notice of environmental, health and safety violations. Based on what the Group’s Management currently knows, such claims are not expected to have a material impact on the Consolidated Financial Statements. |
Note 5 Consolidated Statement of Cash Flow
The Consolidated Statement of Cash Flow shows the Group’s cash flows for the year for operating, investing and financing activities and the change in cash and cash equivalents during the year.
Cash flows from operating activities are computed from the results for the year adjusted for non-cash operating items, changes in net working capital, and corporate tax. Income tax paid is presented as a separate item under operating activities.
Cash flows from investing activities include payments in connection with the purchase and sale of property, plant and equipment and cash flows relating to the purchase and sale of enterprises to third parties, if any.
Cash flows from financing activities include changes in equity, and proceeds from borrowings and repayment of loans.
Cash and cash equivalents include bank overdraft, if any, and liquid funds with a term of less than three months.
The following chart describes non-cash transactions related to the Consolidated Statement of Cash Flow:
| | | | | | |
Amounts in US$‘000 |
| 2021 |
| 2020 |
| 2019 |
(Decrease) Increase in asset retirement obligation |
| (651) |
| (1,812) |
| 13,299 |
(Decrease) Increase in provisions for other long-term liabilities |
| (443) |
| (1,051) |
| 1,867 |
Purchase of property, plant and equipment |
| — |
| — |
| (733) |
Changes in working capital shown in the Consolidated Statement of Cash Flow are disclosed as follows:
| | | | | | |
Amounts in US$‘000 |
| 2021 |
| 2020 |
| 2019 |
Decrease (Increase) in Inventories |
| 1,241 |
| 1,220 |
| (1,675) |
(Increase) Decrease in Trade receivables |
| (23,290) |
| 3,190 |
| (27,839) |
(Increase) Decrease in Prepayments and other receivables and Other assets |
| (13,817) |
| 38,742 |
| (27,547) |
Increase (Decrease) in Trade and other payables |
| 26,515 |
| (48,392) |
| 11,964 |
|
| (9,351) |
| (5,240) |
| (45,097) |
28
Note 5 Consolidated Statement of Cash Flow (continued)
The following chart shows the movements in the borrowings and lease liabilities for each of the periods presented:
| | | | | | |
| | | | Lease | | |
Amounts in US$‘000 |
| Borrowings |
| Liabilities |
| Total |
As of January 1, 2019 |
| 447,002 |
| — | | 447,002 |
Initial recognition of lease liabilities | | — | | 14,610 | | 14,610 |
Addition to lease liabilities | | — | | 2,496 | | 2,496 |
Accrual of borrowing's interests |
| 29,940 | | — | | 29,940 |
Exchange difference |
| 5 | | 566 | | 571 |
Foreign currency translation |
| (639) | | 7 | | (632) |
Unwinding of discount | | — | | 419 | | 419 |
Principal paid |
| (9,790) | | — | | (9,790) |
Interest paid |
| (29,099) | | — | | (29,099) |
Lease payments | | — | | (4,855) | | (4,855) |
As of December 31, 2019 | | 437,419 |
| 13,243 | | 450,662 |
Proceeds from borrowings | | 350,000 | | — | | 350,000 |
Debt issuance costs paid | | (7,507) | | — | | (7,507) |
Acquisitions (Note 36.1) | | — | | 17,851 | | 17,851 |
Addition to lease liabilities | | — | | 561 | | 561 |
Accrual of borrowing's interests | | 48,232 | | — | | 48,232 |
Exchange difference | | — | | 466 | | 466 |
Foreign currency translation | | (2,389) | | (1,641) | | (4,030) |
Unwinding of discount | | — | | 1,247 | | 1,247 |
Principal paid | | (3,575) | | — | | (3,575) |
Interest paid | | (37,594) | | — | | (37,594) |
Lease payments | | — | | (9,380) | | (9,380) |
As of December 31, 2020 | | 784,586 |
| 22,347 | | 806,933 |
Proceeds from borrowings | | 172,174 | | — | | 172,174 |
Debt issuance costs paid | | (2,019) | | — | | (2,019) |
Addition to lease liabilities | | — | | 5,288 | | 5,288 |
Accrual of borrowing's interests | | 44,323 | | — | | 44,323 |
Exchange difference | | (581) | | (365) | | (946) |
Foreign currency translation | | (265) | | (461) | | (726) |
Unwinding of discount | | — | | 1,453 | | 1,453 |
Principal paid | | (274,934) | | — | | (274,934) |
Interest paid | | (42,592) | | — | | (42,592) |
Borrowings cancellation costs | | 6,308 | | — | | 6,308 |
Borrowings cancellation costs paid | | (12,908) | | — | | (12,908) |
Lease payments | | — | | (7,518) | | (7,518) |
As of December 31, 2021 | | 674,092 |
| 20,744 | | 694,836 |
29
Note 6 Segment information
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Committee. This committee is integrated by the CEO, COO, CFO and managers in charge of the Geoscience, Operations, Legal and Corporate Governance, People and Sustainability departments. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments based on these reports. The committee considers the business from a geographic perspective.
The Executive Committee assesses the performance of the operating segments based on a measure of Adjusted EBITDA. Adjusted EBITDA is defined as (loss) profit for the period (determined as if IFRS 16 Leases has not been adopted), before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful exploration efforts, accrual of share-based payment, unrealized result on commodity risk management contracts, geological and geophysical expenses allocated to capitalized projects, and other non-recurring events. Other information provided to the Executive Committee is measured in a manner consistent with that in the Consolidated Financial Statements.
Segment areas (geographical segments)
| | | | | | | | | | | | | | |
Amounts in US$ ‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Ecuador (b) | | Corporate |
| Total |
2021 | | | | | | | | | | | | | | |
Revenue |
| 618,268 |
| 21,471 |
| 20,109 |
| 28,695 |
| — | | — |
| 688,543 |
Sale of crude oil |
| 616,133 | | 6,297 | | 661 | | 24,468 | | — | | — |
| 647,559 |
Sale of gas |
| 2,135 | | 15,174 | | 19,448 | | 4,227 | | — | | — |
| 40,984 |
Realized loss on commodity risk management contracts |
| (109,654) | | — | | — | | — | | — | | — |
| (109,654) |
Production and operating costs |
| (178,384) | | (11,050) | | (4,596) | | (18,760) | | — | | — |
| (212,790) |
Royalties |
| (106,341) | | (770) | | (1,642) | | (4,270) | | — | | — |
| (113,023) |
Share-based payment |
| (334) | | (31) | | — | | 26 | | — | | — |
| (339) |
Other operating costs |
| (71,709) | | (10,249) | | (2,954) | | (14,516) | | — | | — |
| (99,428) |
Adjusted EBITDA |
| 294,847 | | 7,639 | | 12,569 | | 2,124 | | (2,071) | | (14,308) |
| 300,800 |
Depreciation |
| (61,279) | | (14,275) | | (4,082) | | (9,130) | | (200) | | (3) | | (88,969) |
(Recognition) Reversal of impairment losses |
| — | | (17,641) | | — | | 13,307 | | — | | — | | (4,334) |
Write-off of unsuccessful exploration efforts |
| (7,827) | | (4,435) | | — | | — | | — | | — | | (12,262) |
Total assets |
| 689,401 | | 71,515 | | 38,846 | | 38,111 | | 7,782 | | 50,086 | | 895,741 |
Employees (average) (a) |
| 308 | | 55 | | 4 | | 92 | | 8 | | 9 | | 476 |
Employees at year end (a) |
| 321 | | 52 | | 4 | | 74 | | 3 | | 9 | | 463 |
(a) | Unaudited. |
(b) | Includes certain expenses and 4 average employees (who are no longer in the Group at year-end) that correspond to the Peruvian subsidiaries, which act as holding companies of the Ecuadorian branch since Peru is no longer an operating segment due to the retirement from the Morona Block. |
30
Note 6 Segment information (continued)
| | | | | | | | | | | | | | | | |
Amounts in US$ ‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Peru (b) |
| Ecuador |
| Corporate |
| Total |
2020 | | | | | | | | | | | | | | | | |
Revenue |
| 334,606 |
| 21,704 |
| 12,783 |
| 24,599 |
| — |
| — | | — |
| 393,692 |
Sale of crude oil |
| 332,461 | | 5,103 | | 891 | | 21,185 | | — | | — | | — |
| 359,640 |
Sale of gas |
| 2,145 | | 16,601 | | 11,892 | | 3,414 | | — | | — | | — |
| 34,052 |
Realized gain on commodity risk management contracts |
| 21,059 | | — | | — | | — | | — | | — | | — |
| 21,059 |
Production and operating costs |
| (92,319) | | (10,244) | | (3,876) | | (18,633) | | — | | — | | — |
| (125,072) |
Royalties |
| (30,453) | | (753) | | (1,049) | | (3,620) | | — | | — | | — |
| (35,875) |
Share-based payment |
| (362) | | (94) | | — | | (72) | | — | | — | | — |
| (528) |
Other operating costs |
| (61,504) | | (9,397) | | (2,827) | | (14,941) | | — | | — | | — |
| (88,669) |
Adjusted EBITDA |
| 218,524 | | 8,148 | | 4,784 | | 1,195 | | (1,952) | | (773) | | (12,395) |
| 217,531 |
Depreciation |
| (63,687) | | (33,571) | | (3,732) | | (16,564) | | (401) | | (52) | | (66) | | (118,073) |
Recognition of impairment losses | | — | | (81,967) | | (1,717) | | (16,205) | | (33,975) | | — | | — | | (133,864) |
Write-off of unsuccessful exploration efforts |
| (1,949) | | (50,167) | | (536) | | — | | — | | — | | — | | (52,652) |
Total assets |
| 680,828 | | 101,742 | | 38,172 | | 36,803 | | 4,656 | | 1,127 | | 96,938 | | 960,266 |
Employees (average) (a) |
| 238 | | 68 | | 11 | | 114 | | 10 | | 2 | | 4 | | 447 |
Employees at year end (a) |
| 268 | | 57 | | 5 | | 97 | | 5 | | 2 | | 3 | | 437 |
| | | | | | | | | | | | | | | | |
Amounts in US$ ‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Peru (b) | | Ecuador |
| Corporate |
| Total |
2019 | | | | | | | | | | | | | | | | |
Revenue |
| 538,917 |
| 32,336 |
| 23,049 |
| 34,605 |
| — |
| — | | — |
| 628,907 |
Sale of crude oil |
| 536,986 | | 10,551 | | 1,469 | | 30,024 | | — | | — | | — |
| 579,030 |
Sale of gas |
| 1,931 | | 21,785 | | 21,580 | | 4,581 | | — | | — | | — |
| 49,877 |
Realized gain on commodity risk management contracts |
| 3,888 | | — | | — | | — | | — | | — | | — |
| 3,888 |
Production and operating costs |
| (116,944) | | (19,789) | | (5,953) | | (26,278) | | — | | — | | — |
| (168,964) |
Royalties |
| (56,399) | | (1,181) | | (1,855) | | (5,141) | | — | | — | | — |
| (64,576) |
Share-based payment |
| (231) | | (31) | | (29) | | (38) | | — | | — | | — |
| (329) |
Other operating costs |
| (60,314) | | (18,577) | | (4,069) | | (21,099) | | — | | — | | — |
| (104,059) |
Adjusted EBITDA |
| 367,058 | | 8,310 | | 11,750 | | 868 | | (6,540) | | (535) | | (17,576) |
| 363,335 |
Depreciation |
| (46,917) | | (34,826) | | (7,445) | | (15,618) | | (576) | | (1) | | (149) | | (105,532) |
Recognition of impairment losses |
| — | | — | | — | | (7,559) | | — | | — | | — | | (7,559) |
Write-off of unsuccessful exploration efforts |
| — | | — | | (5,120) | | (13,170) | | — | | — | | — | | (18,290) |
Total assets |
| 357,125 | | 249,207 | | 68,480 | | 79,062 | | 53,993 | | 1,119 | | 43,146 | | 852,132 |
Employees (average) (a) |
| 195 | | 89 | | 13 | | 133 | | 26 | | 2 | | 3 |
| 461 |
Employees at year end (a) |
| 202 | | 77 | | 13 | | 128 | | 14 | | 2 | | 3 |
| 439 |
(a) | Unaudited. |
(b) | As of the date of these Consolidated Financial Statements, Peru is no longer an operating segment due to the retirement from the Morona Block. |
In 2021, approximately 93% of capital expenditure was incurred by Colombia (82% in 2020 and 61% in 2019), 3% was incurred by Chile (15.5% in 2020 and 8% in 2019), 0% was incurred by Brazil (0.5% in 2020 and 4% in 2019), 0% was incurred by Argentina (1% in 2020 and 15% in 2019), 0% was incurred by Peru (0.5% in 2020 and 11.5% in 2019) and 4% was incurred by Ecuador (0.5% in 2020 and 2019).
31
Note 6 Segment information (continued)
A reconciliation of total Adjusted EBITDA to total profit (loss) before income tax is provided as follows:
| | | | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
| 2019 |
Adjusted EBITDA |
| 300,800 |
| 217,531 |
| 363,335 |
Unrealized gain (loss) on commodity risk management contracts |
| 463 |
| (12,978) |
| (26,411) |
Depreciation (a) |
| (88,969) |
| (118,073) |
| (105,532) |
Share-based payment |
| (6,621) |
| (8,444) |
| (2,717) |
Impairment and write-off of unsuccessful exploration efforts, net |
| (16,596) |
| (186,516) |
| (25,849) |
Lease accounting - IFRS 16 | | 7,518 | | 9,380 | | 4,855 |
Others (b) |
| (10,786) |
| (11,563) |
| 2,994 |
Operating profit (loss) |
| 185,809 |
| (110,663) |
| 210,675 |
Financial expenses |
| (64,112) |
| (64,582) |
| (41,070) |
Financial income |
| 1,652 |
| 3,166 |
| 2,360 |
Foreign exchange gain (loss) |
| 5,049 |
| (13,008) |
| (2,446) |
Profit (Loss) before tax |
| 128,398 |
| (185,087) |
| 169,519 |
(a) | Net of capitalized costs for oil stock included in Inventories. |
(b) | Includes allocation to capitalized projects. In 2021, also includes termination costs and write-down of tax credits in Argentina and, in 2020, also includes termination costs, and write-down of VAT credits and recognition of a provision for environmental liabilities in Peru. |
Note 7 Revenue
| | | | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
| 2019 |
Sale of crude oil |
| 647,559 |
| 359,640 |
| 579,030 |
Sale of gas |
| 40,984 |
| 34,052 |
| 49,877 |
|
| 688,543 |
| 393,692 |
| 628,907 |
32
Note 8 Commodity risk management contracts
The Group has entered into derivative financial instruments to manage its exposure to oil price risk. These derivatives are zero-premium collars, fixed price or zero-premium 3-ways (put spread plus call), and were placed with major financial institutions and commodity traders. The Group entered into the derivatives under ISDA Master Agreements and Credit Support Annexes, which provide credit lines for collateral posting thus alleviating possible liquidity needs under the instruments and protect the Group from potential non-performance risk by its counterparties. The Group’s derivatives are accounted for as non-hedge derivatives and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the results of the periods in which they occur.
The following table presents the Group’s production hedged during the year ended December 31, 2020 and for the following periods as a consequence of the derivative contracts in force as of December 31, 2021:
| | | | | | | | |
Period |
| Reference |
| Type |
| Volume bbl/d |
| Weighted average price US$/bbl |
January 1, 2021 - March 31, 2021 | | ICE BRENT | | Zero Premium Collars | | 23,500 | | 38.91 Put 52.72 Call |
January 1, 2021 - March 31, 2021 | | VASCONIA(a) | | Zero Premium Collars | | 2,000 | | 35.00 Put 43.01 Call |
| | | | | | 25,500 | | |
April 1, 2021 - June 30, 2021 | | ICE BRENT | | Zero Premium Collars | | 25,500 | | 40.61 Put 53.59 Call |
| | | | | | 25,500 | | |
July 1, 2021 - September 30, 2021 | | ICE BRENT | | Zero Premium Collars | | 18,000 | | 43.19 Put 60.64 Call |
July 1, 2021 - September 30, 2021 | | VASCONIA(a) | | Zero Premium Collars | | 2,000 | | 41.50 Put 68.57 Call |
| | | | | | 20,000 | | |
October 1, 2021 - December 31, 2021 | | ICE BRENT | | Zero Premium Collars | | 19,500 | | 43.72 Put 62.65 Call |
| | | | | | 19,500 | | |
January 1, 2022 - March 31, 2022 | | ICE BRENT | | Zero Premium Collars | | 14,500 | | 49.10 Put 74.81 Call |
| | | | | | 14,500 | | |
April 1, 2022 - June 30, 2022 | | ICE BRENT | | Zero Premium Collars | | 12,500 | | 53.35 Put 79.38 Call |
| | | | | | 12,500 | | |
July 1, 2022 - September 30, 2022 | | ICE BRENT | | Zero Premium Collars | | 10,000 | | 58.23 Put 84.37 Call |
| | | | | | 10,000 | | |
October 1, 2022 - December 31, 2022 | | ICE BRENT | | Zero Premium Collars | | 6,000 | | 60.00 Put 86.38 Call |
| | | | | | 6,000 | | |
(a) | Vasconia Crude (Ice Brent minus Vasconia Differential) |
Since 2020, the Group has entered into Vasconia-based derivative contracts, a new instrument within its 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 the GeoPark’s Llanos Basin crude production in Colombia.
33
Note 8 Commodity risk management contracts (continued)
The table below summarizes the gain (loss) on the commodity risk management contracts:
| | | | | | |
|
| 2021 |
| 2020 |
| 2019 |
Realized (loss) gain on commodity risk management contracts |
| (109,654) |
| 21,059 |
| 3,888 |
Unrealized gain (loss) on commodity risk management contracts |
| 463 |
| (12,978) |
| (26,411) |
|
| (109,191) |
| 8,081 |
| (22,523) |
The following table presents the Group’s derivative contracts agreed after the balance sheet date:
| | | | | | | | |
Period |
| Reference |
| Type |
| Volume bbl/d |
| Price US$/bbl |
July 1, 2022 - September 30, 2022 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 60.00 Put 90.50 Call |
July 1, 2022 - September 30, 2022 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 60.00 Put 96.70 Call |
October 1, 2022 - December 31, 2022 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 60.00 Put 91.40 Call |
October 1, 2022 - December 31, 2022 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 60.00 Put 99.30 Call |
October 1, 2022 - December 31, 2022 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 60.00 Put 101.70 Call |
October 1, 2022 - December 31, 2022 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 65.00 Put 102.50 Call |
January 1, 2023 - March 31, 2023 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 60.00 Put 103.70 Call |
January 1, 2023 - March 31, 2023 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 60.00 Put 104.75 Call |
January 1, 2023 - March 31, 2023 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 65.00 Put 104.90 Call |
January 1, 2023 - March 31, 2023 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 70.00 Put 102.30 Call |
January 1, 2023 - March 31, 2023 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 70.00 Put 109.50 Call |
April 1, 2023 - June 30, 2023 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 65.00 Put 100.75 Call |
April 1, 2023 - June 30, 2023 | | ICE BRENT | | Zero Premium Collars | | 1,500 | | 70.00 Put 103.50 Call |
Note 9 Production and operating costs
| | | | | | |
Amounts in US$ '000 |
| 2021 |
| 2020 |
| 2019 |
Staff costs (Note 11) |
| 16,655 |
| 14,689 |
| 14,213 |
Share-based payment (Note 11) |
| 339 |
| 528 |
| 329 |
Royalties |
| 113,023 |
| 35,875 |
| 64,576 |
Well and facilities maintenance |
| 17,989 |
| 15,039 |
| 27,660 |
Operation and maintenance |
| 7,826 |
| 7,491 |
| 7,743 |
Consumables |
| 19,270 |
| 16,776 |
| 17,625 |
Equipment rental |
| 8,127 |
| 8,570 |
| 10,476 |
Safety and Insurance costs |
| 4,216 |
| 4,505 |
| 4,107 |
Gas plant costs |
| 2,596 |
| 1,591 |
| 3,414 |
Transportation costs |
| 3,383 |
| 5,622 |
| 2,941 |
Field camp |
| 4,386 |
| 3,130 |
| 2,583 |
Non-operated blocks costs |
| 4,941 |
| 3,442 |
| 1,353 |
Other costs |
| 10,039 |
| 7,814 |
| 11,944 |
|
| 212,790 |
| 125,072 |
| 168,964 |
34
Note 10 DepreciationS | | | | | | |
Note 10 Depreciation
| | | | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
| 2019 |
Oil and gas properties |
| 66,011 |
| 89,344 |
| 83,276 |
Production facilities and machinery |
| 12,468 |
| 16,820 |
| 16,708 |
Furniture, equipment and vehicles |
| 1,960 |
| 2,317 |
| 2,096 |
Buildings and improvements |
| 700 |
| 490 |
| 804 |
Depreciation of property, plant and equipment (a) |
| 81,139 |
| 108,971 |
| 102,884 |
Related to: |
|
|
|
|
|
|
Productive assets |
| 78,479 |
| 106,164 |
| 99,984 |
Administrative assets |
| 2,660 |
| 2,807 |
| 2,900 |
Depreciation total (a) |
| 81,139 |
| 108,971 |
| 102,884 |
(a) | Depreciation without considering capitalized costs for oil stock included in Inventories nor depreciation of right-of-use assets. |
Note 11 Staff costs and Directors’ Remuneration
| | | | | | |
|
| 2021 |
| 2020 |
| 2019 |
Number of employees at year end (a) |
| 463 |
| 437 |
| 439 |
Amounts in US$ ‘000 |
| |
| |
|
|
Wages and salaries |
| 42,236 |
| 49,338 |
| 55,325 |
Share-based payments (b) (Note 31) |
| 6,621 |
| 8,444 |
| 2,717 |
Social security charges |
| 6,863 |
| 5,712 |
| 6,888 |
Director’s fees and allowance |
| 2,853 |
| 2,094 |
| 3,266 |
|
| 58,573 |
| 65,588 |
| 68,196 |
Recognized as follows: |
|
|
|
|
|
|
Production and operating costs |
| 16,994 |
| 15,217 |
| 14,542 |
Geological and geophysical expenses |
| 6,219 |
| 12,893 |
| 18,448 |
Administrative expenses |
| 35,360 |
| 37,478 |
| 35,206 |
|
| 58,573 |
| 65,588 |
| 68,196 |
Board of Directors’ and key managers’ remuneration |
|
|
|
|
|
|
Salaries and fees |
| 9,069 |
| 8,641 |
| 13,483 |
Share-based payments |
| 5,759 |
| 7,170 |
| 2,251 |
Other benefits in kind |
| 296 |
| 232 |
| 262 |
|
| 15,124 |
| 16,043 |
| 15,996 |
(a) | Unaudited. |
(b) | The increase in share-based payments in 2021 and 2020 is explained by the accrual of the 2019 VCP and the 2020 Plan, which were granted in November 2019 and February 2020, respectively. |
35
Note 11 Staff costs and Directors’ Remuneration (continued)
Directors’ Remuneration
| | | | | | | | | | |
|
| Executive |
| Executive |
| Non-Executive |
| Director Fees |
| Cash Equivalent |
| | Directors’ Fees | | Directors’ Bonus | | Directors’ Fees | | Paid in Shares | | Total Remuneration |
| | (in US$) | | (in US$) | | (in US$) | | (No. of Shares) | | (in US$) |
Gerald O’Shaughnessy (a) |
| 261,560 | | — | | — | | — |
| 261,560 |
James F. Park |
| 800,000 | | 800,000 | (b) | — | | — |
| 1,600,000 |
Pedro E. Aylwin (c) |
| — | | — | | — | | — |
| — |
Carlos Gulisano |
| — | | — | | 82,083 | | 7,845 |
| 185,953 |
Robert Bedingfield (d) |
| — | | — | | 32,500 | | 15,438 |
| 238,527 |
Constantin Papadimitriou (e) (f) |
| — | | — | | 112,500 | | 14,852 |
| 310,646 |
Somit Varma (f) (g) | | — | | — | | 141,875 | | 14,803 | | 339,239 |
Sylvia Escovar Gomez (h) | | — | | — | | 67,500 | | 11,331 | | 223,465 |
(a) | Chair of GeoPark's board until his resignation on June 8, 2021. Sylvia Escovar Gomez was appointed as new Chair of the Board. |
(b) | The service contract with the Company to act as Chief Executive Officer established a bonus based on metrics and targets defined by the Compensation Committee over the performance of the Company. The target bonus is an amount equal to the annual salary. On March 10, 2021, the independent directors of the Board approved, as per recommendation of the Compensation Committee, Mr. Park’s bonus for the performance in 2020. Given the impact of COVID-19 and oil price crisis during 2020, the cash bonus approved was reduced to US$ 400,000. |
(c) | Pedro E. Aylwin has a service contract that provides for him to act as Director of Legal and Governance, so he relinquished his fees as a member of the Board. |
(d) | Audit Committee and Nomination & Corporate Governance Committee Chairman until November 10, 2021. Mr. Somit Varma was appointed as new Chairman of the Nomination & Corporate Governance Committee. |
(e) | Compensation Committee Chairman. |
(f) | Constantin Papadimitriou and Somit Varma, as members of the Strategy & Risk Committee, instructed by the Board, were awarded additional fees on their work related to specific projects and activities. The additional fees for 2021 amounted to US$ 82,500 and US$ 111,875, respectively and are included in the table above |
(g) | Strategy & Risk Committee Chairman. |
(h) | Includes an additional annual remuneration of US$ 50,000 to act as independent Chair of the Board. |
Note 12 Geological and geophysical expenses
| | | | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
| 2019 |
Staff costs (Note 11) |
| 6,042 |
| 12,653 |
| 18,312 |
Share-based payment (Note 11) |
| 177 |
| 240 |
| 136 |
Allocation to capitalized project |
| (953) |
| (102) |
| (4,834) |
Other services |
| 2,625 |
| 2,160 |
| 4,979 |
|
| 7,891 |
| 14,951 |
| 18,593 |
36
Note 13 Administrative expenses
| | | | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
| 2019 |
Staff costs (Note 11) |
| 26,402 |
| 27,708 |
| 29,688 |
Share-based payment (Note 11) |
| 6,105 |
| 7,676 |
| 2,252 |
Consultant fees |
| 10,806 |
| 8,570 |
| 18,685 |
Office expenses |
| 224 |
| 1,525 |
| 1,386 |
Travel expenses |
| 719 |
| 939 |
| 4,867 |
Director’s fees and allowance (Note 11) |
| 2,853 |
| 2,094 |
| 3,266 |
Communication and IT costs |
| 4,214 |
| 2,937 |
| 2,928 |
Allocation to joint operations |
| (8,574) |
| (6,720) |
| (8,008) |
Other administrative expenses |
| 4,079 |
| 5,586 |
| 5,754 |
|
| 46,828 |
| 50,315 |
| 60,818 |
Note 14 Selling expenses
| | | | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
| 2019 |
Transportation |
| 4,233 |
| 4,787 |
| 12,985 |
Selling taxes and other |
| 4,497 |
| 1,057 |
| 1,128 |
|
| 8,730 |
| 5,844 |
| 14,113 |
Note 15 Financial results
| | | | | | |
Amounts in US$ '000 |
| 2021 |
| 2020 |
| 2019 |
Financial expenses |
|
|
|
|
|
|
Interest and amortization of debt issue costs |
| (44,713) |
| (48,779) |
| (29,977) |
Less: amounts capitalized on qualifying assets |
| — |
| — |
| 367 |
Borrowings cancellation costs | | (6,308) | | — | | — |
Bank charges and other financial results |
| (8,012) |
| (9,909) |
| (6,900) |
Unwinding of long-term liabilities |
| (5,079) |
| (5,894) |
| (4,560) |
|
| (64,112) |
| (64,582) |
| (41,070) |
Financial income |
|
|
|
|
|
|
Interest received |
| 1,652 |
| 3,166 |
| 2,360 |
|
| 1,652 |
| 3,166 |
| 2,360 |
Foreign exchange gains and losses |
|
|
|
|
|
|
Foreign exchange gain (loss), net |
| 5,049 |
| (2,720) |
| (6,163) |
Realized result on currency risk management contracts | | — | | (9,414) | | 2,843 |
Unrealized result on currency risk management contracts | | — | | (874) | | 874 |
|
| 5,049 |
| (13,008) |
| (2,446) |
Total Financial results |
| (57,411) |
| (74,424) |
| (41,156) |
37
Colombia
In September 2021, a tax reform was approved in Colombia. The new legislation focuses on corporate income tax, increasing the tax rate from 30% to 35% from fiscal year 2022 onwards (the corporate income tax rate was 31% in 2021, 32% in 2020 and 33% in 2019).
Although the new tax provisions do not affect tax bases or tax rate for fiscal year 2021, the tax rate increase shall be considered for deferred income tax purposes.
Argentina
In June 2021, a tax reform was approved in Argentina. The new legislation focuses on the corporate income tax, with gradual rates on cumulative net income according to the following schedule: i) up to Argentine Peso (“AR$”) 5,000,000: 25% rate; ii) over AR$ 5,000,000 up to AR$ 50,000,000: AR$ 1,250,000 plus 30% on the surplus of AR$ 5,000,000; iii) over AR$ 50,000,000: AR$ 14,750,000 plus 35% on the surplus of AR$ 50,000,000. The detailed schedule applies from fiscal year 2021 onwards (the corporate income tax rate was 30% in 2020 and 2019).
Spain
As from December 2021, a set of tax rules approved in December 2020 became applicable for the Spanish holding entities. As stated, the new tax regulations turned a full income tax exemption on dividend and capital gains income into a 95% exemption.
Note 17 Income tax
| | | | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
| 2019 |
Current income tax charge |
| (49,291) |
| (41,927) |
| (111,371) |
Deferred income tax charge (Note 18) |
| (17,980) |
| (5,936) |
| (391) |
|
| (67,271) |
| (47,863) |
| (111,762) |
38
Note 17 Income tax (continued)
The tax on the Group’s (loss) profit before tax differs from the theoretical amount that would arise using the weighted average tax rate applicable to profits of the consolidated entities as follows:
| | | | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
| 2019 |
Profit (Loss) before tax |
| 128,398 |
| (185,087) |
| 169,519 |
Tax losses from non-taxable jurisdictions |
| 91,351 |
| 53,652 |
| 49,360 |
Taxable profit |
| 219,749 |
| (131,435) |
| 218,879 |
|
|
|
|
|
|
|
Income tax calculated at domestic tax rates applicable to Profit in the respective countries |
| (71,086) |
| 12,450 |
| (79,395) |
Tax losses where no deferred tax benefit is recognized |
| (7,510) |
| (23,117) |
| (2,563) |
Effect of currency translation on tax base |
| (10,354) |
| (923) |
| (16,795) |
Effect of inflation adjustment for tax purposes | | 2,482 | | (867) | | 541 |
Changes in the income tax rate (Note 16) |
| (1,703) |
| (925) |
| 1,279 |
Write-down of deferred tax benefits previously recognized (a) | | (7,261) |
| (32,565) |
| — |
Previously unrecognized tax losses |
| 9,593 |
| — |
| 1,820 |
Fiscal recognition of property, plant and equipment | | 8,919 | | — | | — |
Out of period adjustment (b) | | — | | — | | (9,910) |
Non-taxable results (c) |
| 9,649 |
| (1,916) |
| (6,739) |
Income tax |
| (67,271) |
| (47,863) |
| (111,762) |
(a) | Includes write-down of the deferred income tax asset in Peru due to the decision to retire from the Morona Block (see Note 36.4.1) in 2020, and write-down of a portion of tax losses and other deferred income tax assets in Chile, Brazil and Argentina where there is insufficient evidence of future taxable profits to offset them, in accordance with the expected future cash-flows as of December 31, 2021 and 2020. |
(b) | Adjustment related to prior periods that increased the income tax expense during the year ended December 31, 2019, due to the increase in deferred tax liabilities as a result of computing as temporary, differences generated between the tax and book basis of Property, plant and equipment, that were originally considered as permanent. The Group concluded that this adjustment was not material to the year ended December 31, 2019 or to any previously reported Consolidated Financial Statements. |
(c) | Includes non-deductible expenses and non-taxable gains in each jurisdiction. |
Under current Bermuda law, the Company is not required to pay any taxes in Bermuda on income or capital gains. The Company has received an undertaking from the Minister of Finance in Bermuda that, in the event of any taxes being imposed, they will be exempt from taxation in Bermuda until March 2035. Income tax rates in those countries where the Group operates (Colombia, Chile, Brazil, Argentina and Ecuador) ranges from 15% to 35%. There are no income tax consequences attached to the payment of dividends by the Group to its shareholders.
The Group has tax losses available which can be utilized against future taxable profit in the following countries:
| | | | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
| 2019 |
Chile (a) |
| 285,456 |
| 403,258 |
| 317,644 |
Brazil (a) |
| 26,781 |
| 32,452 |
| 37,848 |
Argentina (b) |
| 35,773 |
| 20,734 |
| 22,930 |
Total tax losses as of December 31 |
| 348,010 |
| 456,444 |
| 378,422 |
(a) | Taxable losses have no expiration date. |
(b) | Tax losses accumulated as of December 31, 2021 are: US$ 646,000, US$ 1,715,000, US$ 8,211,000, US$ 5,671,000 and US$ 19,530,000 expiring in 2022, 2023, 2024, 2025 and 2026, respectively. |
At the balance sheet date, deferred tax assets in respect of tax losses in certain companies in Chile and a portion of tax losses in Brazil have not been recognized as there is insufficient evidence of future taxable profits to offset them.
39
Note 18 Deferred income tax
The gross movement on the deferred income tax account is as follows:
| | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
Deferred income tax as of January 1 |
| 10,978 |
| 16,084 |
Acquisitions (Note 36.1) | | — |
| 4,071 |
Currency translation differences |
| 127 |
| (3,241) |
Income statement charge |
| (17,980) |
| (5,936) |
Deferred income tax as of December 31 |
| (6,875) |
| 10,978 |
The breakdown and movement of deferred income tax assets and liabilities as of December 31, 2021 and 2020 are as follows:
| | | | | | | | | | | | |
|
| At the |
| |
| |
| Currency |
| |
| |
| | beginning | | | | Charged to | | translation | | | | At the end |
Amounts in US$ ‘000 | | of year | | Acquisitions | | net profit | | differences | | Reclassification | | of year |
Deferred income tax assets |
|
|
|
|
|
|
|
|
|
|
|
|
Difference in depreciation rates and other |
| (4,628) | | — | | 4,157 | | 127 | | — |
| (344) |
Tax losses |
| 22,796 | | — | | (8,380) | | — | | — |
| 14,416 |
Total 2021 |
| 18,168 |
| — |
| (4,223) |
| 127 |
| — |
| 14,072 |
Total 2020 |
| 26,934 |
| 4,071 |
| (18,414) |
| (3,241) |
| 8,818 |
| 18,168 |
| | | | | | | | |
|
| At the beginning |
| Charged to |
| |
| At the end |
Amounts in US$ ‘000 | | of year | | net profit | | Reclassification | | of year |
Deferred income tax liabilities |
|
|
|
|
|
|
|
|
Difference in depreciation rates and other |
| (7,190) | | (13,757) | | — |
| (20,947) |
Total 2021 |
| (7,190) |
| (13,757) |
| — |
| (20,947) |
Total 2020 |
| (10,850) |
| 12,478 |
| (8,818) |
| (7,190) |
Note 19 Earnings per share
| | | | | | |
Amounts in US$ ‘000 except for shares |
| 2021 |
| 2020 |
| 2019 |
Numerator: Profit (Loss) for the year |
| 61,127 |
| (232,950) |
| 57,757 |
Denominator: Weighted average number of shares used in basic EPS |
| 60,901,109 |
| 60,668,185 |
| 60,217,523 |
Earnings (Losses) after tax per share (US$) – basic |
| 1.00 |
| (3.84) |
| 0.96 |
| | | | | | |
Amounts in US$ ‘000 except for shares |
| 2021 |
| 2020 |
| 2019 |
Weighted average number of shares used in basic EPS |
| 60,901,109 |
| 60,668,185 |
| 60,217,523 |
Effect of dilutive potential common shares (a) |
| |
| |
|
|
Stock awards at US$ 0.001 |
| 559,012 |
| — |
| 2,433,126 |
Weighted average number of common shares for the purposes of diluted earnings per shares |
| 61,460,121 |
| 60,668,185 |
| 62,650,649 |
Earnings (Losses) after tax per share (US$) – diluted |
| 0.99 |
| (3.84) |
| 0.92 |
(a) | For the year ended December 31, 2020, there were 974,159 potential shares that could have a dilutive impact. They were considered antidilutive due to negative earnings. |
40
Note 20 Property, plant and equipment
| | | | | | | | | | | | | | |
|
| |
| Furniture, |
| Production |
| Buildings |
| |
| Exploration |
| |
| | Oil & gas | | equipment | | facilities and | | and | | Construction in | | and evaluation | | |
Amounts in US$’000 | | properties | | and vehicles | | machinery | | improvements | | progress | | assets(a) | | Total |
Cost as of January 1, 2019 |
| 717,510 | | 17,748 |
| 172,094 |
| 11,554 |
| 60,597 |
| 59,992 |
| 1,039,495 |
Additions |
| 14,696 | (b) | 2,052 |
| 381 |
| 159 |
| 96,012 |
| 27,449 |
| 140,749 |
Currency translation differences |
| (3,022) | | (414) |
| (561) |
| (8) |
| (106) |
| (449) |
| (4,560) |
Disposals |
| — | | (102) |
| (101) |
| — |
| — |
| (59) |
| (262) |
Write-off / Impairment |
| (7,559) | (c) | — |
| — | (c) | — |
| — | (c) | (18,290) | (d) | (25,849) |
Transfers |
| 83,010 | | 265 |
| 24,183 |
| 65 |
| (86,916) |
| (20,607) |
| — |
Reclassification (g) | | 26,302 | | — |
| (23,489) |
| — | | — |
| — |
| 2,813 |
Cost as of December 31, 2019 |
| 830,937 | | 19,549 |
| 172,507 |
| 11,770 |
| 69,587 |
| 48,036 |
| 1,152,386 |
Additions |
| (2,863) | (b) | 1,180 | | — | | 422 | | 55,267 | | 18,429 |
| 72,435 |
Acquisitions (Note 36.1) | | 185,533 | | 553 | | 16,181 | | 212 | | 1,199 | | 73,310 |
| 276,988 |
Currency translation differences |
| (14,399) | | (194) | | (1,036) | | (59) | | (47) | | (401) |
| (16,136) |
Disposals |
| — | | (555) | | — | | (227) | | (33) | | — |
| (815) |
Write-off / Impairment |
| (77,667) | (c) | — | | (11,357) | | — | | (44,840) | | (52,652) | (e) | (186,516) |
Transfers |
| 48,361 | | 174 | | 21,534 | | 324 | | (62,285) | | (8,108) |
| — |
Assets held for sale (Note 36.2.2) |
| (1,285) | | — | | — | | — | | — | | — |
| (1,285) |
Cost as of December 31, 2020 |
| 968,617 | | 20,707 | | 197,829 | | 12,442 | | 18,848 | | 78,614 |
| 1,297,057 |
Additions |
| (1,094) | (b) | 930 | | — | | — | | 82,094 | | 46,234 |
| 128,164 |
Currency translation differences |
| (3,284) | | (43) | | (246) | | (16) | | (18) | | (30) |
| (3,637) |
Disposals | | — | | (1,762) | | (900) | | (978) | | (3,372) | | (338) |
| (7,350) |
Write-off / Impairment |
| (1,575) | (c) | — | | (2,759) | (c) | — | | — | (c) | (12,262) | (f) | (16,596) |
Transfers |
| 68,315 | | 58 | | 13,305 | | 391 | | (70,321) | | (11,748) |
| — |
Assets held for sale (Note 36.3.1) |
| (73,047) | | (1,178) | | (6,052) | | (177) | | (27) | | — | | (80,481) |
Cost as of December 31, 2021 |
| 957,932 | | 18,712 | | 201,177 | | 11,662 | | 27,204 | | 100,470 |
| 1,317,157 |
| | | | | | | | | | | | | | |
Depreciation and write-down as of January 1, 2019 |
| (359,358) |
| (13,361) |
| (103,704) |
| (5,902) |
| — |
| — |
| (482,325) |
Depreciation |
| (83,276) |
| (2,096) |
| (16,708) |
| (804) |
| — |
| — |
| (102,884) |
Disposals |
| — |
| 85 |
| 34 |
| — |
| — |
| — |
| 119 |
Currency translation differences |
| 2,492 |
| 223 |
| 480 |
| 110 |
| — |
| — |
| 3,305 |
Reclassification (g) | | (27,664) |
| — | | 24,851 |
| — |
| — |
| — |
| (2,813) |
Depreciation and write-down as of December 31, 2019 |
| (467,806) |
| (15,149) |
| (95,047) |
| (6,596) |
| — |
| — |
| (584,598) |
Depreciation |
| (89,344) | | (2,317) | | (16,820) | | (490) | | — | | — |
| (108,971) |
Disposals |
| — | | 326 | | — | | 72 | | — | | — |
| 398 |
Currency translation differences |
| 8,572 | | 155 | | 1,880 | | 39 | | — | | — |
| 10,646 |
Assets held for sale (Note 36.2.2) |
| 133 | | — | | — | | — | | — | | — |
| 133 |
Depreciation and write-down as of December 31, 2020 |
| (548,445) | | (16,985) | | (109,987) | | (6,975) | | — | | — |
| (682,392) |
Depreciation |
| (66,011) | | (1,960) | | (12,468) | | (700) | | — | | — |
| (81,139) |
Disposals |
| ��� | | 1,325 | | 900 | | 838 | | — | | — |
| 3,063 |
Currency translation differences |
| 2,219 | | 37 | | 246 | | 16 | | — | | — |
| 2,518 |
Assets held for sale (Note 36.3.1) |
| 49,080 | | 915 | | 4,692 | | 153 | | — | | — | | 54,840 |
Depreciation and write-down as of December 31, 2021 |
| (563,157) | | (16,668) | | (116,617) | | (6,668) | | — | | — |
| (703,110) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Carrying amount as of December 31, 2019 |
| 363,131 |
| 4,400 |
| 77,460 |
| 5,174 |
| 69,587 |
| 48,036 |
| 567,788 |
Carrying amount as of December 31, 2020 |
| 420,172 | | 3,722 | | 87,842 | | 5,467 | | 18,848 | | 78,614 |
| 614,665 |
Carrying amount as of December 31, 2021 |
| 394,775 | | 2,044 | | 84,560 | | 4,994 | | 27,204 | | 100,470 |
| 614,047 |
41
Note 20 Property, plant and equipment (continued)
(a) | Exploration wells movement and balances are shown in the table below; mining property associated with unproved reserves and resources, seismic and other exploratory assets amount to US$ 90,166,000 (US$ 75,485,000 in 2020 and US$ 44,047,000 in 2019). |
| | |
Amounts in US$ ‘000 |
| Total |
Exploration wells as of December 31, 2019 |
| 3,989 |
Additions |
| 11,016 |
Acquisitions | | 3,129 |
Write-offs |
| (7,947) |
Transfers |
| (7,058) |
Exploration wells as of December 31, 2020 |
| 3,129 |
Additions |
| 25,795 |
Write-offs |
| (6,814) |
Transfers |
| (11,806) |
Exploration wells as of December 31, 2021 |
| 10,304 |
As of December 31, 2021, there were three exploratory wells that has been capitalized for a period less than a year amounting to US$ 10,304,000.
(b) | Corresponds to the effect of change in estimate of assets retirement obligations. |
(c) | See Note 37. |
(d) | Corresponds to five unsuccessful exploratory wells, four wells drilled in Argentina (Sierra del Nevado, Puelen and Aguada Baguales Blocks) and a well drilled in Brazil (POT-T-747 Block). The charge also includes the write-off of wells and other exploration costs incurred in previous years in the Argentinean Blocks for which no additional work would be performed. In addition, due to the results from REC-T-94, SEAL-T-268 and POT-T-747 Blocks (Brazil), during December 2019 the Group decided to relinquish these blocks so the associated investment was written off. |
(f) | Corresponds to two unsuccessful exploratory wells drilled in the Llanos 32 Block (Colombia), other exploration costs incurred in the Fell Block (Chile), an exploratory well drilled in previous years in the CPO-5 Block (Colombia) and other exploration costs incurred in previous years in the PUT-30 Block (Colombia) for which no additional work would be performed. |
(g) | Corresponds to the final closing of the sale of the La Cuerva and Yamu Blocks (Colombia). |
42
Note 21 Subsidiary undertakings
The following chart illustrates main companies of the Group structure as of December 31, 2021:
Group structure
During the year ended December 31, 2021, the following changes to the Group structure have taken place:
● | The Company incorporated a subsidiary in the United States named Market Access LLP (ownership interest: 9%). |
● | GeoPark Latin America Limited and its Chilean branch GeoPark Latin America Limited - Agencia en Chile were voluntarily dissolved and liquidated. |
● | The shares of Amerisurexplor Ecuador S.A. were transferred to GeoPark Latin America S.L.U. |
● | The Peruvian subsidiaries finalized a merger process by which GeoPark Peru S.A.C. continued the operations related to GeoPark S.A.C. and GeoPark Operadora del Peru S.A.C. |
43
Note 21 Subsidiary undertakings (continued)
Details of the subsidiaries of the Group are set out below:
| | | | |
|
| Name and registered office |
| Ownership interest |
Subsidiaries |
| GeoPark Argentina S.A.U (Argentina) |
| 100% (a) |
|
| GeoPark Brasil Exploração y Produção de Petróleo e Gás Ltda. (Brazil) |
| 100% (a) |
|
| GeoPark Chile S.p.A. (Chile) |
| 100% (a) |
|
| GeoPark Fell S.p.A. (Chile) |
| 100% (a) |
|
| GeoPark Magallanes Limitada (Chile) |
| 100% (a) |
|
| GeoPark TdF S.p.A. (Chile) |
| 100% (a) |
|
| GeoPark Colombia S.A.S. (Colombia) |
| 100% (a) |
|
| GeoPark Latin America S.L.U. (Spain) |
| 100% (a) |
|
| GeoPark Colombia S.L.U. (Spain) |
| 100% (a) |
|
| GeoPark Perú S.A.C. (Peru) |
| 100% (a) |
|
| GeoPark Colombia E&P S.A. (Panama) |
| 100% (a) |
|
| GeoPark Colombia E&P Sucursal Colombia (Colombia) |
| 100% (a) |
|
| GeoPark Mexico S.A.P.I. de C.V. (Mexico) |
| 100% (a) (b) |
|
| GeoPark E&P S.A.P.I. de C.V. (Mexico) |
| 100% (a) (b) |
| | GeoPark Perú S.A.C. Sucursal Ecuador (Ecuador) | | 100% (a) |
|
| GeoPark (UK) Limited (United Kingdom) |
| 100% |
| | Amerisur Resources Limited (United Kingdom) |
| 100% (a) |
| | Amerisur Exploración Colombia Limited (British Virgin Islands) |
| 100% (a) |
| | Amerisur Exploración Colombia Limited Sucursal Colombia (Colombia) |
| 100% (a) |
| | Yarumal S.A.S. (Colombia) |
| 100% (a) (b) |
| | Petrodorado South America S.A. (Panama) |
| 100% (a) |
| | Petrodorado South America S.A. Sucursal Colombia (Colombia) |
| 100% (a) |
| | Fenix Oil & Gas Limited (British Virgin Islands) |
| 100% (a) (b) |
| | Fenix Oil & Gas Limited Sucursal Colombia (Colombia) |
| 100% (a) (b) |
| | Amerisurexplor Ecuador S.A. (Ecuador) |
| 100% (a) (b) |
| | Amerisur S.A. (Paraguay) |
| 100% (a) (b) |
|
| Market Access LLP (United States) |
| 9% |
(a) | Indirectly owned. |
(b) | Dormant companies. |
44
Note 21 Subsidiary undertakings (continued)
Details of the joint operations of the Group are set out below:
| | | | |
|
| Name and registered office |
| Ownership interest |
Joint operations |
| Flamenco Block (Chile) |
| 50% (a) |
|
| Campanario Block (Chile) |
| 50% (a) |
|
| Isla Norte Block (Chile) |
| 60% (a) |
|
| Llanos 34 Block (Colombia) |
| 45% (a) |
|
| Llanos 32 Block (Colombia) |
| 12.5% |
|
| Puelen Block (Argentina) |
| 18% (b) |
|
| Sierra del Nevado Block (Argentina) |
| 18% (b) |
|
| CN-V Block (Argentina) |
| 50% |
| | Los Parlamentos (Argentina) |
| 50% |
|
| Manati Field (Brazil) |
| 10% |
|
| POT-T-785 Block (Brazil) |
| 70% (a) |
| | Espejo Block (Ecuador) |
| 50% (a) |
| | Perico Block (Ecuador) |
| 50% |
| | Llanos 86 Block (Colombia) |
| 50% (a) |
| | Llanos 87 Block (Colombia) |
| 50% (a) |
| | Llanos 104 Block (Colombia) |
| 50% (a) |
| | Llanos 123 Block (Colombia) |
| 50% (a) |
| | Llanos 124 Block (Colombia) |
| 50% (a) |
| | CPO-5 Block (Colombia) |
| 30% |
| | Mecaya Block (Colombia) |
| 50% (a) |
| | PUT-8 Block (Colombia) |
| 50% (a) |
| | PUT-9 Block (Colombia) |
| 50% (a) |
| | PUT-12 Block (Colombia) |
| 60% (a) (b) |
| | Tacacho Block (Colombia) |
| 50% (a) |
| | Terecay Block (Colombia) |
| 50% (a) |
| | Llanos 94 Block (Colombia) |
| 50% |
| | PUT-36 Block (Colombia) |
| 50% (a) |
(a) | GeoPark is the operator. |
(b) | In process of relinquishment. |
45
Note 22 Prepayments and other receivables
| | | | |
Amounts in US$ '000 |
| 2021 |
| 2020 |
V.A.T. |
| 1,711 |
| 12,083 |
Income tax payments in advance |
| 3,227 |
| 3,460 |
Other prepaid taxes |
| 996 |
| 1,995 |
To be recovered from co-venturers (Note 34) | | 4,680 | | 2,236 |
Prepayments and other receivables | | 12,184 | | 8,549 |
|
| 22,798 |
| 28,323 |
Classified as follows: |
|
|
|
|
Current |
| 22,650 |
| 27,263 |
Non-current |
| 148 |
| 1,060 |
|
| 22,798 |
| 28,323 |
Movements on the Group provision for impairment are as follows:
| | | | |
Amounts in US$ '000 |
| 2021 |
| 2020 |
At January 1 |
| 144 |
| 550 |
Foreign exchange (loss) income |
| (13) |
| (25) |
Uses |
| (124) |
| (381) |
|
| 7 |
| 144 |
Note 23 Inventories
| | | | |
Amounts in US$ '000 |
| 2021 |
| 2020 |
Crude oil |
| 5,419 |
| 7,537 |
Materials and spares |
| 5,496 |
| 5,789 |
|
| 10,915 |
| 13,326 |
Note 24 Trade receivables
| | | | |
Amounts in US$ '000 |
| 2021 |
| 2020 |
Trade receivables |
| 70,531 | | 46,918 |
|
| 70,531 |
| 46,918 |
As of December 31, 2021 and 2020, there are no balances that were aged by more than 3 months. Trade receivables that are aged by less than three months are not considered impaired.
The credit period for trade receivables is 30 days. The maximum exposure to credit risk at the reporting date is the carrying value of each class of receivable. The Group does not hold any collateral as security related to trade receivables.
The carrying value of trade receivables is considered to represent a reasonable approximation of its fair value due to their short-term nature.
46
Note 25 Financial instruments by category
| | | | |
| | Assets as per statement | ||
| | of financial position | ||
Amounts in US$ '000 |
| 2021 |
| 2020 |
Financial assets at fair value through profit or loss | | | | |
Derivative financial instrument assets |
| 126 |
| 1,013 |
Cash and cash equivalents |
| 427 |
| 823 |
|
| 553 |
| 1,836 |
Other financial assets at amortized cost |
|
|
|
|
Trade receivables |
| 70,531 |
| 46,918 |
To be recovered from co-venturers (Note 34) |
| 4,680 |
| 2,236 |
Other financial assets (a) |
| 14,747 |
| 13,392 |
Cash and cash equivalents |
| 100,177 |
| 201,084 |
|
| 190,135 |
| 263,630 |
Total financial assets |
| 190,688 |
| 265,466 |
(a) | Non-current other financial assets relate to contributions made for environmental obligations according to Brazilian government regulations. Current other financial assets correspond to short-term investments with original maturities up to twelve months and over three months. |
| | | | |
| | Liabilities as per statement | ||
| | of financial position | ||
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
Liabilities at fair value through profit and loss |
|
|
|
|
Derivative financial instrument liabilities |
| 20,757 |
| 15,094 |
|
| 20,757 |
| 15,094 |
Other financial liabilities at amortized cost |
|
|
|
|
Trade payables |
| 86,672 |
| 63,528 |
Payables to LGI (former non-controlling interest) |
| — |
| 3,528 |
To be paid to co-venturers (Note 34) |
| 953 |
| 5,760 |
Lease liabilities | | 20,744 |
| 22,347 |
Borrowings |
| 674,092 |
| 784,586 |
|
| 782,461 |
| 879,749 |
Total financial liabilities |
| 803,218 |
| 894,843 |
47
Note 25 Financial instruments by category (continued)
25.1 Credit quality of financial assets
The credit quality of financial assets that are neither past due nor impaired can be assessed by reference to external credit ratings (if available) or to historical information about counterparty default rates:
| | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
Trade receivables |
|
|
|
|
Counterparties with an external credit rating (Moody’s, S&P, Fitch) |
|
|
|
|
Aa2 | | 7,132 | | 2,321 |
Baa3 | | 24,163 | | 26,252 |
Ba2 | | — | | 3,847 |
Ba1 |
| 4,984 | | 1,333 |
B3 |
| — | | 32 |
B | | 70 | | — |
Counterparties without an external credit rating |
| | | |
Group 1 (a) |
| 34,182 | | 13,133 |
Total trade receivables |
| 70,531 |
| 46,918 |
(a) | Group 1 – existing customers (more than 6 months) with no defaults in the past. |
All trade receivables are denominated in US Dollars, except in Brazil where they are denominated in Brazilian Real.
Cash at bank and other financial assets (a)
| | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
Counterparties with an external credit rating (Moody’s, S&P, Fitch, BRC Investor Services) |
|
|
|
|
A2 |
| 53,114 |
| 122,229 |
A3 |
| 27,257 |
| 44,808 |
AAA |
| 3,529 |
| 18,119 |
Ba1 |
| 67 |
| 2,343 |
Baa1 |
| 1,605 |
| 574 |
Baa2 |
| 3,708 |
| 2,146 |
Ba3 |
| 5,117 |
| 43 |
Aa2 | | — | | 1,073 |
Ba2 | | 21 | | — |
Aa3 | | 8 | | — |
Counterparties without an external credit rating |
| 20,908 |
| 23,941 |
Total |
| 115,334 |
| 215,276 |
(a) | The remaining balance sheet item ‘cash and cash equivalents’ corresponds to cash on hand amounting to US$ 17,000 (US$ 23,000 in 2020). |
48
Note 25 Financial instruments by category (continued)
25.2 Financial liabilities- contractual undiscounted cash flows
The table below analyses the Group’s financial liabilities into relevant maturity groupings based on the remaining period at the balance sheet to the contractual maturity date. The amounts disclosed in the table are the contractual undiscounted cash flows.
| | | | | | | | |
| | Less than 1 |
| Between 1 | | Between 2 | | Over 5 |
Amounts in US$ ‘000 |
| year |
| and 2 years |
| and 5 years |
| years |
As of December 31, 2021 |
| |
| |
| |
| |
Borrowings |
| 40,943 | | 38,550 | | 263,550 | | 513,750 |
Lease liabilities |
| 9,230 | | 6,558 | | 5,820 | | 2,871 |
Trade payables | | 85,132 | | 1,540 | | — | | — |
To be paid to co-venturers (Note 34) | | 953 | | — | | — | | — |
|
| 136,258 |
| 46,648 |
| 269,370 |
| 516,621 |
As of December 31, 2020 |
|
|
|
|
|
|
|
|
Borrowings |
| 48,311 | | 49,444 | | 538,000 | | 378,875 |
Lease liabilities | | 10,890 | | 6,230 | | 5,294 | | 3,653 |
Trade payables |
| 62,408 | | 1,120 | | — | | — |
To be paid to co-venturers (Note 34) | | 1,994 | | 3,766 | | — | | — |
Payables to LGI |
| 3,528 | | — | | — | | — |
|
| 127,131 |
| 60,560 |
| 543,294 |
| 382,528 |
25.3 Fair value measurement of financial instruments
Accounting policies for financial instruments have been applied to classify as either: amortized cost, financial assets at fair value through profit or loss and fair value through other comprehensive income. For financial instruments that are measured in the statement of financial position at fair value, IFRS 13 requires a disclosure of fair value measurements by level according to the following fair value measurement hierarchy:
Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities.
Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (that is, as prices) or indirectly (that is, derived from prices).
Level 3 - Inputs for the asset or liability that are not based on observable market data (that is, unobservable inputs).
This note provides an update on the judgements and estimates made by the Group in determining the fair values of the financial instruments since the last annual financial report.
49
Note 25 Financial instruments by category (continued)
25.3 Fair value measurement of financial instruments (continued)
25.3.1 Fair value hierarchy
The following table presents the Group’s financial assets and financial liabilities measured and recognized at fair value as of December 31, 2021 and 2020 on a recurring basis:
| | | | | | |
| | |
| |
| As of December 31, |
Amounts in US$ ‘000 |
| Level 1 |
| Level 2 |
| 2021 |
Assets | |
| |
| |
|
Cash and cash equivalents |
|
|
|
|
|
|
Money market funds |
| 427 |
| — |
| 427 |
Derivative financial instrument assets |
|
|
|
|
|
|
Commodity risk management contracts | | — | | 126 | | 126 |
Total Assets |
| 427 |
| 126 |
| 553 |
Liabilities | | | | | | |
Derivative financial instrument liabilities | | | | | | |
Commodity risk management contracts | | — | | 20,757 | | 20,757 |
Total Liabilities | | — | | 20,757 | | 20,757 |
| | | | | | |
|
| |
| |
| As of December 31, |
Amounts in US$ ‘000 | | Level 1 | | Level 2 | | 2020 |
Assets | |
| |
| |
|
Cash and cash equivalents |
|
|
|
|
|
|
Money market funds |
| 823 |
| — |
| 823 |
Derivative financial instrument assets |
|
|
|
|
|
|
Commodity risk management contracts |
| — |
| 1,013 |
| 1,013 |
Total Assets |
| 823 |
| 1,013 |
| 1,836 |
Liabilities | | | | | | |
Derivative financial instrument liabilities | | | | | | |
Commodity risk management contracts | | — | | 15,094 | | 15,094 |
Total Liabilities | | — | | 15,094 | | 15,094 |
There were no transfers between Level 2 and 3 during the period.
The Group did not measure any financial assets or financial liabilities at fair value on a non-recurring basis as of December 31, 2021.
50
Note 25 Financial instruments by category (continued)
25.3 Fair value measurement of financial instruments (continued)
25.3.2 Valuation techniques used to determine fair values
Specific valuation techniques used to value financial instruments include:
● | The use of quoted market prices or dealer quotes for similar instruments. |
● | The mark-to-market fair value of the Group’s outstanding derivative instruments is based on independently provided market rates and determined using standard valuation techniques, including the impact of counterparty credit risk and are within level 2 of the fair value hierarchy. |
● | The fair value of the remaining financial instruments is determined using discounted cash flow analysis. All of the resulting fair value estimates are included in level 2. |
25.3.3 Fair values of other financial instruments (unrecognized)
The Group also has a number of financial instruments which are not measured at fair value in the balance sheet. For the majority of these instruments, the fair values are not materially different to their carrying amounts, since the interest receivable/payable is either close to current market rates or the instruments are short-term in nature.
Borrowings are comprised primarily of fixed rate debt and variable rate debt with a short-term portion where interest has already been fixed. They are classified under other financial liabilities and measured at their amortized cost.
The fair value of these financial instruments as of December 31, 2021 amounts to US$ 661,404,000 (US$ 797,126,000 in 2020). The fair values are based on market price for the Notes and cash flows discounted for other borrowings using a rate based on the borrowing rate and are within level 1 and level 2 of the fair value hierarchy, respectively.
Note 26 Equity
26.1 Share capital and Share premium
| | | | |
Issued share capital |
| 2021 |
| 2020 |
Common stock (amounts in US$ ‘000) |
| 60 |
| 61 |
The share capital is distributed as follows: |
|
|
|
|
Common shares, of nominal US$ 0.001 |
| 60,238,026 |
| 61,029,772 |
Total common shares in issue |
| 60,238,026 |
| 61,029,772 |
|
|
|
|
|
Authorized share capital |
|
|
|
|
US$ per share |
| 0.001 |
| 0.001 |
|
|
|
|
|
Number of common shares (US$ 0.001 each) |
| 5,171,949,000 |
| 5,171,949,000 |
Amount in US$ |
| 5,171,949 |
| 5,171,949 |
Details regarding the share capital of the Company are set out below.
51
Note 26 Equity (continued)
26.1 Share capital and Share premium (continued)
26.1.1 Common shares
As of December 31, 2021, the outstanding common shares confer the following rights on the holder:
● | the right to one vote per share |
● | ranking pari passu, the right to any dividend declared and payable on common shares |
| | | | | | | | |
|
| |
| Shares |
| Shares |
| |
| | | | issued | | closing | | US$(`000) |
GeoPark common shares history | | Date | | (millions) | | (millions) | | Closing |
Shares outstanding at the end of 2019 |
|
|
|
|
| 59.2 |
| 59 |
Stock awards |
| Jan 2020 |
| 1.5 | | 60.7 | | 61 |
Stock awards | | Mar 2020 | | 0.2 | | 60.9 | | 61 |
Buyback program | | Mar 2020 | | (0.3) | | 60.6 | | 61 |
Stock awards | | Nov 2020 | | 0.5 | | 61.1 | | 61 |
Buyback program |
| Nov 2020 |
| (0.1) | | 61.0 | | 61 |
Shares outstanding at the end of 2020 |
| |
|
|
| 61.0 |
| 61 |
Stock awards | | May 2021 | | 0.2 | | 61.2 | | 61 |
Buyback program | | Jun 2021 | | (0.1) | | 61.1 | | 61 |
Buyback program | | Sep 2021 | | (0.4) | | 60.7 | | 61 |
Buyback program |
| Dec 2021 |
| (0.5) | | 60.2 | | 60 |
Shares outstanding at the end of 2021 |
|
|
|
|
| 60.2 | | 60 |
26.1.2 Stock Award Program and Other Share Based Payments
Non-Executive Directors Fees
During 2021, the Company issued 64,269 (60,204 in 2020 and 29,220 in 2019) shares to Non-Executive Directors in accordance with contracts as compensation, generating a share premium of US$ 861,000 (US$ 665,000 in 2020 and US$ 499,000 in 2019). The amount of shares issued is determined considering the contractual compensation and the fair value of the shares for each relevant period.
Stock Award Program and Other Share Based Payments
On November 12, 2020, 499,614 common shares were allotted to the trustee of the Employee Beneficiary Trust (“EBT”) to be assigned to certain employees as part of their 2019 bonus compensation, generating a share capital and share premium of US$ 1,000 and US$ 4,351,000, respectively.
On January 2, 2020 and 2019 (50% each year, as set up in the plan), the vested Value Creation Plan (“VCP”) awards, representing 2,976,781 common shares, was issued to key management (including 878,150 common shares issued to Directors involved in the performance of the Company), generating a share premium of US$ 4,668,000 (50% each year).
On July 8, 2019, 1,484,847 common shares were allotted to the trustee of the EBT to be assigned to employees since the 2016 and 2018 Plans vested, generating a share premium of US$ 4,311,000.
52
Note 26 Equity (continued)
26.1 Share capital and Share premium (continued)
26.1.3 Buyback Program
On December 20, 2018, the Company’s Board of Directors approved a program to repurchase up to 10% of its shares outstanding or approximately 6,063,000 shares. The repurchase program began on December 21, 2018 and expired on December 31, 2019. During 2019, the Company purchased 4,318,320 common shares (145,917 in 2018) for a total amount of US$ 71,272,000 (US$ 1,801,000 in 2018). These transactions had no impact on the Group’s results.
On February 10, 2020, the Company’s Board of Directors approved another program to repurchase up to 10% of its shares outstanding or approximately 5,930,000 shares. The repurchase program began on February 11, 2020 and was suspended in Abril 2020 as part of the revised work program for 2020 because of the coronavirus and oil price crisis. During 2020, the Company purchased 316,445 common shares for a total amount of US$ 3,071,000. These transactions had no impact on the Group’s results.
On November 4, 2020, the Company’s Board of Directors approved a new program to repurchase up to 10% of its shares outstanding or approximately 6,062,000 shares. The repurchase program began on November 5, 2020 and was set to expire on November 15, 2021. On November 10, 2021, the Company’s Board of Directors approved the renewal of this repurchase program until November 10, 2022. During 2021, the Company purchased 960,454 common shares (101,986 in 2020) for a total amount of US$ 11,841,000 (US$ 938,000 in 2020). These transactions had no impact on the Group’s results.
26.2 Cash distributions
On November 6, 2019, the Company’s Board of Directors declared the initiation of a quarterly cash distribution of US$ 0.0413 per share. Consequently, on December 10, 2019 and April 8, 2020, US$ 2,444,000 and US$ 2,343,000 were distributed to shareholders, respectively. The quarterly cash distributions were temporary suspended from April 2020 as part of the revised work program for 2020 due to the COVID-19 pandemic and the oil price crisis.
On November 4, 2020, the Company’s Board of Directors declared an extraordinary cash distribution of US$ 0.0206 per share for 2020 and a quarterly cash distribution of US$ 0.0206 per share. Consequently, on December 9, 2020, US$ 2,516,000 were distributed to shareholders of record at the close of business on November 20, 2020.
On March 10, 2021 and May 5, 2021, the Company’s Board of Directors declared quarterly cash distributions of US$ 0.0205 per share that were paid on April 13, 2021 and May 28, 2021 for US$ 1,133,000 and US$ 1,220,000, respectively.
On August 4, 2021 and November 10, 2021, the Company’s Board of Directors declared quarterly cash distributions of US$ 0.041 per share that were paid on August 31, 2021 and December 7, 2021 for US$ 2,442,000 and US$ 2,429,000, respectively.
These distributions are deducted from Other Reserve.
26.3 Stock distribution
On February 10, 2020, the Company’s Board of Directors declared a special stock distribution of 0.004 shares per share. Consequently, on March 11, 2020, 242,650 common shares were distributed to the shareholders of record at the close of business on February 25, 2020.
53
Note 27 Borrowings
| | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
Outstanding amounts as of December 31 |
|
|
|
|
2024 Notes (a) (c) |
| 171,880 |
| 428,737 |
2027 Notes (b) (c) | | 499,893 | | 352,113 |
Banco Santander (d) | | 2,319 | | 3,736 |
|
| 674,092 |
| 784,586 |
Classified as follows: |
|
|
|
|
Current |
| 17,916 |
| 17,689 |
Non-current |
| 656,176 |
| 766,897 |
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.
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 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, the Company reduced its total indebtedness nominal amount by US$ 105,000,000 and improved its financial profile by extending its debt maturities. The current outstanding nominal amount of the 2024 Notes and 2027 Notes is US$ 170,000,000 and US$ 500,000,000, respectively. The Company recorded a loss of US$ 6,308,000 within Financial expenses for the year ended December 31, 2021 as a consequence of these transactions.
54
Note 27 Borrowings (continued)
The indentures governing the 2024 Notes and the 2027 Notes include incurrence test covenants that provide among other things, that, the Net Debt to Adjusted EBITDA ratio should not exceed 3.25 times and the Adjusted EBITDA to Interest ratio should exceed 2.5 times. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit the Company’s capacity to incur additional indebtedness, as specified in the indentures governing the Notes. Incurrence covenants as opposed to maintenance covenants must be tested by the Company before incurring additional debt or performing certain corporate actions including but not limited to dividend payments, restricted payments and others. As of the date of these Consolidated Financial Statements, the Company is in compliance of all the indentures’ provisions and covenants.
In September 2020, GeoPark Brasil Exploração y Produção de Petróleo e Gás Ltda. executed the refinancing of the outstanding principal with Banco Santander for a total amount of Brazilian Real 19,410,000 (equivalent to US$ 3,441,000 at the moment of the refinancing execution). The interest rate is CDI plus 3.55% per annum. Interests are paid on a monthly basis, and principal will be paid semi-annually in three equal instalments in October 2021, April 2022 and October 2022.
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 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 the IBR index (interest rate of reference for short-term loans in Colombia) plus 1.6% per annum, the original maturity was on May 14, 2022 and interests were payable monthly. In August 2021, GeoPark optionally prepaid the full amount of the loan, with no additional cost.
In July 2021, GeoPark Colombia S.A.S. executed a loan agreement with Itau Bank for Colombian Pesos 37,653,000,000 (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 US$ 143,255,000.
55
Note 28 Leases
The Consolidated Statement of Financial Position shows the following amounts relating to leases:
| | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
Right of use assets |
|
|
|
|
Production, facilities and machinery |
| 15,175 |
| 14,806 |
Buildings and improvements | | 5,839 | | 6,596 |
|
| 21,014 |
| 21,402 |
Lease liabilities |
|
|
|
|
Current |
| 8,231 |
| 10,890 |
Non-current |
| 12,513 |
| 11,457 |
| | 20,744 | | 22,347 |
The Consolidated Statement of Income shows the following amounts relating to leases:
| | | | | | |
Amounts in US$ ‘000 |
| 2021 | | 2020 | | 2019 |
Depreciation charge of Right of use assets |
|
| |
| |
|
Production, facilities and machinery |
| (5,526) | | (6,472) | | (1,834) |
Buildings and improvements | | (1,136) | | (1,600) | | (1,810) |
|
| (6,662) | | (8,072) | | (3,644) |
Unwinding of long-term liabilities (included in Financial results) |
| (1,453) | | (1,247) | | (419) |
Expenses related to short-term leases (included in Production and operating cost and Administrative expenses) | | (1,101) | | (1,317) | | (13,463) |
Expenses related to low-value leases (included in Administrative expenses) |
| (906) | | (736) | | (314) |
The table below summarizes the amounts of Right-of-use assets recognised and the movements during the reporting years:
| | | | |
Amounts in US$‘000 |
| 2021 |
| 2020 |
Right-of-use assets as of January 1 | | 21,402 | | 13,462 |
Additions / changes in estimates | | 5,288 | | 561 |
Acquisitions (Note 36.1) | | — | | 16,674 |
Foreign currency translation | | 986 | | (1,223) |
Depreciation | | (6,662) | | (8,072) |
Right-of-use assets as of December 31 | | 21,014 | | 21,402 |
The table below summarizes the amounts of Lease liabilities recognised and the movements during the reporting years:
| | | | |
Amounts in US$‘000 |
| 2021 |
| 2020 |
Lease liabilities as of January 1 | | 22,347 | | 13,243 |
Additions / changes in estimates | | 5,288 | | 561 |
Acquisitions (Note 36.1) | | — | | 17,851 |
Exchange difference | | (365) | | 466 |
Foreign currency translation | | (461) | | (1,641) |
Unwinding of discount | | 1,453 | | 1,247 |
Lease payments | | (7,518) | | (9,380) |
Lease liabilities as of December 31 | | 20,744 | | 22,347 |
56
Note 29 Provisions and other long-term liabilities
| | | | | | | | |
|
| Asset retirement |
| Deferred |
| |
| |
Amounts in US$ ‘000 | | obligation | | Income | | Other | | Total |
As of January 1, 2020 |
| 56,113 |
| 2,267 |
| 3,682 |
| 62,062 |
Addition to provision / changes in estimates |
| (1,812) | | (258) | | 1,904 |
| (166) |
Acquisitions (Note 36.1) | | 5,629 | | 2,339 | | 8,551 | | 16,519 |
Exchange difference | | 2,215 | | (93) | | 133 | | 2,255 |
Foreign currency translation | | (2,057) | | — | | — | | (2,057) |
Amortization |
| — | | (387) | | — |
| (387) |
Unwinding of discount |
| 4,276 | | — | | 371 |
| 4,647 |
Amounts used during the year | | (272) | | (40) | | (139) | | (451) |
Liabilities associated with assets held for sale | | (52) | | — | | — |
| (52) |
As of December 31, 2020 |
| 64,040 |
| 3,828 |
| 14,502 |
| 82,370 |
Addition to provision / changes in estimates |
| (651) | | (46) | | 59 |
| (638) |
Acquisitions (Note 36.1) | | — | | — | | — | | — |
Exchange difference |
| (668) | | (228) | | (1,079) | | (1,975) |
Foreign currency translation |
| (651) | | — | | (2) | | (653) |
Amortization | | — | | (223) | | — |
| (223) |
Unwinding of discount |
| 3,140 | | — | | 486 |
| 3,626 |
Amounts used during the year |
| (170) | | — | | (291) | | (461) |
Liabilities associated with assets held for sale | | (19,198) | | — | | — |
| (19,198) |
As of December 31, 2021 |
| 45,842 |
| 3,331 |
| 13,675 |
| 62,848 |
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 relating to the purchase of property, plant and equipment in Colombia. The amortization is in line with the related assets.
57
Note 29 Provisions and other long-term liabilities (continued)
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 claim states that the Claimants seek compensation for economic and non-economic damages said to be caused by alleged environmental contamination and pollution caused by Amerisur’s operations in Colombia. Amerisur stated that the accusations of environmental damage referenced in the claim are being investigated by Colombian authorities and to-date have been deemed to be without merit. Amerisur further stated that it viewed the substance of the claim to be without merit. Following court hearings held in January and February 2020, an interim freezing order was imposed on Amerisur in respect to GBP 4,465,600 (equivalent to US$ 6,022,000 as of December 31, 2021) of its assets located in the United Kingdom. On November 10, 2020, the freezing order was discharged by agreement between the parties as Amerisur provided alternative security in the form of a Letter of Credit from an UK Bank. On January 12, 2021 a hearing was held, where the Court ordered the Claimants to serve the Group Particulars of Claim (GPoC) by February 26, 2021. Amerisur served its defence to the GPoC on May 21, 2021. A Case Management Conference was held on July 7, 2021, where the Court ordered: i) to schedule a limited trial, relating to 2 preliminary Colombian law issues, namely, limitation and parent company liability; and ii) to schedule a Costs Management Conference. The Costs Management Conference was held on October 26, 2021 before the Court. The Court ruled that: i) Amerisur’s costs of the general pollution claims are enforceable against the Claimants only after the conclusion of the proceedings and those costs have been either assessed or agreed; and, ii) Amerisur’s application for an interim payment in respect of those costs and for security for costs were dismissed. As of the date of these Consolidated Financial Statements, the process is ongoing.
Note 30 Trade and other payables
| | | | |
Amounts in US$ ‘000 |
| 2021 |
| 2020 |
V.A.T |
| 7,473 |
| 3,453 |
Trade payables |
| 86,672 |
| 63,528 |
Payables to LGI (former non-controlling interest) |
| — |
| 3,528 |
Customer advance payments | | 426 | | — |
Other short-term advance payments (a) | | 1,558 | | — |
Staff costs to be paid |
| 17,973 |
| 13,752 |
Royalties to be paid |
| 7,347 |
| 5,287 |
Taxes and other debts to be paid |
| 6,651 |
| 9,734 |
To be paid to co-venturers (Note 34) |
| 953 |
| 5,760 |
|
| 129,053 |
| 105,042 |
Classified as follows: |
|
|
|
|
Current |
| 127,513 |
| 100,156 |
Non-current |
| 1,540 |
| 4,886 |
(a) | Advance payment collected in relation with the sale of the Aguada Baguales, El Porvenir and Puesto Touquet Blocks (see Note 36.3.1). |
The average credit period (expressed as creditor days) during the year ended December 31, 2021 was 89 days (2020: 110 days).
The fair value of these short-term financial instruments is not individually determined as the carrying amount is a reasonable approximation of fair value.
58
Note 31 Share-based payment
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.
In November 2019, the Group approved a share-based compensation program for approximately 800,000 shares to be granted in 2020. The main characteristics of the Stock Awards Programs are:
● | Employees not included in the VCP and new hiring are eligible. |
● | Exercise price is equal to the nominal value of shares. |
● | Vesting date: January 2, 2023. |
● | Each employee could receive between three and six salaries (to be pro-rated between the hiring date and the vesting date for new hiring) by achieving the following conditions: continue to be an employee, the stock market price at the date of vesting should be higher than the share price at the date of grant and obtain the Group minimum production, adjusted EBITDA and reserves target for the year of vesting. |
During 2019, the Group approved a plan named Value Creation Plan (“VCP”) oriented to key Management. The main characteristics of the VCP are:
● | Awards payables in a variable number of shares which shall not exceed the quantity of 3,024,172 shares. |
● | Subject to certain market conditions, among others, reaching a stock market price for the Company shares of above US$ 19.42 at vesting date. |
● | Vesting date: December 31, 2021 and 2022 (50% each year). |
VCP has been classified as an equity-settled plan. 20% of this plan was awarded to Directors involved in the performance of the Company. As of December 31, 2021, the conditions were 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:
| | | | | | | | | | | | | | | | |
| | Awards at the | | Awards granted | | Awards | | Awards | | Awards at | | Charged to net loss / profit | ||||
Year of issuance |
| beginning |
| in the year |
| forfeited |
| exercised |
| year end |
| 2021 |
| 2020 |
| 2019 |
2020 | | 405,125 |
| 97,277 | | (88,337) | | — |
| 414,065 |
| 862 | | 1,274 | | — |
2018 (a) | | — |
| — | | — | | — |
| — |
| — | | — | | 416 |
2016 (b) |
| — |
| — | | — | | — |
| — |
| — |
| — |
| 50 |
Subtotal |
| 405,125 |
| 97,277 |
| (88,337) |
| — |
| 414,065 |
| 862 |
| 1,274 |
| 466 |
Shares granted to Non-Executive Directors |
| — |
| 64,269 | | — | | (64,269) |
| — |
| 861 |
| 665 |
| 500 |
Executive Directors Bonus |
| 156,497 |
| 118,272 | | — | | (104,439) |
| 170,330 |
| 800 |
| 800 |
| 800 |
VCP 2019 |
| 378,053 |
| — | | (378,053) | | — |
| — |
| 4,098 |
| 5,705 |
| 951 |
|
| 939,675 |
| 279,818 |
| (466,390) |
| (168,708) |
| 584,395 |
| 6,621 |
| 8,444 |
| 2,717 |
(a) | The vesting date of the program was June 30, 2019. A total of 131,330 shares were issued, considering the vesting conditions. |
(b) | The vesting date of the program was June 30, 2019. A total of 1,353,517 shares were issued, considering the vesting conditions. |
The awards that are forfeited correspond to employees that had left the Group before vesting date.
59
Note 32 Interests in Joint operations
The Group has interests in joint operations, which are engaged in the exploration of hydrocarbons in Colombia, Chile, Brazil, Argentina and Ecuador.
GeoPark is the operator in the Llanos 34, Llanos 32, Llanos 86, Llanos 87 and Llanos 104 Blocks in Colombia, in the Flamenco, Campanario and Isla Norte Blocks in Chile, in the POT-T-747 and REC-T-128 Blocks in Brazil, and in the Espejo Block in Ecuador.
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:
| | | | | | | | | | | | | | | | |
Subsidiary / |
| |
| |
| Other |
| Total |
| Total |
| Net Assets/ |
| |
| Operating |
Joint operation | | Interest | | PP&E | | Assets | | Assets | | Liabilities | | (Liabilities) | | Revenue | | profit (loss) |
2021 | | | | | | | | | | | | | | | | |
GeoPark Colombia S.A.S. | | | | | | | | | | | | | | | | |
Llanos 34 Block |
| 45 | % | 260,589 | | 1,866 | | 262,455 | | (5,573) |
| 256,882 |
| 486,779 | | 341,473 |
Llanos 32 Block |
| 12.5 | % | 2,730 | | — | | 2,730 | | (197) |
| 2,533 |
| 7,690 | | 5,378 |
Llanos 86 Block | | 50 | % | 408 | | — | | 408 | | — | | 408 | | — | | (60) |
Llanos 87 Block | | 50 | % | 1,220 | | — | | 1,220 | | — | | 1,220 | | — | | (60) |
Llanos 94 Block | | 50 | % | 1,489 | | — | | 1,489 | | (270) | | 1,219 | | — | | (171) |
Llanos 104 Block | | 50 | % | 434 | | — | | 434 | | — | | 434 | | — | | (60) |
Llanos 123 Block | | 50 | % | 907 | | — | | 907 | | — | | 907 | | — | | (60) |
Llanos 124 Block | | 50 | % | 841 | | — | | 841 | | — | | 841 | | — | | (60) |
CPO-5 Block | | 30 | % | 210,154 | | — | | 210,154 | | (929) | | 209,225 | | 88,479 | | 55,131 |
Amerisur Exploración Colombia Limitada Sucursal Colombia | | | | | | | | | | | | | | | | |
Mecaya Block | | 50 | % | 3,837 | | — | | 3,837 | | (84) | | 3,753 | | — | | — |
PUT-8 Block | | 50 | % | 7,070 | | — | | 7,070 | | — | | 7,070 | | — | | — |
PUT-9 Block | | 50 | % | 4,342 | | — | | 4,342 | | — | | 4,342 | | — | | — |
PUT-36 Block | | 50 | % | 2,870 | | — | | 2,870 | | — | | 2,870 | | — | | — |
Tacacho Block | | 50 | % | 3,629 | | — | | 3,629 | | — | | 3,629 | | — | | — |
Terecay Block | | 50 | % | 226 | | — | | 226 | | — | | 226 | | — | | — |
GeoPark TdF S.p.A. |
| |
| | | | | | | |
|
|
| | | |
Flamenco Block |
| 50 | % | — | | — | | — | | (2,082) |
| (2,082) |
| — | | (137) |
Campanario Block |
| 50 | % | — | | — | | — | | (551) |
| (551) |
| — | | (106) |
Isla Norte Block |
| 60 | % | — | | — | | — | | (138) |
| (138) |
| — | | (122) |
GeoPark Brasil Exploração y Produção de Petróleo e Gas Ltda. |
| |
| | | | | | | |
|
|
| | | |
Manati Field |
| 10 | % | 6,851 | | 18,269 | | 25,120 | | (13,657) |
| 11,463 |
| 20,109 | | 9,899 |
POT-T‑785 | | 70 | % | 157 | | — | | 157 | | — | | 157 | | — | | — |
GeoPark Argentina S.A.U. |
| |
| | | | | | | |
|
|
| | | |
CN-V Block |
| 50 | % | — | | 149 | | 149 | | (528) |
| (379) |
| — | | (839) |
Los Parlamentos Block | | 50 | % | — | | — | | — | | — |
| — |
| — | | (285) |
Puelen Block |
| 18 | % | — | | 12 | | 12 | | (18) |
| (6) |
| — | | (55) |
Sierra del Nevado Block |
| 18 | % | — | | 1 | | 1 | | (5) |
| (4) |
| — | | (10) |
GeoPark Perú S.A.C. - Sucursal Ecuador | | | | | | | | | | | | | | | | |
Espejo | | 50 | % | 1,132 | | 78 | | 1,210 | | (610) | | 600 | | — | | (589) |
Perico | | 50 | % | 4,658 | | 1,449 | | 6,107 | | (4,535) | | 1,572 | | — | | (669) |
60
Note 32 Interests in Joint operations (continued)
| | | | | | | | | | | | | | | | |
Subsidiary / |
| |
| |
| Other |
| Total |
| Total |
| Net Assets/ |
| |
| Operating |
Joint operation | | Interest | | PP&E | | Assets | | Assets | | Liabilities | | (Liabilities) | | Revenue | | profit (loss) |
2020 | | | | | | | | | | | | | | | | |
GeoPark Colombia S.A.S. | | | | | | | | | | | | | | | | |
Llanos 34 Block |
| 45 | % | 212,914 | | 2,834 | | 215,748 | | (6,829) |
| 208,919 |
| 273,077 | | 203,386 |
Llanos 32 Block |
| 12.5 | % | 1,484 | | — | | 1,484 | | (273) |
| 1,211 |
| 5,885 | | 4,248 |
Llanos 86 Block | | 50 | % | 137 | | — | | 137 | | — | | 137 | | — | | — |
Llanos 87 Block | | 50 | % | 333 | | — | | 333 | | — | | 333 | | — | | — |
Llanos 94 Block | | 50 | % | 42 | | — | | 42 | | (68) | | (26) | | — | | — |
Llanos 104 Block | | 50 | % | 145 | | — | | 145 | | — | | 145 | | — | | — |
Llanos 123 Block | | 50 | % | 248 | | — | | 248 | | — | | 248 | | — | | — |
Llanos 124 Block | | 50 | % | 240 | | — | | 240 | | — | | 240 | | — | | — |
Petrodorado South America S.A. Sucursal Colombia | | | | | | | | | | | | | | | | |
CPO-5 Block | | 30 | % | 218,298 | | — | | 218,298 | | (455) | | 217,843 | | 29,552 | | 14,398 |
Amerisur Exploración Colombia Limitada Sucursal Colombia | | | | | | | | | | | | | | | | |
Mecaya Block | | 50 | % | 1,301 | | — | | 1,301 | | (128) | | 1,173 | | — | | — |
PUT-8 Block | | 50 | % | 2,334 | | — | | 2,334 | | — | | 2,334 | | — | | — |
PUT-9 Block | | 50 | % | 924 | | — | | 924 | | — | | 924 | | — | | — |
PUT-12 Block | | 60 | % | 610 | | — | | 610 | | — | | 610 | | — | | — |
PUT-36 Block | | 50 | % | 31 | | — | | 31 | | — | | 31 | | — | | — |
Tacacho Block | | 50 | % | 3,591 | | — | | 3,591 | | — | | 3,591 | | — | | — |
Terecay Block | | 50 | % | 173 | | — | | 173 | | — | | 173 | | — | | — |
GeoPark TdF S.p.A. |
| |
| | | | | | | |
|
|
| | | |
Flamenco Block |
| 50 | % | — | | — | | — | | (1,577) |
| (1,577) |
| — | | (7,532) |
Campanario Block |
| 50 | % | — | | — | | — | | (372) |
| (372) |
| — | | (16,913) |
Isla Norte Block |
| 60 | % | — | | — | | — | | (132) |
| (132) |
| — | | (9,418) |
GeoPark Brasil Exploração y Produção de Petróleo e Gas Ltda. |
| |
| | | | | | | |
|
|
| | | |
Manati Field |
| 10 | % | 13,280 | | 15,557 | | 28,837 | | (11,515) |
| 17,322 |
| 12,286 | | 3,339 |
REC-T‑128 |
| 70 | % | — | | 1,152 | | 1,152 | | (52) |
| 1,100 |
| 497 | | (72) |
POT-T‑785 | | 70 | % | 79 | | — | | 79 | | — | | 79 | | — | | — |
GeoPark Argentina S.A.U. |
| |
| | | | | | | |
|
|
| | | |
CN-V Block |
| 50 | % | — | | 107 | | 107 | | (164) |
| (57) |
| — | | (289) |
Los Parlamentos Block | | 50 | % | — | | — | | — | | — |
| — |
| — | | (244) |
Puelen Block |
| 18 | % | — | | 20 | | 20 | | (106) |
| (86) |
| — | | (156) |
Sierra del Nevado Block |
| 18 | % | — | | 7 | | 7 | | (6) |
| 1 |
| — | | (13) |
GeoPark Perú S.A.C. |
| |
| | | | | | | |
|
|
| | | |
Morona |
| 75 | % | 3,651 | | 607 | | 4,258 | | (6,622) |
| (2,364) |
| — | | (36,980) |
GeoPark Perú S.A.C. - Sucursal Ecuador | | | | | | | | | | | | | | | | |
Espejo | | 50 | % | 409 | | 29 | | 438 | | (131) | | 307 | | — | | (464) |
Perico | | 50 | % | 397 | | 52 | | 449 | | (229) | | 220 | | — | | (543) |
61
Note 32 Interests in Joint operations (continued)
| | | | | | | | | | | | | | | | |
Subsidiary / |
| |
| |
| Other |
| Total |
| Total |
| Net Assets/ |
| |
| Operating |
Joint operation | | Interest | | PP&E | | Assets | | Assets | | Liabilities | | (Liabilities) | | Revenue | | profit (loss) |
2019 | | | | | | | | | | | | | | | | |
GeoPark Colombia S.A.S. | | | | | | | | | | | | | | | | |
Llanos 34 Block |
| 45 | % | 208,156 | | 3,128 | | 211,284 | | (6,267) |
| 205,017 |
| 513,378 | | 398,953 |
Llanos 32 Block |
| 12.5 | % | 1,136 | | — | | 1,136 | | (519) |
| 617 |
| 6,053 | | 2,791 |
Llanos 86 Block | | 50 | % | 21 | | — | | 21 | | — | | 21 | | — | | — |
Llanos 87 Block | | 50 | % | 40 | | — | | 40 | | — | | 40 | | — | | — |
Llanos 104 Block | | 50 | % | 26 | | — | | 26 | | — | | 26 | | — | | — |
GeoPark TdF S.p.A. |
| |
| | | | | | | |
|
|
| | | |
Flamenco Block |
| 50 | % | 4,623 | | — | | 4,623 | | (1,382) |
| 3,241 |
| — | | (313) |
Campanario Block |
| 50 | % | 16,445 | | — | | 16,445 | | (331) |
| 16,114 |
| — | | (156) |
Isla Norte Block |
| 60 | % | 8,896 | | — | | 8,896 | | (101) |
| 8,795 |
| — | | (189) |
GeoPark Brasil Exploração y Produção de Petróleo e Gas Ltda. |
| |
| | | | | | | |
|
|
| | | |
Manati Field |
| 10 | % | 18,537 | | 18,066 | | 36,603 | | (15,980) |
| 20,623 |
| 22,375 | | 9,263 |
POT-T‑747 |
| 70 | % | — | | — | | — | | — |
| — |
| — | | (1,516) |
REC-T‑128 |
| 70 | % | 3,886 | | 919 | | 4,805 | | (143) |
| 4,662 |
| 674 | | 57 |
POT-T‑785 | | 70 | % | 125 | | — | | 125 | | — | | 125 | | — | | — |
GeoPark Argentina S.A.U. |
| |
| | | | | | | |
|
|
| | | |
CN-V Block |
| 50 | % | — | | 274 | | 274 | | (237) |
| 37 |
| — | | (15,451) |
Puelen Block |
| 18 | % | — | | 47 | | 47 | | (41) |
| 6 |
| — | | (1,959) |
Sierra del Nevado Block |
| 18 | % | — | | 63 | | 63 | | (79) |
| (16) |
| — | | (1,705) |
GeoPark Perú S.A.C. |
| |
| | | | | | | |
|
|
| | | |
Morona |
| 75 | % | 8,921 | | 6,862 | | 15,783 | | (10,161) |
| 5,622 |
| — | | (4,976) |
GeoPark Perú S.A.C. - Sucursal Ecuador | | | | | | | | | | | | | | | | |
Espejo | | 50 | % | 199 | | 321 | | 520 | | (610) | | (90) | | — | | (272) |
Perico | | 50 | % | 304 | | 61 | | 365 | | (541) | | (176) | | — | | (176) |
Capital commitments are disclosed in Note 33.2.
Note 33 Commitments
33.1 Royalty commitments
In Colombia, royalties on production are payable to the Colombian Government and are determined on a field-by-field basis using the level of production sliding scale detailed below:
| | |
Average daily production in barrels |
| Production Royalty rate |
Up to 5,000 |
| 8% |
5,000 to 125,000 |
| 8% + (production - 5,000) * 0.1 |
125,000 to 400,000 |
| 20% |
400,000 to 600,000 |
| 20% + (production - 400,000) * 0.025 |
Greater than 600,000 |
| 25% |
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.
According to each E&P Contract, the Colombian National Hydrocarbons Agency (“ANH”) also has an additional economic right, offered by the operator at the moment of the ANH bid. This additional economic right, which is based on the production of the block after royalty discount, is equal to 1% in the Llanos 34 and Llanos 32 Blocks, 23% in the CPO-5 Block and 0% in the Platanillo Block.
When the accumulated production of each field, including the royalties’ volume, exceeds 5,000,000 of barrels and the WTI price exceeds certain price level previously determined, the Group should also deliver to ANH a share of the production net of royalties in accordance with a formula defined in each E&P Contract, which basically depends on the WTI price and the crude quality.
62
Note 33 Commitments (continued)
33.1 Royalty commitments (continued)
Additionally, GeoPark is obligated to pay an overriding royalty of 4% and 2.5%, respectively, to the previous owners of the Llanos 34 and CPO-5 Blocks, based on the production and sale of hydrocarbons discovered in the blocks. During 2021, the Group has accrued US$ 22,562,077 (US$ 14,018,000 in 2020 and US$ 24,700,000 in 2019) in relation with these overriding royalty agreements. Furthermore, there are overriding royalty agreements in place from 1.2% to 8.5% of the net production in the Andaquies, Coati, Mecaya, PUT-8, PUT-9, Tacacho and 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.
During 2021, the Group incurred investments of US$ 20,172,000 to fulfil its commitments, at GeoPark’s working interest.
33.2.1 Colombia
The future investment commitments assumed by GeoPark, at its working interest, are up to:
● | Llanos 34 Block: 3 exploratory wells (US$ 17,381,000) before November 10, 2021. Pursuant to a private agreement with the partner in the block, the investment commitment incurred by GeoPark amounts to US$ 12,840,000. As of the date of these Consolidated Financial Statements, GeoPark has already drilled the three exploratory wells and is waiting for ANH’s approval to fulfill the investment commitment. |
● | Llanos 32 Block: 5 exploratory wells before February 20, 2022. Pursuant to a private agreement with the partner in the block, the investment commitment incurred by GeoPark amounts to US$ 9,225,000. As of the date of these Consolidated Financial Statements, the five exploratory wells have already been drilled and ANH approval of the fulfillment of the investment commitment is pending. |
● | Llanos 87 Block: 3D seismic reprocessing, aerogeophysic and 4 exploratory wells (US$ 13,150,000) before January 18, 2023. |
● | Llanos 94 Block: 3D seismic acquisition and reprocessing and 3 exploratory wells (US$ 10,901,000) before October 1, 2023. |
● | Llanos 123 Block: 3D seismic reprocessing, geochemistry and 2 exploratory wells (US$ 6,777,000) before January 14, 2024. |
63
Note 33 Commitments (continued)
33.2 Capital commitments (continued)
33.2.1 Colombia (continued)
● | Llanos 124 Block: 3D seismic acquisition and reprocessing, geochemistry and 3 exploratory wells (US$ 10,031,000) before January 14, 2024. |
● | CPO-5 Block: 3D seismic acquisition, processing and interpretation and 1 exploratory well (US$ 2,794,000) before July 8, 2024. Pursuant to a private agreement with the partner in the block, the investment commitment to be incurred by GeoPark amounts to US$ 9,313,000. |
● | Coati Block: 3D seismic and 2D seismic acquisition (US$ 4,500,000). The exploratory period is currently suspended. |
● | Mecaya Block: 3D seismic or 1 exploratory well (US$ 2,000,000). The exploratory period is currently suspended. Pursuant to a private agreement with the partner in the block, the investment commitment to be incurred by GeoPark amounts to US$ 600,000. |
● | Platanillo Block: 2 exploratory wells (US$ 10,894,000) before February 2, 2022. |
● | PUT-8 Block: 3D seismic acquisition and reprocessing and 3 exploratory wells (US$ 13,107,000) before July 5, 2023. Part of the 3D seismic committed in the block has already been acquired during 2020 and 2021. |
● | PUT-9 Block: 3D seismic acquisition and 2 exploratory wells (US$ 10,550,000). GeoPark has signed a private agreement with the other partner in the block resulting in the total investment commitment to be incurred by GeoPark amounting to US$ 4,365,000. The exploratory period is currently suspended. |
● | PUT-12 Block: 2D seismic acquisition, reprocessing and interpretation, geochemistry and 1 exploratory well (US$ 14,347,000). On February 23, 2021, GeoPark filed a termination request before the ANH due to force majeure that restricts the possibility to fulfill the exploratory commitments in the block. |
● | Tacacho Block: 2D seismic acquisition, processing and interpretation (US$ 4,080,000). GeoPark has signed a private agreement with the other partner in the block resulting in the total investment commitment to be incurred by GeoPark amounting to US$ 1,224,000. The exploratory period is currently suspended. |
● | Terecay Block: 2D seismic acquisition, processing and interpretation (US$ 4,046,000). GeoPark has signed a private agreement with the other partner in the block resulting in the total investment commitment to be incurred by GeoPark amounting to US$ 2,856,000. The exploratory period is currently suspended. |
● | The Llanos 86, Llanos 104, PUT-14 and PUT-36 Blocks are in a Preliminary Phase as of the date of these Consolidated Financial Statements. During this Preliminary Phase, GeoPark must request from the Ministry of Interior a certificate that indicates presence or no presence of indigenous communities and develop previous consultation, 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 are mandatory. The investment commitments for the blocks over three-years term of Phase 1 would be the following: |
- | Llanos 86 Block: 3D seismic, 2D seismic reprocessing and 1 exploratory well (US$ 9,479,000) |
- | Llanos 104 Block: 3D seismic, 2D seismic reprocessing and 1 exploratory well (US$ 8,424,000) |
- | PUT-14 Block: 2D seismic acquisition and 1 exploratory well (US$ 16,122,000) |
- | PUT-36 Block: 3D seismic acquisition and 2 exploratory wells (US$ 11,301,000) |
64
Note 33 Commitments (continued)
33.2 Capital commitments (continued)
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:
● | Campanario Block: 2 exploratory wells before April 20, 2023 (US$ 5,002,000) |
● | Isla Norte Block: 1 exploratory well before February 19, 2023 (US$ 867,000) |
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:
● | POT-T-785 Block: 3D seismic and electromagnetic survey before January 29, 2023 (US$ 70,000). |
● | REC-T-58 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 140,000). |
● | REC-T-67 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 140,000). |
● | REC-T-77 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 140,000). |
● | POT-T-834 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 140,000) |
33.2.4 Argentina
The investment commitment in the Los Parlamentos Block (50% working interest) for the first exploratory period, ending on October 30, 2022, which includes 1 exploratory wells and 3D seismic, amounts to US$ 6,000,000, at GeoPark’s working interest.
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:
● | Espejo Block: 3D seismic and 4 exploratory wells before June 17, 2025 (US$ 20,912,000). |
● | Perico Block: 4 exploratory wells before June 16, 2025 (US$ 18,084,000). |
65
Note 34 Related parties
Controlling interest
The main shareholders of GeoPark Limited, a company registered in Bermuda, as of December 31, 2021, are:
| | | | | |
|
| Common |
| Percentage of outstanding |
|
Shareholder | | shares | | common shares |
|
James F. Park (a) |
| 8,414,255 |
| 13.97 | % |
Compass Group LLC (b) |
| 6,102,239 |
| 10.13 | % |
Gerald E. O’Shaughnessy (c) |
| 6,043,163 |
| 10.03 | % |
Renaissance Technologies LLC (d) |
| 3,538,931 |
| 5.87 | % |
Other shareholders |
| 36,139,438 |
| 59.99 | % |
|
| 60,238,026 |
| 100.00 | % |
(a) | Held by James F. Park directly and indirectly through GoodRock, LLC, which is controlled by Mr. Park. The information set forth above and listed in the table is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC on February 14, 2022. 602,400 of Mr. Park’s shares have been pledged pursuant to lending arrangements. |
(b) | The information set forth above and listed in the table is based solely on the disclosure set forth in Compass Group LLC’s most recent Schedule 13G filed with the SEC on February 14, 2022. |
(c) | Held by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP; GPK Holdings, LLC; The Globe Resources Group, Inc.; and other investment vehicles. |
(d) | The information set forth above and listed in the table is based solely on the disclosure set forth in Renaissance’s most recent Schedule 13G filed with the SEC on February 11, 2022. |
Balances outstanding and transactions with related parties
| | | | | | | | |
|
| |
| Balances |
| |
| |
| | Transaction | | at year | | | | |
Account (Amounts in US$´000) | | in the year | | end | | Related Party | | Relationship |
2021 | | | | | | | | |
To be recovered from co-venturers |
| — | | 4,680 |
| Joint Operations |
| Joint Operations |
To be paid to co-venturers |
| — | | (953) |
| Joint Operations |
| Joint Operations |
Geological and geophysical expenses |
| 160 | | — |
| Carlos Gulisano |
| Non-Executive Director (a) |
Administrative expenses |
| 656 | | — |
| Pedro E. Aylwin |
| Executive Director (b) |
2020 |
|
|
|
|
|
|
|
|
To be recovered from co-venturers |
| — | | 2,236 |
| Joint Operations |
| Joint Operations |
To be paid to co-venturers |
| — | | (5,760) |
| Joint Operations |
| Joint Operations |
Geological and geophysical expenses |
| 130 | | — |
| Carlos Gulisano |
| Non-Executive Director (a) |
Administrative expenses |
| 561 | | — |
| Pedro E. Aylwin |
| Executive Director (b) |
2019 |
|
|
|
|
|
|
|
|
To be recovered from co-venturers |
| — | | 1,035 |
| Joint Operations |
| Joint Operations |
To be paid to co-venturers |
| — | | (4,803) |
| Joint Operations |
| Joint Operations |
Geological and geophysical expenses |
| 160 | | — |
| Carlos Gulisano |
| Non-Executive Director (a) |
Administrative expenses |
| 581 | | — |
| Pedro E. Aylwin |
| Executive Director (b) |
(a) | Corresponding to consultancy services. |
(b) | Corresponding to wages and salaries for US$ 392,000 (US$ 336,000 in 2020 and US$ 390,000 in 2019) and bonus for US$ 230,000 (US$ 225,000 in 2020 and US$ 191,000 in 2019). During 2021, Aylwin, Mendoza, Luksic & Valencia Law firm, where Pedro Aylwin is a partner and has a participation through Asesorías e Inversiones A&P Ltda, received US$ 34,000 for general legal services to all the Chilean entities, in Chilean corporate, labor, environmental, regulatory, and commercial laws. |
66
Note 34 Related parties (continued)
Balances outstanding and transactions with related parties (continued)
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
| | | | | | |
Amounts in US$‘000 |
| 2021 |
| 2020 |
| 2019 |
Audit fees |
| 1,023 |
| 926 |
| 763 |
Audit related fees |
| 65 |
| — |
| 510 |
Tax services fees |
| 47 |
| 35 |
| 165 |
Non-audit services fees |
| — |
| — |
| 5 |
Total Auditors Fees |
| 1,135 |
| 961 |
| 1,443 |
Fees are shown net of VAT and other associated tax charges.
Non-audit services fees relate to consultancy and other services.
Note 36 Business transactions
36.1 Acquisition of Amerisur Resources Plc
On January 16, 2020, GeoPark acquired the 100% share capital of Amerisur Resources Plc, a company listed on the Alternative Investment Market (“AIM”) of the London Stock Exchange. After the acquisition, the company was delisted and its name changed to Amerisur Resources Limited. The principal activities of Amerisur Resources Limited and its subsidiaries (“Amerisur”) are exploration, development and production for oil and gas reserves in Latin America. Amerisur owns thirteen production, development and exploration blocks in Colombia (twelve operated blocks in the Putumayo basin and one non-operated block in the Llanos basin) and an export oil pipeline from Colombia to Ecuador named Oleoducto Binacional Amerisur (“OBA”).
GeoPark paid a cash consideration of US$ 314,163,077 at the 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.
67
Note 36 Business transactions (continued)
36.1 Acquisition of Amerisur Resources Plc (continued)
The following table summarises the combined consideration paid for the acquired business and the final allocation of fair value of the assets acquired and liabilities assumed for the abovementioned transaction:
| | |
Amounts in US$‘000 |
| Total |
Cash |
| 314,163 |
Total consideration | | 314,163 |
Property, plant and equipment (including mineral interest) | | 276,988 |
Right-of-use assets | | 16,674 |
Deferred income tax asset | | 4,071 |
Prepayments and other receivables | | 30,024 |
Trade receivables | | 5,964 |
Inventories | | 4,128 |
Other assets | | 5,991 |
Cash and cash equivalents |
| 41,828 |
Lease liabilities | | (17,851) |
Provision for other long-term liabilities | | (16,519) |
Current income tax liability | | (3,426) |
Trade and other payables | | (33,709) |
Total identifiable net assets | | 314,163 |
Considering that Amerisur issues financial information on a monthly basis, the Group has considered the identified assets and liabilities as of December 31, 2019. If the purchase price allocation exercise had been carried out as of January 16, 2020, it would not have deferred significantly.
Since the acquisition date, Amerisur contributed revenue of US$ 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 10% non-operated working interest in the Manati Block in Brazil. The total consideration amounts to Brazilian Real 144,400,000 (equivalent to US$ 27,787,000 as of December 31, 2020), including a fixed payment of Brazilian Real 124,400,000 plus an earn-out of Brazilian Real 20,000,000, which is subject to obtaining certain regulatory approvals. The transaction is subject to certain conditions that should be met before March 31, 2022, including the acquisition by the acquirer of the remaining working interest and operatorship of the Manati gas field, and other regulatory approvals. As of the date of these Consolidated Financial Statements, these conditions have not been met.
36.2.2 REC-T-128 Block
In July 2020, GeoPark initiated a farm-out process to sell its 70% interest in the non-producing REC-T-128 Block in Brazil. On March 1, 2021, the farm-out agreement was signed. The total consideration is US$ 1,100,000, plus a contingent payment of up to US$ 710,000. The closing of the transaction took place in May 2021, after the corresponding customary regulatory approvals.
68
Note 36 Business transactions (continued)
36.3 Argentina
36.3.1 Aguada Baguales, El Porvenir and Puesto Touquet Blocks
In August 2021, the Company’s Board of Directors approved the decision to evaluate farm-out or divestment opportunities to sell its 100% working interest and operationship in the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina, including the associated gas transportation license through the Puesto Touquet pipeline. Several local and international companies have participated in the process and submitted binding offers in September 2021.
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 of December 31, 2021, the amount of Property, plant and equipment related to the blocks and the liabilities associated with them have been classified as held for sale. Immediately before the classification as held for sale, the recoverable amount of the blocks was estimated and an impairment reversal of US$ 13,307,000 was recognized in the Consolidated Statement of Income. The reversal was limited so that the carrying amount of the blocks does not exceed the lower of its recoverable amount, or the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the blocks in prior years (see Note 37).
36.4 Peru
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 and Petroperu on November 15, 2021. Consequently, from such date, all the rights and obligations under the Morona Block license contract are the exclusive responsibility of Petroperu.
During 2020, the Group recognized an impairment of its Property, plant and equipment for a total amount of US$ 33,976,000, wrote-down VAT credits for US$ 6,017,000 and Deferred income tax asset for US$ 8,353,000, recognizing those charges within Other expenses and Income tax expenses, respectively, in the Consolidated Statement of Income, and recognized a provision for environmental obligations for a present value of US$ 1,886,000, with impact in Other expenses in the Consolidated Statement of Income.
69
Note 37 Impairment test on Property, plant and equipment
During 2021, the crude oil demand recovery resulted in improvements in the market conditions. Nevertheless, a revision of the estimation of the proved reserves in the Fell Block (Chile) at year-end evidenced a significant decline as compared to the prior year estimation. Management considered this to be an impairment indicator and the Group carried out an impairment review of this cash-generating unit (“CGU”). No impairment indicators were noted in the other CGUs.
The Management of the Group considers as CGU each of the blocks or group of blocks in which the Group has working or economic interests. The blocks with no material investment on property, plant and equipment or with operations that are not linked to oil and gas prices were not subject to the impairment test.
The main assumptions taken into account for the impairment tests were:
- | The future oil prices have been calculated taking into consideration the oil price curves available in the market, provided by international advisory companies, and weighted through internal estimations in accordance with price curves used by D&M. |
- | The following Brent oil prices were considered: US$ 74.93 per Bbl for 2022, US$ 66.41 per Bbl for 2023, US$ 67.74 per Bbl for 2024, US$ 69.09 per Bbl for 2025 and US$ 70.48 per Bbl for 2026 and onwards. These prices were based on Brent future price estimations; the Group adjusted them on its model valuation to reflect the effective price applicable in each location (see Note 3 “Price risk”). |
- | Three gas price scenarios were projected and weighted in order to minimize misleading estimations: low-price, middle-price and high-price. These gas price scenarios were based on the gas sales agreement in place with Methanex in Chile. |
- | The model valuation was based on the expected cash flow approach. |
- | The revenues were calculated linking price curves with levels of production according to certified reserves. |
- | The levels of production have been linked to certified risked P1, P2 and P3 reserves case by case (see Note 4). |
- | Production and structure costs were estimated considering internal historical data according to GeoPark’s own records and aligned to the 2022 approved budget. |
- | The capital expenditures were estimated considering the drilling campaign necessary to develop the certified reserves. |
- | The assets subject to impairment test are the ones classified as Oil and Gas properties, Production facilities and machinery and Construction in progress. |
- | The carrying amount subject to impairment test includes mineral interest, if any. |
- | The income tax charges have considered future changes in the applicable income tax rates (see Note 16). |
70
Note 37 Impairment test on Property, plant and equipment (continued)
As a consequence of the evaluation, the following amounts of impairment loss were (recognized) reversed:
| | | | | | |
Amounts in US$‘000 |
| 2021 |
| 2020 |
| 2019 |
Chile (a) | | (17,641) | | (81,967) | | — |
Brazil (b) | | — | | (1,717) | | — |
Argentina (c) |
| 13,307 |
| (16,205) |
| (7,559) |
Peru (d) |
| — |
| (33,975) |
| — |
|
| (4,334) |
| (133,864) |
| (7,559) |
(a) | Recognition of impairment loss in the Fell Block due to the decline in the proved reserves estimation in 2021 and the commercial viability has been decreased significantly as a consequence of the lower crude prices relative to its high cash costs of production in 2020. |
(b) | Recognition of impairment loss in the REC-T-128 Block due to the fair value less cost to sale determined in the context of the farm-out process described in Note 36.2.2. |
(c) | Reversal of impairment loss in the Aguada Baguales and El Porvenir Blocks in 2021 due to the known market price of the blocks in the context of the transaction described in Note 36.3.1. Recognition of impairment loss in the Aguada Baguales and El Porvenir Blocks in 2020 due to the commercial viability has been decreased significantly as a consequence of the lower crude prices relative to its high cash costs of production, which also led to reduced estimates of the quantities of hydrocarbons recoverable, and in the CN-V Block in 2019 for the total amount capitalized in the block due to a negative revision of reserves. |
(d) | Recognition of impairment loss in the Morona Block due to the situation described in Note 36.4.1. |
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.
71
Note 38 Supplemental information on oil and gas activities (unaudited)
The following information is presented in accordance with ASC No. 932 “Extractive 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, 2008. This information includes the Group’s oil and gas production activities carried out in each country.
Table 1 - Costs incurred in exploration, property acquisitions and development
The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended December 31, 2021, 2020 and 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 |
| Total |
Year ended December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
Acquisition of properties |
|
|
|
|
|
|
|
|
|
|
Proved |
| — | | — | | — | | — |
| — |
Unproved |
| — | | — | | — | | — |
| — |
Total property acquisition |
| — | | — | | — | | — |
| — |
Exploration |
| 40,828 | | 3,940 | | 3 | | 998 | | 45,769 |
Development (a) |
| 81,310 | | 1,900 | | (2,212) | | 2 | | 81,000 |
Total costs incurred |
| 122,138 |
| 5,840 |
| (2,209) |
| 1,000 |
| 126,769 |
| | | | | | | | | | |
Amounts in US$‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Total |
Year ended December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
Acquisition of properties |
|
|
|
|
|
|
|
|
|
|
Proved |
| 202,913 |
| — |
| — |
| — |
| 202,913 |
Unproved |
| 73,310 |
| — |
| — |
| — |
| 73,310 |
Total property acquisition |
| 276,223 |
| — |
| — |
| — |
| 276,223 |
Exploration |
| 19,142 | | 9,447 | | 668 | | 694 | | 29,951 |
Development (a) |
| 51,793 | | 3,580 | | 412 | | (3,855) | | 51,930 |
Total costs incurred |
| 70,935 |
| 13,027 |
| 1,080 |
| (3,161) |
| 81,881 |
| | | | | | | | | | | | |
Amounts in US$‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Peru |
| Total |
Year ended December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of properties |
| | | | | | | | | |
|
|
Proved |
| — |
| — |
| — |
| — |
| — |
| — |
Unproved |
| — |
| — |
| — |
| — |
| — |
| — |
Total property acquisition |
| — |
| — |
| — |
| — |
| — |
| — |
Exploration |
| 22,008 | | 8,483 | | 5,219 | | 4,116 | | — |
| 39,826 |
Development (a) |
| 68,818 | | 2,611 | | 143 | | 25,109 | | 14,408 |
| 111,089 |
Total costs incurred |
| 90,826 |
| 11,094 |
| 5,362 |
| 29,225 |
| 14,408 |
| 150,915 |
(a) | Includes the effect of change in estimate of assets retirement obligations. |
72
Note 38 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 of December 31, 2021, 2020 and 2019, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.
| | | | | | | | | | |
Amounts in US$‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Total |
As of December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
Proved properties (a) |
|
|
|
|
|
|
|
|
|
|
Equipment, camps and other facilities |
| 125,078 | | 72,766 | | 3,333 | | — | | 201,177 |
Mineral interest and wells |
| 580,931 | | 334,993 | | 42,008 | | — | | 957,932 |
Other uncompleted projects |
| 26,136 | | 818 | | 250 | | — | | 27,204 |
Unproved properties (b) |
| 94,419 | | — | | 271 | | — | | 94,690 |
Gross capitalized costs |
| 826,564 |
| 408,577 |
| 45,862 |
| — |
| 1,281,003 |
Accumulated depreciation |
| (282,616) | | (358,417) | | (38,741) | | — | | (679,774) |
Total net capitalized costs |
| 543,948 |
| 50,160 |
| 7,121 |
| — |
| 601,229 |
(b) | Includes capitalized amounts related to asset retirement obligations, impairment loss recognized in Chile for US$ 17,641,000 and impairment loss reversed in Argentina for US$ 13,307,000. |
(c) | Do not include Ecuador capitalized costs. |
| | | | | | | | | | |
Amounts in US$‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Total |
As of December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
Proved properties (a) |
|
|
|
|
|
|
|
|
|
|
Equipment, camps and other facilities |
| 115,577 | | 74,363 | | 3,580 | | 4,309 |
| 197,829 |
Mineral interest and wells |
| 511,040 | | 348,366 | | 47,729 | | 61,482 |
| 968,617 |
Other uncompleted projects (b) |
| 13,048 | | 2,158 | | 245 | | 26 |
| 15,477 |
Unproved properties (c) |
| 77,388 | | — | | 432 | | — |
| 77,820 |
Gross capitalized costs |
| 717,053 |
| 424,887 |
| 51,986 |
| 65,817 |
| 1,259,743 |
Accumulated depreciation |
| (228,929) | | (345,611) | | (38,273) | | (45,619) |
| (658,432) |
Total net capitalized costs |
| 488,124 |
| 79,276 |
| 13,713 |
| 20,198 |
| 601,311 |
(a) | Includes capitalized amounts related to asset retirement obligations, impairment loss in Chile, Argentina and Brazil for US$ 81,967,000, US$ 16,205,000 and US$ 1,717,000, respectively. |
(b) | Do not include Peru capitalized costs. |
(c) | Do not include Ecuador capitalized costs. |
| | | | | | | | | | |
Amounts in US$‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Total |
As of December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
Proved properties (a) |
|
|
|
|
|
|
|
|
|
|
Equipment, camps and other facilities |
| 79,999 | | 84,069 | | 4,615 | | 3,824 |
| 172,507 |
Mineral interest and wells |
| 282,973 | | 402,392 | | 64,179 | | 81,393 |
| 830,937 |
Other uncompleted projects (b) |
| 19,754 | | 11,984 | | 209 | | 765 |
| 32,712 |
Unproved properties |
| 567 | | 45,681 | | 1,788 | | — |
| 48,036 |
Gross capitalized costs |
| 383,293 |
| 544,126 |
| 70,791 |
| 85,982 |
| 1,084,192 |
Accumulated depreciation |
| (172,207) | | (313,379) | | (46,370) | | (30,897) |
| (562,853) |
Total net capitalized costs |
| 211,086 |
| 230,747 |
| 24,421 |
| 55,085 |
| 521,339 |
(a) | Includes capitalized amounts related to asset retirement obligations, impairment loss in Argentina for US$ 7,559,000. |
(b) | Do not include Peru capitalized costs. |
73
Note 38 Supplemental information on oil and gas activities (unaudited - continued)
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, 2021, 2020 and 2019. Income tax for the years presented was calculated utilizing the statutory tax rates.
| | | | | | | | | | |
Amounts in US$‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Total |
Year ended December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
Revenue |
| 618,268 | | 21,471 | | 20,109 | | 28,695 | | 688,543 |
Production costs, excluding depreciation |
| | | | | | | | | |
Operating costs |
| (72,043) | | (10,280) | | (2,954) | | (14,490) | | (99,767) |
Royalties |
| (106,341) | | (770) | | (1,642) | | (4,270) | | (113,023) |
Total production costs |
| (178,384) |
| (11,050) |
| (4,596) |
| (18,760) |
| (212,790) |
Exploration expenses (a) |
| (11,276) | | (4,509) | | — | | (998) | | (16,783) |
Accretion expense (b) |
| (576) | | (1,319) | | (535) | | (710) | | (3,140) |
Impairment loss for non-financial assets |
| — | | (17,641) | | — | | 13,307 | | (4,334) |
Depreciation, depletion and amortization |
| (54,588) | | (12,806) | | (2,933) | | (8,152) | | (78,479) |
Results of operations before income tax |
| 373,444 |
| (25,854) |
| 12,045 |
| 13,382 |
| 373,017 |
Income tax (expense) benefit |
| (115,989) | | 3,878 | | (4,095) | | (4,684) | | (120,890) |
Results of oil and gas operations |
| 257,455 |
| (21,976) |
| 7,950 |
| 8,698 |
| 252,127 |
| | | | | | | | | | |
Amounts in US$‘000 |
| Colombia |
| Chile |
| Brazil |
| Argentina |
| Total |
Year ended December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
Revenue |
| 334,606 | | 21,704 | | 12,783 | | 24,599 |
| 393,692 |
Production costs, excluding depreciation |
| | | | | | | |
| |
Operating costs |
| (61,866) | | (9,491) | | (2,827) | | (15,013) |
| (89,197) |
Royalties |
| (30,453) | | (753) | | (1,049) | | (3,620) |
| (35,875) |
Total production costs |
| (92,319) |
| (10,244) |
| (3,876) |
| (18,633) |
| (125,072) |
Exploration expenses (a) |
| (12,493) | | (50,301) | | (1,000) | | (694) |
| (64,488) |
Accretion expense (b) |
| (670) | | (1,358) | | (867) | | (1,381) |
| (4,276) |
Impairment loss for non-financial assets | | — | | (81,967) | | (1,717) | | (16,205) | | (99,889) |
Depreciation, depletion and amortization |
| (56,720) | | (32,233) | | (2,488) | | (14,723) |
| (106,164) |
Results of operations before income tax |
| 172,404 |
| (154,399) |
| 2,835 |
| (27,037) |
| (6,197) |
Income tax (expense) benefit |
| (55,169) | | 23,160 | | (964) | | 8,111 |
| (24,862) |
Results of oil and gas operations |
| 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 | | — | | — | | — | | (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 |
(a) | Do not include Peru and Ecuador costs. |
(b) | Represents accretion of ARO and other environmental liabilities. |
74
Note 38 Supplemental information on oil and gas activities (unaudited - continued)
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, 2021, 2020 and 2019 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).
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.
75
Note 38 Supplemental information on oil and gas activities (unaudited - continued)
Table 4 - Reserve quantity information (continued)
The estimated GeoPark net proved reserves for the properties evaluated as of December 31, 2021, 2020, 2019 and 2018 are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):
| | | | | | | | | | | | | | | | |
| | 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 | | — |
| 45,240 | | — |
| 51,212 |
| — |
| 42,449 |
| 359 |
Chile (b) |
| 575 | | 1,563 |
| 1,229 | | 5,661 |
| 2,809 |
| 6,413 |
| 2,622 |
| 8,823 |
Argentina (f) |
| 603 | | — |
| 104 | | — |
| 1,370 |
| 450 |
| 1,440 |
| 3,174 |
Peru (g) |
| — | | — |
| — |
| — |
| 19,210 |
| — |
| 18,460 |
| — |
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 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% in 2018) of the proved developed reserves, respectively. |
(b) | Fell Block accounts for 100% of the reserves. |
(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 34 Block, 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% in 2018) of the proved undeveloped reserves, respectively. |
(f) | Aguada Baguales Block accounts for 100% (Aguada Baguales Block accounts for 100% in 2020 and 2019, and Aguada Baguales Block and El Porvenir Block account for 75% and 25% in 2018) of the proved undeveloped reserves, respectively. |
(g) | Morona Block accounted for 100% of the reserves. |
76
Note 38 Supplemental information on oil and gas activities (unaudited - continued)
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 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 | | — | | — | | — |
| 8,107 |
Production |
| (10,578) | | (188) | | (11) | | (565) | | — |
| (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) | | — |
| (4,530) |
Extensions and discoveries (d) |
| 4,545 | | 279 | | — | | — | | — |
| 4,824 |
Purchase or (Disposal) of Minerals in place (e) | | 6,853 | | — | | — | | — | | (19,210) | | (12,357) |
Production |
| (10,986) | | (134) | | (7) | | (505) | | — |
| (11,632) |
Reserves as of December 31, 2020 |
| 89,057 |
| 2,027 |
| 34 |
| 1,789 |
| — |
| 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 |
| — |
| 81,947 |
(a) | For the year ended December 31, 2019, the Group’s oil and condensate proved reserves were revised upward by 19.7 mmbbl. The primary factors leading to the above were: |
- 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 that increase the proved developed reserves, mostly originated in Colombia (6.3 mmbbl) from the Tigana and Jacana fields in the Llanos 34 Block. There were also minor increments in Argentina (0.4 mmbbl) originated in better performance of the Aguada Baguales Field wells; and in Chile (0.3 mmbbl) mostly in the Yagan Norte, Konawentru, Alakaluf and Yagan Fields.
- An updated geological model for the Situche Field in the Morona Block originated a new estimation of the proved original oil in place volumes that increased the proved undevelop reserves of the block by 0.7 mmbbl.
- Such increase was partially offset by a lower average oil prices resulted in a 0.3 mmbbl and 0.3 mmbbl decrease in reserves from the blocks in Colombia and Argentina, respectively.
- There were also better well types considered for the Kiuaku, Loij and Konawentru Field that originated a minor increment of 0.2 mmbbl, partially compensated by a reduction of 0.04 mmbbl in Argentina Challaco Field condensate due to an unsuccessful well.
(b) | In Colombia, the extensions and discoveries are primary due to the Tigana and Jacana fields appraisal wells and the Guaco field discovery in the Llanos 34 Block and the Azogue field discovery in the Llanos 32 Block. In the Fell Block in Chile, the discovery of the Jauke field. |
(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 above 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.
- A 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.
77
Note 38 Supplemental information on oil and gas activities (unaudited - continued)
Table 5 - Net proved reserves of oil, condensate and natural gas (continued)
(d) | In Colombia, the extensions and discoveries are primary due to the Tigui Field appraisal wells and in Chile are due to the Jauke Field discovery in the Fell Block. |
(e) | Purchase of Minerals in place refers to the CPO-5 and Platanillo Blocks acquisition during 2020 in Colombia. The reduction in Peru is due to the decision to retire from the Morona Block (see Note 36.4.1). |
(f) | For the year ended December 31, 2021, the Group’s oil and condensate proved reserves were revised downward by 4.0 mmbbl. The primary factors leading to the above were: |
- 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 prices resulted in a 5.7 mmbbl, 0.1 mmbbl and 0.3 mmbbl increase in reserves from the blocks in Colombia, Argentina and Chile, respectively.
(g) | In Colombia, the extensions and discoveries are primary due to the Tigui Field appraisal wells and in Argentina are due to the Aguada Baguales Field. |
Net proved reserves (developed and undeveloped) of natural gas:
| | | | | | | | | | |
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 | | — | | — | | 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) |
| — | | 10,456 | | — | | — |
| 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, 2019, the Group’s proved natural gas reserves were revised upward by 0.5 billion cubic feet. This was the combined effect of: |
- An increase of proved developed reserves due to better performance of existing wells in Chile (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 Manati Field; Colombia (0.6 billion cubic feet) due to a better performance of the Tigana and Jacana Fields; and Argentina (0.1 billion cubic feet) mostly associated to a better performance of wells in the Aguada Baguales Field.
- The above was partially offset by lower than expected performance for 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 Challaco Bajo Field.
- Lower average prices resulted in a decrease of 0.5 billion cubic feet reduction in gas proved developed reserves in Argentina.
78
Note 38 Supplemental information on oil and gas activities (unaudited - continued)
Table 5 - Net proved reserves of oil, condensate and natural gas (continued)
(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) | For the year ended December 31, 2020, the Group’s proved natural gas reserves were revised upwards by 2.1 billion cubic feet. This was the combined effect of: |
- 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) | The extensions and discoveries are primary due to the Jauke Field discovery in the Fell Block, in Chile. |
(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.
79
Note 38 Supplemental information on oil and gas activities (unaudited - continued)
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 2021, 2020 and 2019 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 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 | | — |
| 4,716,229 |
Future production costs |
| (1,715,554) | | (69,067) | | (34,930) | | (61,660) | | — |
| (1,881,211) |
Future development costs |
| (197,461) | | (40,339) | | (1,955) | | (49,200) | | — |
| (288,955) |
Future income taxes |
| (754,205) | | — | | (3,449) | | (2,947) | | — |
| (760,601) |
Undiscounted future net cash flows |
| 1,713,971 |
| 26,746 |
| 48,874 |
| (4,129) |
| — |
| 1,785,462 |
10% annual discount |
| (496,150) | | 6,121 | | (7,171) | | 4,471 | | — |
| (492,729) |
Standardized measure of discounted future net cash flows |
| 1,217,821 |
| 32,867 |
| 41,703 |
| 342 |
| — |
| 1,292,733 |
As of December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
| |
Future cash inflows |
| 2,561,947 | | 130,200 | | 68,857 | | 83,125 | | — |
| 2,844,129 |
Future production costs |
| (850,029) | | (82,290) | | (36,254) | | (65,536) | | — |
| (1,034,109) |
Future development costs |
| (197,859) | | (28,620) | | (2,355) | | (24,640) | | — |
| (253,474) |
Future income taxes |
| (409,276) | | — | | (327) | | — | | — |
| (409,603) |
Undiscounted future net cash flows |
| 1,104,783 |
| 19,290 |
| 29,921 |
| (7,051) |
| — |
| 1,146,943 |
10% annual discount |
| (345,550) | | (2,258) | | (4,543) | | 7,032 | | — |
| (345,319) |
Standardized measure of discounted future net cash flows |
| 759,233 |
| 17,032 |
| 25,378 |
| (19) |
| — |
| 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 |
80
Note 38 Supplemental information on oil and gas activities (unaudited - continued)
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 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 |
| (411,528) | | (14,284) | | (17,289) | | (13,280) | | — |
| (456,381) |
Net changes in sales price and production costs |
| (299,642) | | 12,799 | | 6,923 | | (20,694) | | (48,823) |
| (349,437) |
Changes in estimated future development costs |
| (268,377) | | (22,163) | | 1,165 | | 573 | | (175,248) |
| (464,050) |
Extensions and discoveries less related costs |
| 182,857 | | 17,300 | | — | | — | | — |
| 200,157 |
Development costs incurred |
| 69,694 | | 4,023 | | 445 | | 4,325 | | — |
| 78,487 |
Revisions of previous quantity estimates |
| 415,349 | | 9,508 | | 5,482 | | (2,358) | | 11,992 |
| 439,973 |
Net changes in income taxes |
| 23,398 | | (2,025) | | 729 | | 3,760 | | 51,917 |
| 77,779 |
Accretion of discount |
| 222,758 | | 9,235 | | 4,378 | | 4,148 | | 42,846 |
| 283,365 |
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 |
| (221,620) | | (12,803) | | 8,080 | | (10,454) | | — |
| (236,797) |
Net changes in sales price and production costs |
| (975,716) | | (117,895) | | (14,580) | | (113) | | — |
| (1,108,304) |
Changes in estimated future development costs |
| 514,317 | | 20,870 | | (19,606) | | (2,587) | | — |
| 512,994 |
Extensions and discoveries less related costs |
| 59,898 | | 13,914 | | — | | — | | — |
| 73,812 |
Development costs incurred |
| 69,694 | | 10,743 | | 394 | | 445 | | — |
| 81,276 |
Revisions of previous quantity estimates |
| (27,190) | | (13,002) | | 3,519 | | (10) | | — |
| (36,683) |
Purchase or (Disposal) of Minerals in place | | 90,315 | | — | | — | | — | | (121,217) | | (30,902) |
Net changes in income taxes |
| (281,264) | | — | | (290) | | — | | — |
| (281,554) |
Accretion of discount |
| 217,227 | | 10,982 | | 4,479 | | 1,359 | | — |
| 234,047 |
Present value as of December 31, 2020 |
| 759,233 |
| 17,032 |
| 25,378 |
| (19) |
| — |
| 801,624 |
Sales of hydrocarbon, net of production costs |
| (516,844) | | (11,520) | | (15,677) | | (16,855) | | — |
| (560,896) |
Net changes in sales price and production costs |
| 924,875 | | 64,048 | | 19,393 | | (3,145) | | — |
| 1,005,171 |
Changes in estimated future development costs |
| 96,364 | | (18,731) | | 861 | | 20,674 | | — |
| 99,168 |
Extensions and discoveries less related costs |
| 80,933 | | — | | — | | (1,020) | | — |
| 79,913 |
Development costs incurred |
| 87,877 | | 4,111 | | — | | — | | — |
| 91,988 |
Revisions of previous quantity estimates |
| (76,850) | | (23,776) | | 11,957 | | 465 | | — |
| (88,204) |
Net changes in income taxes |
| (254,618) | | — | | (2,780) | | 244 | | — |
| (257,154) |
Accretion of discount |
| 116,851 | | 1,703 | | 2,571 | | (2) | | — |
| 121,123 |
Present value as of December 31, 2021 |
| 1,217,821 |
| 32,867 |
| 41,703 |
| 342 |
| — |
| 1,292,733 |
81
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | |
| GeoPark Limited | |
| | |
| | |
| By: | /s/ Andrés Ocampo |
| | Name: Andrés Ocampo |
| | Title: Chief Financial Officer |
Date: March 9, 2022
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