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 Cumberland House, 9th Floor, 1 Victoria 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 Chile, Colombia, Brazil, Peru and Argentina.
These Consolidated Financial Statements
were authorised for issue by the Board of Directors on 7 March 2018.
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 convention.
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.
Note
2 Summary of significant accounting policies
(continued)
2.1 Basis of preparation (continued)
2.1.1 Changes in accounting policy and
disclosure
New and amended standards adopted by
the Group
The following standards have been adopted
by the Group for the first time for the financial year beginning on or after 1 January 2017:
·
Recognition of Deferred Tax Assets for Unrealised Losses – Amendments to IAS 12
·
Disclosure initiative – Amendments to IAS 7
The adoption of these amendments did not
have any impact on the current period or any prior period and is not likely to affect future periods.
New standards, amendments and interpretations
issued but not effective for the financial year beginning 1 January 2017 and not early adopted.
·
IFRS 2 Share based payments: amended in June 2016 to clarify the measurement basis for cash-settled share-based payments and
the accounting for modifications that change an award from cash-settled to equity-settled. It also introduces an exception to
IFRS 2 principles by requiring an award to be treated as if it was wholly equity-settled, where an employer is obliged to
withhold an amount for the employee’s tax obligation associated with a share-based payment and pay that amount to the
tax authority. It is effective for annual periods beginning on or after January 1, 2018. The Group estimates that these
amendments will not have a material impact on the Group’s operating results or financial position.
·
IFRS 9 Financial Instruments and associated amendments to various other standards: IFRS 9 replaces the multiple
classification and measurement models in IAS 39. Classification of debt assets will be driven by the entity’s business
model for managing the financial assets and the contractual cash flow characteristics of the financial assets. A debt
instrument is measured at amortised cost if: a) the objective of the business model is to hold the financial asset for the
collection of the contractual cash flows, and b) the contractual cash flows under the instrument solely represent payments of
principal and interest. All other debt and equity instruments, including investments in complex debt instruments and equity
investments, must be recognised at fair value.
All fair value movements on financial assets
are taken through the statement of profit or loss, except for equity investments that are not held for trading, which may be recorded
in the statement of profit or loss or in reserves (without subsequent recycling to profit or loss). For financial liabilities that
are measured under the fair value option entities will need to recognise the part of the fair value change that is due to changes
in their own credit risk in other comprehensive income rather than profit or loss.
The new hedge accounting rules (released
in December 2013) align hedge accounting more closely with common risk management practices. As a general rule, it will be easier
to apply hedge accounting going forward.
Note
2 Summary of significant accounting policies
(continued)
2.1 Basis of preparation (continued)
2.1.1 Changes in accounting policy and
disclosure (continued)
The new impairment model under IFRS 9 requires
the recognition of impairment provisions based on expected credit losses rather than only incurred credit losses as is the case
under IAS 39. It applies to financial assets classified at amortised cost, debt instruments measured at fair value through other
comprehensive income, contract assets under IFRS 15, lease receivables, loan commitments and certain financial guarantee contracts.
The new standard also introduces expanded
disclosure requirements and changes in presentation.
Management has assessed the effects of applying
the new standard on the Group’s Consolidated Financial Statements and concluded that no material impact will be expected.
·
IFRS 15 Revenue from contracts with customers and associated amendments to various other standards: The IASB has issued a new standard
for the recognition of revenue. This will replace IAS 18 which covers contracts for goods and services and IAS 11 which covers
construction contracts. The new standard is based on the principle that revenue is recognised when control of a good or service
transfers to a customer so the notion of control replaces the existing notion of risks and rewards.
These accounting changes may have flow-on
effects on the entity’s business practices regarding systems, processes and controls, compensation and bonus plans, contracts,
tax planning and investor communications. Entities will have a choice of full retrospective application, or prospective application
with additional disclosures.
It is mandatory for financial years commencing
on or after 1 January 2018. The Group intends to adopt the standard using the modified retrospective approach which means that
the cumulative impact of the adoption will be recognised in retained earnings as of 1 January 2018 and that comparatives will not
be restated.
Management has assessed the effects of applying
the new standard on the Group’s Consolidated Financial Statements and concluded that no material impact will be expected.
·
IFRS 16 Leases: will affect primarily the accounting by lessees and will result in the recognition of almost all leases on
balance sheet. The standard removes the current distinction between operating and financing leases and requires recognition
of an asset (the right to use the leased item) and a financial liability to pay rentals for virtually all lease contracts. An
optional exemption exists for short-term and low-value leases. The accounting by lessors will not significantly change. Some
differences may arise as a result of the new guidance on the definition of a lease.
The Group has not yet determined to what
extent its commitments will result in the recognition of an asset and a liability for future payments and how this will affect
the Group’s profit and classification of cash flows. Some of the commitments may be covered by the exception for short-term
and low-value leases and some commitments may relate to arrangements that will not qualify as leases under IFRS 16. At this stage,
the Group does not intend to adopt the standard before its effective date. The Group intends to apply the simplified transition
approach and will not restate comparative amounts for the year prior to first adoption.
Note
2 Summary of significant accounting policies
(continued)
2.1 Basis of preparation (continued)
2.1.1 Changes in accounting policy and
disclosure (continued)
·
IFRIC 22 Foreign Currency Transactions and Advance Consideration: issued in December 2016. The interpretation addresses how
to determine the date of the transaction for the purpose of determining the exchange rate to use on initial recognition of
the related asset, expense or income related to an entity that has received or paid an advance consideration in a foreign
currency. The date of the transaction is the date on which an entity initially recognises the non-monetary asset or
non-monetary liability arising from the payment or receipt of advance consideration. It is effective for annual periods
beginning on January 1, 2018. The Group estimates that these interpretations will not have a material impact on the
Group’s operating results or financial position.
·
Sale or contribution of assets between an investor and its associate or joint venture – Amendments to IFRS 10 and IAS
28: The amendments clarify the accounting treatment for sales or contribution of assets between an investor and its
associates or joint ventures.
·
Improvements to IFRSs – 2014-2016 Cycle: amendments issued in December 2016 that are effective for periods beginning on or
after January 1, 2018. The Group estimates that these amendments will not have an impact on the Group’s operating results
or financial position.
There are no other standards that are not
yet effective and that would be expected to have a material impact on the entity in the current or future reporting periods and
on foreseeable future transactions.
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 macroeconomic environment conditions,
the performance of the operations, the US$ 425,000,000 debt fund raising completed in September 2017, the Group’s cash position,
and the fact that over 99% of its total indebtedness maturing in 2024, the Directors have formed a judgement, at the time of approving
the 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.
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.
The Group applies the acquisition method
to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair value of the assets
transferred, the liabilities incurred by the former owners of the acquiree and the equity interests issued by the Group. The consideration
transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable
assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their
fair values at the acquisition date. Acquisition-related costs are expensed as incurred.
The excess of the consideration transferred,
the amount of any non-controlling interest in the acquired entity, and the acquisition-date fair value of any previous equity interest
in the acquired entity over the fair value of the identifiable net assets acquired is recorded as goodwill. If the total of consideration
transferred, non-controlling interest recognised and previously held interest measured is less than the fair value of the net assets
of the subsidiary acquired in the case of a bargain purchase, the difference is recognised directly in the income statement.
Intercompany transactions, balances and
unrealised gains on transactions between the Group and its subsidiaries are eliminated. Unrealised 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, Corporate Governance,
Finance and People 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.
Note
2 Summary of significant accounting policies
(continued)
2.5 Foreign currency translation
a)
Functional and presentation currency
The Consolidated Financial Statements are
presented in US Dollars, which is the Group’s presentation currency.
Items included in the 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 Chile, Colombia, Peru and Argentina
is the US Dollar, meanwhile for the Group´s Brazilian company the functional currency is the local currency, which is the
Brazilian Real.
b)
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 recognised in the Consolidated Statement of 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 financial statements.
2.7 Revenue recognition
Revenue from the sale of crude oil and gas
is recognised in the Consolidated Statement of Income when risk is transferred to the purchaser, and if the revenue can be measured
reliably and is expected to be received. 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 32 (a).
Note
2 Summary of significant accounting policies
(continued)
2.8 Production and operating costs
Production costs include wages and salaries
incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, leasing and
royalties are also included within this account.
2.9 Financial results
Financial results include interest expenses,
interest income, bank charges, the amortisation of financial assets and liabilities, and foreign exchanges gain and losses. The
Group has capitalised borrowing cost for wells and facilities that were initiated after 1 January 2009. The capitalisation rate
used to determine the amount of borrowing costs to be capitalised is the weighted average interest rate applicable to the Group’s
general borrowings during the year, which was 6.90% at year end 2017 (7.98% at year end 2016 and 2015). Amounts capitalised during
the year
amounted to
US$ 610,841 (US$ 254,950 in 2016 and US$ 637,390 in 2015).
2.10 Property, plant and equipment
Property, plant and equipment are stated
at historical cost less depreciation and impairment charge, 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, capitalising 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 labour costs and drilling costs of exploratory
wells. No depreciation and/or amortisation 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 found 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$ 5,834,000 has been
recognised in the Consolidated Statement of Income within Write-off of unsuccessful exploration efforts (US$ 31,366,000 in 2016
and US$ 30,084,000 in 2015). See Note 20.
All field development costs are considered
construction in progress until they are finished and capitalised 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.
Note
2 Summary of significant accounting policies
(continued)
2.10 Property, plant and equipment (continued)
Workovers of wells made to develop reserves
and/or increase production are capitalised as development costs. Maintenance costs are charged to the Consolidated Statement of
Income when incurred.
Capitalised 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 reserves. The calculation of the “unit of production”
depreciation takes into account estimated future finding and development costs and is based on current year end unescalated price
levels. Changes in reserves and cost estimates are recognised 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 up 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 2.12).
2.11 Provisions and other long-term liabilities
Provisions for asset retirement obligations,
deferred income, restructuring obligations and legal claims are recognised 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 comprise lease termination penalties and employee 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
recognised as financial expense.
Note
2 Summary of significant accounting policies
(continued)
2.11 Provisions and other long-term liabilities
(continued)
2.11.1 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 capitalises 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 capitalised cost is depreciated over the estimated useful life of the related
asset. According to interpretations and 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 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.
2.11.2 Deferred Income
Relates to contributions received in cash
from the Group’s clients to improve the project economics of gas wells. The amounts collected are reflected as a deferred
income in the balance sheet and recognised in the Consolidated Statement of Income over the productive life of the associated wells.
The depreciation of the gas wells that generated the deferred income is charged to the Consolidated Statement of Income simultaneously
with the amortisation of the deferred income. The addition in 2016 and the amounts used in 2017 correspond to the deferred income
related to the take or pay provision associated to gas sales in Brazil.
2.12 Impairment of non-financial assets
Assets that are not subject to depreciation
and/or amortisation (i.e.: exploration and evaluation assets) are tested annually for impairment. Assets that are subject to depreciation
and/or amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may
not be recoverable.
An impairment loss is recognised for the
amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s
fair value 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.
Note
2 Summary of significant accounting policies
(continued)
2.12 Impairment of non-financial assets
(continued)
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 2017, no impairment loss was recognised
(impairment loss reversed for US$ 5,664,000 in 2016 and impairment loss recognised for US$ 149,574,000 in 2015). See Note
36. The write-offs are detailed in Note 20.
2.13 Lease contracts
All current lease contracts are considered
to be operating leases on the basis that the lessor retains substantially all the risks and rewards related to the ownership of
the leased asset. Payments related to operating leases and other rental agreements are recognised in the Consolidated Income Statement
on a straight line basis over the term of the contract. The Group's total commitment relating to operating leases and rental agreements
is disclosed in Note 32.
Leases in which substantially all of the
risks and rewards of ownership are transferred to the lessee are classified as finance leases. Under a finance lease, the Group
as lessor has to recognise an amount receivable equal to the aggregate of the minimum lease payments plus any unguaranteed residual
value accruing to the lessor, discounted at the interest rate implicit in the lease.
2.14 Inventories
Inventories comprise crude oil and materials.
Crude oil is measured at the lower of cost
and net realisable 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.
2.15 Current and deferred income tax
The tax expense for the year comprises current
and deferred tax. Tax is recognised 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 balance sheet 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.
Note
2 Summary of significant accounting policies
(continued)
2.15 Current and deferred income tax
(continued)
Deferred income tax is recognised, 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 balance sheet date and are expected to apply when the related deferred income tax asset is realised
or the deferred income tax liability is settled.
In addition, the Group has tax-loss carry-forwards
in certain taxing jurisdictions that are available to be offset against future taxable profit. However, deferred tax assets are
recognised 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 tax is recognised in respect of the retained earnings of overseas subsidiaries
only if at the date of the statements of financial position, 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. In the event that these differences revert in total (e.g. dividends
are declared and paid), the deferred tax liability which the Group would have to recognise amounts to approximately US$ 12,300,000.
Deferred tax balances are provided in full,
with no discounting.
2.16 Financial assets
Financial assets are divided into the following
categories: loans and receivables; financial assets at fair value through profit or loss; available-for-sale financial assets;
and held-to-maturity investments. Financial assets are assigned to the different categories by management on initial recognition,
depending on the purpose for which the investments were acquired. The designation of financial assets is re-evaluated at every
reporting date at which a choice of classification or accounting treatment is available.
All financial assets are recognised when
the Group becomes a party to the contractual provisions of the instrument.
All financial assets are initially recognised
at fair value, plus transaction costs.
Note
2 Summary of significant accounting policies
(continued)
2.16 Financial assets (continued)
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 recognised in the Consolidated Statement of Income when receivable, regardless of how the related
carrying amount of financial assets is measured.
Loans and receivables 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. The
Group’s loans and receivables comprise trade receivables, prepayments and other receivables and cash and cash equivalents
in the balance sheet. They arise when the Group provides money, goods or services directly to a debtor with no intention of trading
the receivables. Loans and receivables are subsequently measured at amortised cost using the effective interest method, less provision
for impairment. Any change in their value through impairment or reversal of impairment is recognised in the Consolidated Statement
of Income. All of the Group’s financial assets are classified as loan and receivables.
2.17 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 the
security deposit granted in relation to the purchase of Argentinian assets (see Note 35) and short term investments with original
maturities up to twelve months and over three months.
2.18 Impairment of financial assets
Provision against trade receivables is made
when objective evidence is received that the Group will not be able to collect all amounts due to it in accordance with the original
terms of those receivables. The amount of the write-down is determined as the difference between the asset's carrying amount and
the present value of estimated future cash flows.
2.19 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, and bank overdrafts. Bank overdrafts, if any, are shown within borrowings in the current liabilities section of the Consolidated
Statement of Financial Position.
Note
2 Summary of significant accounting policies
(continued)
2.20 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 recognised initially
at fair value and subsequently measured at amortised cost using the effective interest method.
2.21 Derivatives
Derivative financial instruments are recognised
in the statement of financial position as assets or liabilities and initially and subsequently measured at fair value through profit
and loss. 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 market-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. Gains and losses arising from
changes in fair value are recognised in the Consolidated Statement of Income within Commodity risk management contracts.
For more information about derivatives please
refer to Note 8.
2.22 Borrowings
Borrowings are obligations to pay cash and
are recognised when the Group becomes a party to the contractual provisions of the instrument.
Borrowings are recognised initially at fair
value, net of transaction costs incurred. Borrowings are subsequently stated at amortised cost; any difference between the proceeds
(net of transaction costs) and the redemption value is recognised 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 accruals basis using the effective interest method.
Note
2 Summary of significant accounting policies
(continued)
2.23 Share capital
Equity comprises the following:
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"Share
capital" representing the nominal value of equity shares.
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"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.
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"Other
reserve" representing:
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the equity element attributable to shares granted according to IFRS 2 but not issued at year end
or,
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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.
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"Translation
reserve" representing the differences arising from translation of investments in overseas subsidiaries.
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"(Accumulated
losses) Retained earnings" representing accumulated earnings and losses.
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2.24 Share-based payment
The Group operates a number of equity-settled
and cash-settled share-based compensation plans comprising share awards payments to certain 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 recognised 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 balance sheet date, the entity revises its estimates
of the number of options that are expected to vest. It recognises the impact of the revision to original estimates, if any, in
the Consolidated Statement of Income, with a corresponding adjustment to equity.
The fair value of the share awards payments
is determined at the grant date by reference of the market value of the shares and recognised 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.
For cash-settled share-based payment transactions,
if any, the Company measures the services acquired for amounts that are based on the price of the Company’s shares. The fair
value of the liability incurred is measured using Geometric Brownian Motion method. Until the liability is settled, the Company
is required to remeasure the fair value of the liability at each reporting date and at the date of settlement, with any changes
in value recognised in profit or loss for the period.
Note
3 Financial Instruments-risk management
The Group is exposed through its operations
to the following financial risks:
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Credit
risk – concentration
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Funding
and liquidity risk
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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 Argentina, Colombia, Chile and Peru the
functional currency is the US Dollar. The fluctuation of the local currencies of these countries against 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 Chile, Colombia and Argentina 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.
The Group minimises the local currency positions
in Argentina, Colombia and Chile by seeking to equilibrate 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.
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 2017, the Argentine Peso devaluated
by 17% (22% and 52% in 2016 and 2015) against the US Dollar, the Chilean Peso revaluated by 8% (revaluated by 6% in 2016 and devaluated
by 16% in 2015) and the Colombian Peso revaluated by 1% (revaluated by 5% in 2016 and devaluated by 32% in 2015).
If the Argentine Peso, the Chilean Peso
and the Colombian Peso had each devaluated an additional 10% against the US dollar, with all other variables held constant, post-tax
loss for the year would have been higher by US$ 1,538,000 (US$ 2,683,400 in 2016 and US$ 1,003,300 in 2015).
Note
3 Financial Instruments-risk management
(continued)
Currency risk (continued)
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 Itaú,
which was fully repaid in September 2017, and intercompany loans. Most of the balances are denominated in Brazilian Real, and since
it is the functional currency of the Brazilian subsidiary, there is no exposure to currency fluctuation except from the intercompany
loan and the Itaú loan described in Note 27. The exchange loss generated by the Brazilian subsidiary during 2017 amounted
to US$ 1,274,000 (gain of US$ 14,542,000 in 2016 and loss of US$ 35,605,000 in 2015).
During 2017, the Brazilian Real devaluated
by 2% against the US Dollar (revaluated by 17% in 2016 and devaluated by 47% in 2015, respectively). If the Brazilian Real had
devaluated 10% against the US dollar, with all other variables held constant, post-tax loss for the year would have been higher
by US$ 3,100,000 (US$ 5,300,000 in 2016 and US$ 7,400,000 in 2015).
As of 31 December 2017, the balances denominated
in the Peruvian local currency (Peruvian Soles) are not material.
As currency rate changes between the US
Dollar and the local currencies, the Group recognises gains and losses in the Consolidated Statement of Income.
Price risk
The price realised for the oil produced
by the Group is linked to US dollar denominated crude oil international benchmarks. The market price of these commodities is subject
to significant volatility and has historically fluctuated widely in response to relatively minor changes in the global supply and
demand for oil and natural gas, geopolitical landscape, economic conditions and a variety of additional factors.
In Colombia, the realised oil price is linked
to the Vasconia crude reference price, a marker broadly used in the Llanos basin, adjusted for certain marketing and quality discounts
based on, among other things, API, viscosity, sulphur content, water 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 Gulf methanol spot barge prices, methanol spot Rotterdam prices and spot prices
in Asia.
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.
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 loss for the year would have been higher by US$ 10,423,000 (US$ 23,655,000 in 2016 and US$ 23,940,000
in 2015).
As of October 2016, GeoPark considered it
was appropriate to manage 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 recognised values. There is not considered to be any significant
risk in respect of the Group’s major customers and hedging counterparties.
In Colombia, during 2017, the Colombian
subsidiary made 99% of the oil sales to Trafigura (one of the world’s leading independent commodity trading and logistics
houses), with Trafigura accounting for 79% of consolidated revenues for the same period.
All the oil produced in Chile as well as
the gas produced by TdF Blocks (5% of total revenue, 10% in 2016 and 15% in 2015) is sold to ENAP, the State owned oil and gas
company. In Chile, most of gas production is sold to the local subsidiary of Methanex, a Canadian public company (5% of consolidated
revenue, 9% in 2016 and 7% in 2015).
In Brazil, all the hydrocarbons from Manati
Field are sold to Petrobras, the State owned company, which is the operator of the Manati Field (10% of the consolidated revenue,
15% in 2016 and 2015).
The forementioned companies all have good
credit standing and despite the concentration of the credit risk, the Directors do not consider there to be a significant collection
risk.
In 2016 and 2017, the Group executed 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.
Note
3 Financial Instruments-risk management
(continued)
Funding and Liquidity risk
In the past, the Group was able to raise
capital through different sources of funding including equity, strategic partnerships and financial debt. During 2017, the Group
placed US$ 425,000,000 notes (see Note 27).
The Group is positioned at the end of 2017
with a cash balance of US$ 134,755,000 and over 99% of its total indebtedness maturing in 2024. In addition, the Group has a large
portfolio of attractive and largely discretional projects - both oil and gas - in multiple countries with over 31,000 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 indenture governing the Company Notes
2024 includes incurrence test covenants related to the 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 indenture governing
the Notes. As of the date of these Consolidated Financial Statements, the Group is in compliance with all the indenture’s
provisions and covenants.
The most significant funding transactions
executed in 2017, 2016 and 2015 include:
On September 2017, the Group successfully
placed US$ 425,000,000 notes. These Notes carry a coupon of 6.50% per annum and their final maturity will be 21 September 2024.
The net proceeds from the Notes were used by the Group to fully repay the 7.50% senior secured notes due 2020 and for general corporate
purposes, including capital expenditures and repay other existing indebtedness.
On December 2015, the Group announced the
execution of an offtake and prepayment agreement with Trafigura, one of its customers. The prepayment agreement provided GeoPark
with access to up to US$ 100,000,000 in the form of prepaid future oil sales. The availability period for the prepayment agreement
expired on 30 September 2017. Funds committed by Trafigura are being repaid by the Group through future oil deliveries over 2.5
years with a six-month grace period. As of the date of these Consolidated Financial Statements, outstanding balances related to
the prepayment agreement amount to US$ 10,000,000.
Note
3 Financial Instruments-risk management
(continued)
Interest rate risk
The Group’s interest rate risk arises
from long-term borrowings issued at variable rates, which expose the Group to cash flow to interest rate risk.
The Group does not face interest rate risk
on its US$ 425,000,000 Notes which carry a fixed rate coupon of 6.50% per annum. As a consequence, the accruals and interest payment
are no substantially affected to the market interest rate changes.
The Group analyses its interest rate exposure
on a dynamic basis. Various scenarios are simulated taking into consideration refinancing, renewal of existing positions, alternative
financing and hedging. Based on these scenarios, the Group calculates the impact on profit and loss of a defined interest rate
shift. For each simulation, the same interest rate shift is used for all currencies. The scenarios are run only for liabilities
that represent the major interest-bearing positions.
At 31 December 2017, the Group has no exposure
to fluctuations in the interest rate, since its long-term borrowings were issued at fixed rate. At 31 December 2016 and 2015, if
1% had been added to interest rates on currency-denominated borrowings with all other variables held constant, post tax loss for
the year would have been US$ 467,000 and US$ 507,000 higher, respectively.
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
balance sheet) less cash and cash equivalents. Total capital is calculated as ‘equity’ as shown in the consolidated
balance sheet plus net debt.
The Group’s strategy is to keep the
gearing ratio within a 30% to 45% range, in normal market conditions. Due to the market conditions prevailing during 2017 and 2016
and the growing strategy of the Group, the gearing ratio at year end is above such range.
Note
3 Financial Instruments-risk management
(continued)
Capital risk management (continued)
The gearing ratios at 31 December 2017 and
2016 were as follows:
|
Amounts in US$ '000
|
2017
|
2016
|
|
Net Debt
|
291,449
|
285,109
|
|
Total Equity
|
126,840
|
141,593
|
|
Total Capital
|
418,289
|
426,702
|
|
Gearing Ratio
|
70%
|
67%
|
Note
4 Accounting estimates and assumptions
Estimates and assumptions are used in preparing
the financial statements. Although these estimates are based on management's best knowledge of current events and actions, actual
results may differ from them. 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:
·
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 own 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 will differ, management considers the assessment of impairment to be a critical
accounting estimate (see Note 36).
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 31 December 2017 prepared by DeGolyer and MacNaughton, an international consultancy to the oil and
gas industry based in Dallas. It incorporates many factors and assumptions including:
Note
4 Accounting estimates and assumptions (continued)
|
|
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; 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.
|
|
·
|
The
Group adopts the successful efforts method of accounting. The Management of the Group makes assessments and estimates regarding
whether an exploration asset should continue to be carried forward as an exploration and evaluation asset not yet determined or
when insufficient information exists for this type of cost to remain as an asset. In making this assessment Management takes professional
advice from qualified experts.
|
|
|
·
|
Oil
and gas assets held in property plant and equipment are mainly depreciated on a unit of production 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.
|
|
|
·
|
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 recognising 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 recognised are based upon estimated future abandonment costs, wells
subject to abandonment, time to abandonment, and future inflation rates.
|
|
|
·
|
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 Management of the Group currently knows, it is not expected
any material impact on the 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
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
|
2017
|
2016
|
2015
|
|
Increase in asset retirement obligation
|
5,943
|
1,195
|
985
|
|
Increase in provisions for other long-term liabilities
|
2,053
|
3,468
|
-
|
|
Purchase of property, plant and equipment
|
11,759
|
(4,657)
|
830
|
Changes in working capital shown in the
Consolidated Statement of Cash Flow are disclosed as follows:
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Increase in Prepaid taxes
|
(14,802)
|
(2,351)
|
(16,611)
|
|
(Increase) Decrease in Inventories
|
(2,031)
|
466
|
2,752
|
|
(Increase) Decrease in Trade receivables
|
(1,344)
|
(4,811)
|
22,470
|
|
(Increase) Decrease in Prepayments and other receivables and Other assets
|
(8,623)
|
(1,758)
|
405
|
|
Customer advance (repayments) payments
|
(10,000)
|
20,000
|
-
|
|
Security deposit granted (Note 35)
|
(15,600)
|
-
|
-
|
|
Increase (Decrease) in Trade and other payables
|
27,122
|
374
|
(33,120)
|
|
|
(25,278)
|
11,920
|
(24,104)
|
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, Corporate Governance,
Finance and People 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 profit for the period before net
finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful
efforts, accrual of share-based payment, unrealized result on commodity risk management contracts and other non recurring events.
Operating Netback is equivalent to Adjusted EBITDA before cash expenses included in Administrative, Geological and Geophysical
and Other operating expenses. Other information provided, except as noted below, to the Executive Committee is measured in a manner
consistent with that in the financial statements.
Segment areas (geographical segments):
|
Amounts
in US$ '000
|
Chile
|
Brazil
|
Colombia
|
Peru
|
Argentina
|
Corporate
|
Total
|
|
2017
|
|
|
|
|
|
|
|
|
Revenue
|
32,738
|
34,238
|
263,076
|
-
|
70
|
-
|
330,122
|
|
Sale
of crude oil
|
15,873
|
910
|
262,309
|
-
|
70
|
-
|
279,162
|
|
Sale
of gas
|
16,865
|
33,328
|
767
|
-
|
-
|
-
|
50,960
|
|
Realized
loss on commodity risk management contracts
|
-
|
-
|
(2,148)
|
-
|
-
|
-
|
(2,148)
|
|
Production
and operating costs
|
(20,999)
|
(10,737)
|
(66,913)
|
-
|
(338)
|
-
|
(98,987)
|
|
Royalties
|
(1,314)
|
(3,134)
|
(24,236)
|
-
|
(13)
|
-
|
(28,697)
|
|
Transportation
costs
|
(1,211)
|
-
|
(1,678)
|
-
|
(80)
|
-
|
(2,969)
|
|
Share-based
payment
|
(170)
|
(39)
|
(248)
|
-
|
-
|
-
|
(457)
|
|
Other
costs
|
(18,304)
|
(7,564)
|
(40,751)
|
-
|
(245)
|
-
|
(66,864)
|
|
Operating
(loss) profit
|
(19,675)
|
4,434
|
116,290
|
(3,850)
|
(3,430)
|
(14,773)
|
78,996
|
|
Operating
netback
|
11,222
|
23,540
|
194,013
|
-
|
(467)
|
-
|
228,308
|
|
Adjusted
EBITDA
|
4,070
|
20,166
|
168,303
|
(3,505)
|
(2,183)
|
(11,075)
|
175,776
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
(23,730)
|
(10,809)
|
(40,010)
|
(139)
|
(159)
|
(38)
|
(74,885)
|
|
Write-off
|
(546)
|
(2,978)
|
(1,625)
|
-
|
(685)
|
-
|
(5,834)
|
|
Total
assets
|
301,931
|
91,604
|
288,429
|
22,099
|
30,924
|
51,176
|
786,163
|
|
|
|
|
|
|
|
|
|
|
Employees
(average)
|
102
|
12
|
164
|
13
|
88
|
-
|
379
|
|
Employees
at year end
|
102
|
12
|
180
|
19
|
92
|
-
|
405
|
Note
6 Segment information (continued)
|
Amounts
in US$ '000
|
Chile
|
Brazil
|
Colombia
|
Peru
|
Argentina
|
Corporate
|
Total
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Revenue
|
36,723
|
29,719
|
126,228
|
-
|
-
|
-
|
192,670
|
|
|
Sale
of crude oil
|
18,774
|
688
|
125,731
|
-
|
-
|
-
|
145,193
|
|
|
Sale
of gas
|
17,949
|
29,031
|
497
|
-
|
-
|
-
|
47,477
|
|
|
Realized
gain on commodity risk management contracts
|
-
|
-
|
514
|
-
|
-
|
-
|
514
|
|
|
Production
and operating costs
|
(22,169)
|
(8,459)
|
(36,607)
|
-
|
-
|
-
|
(67,235)
|
|
|
Royalties
|
(1,495)
|
(2,721)
|
(7,281)
|
-
|
-
|
-
|
(11,497)
|
|
|
Transportation
costs
|
(1,170)
|
-
|
(1,111)
|
-
|
-
|
-
|
(2,281)
|
|
|
Share-based
payment
|
(138)
|
(71)
|
(413)
|
-
|
-
|
-
|
(622)
|
|
|
Other
costs
|
(19,366)
|
(5,667)
|
(27,802)
|
-
|
-
|
-
|
(52,835)
|
|
|
Operating
(loss) profit
|
(44,969)
|
(645)
|
31,463
|
(3,147)
|
370
|
(11,685)
|
(28,613)
|
|
|
Operating
netback
|
13,696
|
21,356
|
87,523
|
41
|
(378)
|
(91)
|
122,147
|
|
|
Adjusted
EBITDA
|
5,159
|
17,487
|
66,921
|
(2,607)
|
1,848
|
(10,487)
|
78,321
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
(31,355)
|
(12,974)
|
(31,148)
|
(130)
|
(150)
|
(17)
|
(75,774)
|
|
|
Reversal
of impairment losses
|
-
|
-
|
5,664
|
-
|
-
|
-
|
5,664
|
|
|
Write-off
|
(19,389)
|
(4,583)
|
(7,394)
|
-
|
-
|
-
|
(31,366)
|
|
|
Total
assets
|
317,969
|
99,904
|
182,784
|
5,020
|
6,071
|
28,792
|
640,540
|
|
|
|
|
|
|
|
|
|
|
|
|
Employees
(average)
|
102
|
10
|
138
|
11
|
80
|
-
|
341
|
|
|
Employees
at year end
|
102
|
10
|
146
|
10
|
77
|
-
|
345
|
|
|
Amounts
in US$ '000
|
Chile
|
Brazil
|
Colombia
|
Peru
|
Argentina
|
Corporate
|
Total
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Revenue
|
44,808
|
32,388
|
131,897
|
-
|
597
|
-
|
209,690
|
|
|
Sale
of crude oil
|
29,180
|
955
|
131,897
|
-
|
597
|
-
|
162,629
|
|
|
Sale
of gas
|
15,628
|
31,433
|
-
|
-
|
-
|
-
|
47,061
|
|
|
Production
costs
|
(28,704)
|
(8,056)
|
(48,534)
|
-
|
(1,448)
|
-
|
(86,742)
|
|
|
Royalties
|
(1,973)
|
(2,998)
|
(8,150)
|
-
|
(34)
|
-
|
(13,155)
|
|
|
Transportation
costs
|
(2,441)
|
-
|
(2,068)
|
-
|
(2)
|
-
|
(4,511)
|
|
|
Share-based
payment
|
(132)
|
-
|
(234)
|
-
|
(197)
|
-
|
(563)
|
|
|
Other
costs
|
(24,158)
|
(5,058)
|
(38,082)
|
-
|
(1,215)
|
-
|
(68,513)
|
|
|
Operating
(loss) profit
|
(180,264)
|
6,639
|
(37,227)
|
(6,719)
|
(2,350)
|
(12,570)
|
(232,491)
|
|
|
Operating
netback
|
15,254
|
24,393
|
80,355
|
44
|
(1,732)
|
(287)
|
118,027
|
|
|
Adjusted
EBITDA
|
(183)
|
20,460
|
66,736
|
(6,520)
|
(684)
|
(6,022)
|
73,787
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
(39,227)
|
(13,568)
|
(52,434)
|
(129)
|
(199)
|
-
|
(105,557)
|
|
|
Impairment
loss
|
(104,515)
|
-
|
(45,059)
|
-
|
-
|
-
|
(149,574)
|
|
|
Write-off
|
(25,751)
|
-
|
(4,333)
|
-
|
-
|
-
|
(30,084)
|
|
|
Total
assets
|
381,143
|
114,974
|
153,071
|
4,287
|
3,181
|
47,143
|
703,799
|
|
|
|
|
|
|
|
|
|
|
|
|
Employees
(average)
|
153
|
11
|
130
|
16
|
93
|
-
|
403
|
|
|
Employees
at year end
|
106
|
12
|
133
|
11
|
90
|
-
|
352
|
|
Approximately 76% of capital expenditure
was incurred by Colombia (67% in 2016 and 66% in 2015), 10% was incurred by Chile (20% in 2016 and 22% in 2015), 8% was incurred
by Argentina (4% in 2016 and nil in 2015), 3% was incurred by Brazil (9% in 2016 and 12% in 2015) and 3% was incurred by Peru (nil
in 2016 and 2015).
Note
6 Segment information (continued)
A reconciliation of total Operating netback
to total profit (loss) before income tax is provided as follows:
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Operating netback
|
228,308
|
122,147
|
118,027
|
|
Administrative expenses
|
(38,937)
|
(32,323)
|
(30,590)
|
|
Geological and geophysical expenses
|
(13,595)
|
(11,503)
|
(13,650)
|
|
Adjusted EBITDA for reportable segments
|
175,776
|
78,321
|
73,787
|
|
Unrealized loss on commodity risk management contracts
|
(13,300)
|
(3,068)
|
-
|
|
Depreciation
(a)
|
(74,885)
|
(75,774)
|
(105,557)
|
|
Share-based payment
|
(4,075)
|
(3,367)
|
(8,223)
|
|
Impairment and write-off of unsuccessful exploration efforts
|
(5,834)
|
(25,702)
|
(179,658)
|
|
Others
(b)
|
1,314
|
977
|
(12,840)
|
|
Operating profit (loss)
|
78,996
|
(28,613)
|
(232,491)
|
|
Financial expenses
|
(53,511)
|
(36,229)
|
(36,924)
|
|
Financial income
|
2,016
|
2,128
|
1,269
|
|
Foreign exchange (loss) profit
|
(2,193)
|
13,872
|
(33,474)
|
|
Profit (Loss) before tax
|
25,308
|
(48,842)
|
(301,620)
|
|
|
(a)
|
Net of capitalised costs for oil stock included in Inventories.
|
|
|
(b)
|
In 2015 includes termination costs (see Note 36). Also includes internally capitalised costs.
|
Note
7 Revenue
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Sale of crude oil
|
279,162
|
145,193
|
162,629
|
|
Sale of gas
|
50,960
|
47,477
|
47,061
|
|
|
330,122
|
192,670
|
209,690
|
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 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 as of 31 December 2017 and therefore all changes in the fair values of its
derivative contracts are recognised as gains or losses in the results of the periods in which they occur.
Note
8 Commodity risk management contracts
(continued)
The following table presents the Group’s
derivative contracts in force as of 31 December 2017:
|
Period
|
Reference
|
Type
|
Volume bbl/d
|
Price US$/bbl
|
|
|
|
|
|
|
|
1 October 2017 - 31 March 2018
|
ICE BRENT
|
Zero Premium Collar
|
4,000
|
50.00 Put 54.90 Call
|
|
1 October 2017 - 31 March 2018
|
ICE BRENT
|
Zero Premium Collar
|
2,000
|
50.00 Put 54.95 Call
|
|
1 January 2018 - 30 June 2018
|
ICE BRENT
|
Zero Premium Collar
|
2,000
|
52.00 Put 60.00 Call
|
|
1 January 2018 - 30 June 2018
|
ICE BRENT
|
Zero Premium Collar
|
1,000
|
52.00 Put 58.40 Call
|
|
1 April 2018 - 30 June 2018
|
ICE BRENT
|
Zero Premium Collar
|
2,000
|
52.00 Put 58.25 Call
|
|
1 January 2018 - 30 June 2018
|
ICE BRENT
|
Zero Premium 3 Way
|
1,000
|
42.00-52.00 Put 59.55 Call
|
|
1 January 2018 - 30 June 2018
|
ICE BRENT
|
Zero Premium 3 Way
|
1,000
|
42.00-52.00 Put 59.50 Call
|
|
1 April 2018 - 30 June 2018
|
ICE BRENT
|
Zero Premium 3 Way
|
1,000
|
42.00-52.00 Put 59.60 Call
|
|
1 January 2018 - 30 June 2018
|
ICE BRENT
|
Zero Premium 3 Way
|
2,000
|
43.00-53.00 Put 64.55 Call
|
|
1 July 2018 - 30 September 2018
|
ICE BRENT
|
Zero Premium 3 Way
|
5,000
|
43.00-53.00 Put 69.00 Call
|
The table below summarizes the gain (loss)
on the commodity risk management contracts:
|
|
2017
|
2016
|
2015
|
|
Realized (loss) gain on commodity risk management contracts
|
(2,148)
|
514
|
-
|
|
Unrealized loss on commodity risk management contracts
|
(13,300)
|
(3,068)
|
-
|
|
Total
|
(15,448)
|
(2,554)
|
-
|
Note
9 Production and operating costs
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Well and facilities maintenance
|
14,722
|
13,160
|
19,974
|
|
Staff costs (Note 11)
|
15,017
|
10,859
|
17,999
|
|
Share-based payment (Notes 11)
|
457
|
622
|
563
|
|
Royalties
|
28,697
|
11,497
|
13,155
|
|
Consumables
|
11,902
|
8,283
|
8,591
|
|
Transportation costs
|
2,969
|
2,281
|
4,511
|
|
Equipment rental
|
5,818
|
3,868
|
3,517
|
|
Safety and Insurance costs
|
2,591
|
2,222
|
3,239
|
|
Gas plant costs
|
6,069
|
6,300
|
2,878
|
|
Field camp
|
2,377
|
1,687
|
2,645
|
|
Non operated blocks costs
|
1,213
|
1,082
|
2,127
|
|
Other costs
|
7,155
|
5,374
|
7,543
|
|
|
98,987
|
67,235
|
86,742
|
Note
10 Depreciation
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Oil and gas properties
|
57,725
|
61,080
|
84,849
|
|
Production facilities and machinery
|
14,558
|
10,788
|
15,467
|
|
Furniture, equipment and vehicles
|
1,948
|
2,702
|
2,850
|
|
Buildings and improvements
|
844
|
920
|
874
|
|
Depreciation of property, plant and equipment
(a)
|
75,075
|
75,490
|
104,040
|
Related to:
|
Productive assets
|
72,283
|
71,868
|
100,316
|
|
Administrative assets
|
2,792
|
3,622
|
3,724
|
|
Depreciation total
(a)
|
75,075
|
75,490
|
104,040
|
(a)
Depreciation without considering
capitalised costs for oil stock included in Inventories.
Note
11 Staff costs and Directors Remuneration
|
|
2017
|
2016
|
2015
|
|
Number of employees at year end
|
405
|
345
|
352
|
|
Amounts in US$ '000
|
|
|
|
|
Wages and salaries
|
44,891
|
36,059
|
40,574
|
|
Share-based payments (Note 30)
|
4,075
|
3,367
|
8,223
|
|
Social security charges
|
5,364
|
3,792
|
6,197
|
|
Director’s fees and allowance
|
3,458
|
2,088
|
1,238
|
|
|
57,788
|
45,306
|
56,232
|
Recognised as follows:
|
Production and operating costs
|
15,474
|
11,481
|
18,562
|
|
Geological and geophysical expenses
|
11,026
|
10,439
|
11,336
|
|
Administrative expenses
|
31,288
|
23,386
|
26,334
|
|
|
57,788
|
45,306
|
56,232
|
|
Board of Directors’ and key managers’ remuneration
|
|
|
|
|
Salaries and fees
|
9,674
|
7,337
|
6,549
|
|
Share-based payments
|
2,322
|
1,211
|
6,544
|
|
Other benefits in kind
|
287
|
112
|
167
|
|
|
12,283
|
8,660
|
13,260
|
Note
11 Staff costs and Directors Remuneration
(continued)
Directors’ Remuneration
|
|
Executive Directors’ Fees
|
Executive Directors’ Bonus
|
Non-Executive Directors’ Fees (in US$)
|
Director Fees Paid in Shares (No. of Shares)
|
Cash Equivalent Total Remuneration
|
|
Gerald O’Shaughnessy
|
US$ 400,000
|
-
|
-
|
-
|
US$ 400,000
|
|
James F. Park
|
US$ 800,000
|
US$ 800,000
|
-
|
-
|
US$ 1,600,000
|
|
Pedro Aylwin
(a)
|
-
|
-
|
-
|
-
|
-
|
|
Peter Ryalls
(b)
|
-
|
-
|
US$ 115,000
|
9,388
|
US$ 165,010
|
|
Juan Cristóbal Pavez
(c)
|
-
|
-
|
US$ 110,000
|
15,408
|
US$ 210,020
|
|
Carlos Gulisano
|
-
|
-
|
US$ 110,000
|
15,408
|
US$ 210,020
|
|
Robert Bedingfield
(d)
|
-
|
-
|
US$ 102,500
|
15,408
|
US$ 202,520
|
|
Michael Dingman
|
-
|
-
|
US$ 46,667
|
8,853
|
US$ 105,012
|
|
Jamie Coulter
|
-
|
-
|
US$ 50,000
|
8,015
|
US$ 112,519
|
a
Pedro Aylwin has a service
contract that provides for him to act as Manager of Corporate Governance so he resigned his fees as Director.
b
Technical Committee Chairman
until his death. Afterwards the Chairman is Carlos Gulisano.
c
Compensation Committee Chairman.
d
Audit Committee Chairman.
The non-executive Directors annual fees
correspond to US$ 80,000 to be settled in cash and US$ 100,000 to be settled in stocks, paid quarterly in equal installments.
In the event that a non-executive Director serves as Chairman of any Board Committees, an additional annual fee of US$ 20,000 shall
apply. A Director who serves as a member of any Board Committees shall receive an annual fee of US$ 10,000. Total payment due shall
be calculated in an aggregate basis for Directors serving in more than one Committee. The Chairman fee shall not be added to the
member’s fee for the same Committee. Payments of Chairmen and Committee members’ fees shall be made quarterly in arrears
and settled in cash only.
Note
12 Geological and geophysical expenses
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Staff costs (Note 11)
|
10,525
|
9,541
|
10,557
|
|
Share-based payment (Notes 11)
|
501
|
898
|
779
|
|
Allocation to capitalised project
|
(6,402)
|
(2,119)
|
(598)
|
|
Other services
|
3,070
|
1,962
|
3,093
|
|
|
7,694
|
10,282
|
13,831
|
Note
13 Administrative expenses
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Staff costs (Note 11)
|
24,713
|
19,451
|
18,215
|
|
Share-based payment (Notes 11)
|
3,117
|
1,847
|
6,881
|
|
Consultant fees
|
5,120
|
3,894
|
4,115
|
|
Office expenses
|
2,506
|
2,217
|
2,535
|
|
Travel expenses
|
2,772
|
1,717
|
1,497
|
|
Director’s fees and allowance (Note 11)
|
3,458
|
2,088
|
1,238
|
|
Communication and IT costs
|
2,109
|
2,013
|
1,791
|
|
Allocation to joint operations
|
(7,646)
|
(4,365)
|
(4,203)
|
|
Other administrative expenses
|
5,905
|
5,308
|
5,402
|
|
|
42,054
|
34,170
|
37,471
|
Note
14 Selling expenses
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Transportation
|
864
|
3,559
|
4,760
|
|
Selling taxes and other
|
272
|
663
|
451
|
|
|
1,136
|
4,222
|
5,211
|
Note
15 Financial results
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Financial expenses
|
|
|
|
|
Interest and amortisation of debt issue costs
|
(27,823)
|
(28,984)
|
(28,983)
|
|
Interest with related parties
|
(2,224)
|
(1,587)
|
(1,560)
|
|
Less: amounts capitalised on qualifying assets
|
611
|
255
|
637
|
|
Borrowings cancellation costs
|
(17,575)
|
-
|
-
|
|
Bank charges and other financial results
|
(3,721)
|
(3,220)
|
(4,443)
|
|
Unwinding of long-term liabilities (Note 28)
|
(2,779)
|
(2,693)
|
(2,575)
|
|
|
(53,511)
|
(36,229)
|
(36,924)
|
|
Financial income
|
|
|
|
|
Interest received
|
2,016
|
2,128
|
1,269
|
|
|
2,016
|
2,128
|
1,269
|
|
Foreign exchange gains and losses
|
|
|
|
|
Foreign exchange (loss) gain
|
(2,193)
|
13,872
|
(33,474)
|
|
|
(2,193)
|
13,872
|
(33,474)
|
|
Total Financial results
|
(53,688)
|
(20,229)
|
(69,129)
|
Note
16 Tax reforms
Colombia
A tax reform has
been enacted in Colombia during December 2016. The legislation included significant changes to certain corporate income tax and
statutory income tax provisions, including rate reductions and the repeal of certain corporate-level taxes. The legislation
also aimed to raise tax revenue mostly by increasing the rate of the value added tax (VAT) to 19% (from 16%) and through a variety
of excise taxes. Most of the tax provisions were effective 1 January 2017.
The legislation
also included the following provisions that are intended to simplify the corporate income tax system by:
|
|
·
|
Eliminating the “CREE” tax
on corporations and the CREE surtax (CREE is the Spanish acronym for the “fairness tax”).
|
|
|
·
|
Introducing a temporary income surtax of
6% for 2017 and 4% for 2018.
|
Accordingly, with
this tax reform, the corporate income tax will have the following rate schedule (applied beyond a limited profit threshold):
|
|
·
|
40% in 2017 (34% income tax plus 6% income
surtax)
|
|
|
·
|
37% in 2018 (33% income tax plus 4% income
surtax)
|
|
|
·
|
33% in 2019 and onwards.
|
There is an increase
in the tax rate on deemed income relating to increases in a taxpayer’s net worth (i.e., the increase in the value of a taxpayer’s
assets); the rate is increased from 3% to 3.5%.
Other changes to
the income tax law were the following:
|
|
·
|
New withholding tax on dividends—with
the applicable rates for non-resident shareholders of: (1) 5% for dividends distributed out of the distributing entity’s
previously taxed profits; and (2) 35% for dividends distributed out of the distributing entity’s previously untaxed profits,
plus an additional 5% after having applied and deducted the initial 35% withholding.
|
|
|
·
|
A general 15% withholding tax rate for
taxable income accrued by non-residents without a permanent establishment (certain special rates may apply).
|
|
|
·
|
Lengthen the statute of limitations with
respect to tax returns and assessments.
|
|
|
·
|
Limit loss carryforwards to 12 years.
|
|
|
·
|
Allow for a deduction of VAT paid on certain
acquisitions or imports of capital goods when calculating the taxpayer’s income tax liability.
|
|
|
·
|
Retain the tax on long-term capital gains
at 10% for both corporations and non-residents.
|
The legislation
also revises and refines tax accounting standards based on IFRS rules.
Note
16 Tax reforms (Continued)
Argentina
A tax reform has
been enacted in Argentina during December 2017. The legislation included significant changes to certain corporate income tax and
statutory income tax provisions, including rate reductions. Most of the tax provisions are effective from fiscal year 2018.
With this tax reform,
the corporate income tax -previously 35%- will have the following rate schedule:
|
|
·
|
25% in 2020 and 2021 and onwards.
|
Other changes include
the following:
|
|
·
|
New withholding tax on dividends—with
the applicable rates for non-resident shareholders of: (1) 7% for dividends distributed out of the distributing entity’s
previously taxed profits of fiscal years 2018 and 2019; and (2) 13% for dividends distributed out of the distributing entity’s
previously taxed profits of fiscal years 2020 and onwards.
|
|
|
·
|
Application of inflation adjustment for
corporate tax purposes is reinstated under certain circumstances.
|
|
|
·
|
Possible tax revaluation of investment
in fixed assets, under payment of a special tax.
|
|
|
·
|
Allow for short term recovery of VAT paid
on acquisitions or imports of capital goods, when non recoverable with VAT on usual sales.
|
Note
17 Income tax
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Current tax
|
(48,449)
|
(12,359)
|
(7,262)
|
|
Deferred income tax (Note 18)
|
5,304
|
555
|
24,316
|
|
|
(43,145)
|
(11,804)
|
17,054
|
Note
17 Income tax (continued)
The tax on the Group’s profit (loss)
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
|
2017
|
2016
|
2015
|
|
Profit (Loss) before tax
|
25,308
|
(48,842)
|
(301,620)
|
|
Tax losses from non-taxable jurisdictions
|
22,708
|
12,318
|
15,852
|
|
Taxable profit (loss)
|
48,016
|
(36,524)
|
(285,768)
|
|
|
|
|
|
|
Income tax calculated at domestic tax rates applicable to Profit (Losses) Income in the respective countries
|
(31,107)
|
(809)
|
62,589
|
|
Tax losses where no deferred tax benefit is recognised
|
(8,111)
|
(6,616)
|
(16,325)
|
|
Effect of currency translation on tax base
|
(2,330)
|
(2,840)
|
(6,776)
|
|
Changes in the income tax rate (Note 16)
|
542
|
220
|
(625)
|
|
Non recoverable tax loss carry-forwards
|
-
|
-
|
(15,537)
|
|
Non-taxable results
(a)
|
(2,139)
|
(1,759)
|
(6,272)
|
|
Income tax
|
(43,145)
|
(11,804)
|
17,054
|
(a)
Includes non-deductible expenses in each jurisdiction and changes in the estimation of deferred tax assets and liabilities.
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 (Argentina, Brazil, Colombia, Peru and Chile) ranges from 15% to 40%.
The Group has significant tax losses available
which can be utilised against future taxable profit in the following countries:
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Argentina
|
4,849
|
2,908
|
3,834
|
|
Chile
(a)
|
345,104
|
280,290
|
209,910
|
|
Brazil
(a)
|
33,721
|
16,057
|
-
|
|
Total tax losses at 31 December
|
383,674
|
299,255
|
213,744
|
(a)
Taxable losses have no expiration
date.
Note
17 Income Tax (continued)
At the balance sheet date deferred tax assets
in respect of tax losses in Argentina and in certain Companies in Chile have not been recognised as there is insufficient evidence
of future taxable profits to offset them (in the case of Argentina, before the statute of limitation of these tax losses causes
them to expire).
Expiring dates for tax losses accumulated at
31 December 2017 are:
|
Expiring date
|
Amounts in US$ '000
|
|
2020
|
754
|
|
2021
|
1,446
|
|
2022
|
2,649
|
Note
18 Deferred income tax
The gross movement on the deferred income tax
account is as follows:
|
Amounts in US$ '000
|
2017
|
2016
|
|
Deferred tax at 1 January
|
20,283
|
17,691
|
|
Reclassification
(a)
|
-
|
574
|
|
Currency translation differences
|
(237)
|
1,463
|
|
Income statement credit
|
5,304
|
555
|
|
Deferred tax at 31 December
|
25,350
|
20,283
|
(a)
Corresponds to differences
between income tax provision and the final tax return presented.
The breakdown and movement of deferred tax
assets and liabilities as of 31 December 2017 and 2016 are as follows:
|
Amounts in US$ '000
|
At the beginning of year
|
Currency
translation
differences
|
(Charged) credited to net profit
|
At end of year
|
|
Deferred tax assets
|
|
|
|
|
|
Difference in depreciation
rates and other
|
19,225
|
(237)
|
(2,817)
|
16,171
|
|
Taxable losses
|
3,828
|
-
|
7,637
|
11,465
|
|
Total 2017
|
23,053
|
(237)
|
4,820
|
27,636
|
|
Total 2016
|
34,646
|
1,463
|
(13,056)
|
23,053
|
Note
18 Deferred income tax (continued)
|
Amounts in US$ '000
|
At the beginning of year
|
Credited to
net profit
|
Reclassification
(a)
|
At end
of year
|
|
Deferred tax liabilities
|
|
|
|
|
|
Difference in depreciation
rates and other
|
(17,308)
|
(2,766)
|
-
|
(20,074)
|
|
Taxable losses
|
14,538
|
3,250
|
-
|
17,788
|
|
Total 2017
|
(2,770)
|
484
|
-
|
(2,286)
|
|
Total 2016
|
(16,955)
|
13,611
|
574
|
(2,770)
|
(a)
Corresponds to differences
between income tax provision and the final tax return presented.
Note
19 Earnings per share
|
Amounts in US$ '000 except for shares
|
2017
|
2016
|
2015
|
|
Numerator:
|
|
|
|
|
Loss for the year attributable to owners
|
(24,228)
|
(49,092)
|
(234,031)
|
|
Denominator:
|
|
|
|
|
Weighted average number of shares used in basic EPS
|
60,093,191
|
59,777,145
|
57,759,001
|
|
(Losses) after tax per share (US$) – basic
|
(0.40)
|
(0.82)
|
(4.05)
|
|
Amounts in US$ '000 except for shares
|
2017
(a)
|
2016
|
2015
|
|
Weighted average number of shares used in basic EPS
|
60,093,191
|
59,777,145
|
57,759,001
|
|
Effect of dilutive potential common shares
(a)
|
|
|
|
|
Weighted average
number of common shares for the
purposes of diluted earnings per
shares
|
60,093,191
|
59,777,145
|
57,759,001
|
|
(Losses) after tax per share (US$) – diluted
|
(0.40)
|
(0.82)
|
(4.05)
|
(a)
For the year ended 31 December
2017, there were 4,564,777 (1,390,706 in 2016 and 1,032,279 in 2015) of potential shares that could have a dilutive impact but
were considered antidilutive due to negative earnings.
Note
20 Property, plant and equipment
|
Amounts in US$'000
|
|
Oil & gas properties
|
Furniture, equipment
and vehicles
|
Production facilities and machinery
|
Buildings
and improvements
|
Construction in progress
|
Exploration and evaluation assets
(b)
|
Total
|
|
Cost at 1 January 2015
|
|
749,947
|
12,057
|
111,646
|
9,527
|
59,425
|
140,444
|
1,083,046
|
|
Additions
|
|
(4,640)
(a)
|
954
|
-
|
272
|
36,543
|
12,299
|
45,428
|
|
Currency translation differences
|
|
(27,522)
|
(182)
|
(2,577)
|
(92)
|
-
|
(1,510)
|
(31,883)
|
|
Disposals
|
|
(241)
|
(13)
|
(1,685)
|
(84)
|
-
|
-
|
(2,023)
|
|
Write-off / Impairment loss
|
|
(128,956)
|
-
|
(13,242)
|
-
|
(7,376)
|
(30,084)
(c)
|
(179,658)
|
|
Transfers
|
|
60,404
|
929
|
30,690
|
895
|
(58,769)
|
(34,149)
|
-
|
|
Cost at 31 December 2015
|
|
648,992
|
13,745
|
124,832
|
10,518
|
29,823
|
87,000
|
914,910
|
|
Additions
|
|
(3,531)
(a)
|
406
|
466
|
-
|
20,322
|
18,181
|
35,844
|
|
Currency translation differences
|
|
16,132
|
126
|
2,077
|
35
|
73
|
790
|
19,233
|
|
Disposals
|
|
-
|
(22)
|
-
|
-
|
-
|
-
|
(22)
|
|
Write-off / Impairment reversal
|
|
5,664
|
-
|
-
|
-
|
-
|
(31,366)
(d)
|
(25,702)
|
|
Transfers
|
|
24,984
|
102
|
5,038
|
-
|
(17,292)
|
(12,832)
|
-
|
|
Cost at 31 December 2016
|
|
692,241
|
14,357
|
132,413
|
10,553
|
32,926
|
61,773
|
944,263
|
|
Additions
|
|
7,997
(a)
|
954
|
-
|
-
|
66,953
|
49,455
|
125,359
|
|
Currency translation differences
|
|
(1,142)
|
(12)
|
(147)
|
(3)
|
(62)
|
(104)
|
(1,470)
|
|
Disposals
|
|
-
|
(112)
|
-
|
(189)
|
-
|
-
|
(301)
|
|
Write-off / Impairment reversal
|
|
-
|
-
|
-
|
-
|
-
|
(5,834)
(e)
|
(5,834)
|
|
Transfers
|
|
77,408
|
211
|
25,130
|
-
|
(61,827)
|
(40,922)
|
-
|
|
Cost at 31 December 2017
|
|
776,504
|
15,398
|
157,396
|
10,361
|
37,990
|
64,368
|
1,062,017
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and write-down at 1 January 2015
|
|
(240,439)
|
(4,449)
|
(45,147)
|
(2,244)
|
-
|
-
|
(292,279)
|
|
Depreciation
|
|
(84,849)
|
(2,850)
|
(15,467)
|
(874)
|
-
|
-
|
(104,040)
|
|
Disposals
|
|
-
|
8
|
-
|
15
|
-
|
-
|
23
|
|
Currency translation differences
|
|
4,115
|
(26)
|
-
|
(92)
|
-
|
-
|
3,997
|
|
Depreciation and write-down at 31 December 2015
|
|
(321,173)
|
(7,317)
|
(60,614)
|
(3,195)
|
-
|
-
|
(392,299)
|
|
Depreciation
|
|
(61,080)
|
(2,702)
|
(10,788)
|
(920)
|
-
|
-
|
(75,490)
|
|
Disposals
|
|
-
|
8
|
-
|
-
|
-
|
-
|
8
|
|
Currency translation differences
|
|
(2,486)
|
(38)
|
(296)
|
(16)
|
-
|
-
|
(2,836)
|
|
Depreciation and write-down at 31 December 2016
|
|
(384,739)
|
(10,049)
|
(71,698)
|
(4,131)
|
-
|
-
|
(470,617)
|
|
Depreciation
|
|
(57,725)
|
(1,948)
|
(14,558)
|
(844)
|
-
|
-
|
(75,075)
|
|
Disposals
|
|
-
|
73
|
-
|
38
|
-
|
-
|
111
|
|
Currency translation differences
|
|
930
|
8
|
24
|
5
|
-
|
-
|
967
|
|
Depreciation and write-down at 31 December 2017
|
|
(441,534)
|
(11,916)
|
(86,232)
|
(4,932)
|
-
|
-
|
(544,614)
|
|
|
|
|
|
|
|
|
|
|
|
Carrying amount at 31
December 2015
|
|
327,819
|
6,428
|
64,218
|
7,323
|
29,823
|
87,000
|
522,611
|
|
Carrying amount at 31
December 2016
|
|
307,502
|
4,308
|
60,715
|
6,422
|
32,926
|
61,773
|
473,646
|
|
Carrying amount at 31
December 2017
|
|
334,970
|
3,482
|
71,164
|
5,429
|
37,990
|
64,368
|
517,403
|
Note
20 Property, plant and equipment (continued)
(a)
Corresponds to the effect
of change in estimate of assets retirement obligations.
(b)
Exploration wells movement
and balances are shown in the table below; seismic and other exploratory assets amount to US$ 53,764,000 (US$ 53,523,000 in 2016
and US$ 64,094,000 in 2015).
|
Amounts in US$ '000
|
Total
|
|
Exploration wells at 31 December 2015
|
22,906
|
|
Additions
|
15,088
|
|
Write-offs
|
(19,949)
|
|
Transfers
|
(9,795)
|
|
Exploration wells at 31 December 2016
|
8,250
|
|
Additions
|
35,299
|
|
Write-offs
|
(3,664)
|
|
Transfers
|
(29,281)
|
|
Exploration wells at 31 December 2017
|
10,604
|
As of 31 December 2017, there were two exploratory
wells that have been capitalised for a period less than a year amounting to US$ 4,488,000 and two exploratory wells that have been
capitalised for a period over a year amounting to US$ 6,116,000.
(c)
Corresponds to the cost of
two unsuccessful exploratory wells in Colombia (one well in CPO4 Block and one well in Llanos 32). The charge also includes the
loss generated by the write-off of the seismic cost for Flamenco Block in Chile generated by the relinquishment of 143 sq km in
November 2015 and the write off of two wells drilled in previous years in the same block for which no additional work would be
performed.
(d)
Corresponds to the write-off
of five wells drilled in previous years in the Chilean blocks for which no additional work would be performed, the loss generated
by the write-off of the seismic cost for Llanos 62 Block in Colombia generated by the relinquishment of the area in September 2016.
In addition, during September 2016, five blocks in Brazil were relinquished so the associated investment was written off.
(e)
Corresponds to five unsuccessful
exploratory wells, one well drilled in Colombia (Llanos 34 Block), one well drilled in Brazil (REC-T-94 Block) and three non-operated
wells drilled in Argentina (Puelen and Sierra del Nevado Blocks) in 2017. The charge also includes the loss generated by the write-off
of the seismic cost for Campanario and Isla Norte Blocks in Chile generated by the relinquishment of 327 sq km in 2017.
Note
21 Subsidiary undertakings
The following chart illustrates main companies
of the Group structure as of 31 December 2017
(a)
:
(a)
LGI is not a subsidiary,
it is Non-controlling interest.
Non controlling interest held by LGI:
|
|
·
|
Consolidated Statement of Comprehensive
Income: Total comprehensive income for the year 2017 include a profit of US$ 13,536,000 (profit of US$ 2,791,000 in 2016 and loss
of US$ 7,085,000 in 2015), a loss of US$ 6,200,000 (US$ 10,379,000 in 2016 and US$ 33,260,000 in 2015) and a loss of US$ 945,000
(US$ 3,966,000 in 2016 and US$ 10,190,000 in 2015) corresponding to non-controlling interest held by LGI in GeoPark Colombia Coöperatie
U.A., GeoPark Chile S.A. and GeoPark TdF S.A., respectively.
|
|
|
·
|
Consolidated Statement of Financial Position:
Total Equity as of 31 December 2017 includes US$ 29,330,000 (US$ 16,168,000 in 2016), US$ 15,953,000 (US$ 22,082,000 in 2016) and
a negative amount of US$ 3,368,000 (US$ 2,422,000 in 2016) corresponding to non-controlling interest held by LGI in GeoPark Colombia
Coöperatie U.A., GeoPark Chile S.A. and GeoPark TdF S.A., respectively.
|
|
|
·
|
Consolidated Statement of Changes in Equity:
Dividends distributed to non-controlling interest of US$ 479,000 in 2017 (US$ 6,406,000 in 2016) correspond to non-controlling
interest held by LGI in GeoPark Colombia Coöperatie U.A.
|
Note
21 Subsidiary undertakings (continued)
Details of the subsidiaries and joint operations
of the Group are set out below:
|
|
Name and registered office
|
|
|
Ownership interest
|
|
Subsidiaries
|
GeoPark Argentina Limited (Bermuda)
|
|
|
100%
|
|
|
GeoPark Argentina Limited – Argentinean Branch
|
|
|
100% (a)
|
|
|
GeoPark Latin America Limited (Bermuda)
|
|
|
100%
|
|
|
GeoPark Latin America Limited – Agencia en Chile
|
|
|
100% (a)
|
|
|
GeoPark S.A. (Chile)
|
|
|
100% (a) (b)
|
|
|
GeoPark Brazil Exploração y Produção de Petróleo e Gás Ltda. (Brazil)
|
|
|
100% (a)
|
|
|
GeoPark Chile S.A. (Chile)
|
|
|
80% (a) (c)
|
|
|
GeoPark Fell S.p.A. (Chile)
|
|
|
80% (a) (c)
|
|
|
GeoPark Magallanes Limitada (Chile)
|
|
|
80% (a) (c)
|
|
|
GeoPark TdF S.A. (Chile)
|
|
|
68.8% (a) (d)
|
|
|
GeoPark Colombia S.A. (Chile)
|
|
|
100% (a) (b)
|
|
|
GeoPark Colombia SAS (Colombia)
|
|
|
80% (a) (c)
|
|
|
GeoPark Latin America S.L.U. (Spain)
|
|
|
100% (a)
|
|
|
GeoPark Colombia Coöperatie U.A. (The Netherlands)
|
|
|
80% (a) (c)
|
|
|
GeoPark S.A.C. (Peru)
|
|
|
100% (a)
|
|
|
GeoPark Perú S.A.C. (Peru)
|
|
|
100% (a)
|
|
|
GeoPark Operadora del Perú S.A.C. (Peru)
|
|
|
100% (a)
|
|
|
GeoPark Peru S.L.U. (Spain)
|
|
|
100% (a)
|
|
|
GeoPark Brazil S.L.U. (Spain)
|
|
|
100% (a)
|
|
|
GeoPark Colombia E&P S.A.(Panama)
|
|
|
100% (a) (b)
|
|
|
GeoPark Colombia E&P Sucursal Colombia (Colombia)
|
|
|
100% (a) (b)
|
|
|
GeoPark Mexico S.A.P.I. de C.V. (Mexico)
|
|
|
100% (b)
|
|
|
Ogarrio E&P S.A.P.I. de C.V. (Mexico)
|
|
|
51% (a) (b)
|
|
|
GeoPark (UK) Limited (United Kingdom)
|
|
|
100%
|
|
Joint operations
|
Tranquilo Block (Chile)
|
|
|
50% (e)
|
|
|
Flamenco Block (Chile)
|
|
|
50% (e)
|
|
|
Campanario Block (Chile)
|
|
|
50% (e)
|
|
|
Isla Norte Block (Chile)
|
|
|
60% (e)
|
|
|
Yamu/Carupana Block (Colombia)
|
|
|
89.5%/100% (e)
|
|
|
Llanos 34 Block (Colombia)
|
|
|
45% (e)
|
|
|
Llanos 32 Block (Colombia)
|
|
|
12.5%
|
|
|
CPO-4 Block (Colombia)
|
|
|
50% (e)
|
|
|
Puelen Block (Argentina)
|
|
|
18%
|
|
|
Sierra del Nevado Block (Argentina)
|
|
|
18%
|
|
|
CN-V Block (Argentina)
|
|
|
50% (e)
|
|
|
Manati Field (Brazil)
|
|
|
10%
|
|
|
(c)
|
LG International has 20% interest.
|
|
|
(d)
|
LG International has 20% interest through GeoPark Chile
S.A. and a 14% direct interest, totaling 31.2%.
|
|
|
(e)
|
GeoPark is the operator.
|
Corporate structure reorganization
During 2017, the Company decided to incorporate
a subsidiary in the United Kingdom to conduct the businesses in Latin America by adopting all the key resolutions and decisions
necessary for such purpose. Also, a tax reform enacted in The Netherlands during September 2017 that would harm the Group´s
cashflow, forced the Group to decide the re-domiciliation of its 100% owned Dutch subsidiaries to Spain.
Note
22 Prepaid taxes
|
Amounts in US$ '000
|
2017
|
2016
|
|
V.A.T.
|
27,674
|
14,052
|
|
Income tax payments in advance
|
1,258
|
4,517
|
|
Other prepaid taxes
|
939
|
98
|
|
Total prepaid taxes
|
29,871
|
18,667
|
|
Classified as follows:
|
|
|
|
Current
|
26,048
|
15,815
|
|
Non current
|
3,823
|
2,852
|
|
Total prepaid taxes
|
29,871
|
18,667
|
Note
23 Inventories
|
Amounts in US$ '000
|
|
2017
|
2016
|
|
Crude oil
|
|
1,969
|
1,521
|
|
Materials and spares
|
|
3,769
|
1,994
|
|
|
|
5,738
|
3,515
|
Note
24 Trade receivables and Prepayments
and other receivables
|
Amounts in US$ '000
|
2017
|
2016
|
|
Trade receivables
|
19,519
|
18,426
|
|
|
19,519
|
18,426
|
|
To be recovered from co-venturers (Note 33)
|
2,455
|
3,311
|
|
Related parties receivables (Note 33)
|
56
|
42
|
|
Prepayments and other receivables
|
5,242
|
4,290
|
|
|
7,753
|
7,643
|
|
Total
|
27,272
|
26,069
|
|
|
|
|
|
Classified as follows:
|
|
|
|
Current
|
27,037
|
25,828
|
|
Non current
|
235
|
241
|
|
Total
|
27,272
|
26,069
|
Trade receivables that are aged by less
than three months are not considered impaired. As of 31 December 2017 and 2016, there are no balances that were aged by more than
3 months, but not impaired. These relate to customers for whom there is no recent history of default. There are no balances overdue
between 31 days and 90 days as of 31 December 2017 and 2016.
Note
24 Trade receivables and Prepayments
and other receivables (continued)
Movements on the Group provision for impairment
are as follows:
|
Amounts in US$ '000
|
2017
|
2016
|
|
At 1 January
|
741
|
596
|
|
Foreign exchange (income) loss
|
(147)
|
145
|
|
|
594
|
741
|
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.
Note
25 Financial instruments by category
|
Amounts in US$ '000
|
Assets as per statement of financial position
|
|
|
|
2017
|
2016
|
|
|
Loans and receivables
|
|
|
|
|
|
Trade receivables
|
|
19,519
|
18,426
|
|
|
To be recovered from co-venturers (Note 33)
|
|
2,455
|
3,311
|
|
|
Other financial assets
(a)
|
|
43,488
|
22,027
|
|
|
Cash and cash equivalents
|
|
134,755
|
73,563
|
|
|
|
|
200,217
|
117,327
|
|
(a)
Non current other financial
assets relate to contributions made for environmental obligations according to Colombian and Brazilian government regulations and
also include a non current account receivable with the previous owners of one of the Colombian subsidiaries (see Note 28). Current
other financial assets corresponds to the security deposit granted in relation to the purchase of Argentinian assets (see Note
35) and short term investments with original maturities up to twelve months and over three months.
Note
25 Financial instruments by category (continued)
|
|
Liabilities as per statement of financial position
|
|
Amounts in US$ '000
|
2017
|
2016
|
|
Liabilities at fair value through profit and loss
|
|
|
|
Derivative financial instrument liabilities
|
19,289
|
3,067
|
|
|
19,289
|
3,067
|
|
Other financial liabilities at amortised cost
|
|
|
|
Trade payables
|
52,557
|
23,650
|
|
Payables to related parties (Note 33)
|
31,184
|
27,801
|
|
To be paid to co-venturers (Note 33)
|
10,015
|
1,614
|
|
Borrowings
|
426,204
|
358,672
|
|
|
519,960
|
411,737
|
|
Total financial liabilities
|
539,249
|
414,804
|
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
|
2017
|
2016
|
|
Trade receivables
|
|
|
|
Counterparties with an external credit rating (Moody’s)
|
|
|
|
B2
|
70
|
7,056
|
|
Ba3
|
8,788
|
-
|
|
Baa3
|
3,614
|
3,729
|
|
Counterparties without an external credit rating
|
|
|
|
Group1
(a)
|
7,047
|
7,641
|
|
Total trade receivables
|
19,519
|
18,426
|
(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 are denominated in Brazilian Real.
Note
25 Financial instruments by category
(continued)
|
Cash at bank and other financial assets
(a)
|
|
|
|
|
Amounts in US$ '000
|
|
2017
|
2016
|
|
Counterparties with an external credit rating
(Moody’s,
S&P, Fitch, BRC Investor Services)
|
|
|
|
|
A1
|
|
553
|
813
|
|
A2
|
|
298
|
-
|
|
A3
|
|
63,853
|
-
|
|
Aaa
|
|
15,040
|
-
|
|
Aa3
|
|
11,401
|
42,798
|
|
AAA
|
|
19,634
|
14
|
|
B2
|
|
31
|
-
|
|
Ba1
|
|
18
|
-
|
|
Ba2
|
|
7
|
-
|
|
Baa1
|
|
307
|
100
|
|
Baa2
|
|
4,078
|
4,094
|
|
Ba3
|
|
2,815
|
3,497
|
|
B3
|
|
-
|
10
|
|
BBB
|
|
15,064
|
-
|
|
Counterparties without an external credit rating
|
|
45,123
|
44,252
|
|
Total
|
|
178,222
|
95,578
|
(a)
The remaining balance sheet
item ‘cash and cash equivalents’ corresponds to cash on hand amounting to US$ 21,000 (US$ 12,000 in 2016).
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.
|
Amounts in US$ '000
|
Less than 1 year
|
Between 1 and 2 years
|
Between 2 and 5 years
|
Over 5 years
|
|
At 31 December 2017
|
|
|
|
|
|
Borrowings
|
27,625
|
27,625
|
82,875
|
480,250
|
|
Trade payables
|
52,557
|
-
|
-
|
-
|
|
Payables to related parties
|
7,331
|
2,068
|
27,087
|
-
|
|
|
87,513
|
29,693
|
109,962
|
480,250
|
|
At 31 December 2016
|
|
|
|
|
|
Borrowings
|
48,958
|
43,304
|
355,064
|
-
|
|
Trade payables
|
23,650
|
-
|
-
|
-
|
|
Payables to related parties
|
1,561
|
1,561
|
22,018
|
-
|
|
|
74,169
|
44,865
|
377,082
|
-
|
Note
25 Financial instruments by category (continued)
Fair value measurement of financial instruments
Accounting policies for financial instruments
have been applied to classify as either: loans and receivables, held-to-maturity, available-for-sale, or fair value through profit
and loss. 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.
(a) Fair value hierarchy
The following table presents the Group’s
financial assets and financial liabilities measured and recognised at fair value at 31 December 2017 and 2016 on a recurring basis:
|
Amounts in US$ '000
|
Level 2
|
At 31 December 2017
|
|
Liabilities
|
|
|
|
Derivative financial instrument liabilities
|
|
|
|
Commodity risk management contracts
|
19,289
|
19,289
|
|
Total Liabilities
|
19,289
|
19,289
|
|
Amounts in US$ '000
|
Level 2
|
At 31 December
2016
|
|
Liabilities
|
|
|
|
Derivative financial instrument liabilities
|
|
|
|
Commodity risk management contracts
|
3,067
|
3,067
|
|
Total Liabilities
|
3,067
|
3,067
|
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 at 31 December 2017.
Note
25 Financial instruments by category (continued)
Fair value measurement of financial instruments
(continued)
(b) 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 market-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.
|
(c) Fair values of other financial instruments
(unrecognised)
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
at 31 December 2017 amounts to US$ 425,118,000 (US$ 346,180,000 in 2016). The fair values are based on cash flows discounted using a rate based on the borrowing rate of 6.90%
(7.60% in 2016) and are within level 2 of the fair value hierarchy.
Note
26 Share capital
|
Issued share capital
|
2017
|
2016
|
|
Common stock (amounts in US$ ‘000)
|
61
|
60
|
|
The share capital is distributed as follows:
|
|
|
|
Common shares, of nominal US$ 0.001
|
60,596,219
|
59,940,881
|
|
Total common shares in issue
|
60,596,219
|
59,940,881
|
|
|
|
|
|
Authorised 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:
Common shares
As of 31 December 2017, 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;
|
|
GeoPark common shares history
|
Date
|
Shares issued (millions)
|
Shares closing (millions)
|
US$(`000)
Closing
|
|
Shares outstanding at the end of 2015
|
|
|
59.5
|
59
|
|
Stock awards
|
Feb 2016
|
0.4
|
59.9
|
60
|
|
Stock awards
|
Dec 2016
|
0.5
|
60.4
|
60
|
|
Stock awards
|
Dec 2016
|
0.1
|
60.5
|
60
|
|
Buyback program
|
Dec 2016
|
(0.6)
|
59.9
|
60
|
|
Shares outstanding at the end of 2016
|
|
|
59.9
|
60
|
|
Stock awards
|
Jan 2017
|
0.1
|
60.0
|
60
|
|
Stock awards
|
Dec 2017
|
0.1
|
60.1
|
60
|
|
Stock awards
|
Dec 2017
|
0.5
|
60.6
|
61
|
|
Shares outstanding at the end of 2017
|
|
|
60.6
|
61
|
Note
26 Share capital (continued)
Stock Award Program and Other Share Based
Payments
On 14 December 2017, 490,000 common shares
were allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating a share premium of US$ 2,513,000.
On 15 December 2016, 379,500 common shares
were allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating a share premium of US$ 3,940,000.
On 12 November 2015 and 22 December 2015,
817,600 and 478,000 common shares were allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating
a share premium of US$ 11,359,000 and US$ 3,577,000, respectively.
In January 2017, 82,306 shares were issued
to key management as bonus compensation, generating a share premium of US$ 332,000.
On 8 February 2016, 468,405 shares were
issued to Executive Directors and key management as bonus compensation, generating a share premium of US$ 1,512,000.
On 13 September 2017, 12,546 shares were
issued pursuant to a consulting agreement for services rendered to GeoPark Limited generating a share premium of US$ 43,000.
On 6 September 2016, 8,333 shares were issued
pursuant to a consulting agreement for services rendered to GeoPark Limited generating a share premium of US$ 38,000.
On 30 November 2015, 720,000 new common
shares were issued to the Executive Directors, generating a share premium of US$ 7,309,000.
During 2017, the Company issued 70,485 (137,897
in 2016 and 99,555 in 2015) shares to Non-Executive Directors in accordance with contracts as compensation, generating a share
premium of US$ 257,000 (US$ 541,848 in 2016 and US$ 486,692 in 2015). The amount of shares issued is determined considering
the contractual compensation and the fair value of the shares for each relevant period.
Buyback Program
On 19 December 2014, the Company approved
a program to repurchase up to US$ 10,000,000 of common shares, par value US$ 0.001 per share of the Company (the “Repurchase
Program”). The Repurchase Program began on 19 December 2014 and was resumed on 14 April 2015 and then on 10 June 2015, expiring
on 18 August 2015. During 2016, the Repurchase Program began on 6 April 2016 and then was resumed during the year until November
2016. The Shares repurchased will be used to offset, in part, any expected dilution effects resulting from the Group’s employee
incentive schemes, including grants under the Company’s Stock Award Plan and the Limited Non-Executive Director Plan. In
2017, no shares were repurchased. During 2016 and 2015, the Company purchased 588,868 and 370,074 73,082 common shares for a total
amount of US$ 1,991,000 and US$ 1,615,000, respectively. These transactions had no impact on the Group’s results.
Note
27 Borrowings
|
Amounts in US$ '000
|
2017
|
2016
|
|
Outstanding amounts as of 31 December
|
|
|
|
2024 Notes (a)
|
426,124
|
-
|
|
Notes GeoPark Latin America Agencia en Chile (b)
|
-
|
304,059
|
|
Banco Itaú (c)
|
-
|
49,763
|
|
Banco de Chile (d)
|
-
|
4,709
|
|
Banco de Crédito e Inversiones (e)
|
80
|
141
|
|
|
426,204
|
358,672
|
|
Classified as follows:
|
|
|
|
Current
|
7,664
|
39,283
|
|
Non current
|
418,540
|
319,389
|
(a) During September 2017, the Company successfully
placed US$ 425,000,000 notes which were offered to qualified institutional buyers in accordance with Rule 144A under the United
States Securities Act, and outside the United States to non-U.S. persons in accordance with Regulation S under the United States
Securities Act.
The Notes carry a coupon of 6.50% per annum.
Final maturity of the notes will be 21 September 2024. The Notes are secured with a pledge of all of the equity interests of the
Company, directly or indirectly, in GeoPark Colombia Coöperatie U.A. and GeoPark Chile S.A.. The debt issuance cost for this
transaction amounted to US$ 6,683,000 (debt issuance effective rate: 6.90%). The indenture governing the Notes due 2024 includes
incurrence test covenants that provides among other things, that, during the first two years from the issuance date, the Net Debt
to Adjusted EBITDA ratio should not exceed 3.5 times and the Adjusted EBITDA to Interest ratio should exceed 2 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 indenture 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, (other than in each case, certain specific exceptions). As
of the date of these Consolidated Financial Statements, the Company is in compliance of all the indenture’s provisions and
covenants.
The net proceeds from the Notes were used
by the Company (i) to make a capital contribution to its wholly-owned subsidiary, GeoPark Latin America Limited Agencia en Chile
(“GeoPark LA Agencia”), providing it with sufficient funds to fully repay the 7.50% senior secured notes due 2020 and
to pay any related fees and expenses, including call premium, and (ii) for general corporate purposes, including capital expenditures
and to repay existing indebtedness.
Note
27 Borrowings (continued)
(b) During February 2013, the Group successfully
placed US$ 300,000,000 notes which were offered under Rule 144A and Regulation S exemptions of the United States Securities laws.
The Notes carried a coupon of 7.50% per annum and mature on 11 February 2020. These Notes were fully repaid in September 2017.
(c) During March 2014, GeoPark executed
a loan agreement with Itaú BBA International for US$ 70,450,000 to finance the acquisition of a 10% working interest
in the Manatí field in Brazil. The loan was fully repaid in September 2017.
(d) During December 2015, GeoPark executed
a loan agreement with Banco de Chile for US$ 7,028,000 to finance the start-up of new Ache gas field in GeoPark-operated Fell
Block. The interest rate applicable to this loan is LIBOR plus 2.35% per annum. The interest and the principal have been paid on
monthly basis; with a six months grace period, with final maturity on December 2017. As of the date of these Consolidated Financial
Statements, the loan was fully repaid.
(e) During February 2016, GeoPark executed
a loan agreement with Banco de Crédito e Inversiones for US$ 186,000 to finance the acquisition of vehicles for the
Chilean operation. The interest rate applicable to this loan is 4.14% per annum. The interest and the principal will be paid on
monthly basis, with final maturity on February 2019.
As of the date of these Consolidated Financial
Statements, the Group has available credit lines for over US$ 33,000,000.
Note
28 Provisions and other long-term liabilities
|
Amounts in US$ ‘000
|
Asset retirement obligation
|
Deferred
Income
|
Other
|
Total
|
|
At 1 January 2016
|
31,617
|
5,033
|
5,800
|
42,450
|
|
Addition to provision
|
1,195
|
1,375
|
2,686
|
5,256
|
|
Recovery of abandonments costs
|
(5,504)
|
-
|
-
|
(5,504)
|
|
Exchange difference
|
(1,614)
|
-
|
538
|
(1,076)
|
|
Foreign currency translation
|
1,614
|
-
|
-
|
1,614
|
|
Amortisation
|
-
|
(2,924)
|
-
|
(2,924)
|
|
Unwinding of discount
|
2,554
|
-
|
139
|
2,693
|
|
At 31 December 2016
|
29,862
|
3,484
|
9,163
|
42,509
|
|
Addition to provision
|
5,943
|
-
|
2,220
|
8,163
|
|
Exchange difference
|
134
|
-
|
1,154
|
1,288
|
|
Foreign currency translation
|
(134)
|
-
|
-
|
(134)
|
|
Amortisation
|
-
|
(657)
|
-
|
(657)
|
|
Unwinding of discount
|
2,607
|
-
|
172
|
2,779
|
|
Unused amounts reversed
|
-
|
-
|
(2,535)
|
(2,535)
|
|
Amounts used during the year
|
(337)
|
(1,375)
|
(3,417)
|
(5,129)
|
|
At 31 December 2017
|
38,075
|
1,452
|
6,757
|
46,284
|
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 contributions
received to improve the project economics of the gas wells in Chile. The amortisation is in line with the related asset. The addition
in 2016 and the amounts used in 2017 correspond to the deferred income related to the take or pay provision associated to gas sales
in Brazil.
As of 31 December 2016, Other included a
provision for an amount of US$ 5,636,000 related to fiscal controversies associated to income taxes in one of the Colombian subsidiaries.
These controversies related to fiscal periods prior to the acquisition of these subsidiaries by the Group. During 2017, GeoPark
settled the controversies by paying a total amount of US$ 3,389,000 to the tax authority, under a valid tax amnesty. In connection
to this, the Group recorded an account receivable with the previous owners for the amount paid under the tax amnesty, considering
the contractual right of recovering amounts paid related to fiscal years prior to the acquisition. This account receivable is recognised
under other financial assets in the balance sheet. In addition, actions taken by the Group to maximize ongoing work projects and
to reduce expenses, including renegotiations and reduction of oil and gas service contracts and other initiatives included in the
cost cutting program adopted may expose the Group to claims and contingencies from interested parties that may have a negative
impact on its business, financial condition, results of operations and cash flows. So, the additions in 2016 reflects the future
contingent payments in connection with claims of third parties.
Note
29 Trade and other payables
|
Amounts in US$ '000
|
2017
|
2016
|
|
V.A.T
|
1,118
|
1,102
|
|
Trade payables
|
52,557
|
23,650
|
|
Payables to related parties
(a)
(Note 33)
|
31,184
|
27,801
|
|
Customer advance payments (Note 3)
|
10,000
|
20,000
|
|
Staff costs to be paid
|
9,143
|
7,749
|
|
Royalties to be paid
|
4,110
|
1,503
|
|
Taxes and other debts to be paid
|
4,191
|
3,355
|
|
To be paid to co-venturers (Note 33)
|
10,015
|
1,614
|
|
|
122,318
|
86,774
|
|
Classified as follows:
|
|
|
|
Current
|
96,397
|
52,008
|
|
Non current
|
25,921
|
34,766
|
(a)
The outstanding
amount corresponds to advanced cash call payments granted by LGI to GeoPark Chile S.A. for financing Chilean operations in TdF’s
blocks. The expected maturity of these balances is July 2020 and the applicable interest rate is 8% per annum.
The average credit period (expressed as
creditor days) during the year ended 31 December 2017 was 95 days (2016: 83 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.
Note
30 Share-based payment
IPO Award Program and Executive Stock
Option plan
The Group has established different stock
awards programs and other share-based payment plans to incentivise the Directors, senior management and employees, enabling them
to benefit from the increased market capitalisation of the Company.
Stock Award Program and Other Share Based
Payments
During 2008, GeoPark Shareholders voted
to authorize the Board to use up to 12% of the issued share capital of the Company at the relevant time for the purposes of the
Performance-based Employee Long-Term Incentive Plan.
Note
30 Share-based payment (continued)
During 2016, the Group approved a share-based
compensation program for 1,619,105 shares. Main characteristics of the Stock Awards Programs are:
|
|
·
|
All
employees are eligible.
|
|
|
·
|
Exercise
price is equal to the nominal value of shares.
|
|
|
·
|
Vesting
period is three years.
|
|
|
·
|
Each
employee could receive up to three salaries by achieving the following conditions: continue to be an employee, the stock market
price at the date of vesting should be above US$ 3 and obtain the Group minimum production, adjusted EBITDA and reserves target
for the year of vesting.
|
Also during 2016, the Group approved a plan
named Value Creation Plan (“VCP”) oriented to Top Management. Main characteristics of the VCP are:
|
|
·
|
Awards payables in a variable number of
shares which shall not exceed the quantity of 2,976,781 shares.
|
|
|
·
|
Subject to certain market conditions, among
others, reaching a stock market price for the Company shares of US$ 4.05 at vesting date.
|
|
|
·
|
Vesting date: 31 December 2018.
|
VCP has been classified as an equity-settled
plan.
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:
|
Year of issuance
|
Awards at the beginning
|
Awards granted in the year
|
Awards forfeited
|
Awards exercised
|
Awards at year end
|
Charged to
net loss / profit
|
|
2017
|
2016
|
2015
|
|
2016
|
1,619,105
|
-
|
31,109
|
-
|
1,587,996
|
865
|
445
|
-
|
|
2014
|
490,000
|
-
|
-
|
490,000
|
-
|
838
|
821
|
898
|
|
2013
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
594
|
|
2012
|
-
|
-
|
-
|
-
|
-
|
-
|
855
|
636
|
|
2011
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
879
|
|
Subtotal
|
|
|
|
|
|
1,703
|
2,121
|
3,007
|
|
Stock options to Executive Directors
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
2,390
|
|
Shares granted to Non-Executive Directors
|
-
|
70,485
|
|
70,485
|
|
454
|
400
|
371
|
|
VCP 2013
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
617
|
|
VCP 2016
|
-
|
-
|
-
|
-
|
-
|
1,868
|
934
|
-
|
|
Executive Directors Bonus
|
-
|
-
|
-
|
-
|
-
|
-
|
(325)
|
400
|
|
Key Management Bonus
|
82,306
|
-
|
-
|
82,306
|
-
|
-
|
202
|
1,438
|
|
Stock awards for service contracts
|
-
|
12,546
|
-
|
12,546
|
-
|
50
|
35
|
-
|
|
|
2,191,411
|
83,031
|
31,109
|
655,337
|
1,587,996
|
4,075
|
3,367
|
8,223
|
The awards that are forfeited correspond
to employees that had left the Group before vesting date.
Note
31 Interests in Joint operations
The Group has interests in joint operations,
which are engaged in the exploration of hydrocarbons in Chile, Colombia, Brazil and Argentina.
In Chile, GeoPark is the operator in all
the blocks. In Colombia, GeoPark is the operator in Llanos 34 and Yamu/Carupana blocks. In Argentina, GeoPark is the operator in
CN-V block.
The following amounts represent the Group’s
share in the assets, liabilities and results of the joint operations which have been recognised in the Consolidated Statement of
Financial Position and Statement of Income:
|
Subsidiary /
Joint operation
|
Interest
|
PP&E
E&E Assets
|
Other
Assets
|
Total
Assets
|
Total
Liabilities
|
NET ASSETS/ (LIABILITIES)
|
Revenue
|
Operating (loss)
profit
|
|
2017
|
|
|
|
|
|
|
|
|
|
GeoPark Magallanes Ltda.
|
|
|
Tranquilo Block
|
50%
|
-
|
55
|
55
|
(432)
|
(377)
|
-
|
(48)
|
|
GeoPark TdF S.A.
|
|
|
|
|
|
|
|
|
|
Flamenco Block
|
50%
|
9,893
|
-
|
9,893
|
(1,223)
|
8,670
|
879
|
(1,422)
|
|
Campanario Block
|
50%
|
17,347
|
-
|
17,347
|
(233)
|
17,114
|
-
|
(150)
|
|
Isla Norte Block
|
60%
|
9,553
|
-
|
9,553
|
(60)
|
9,493
|
-
|
(161)
|
|
Colombia SAS
|
|
|
|
|
|
|
|
|
|
Yamu/Carupana Block
|
89.5%
|
4,741
|
1
|
4,742
|
(2,993)
|
1,749
|
3,072
|
(2,721)
|
|
Llanos 34 Block
|
45%
|
131,193
|
4,563
|
135,756
|
(5,847)
|
129,909
|
259,815
|
163,917
|
|
Llanos 32 Block
|
12.5%
|
835
|
209
|
1,044
|
(492)
|
552
|
1,784
|
(319)
|
|
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda.
|
|
|
Manati Field
|
10%
|
44,167
|
19,126
|
63,293
|
(11,444)
|
51,849
|
34,238
|
12,731
|
|
POT-T-747
|
70%
|
849
|
358
|
1,207
|
(1,091)
|
116
|
-
|
-
|
|
GeoPark Argentina Limited – Argentinean Branch
|
|
CN-V Block
|
50%
|
6,819
|
347
|
7,166
|
(984)
|
6,182
|
70
|
(1,163)
|
|
Puelen Block
|
18%
|
1,318
|
72
|
1,390
|
(232)
|
1,158
|
-
|
(546)
|
|
Sierra del Nevado Block
|
18%
|
568
|
169
|
737
|
(837)
|
(100)
|
-
|
(474)
|
|
|
|
|
|
|
|
|
|
|
|
Note
31 Interests in Joint operations (continued)
|
Subsidiary /
Joint operation
|
Interest
|
PP&E
E&E Assets
|
Other
Assets
|
Total
Assets
|
Total
Liabilities
|
NET ASSETS/ (LIABILITIES)
|
Revenue
|
Operating (loss)
profit
|
|
2016
|
|
|
|
|
|
|
|
|
|
GeoPark Magallanes Ltda.
|
|
|
Tranquilo Block
|
50%
|
-
|
55
|
55
|
(424)
|
(369)
|
-
|
(40)
|
|
GeoPark TdF S.A.
|
|
|
|
|
|
|
|
|
|
Flamenco Block
|
50%
|
15,108
|
-
|
15,108
|
(93)
|
15,015
|
1,004
|
(1,988)
|
|
Campanario Block
|
50%
|
29,718
|
-
|
29,718
|
(1)
|
29,717
|
-
|
(399)
|
|
Isla Norte Block
|
60%
|
9,920
|
-
|
9,920
|
(1)
|
9,919
|
5
|
(438)
|
|
Colombia SAS
|
|
|
|
|
|
|
|
|
|
Yamu/Carupana Block
|
89,5%
|
3,418
|
-
|
3,418
|
(2,289)
|
1,129
|
18
|
(307)
|
|
Llanos 34 Block
|
45%
|
79,811
|
693
|
80,504
|
(3,943)
|
76,561
|
125,400
|
83,193
|
|
Llanos 32 Block
|
10%
|
3,819
|
-
|
3,819
|
(211)
|
3,608
|
2,303
|
1,043
|
|
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda.
|
|
|
Manati Field
|
10%
|
54,166
|
15,791
|
69,957
|
(8,442)
|
61,515
|
29,719
|
20,945
|
|
2015
|
|
|
|
|
|
|
|
|
|
GeoPark Magallanes Ltda.
|
|
|
Tranquilo Block
|
50%
|
-
|
45
|
45
|
(2)
|
43
|
-
|
(69)
|
|
GeoPark TdF S.A.
|
|
|
|
|
|
|
|
|
|
Flamenco Block
|
50%
|
14,932
|
-
|
14,932
|
(53)
|
14,879
|
1,810
|
(51,411)
|
|
Campanario Block
|
50%
|
27,570
|
-
|
27,570
|
(10)
|
27,560
|
13
|
(7,267)
|
|
Isla Norte Block
|
60%
|
8,583
|
-
|
8,583
|
(16)
|
8,567
|
355
|
(5,661)
|
|
Colombia SAS
|
|
|
|
|
|
|
|
|
|
Llanos 17 Block
|
36.84%
|
-
|
-
|
-
|
(93)
|
(93)
|
3
|
(6,325)
|
|
Yamu/Carupana Block
|
89,5%
|
3,569
|
2,061
|
5,630
|
(2,235)
|
3,395
|
1,409
|
(16,552)
|
|
Llanos 34 Block
|
45%
|
76,667
|
429
|
77,096
|
(3,295)
|
73,801
|
114,276
|
53,049
|
|
Llanos 32 Block
|
10%
|
3,106
|
96
|
3,202
|
(213)
|
2,989
|
8,258
|
(1,343)
|
|
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda.
|
|
|
Manati Field
|
10%
|
50,801
|
12,930
|
63,731
|
(10,395)
|
53,336
|
32,388
|
20,354
|
|
|
|
|
|
|
|
|
|
|
|
Capital commitments are disclosed in Note 32
(b).
Note
32 Commitments
(a) Royalty commitments
In Colombia, royalties on production are
payable to the Colombian Government and are determined on a field-by-field basis using a level of production sliding scale at a
rate which ranges between 6%-8%. The Colombian National Hydrocarbons Agency (“ANH”) also has an additional economic
right equivalent to 1% of production, net of royalties.
Under Law 756 of 2002, as modified by Law
1530 of 2012, the royalties on Colombian production of light and medium oil are calculated on a field-by-field basis, using the
following sliding scale:
|
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%
|
When the API is lower than 15°, the
payment is reduced to the 75% of the total calculation.
In accordance with Llanos 34 Block operation
contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5,000,000 of barrels and
the WTI exceeds the base price settled in table A, the Group should deliver to ANH a share of the production net of royalties in
accordance with the following formula: Q = ((P – Po) / P) x S; where Q = Economic right to be delivered to ANH, P = WTI,
Po = Base price (see table A) and S = Share (see table B).
|
Table A
|
|
Table B
|
|
API
|
Po (US$/barrel)
|
WTI (P)
|
|
S
|
|
>29°
|
30.22
|
Po < P < 2Po
|
|
30%
|
|
>22°<29°
|
31.39
|
2Po < P < 3Po
|
|
35%
|
|
>15°<22°
|
32.56
|
3Po < P < 4Po
|
|
40%
|
|
>10°<15°
|
46.50
|
4Po < P < 5Po
|
|
45%
|
|
|
|
5Po < P
|
|
50%
|
Note
32 Commitments (continued)
(a) Royalty commitments (continued)
Additionally, under the terms of the Winchester
Stock Purchase Agreement, GeoPark is obligated to make certain payments to the previous owners of Winchester based on the production
and sale of hydrocarbons discovered by exploration wells drilled after 25 October 2011. These payments involve an overriding
royalty equal to an estimated 4% carried interest on the part of the vendor. As at the balance sheet date and based on preliminary
internal estimates of additions of 2P reserves since acquisition, the Group’s best estimate of the total commitment over
the remaining life of the concession is in a range between US$ 80,000,000 and US$ 90,000,000. During 2017, the Group has accrued
and paid US$ 11,369,000 (US$ 5,414,000 in 2016 and US$ 7,100,000 in 2015) and US$ 9,981,000 (US$ 3,772,000 in 2016 and
US$ 9,200,000 in 2015), respectively.
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 Manatí Block, royalties are
calculated at 7.5% of gas production.
In Argentina, crude oil production accrues
royalties payable to the Province of Mendoza equivalent to 12% on estimated value at well head of those products. This value is
equivalent to final sales price less transport, storage and treatment costs.
(b) Capital commitments
Colombia
The VIM 3 Block minimum investment program
consists of 200 sq km of 2D seismic and drilling one exploratory well, with a total estimated investment of US$ 22,290,800 during
the initial three year exploratory period ending 2 September 2018.
Note
32 Commitments (continued)
(b) Capital commitments (continued)
Colombia (continued)
The Llanos 34 Block (45% working interest)
has committed to drill two exploratory wells, one before 15 March 2017 and the other before 14 September 2019. The remaining commitment
amounted to US$ 6,255,000 at GeoPark’s working interest. As of the date of these Consolidated Financial Statements, GeoPark
is awaiting the ANH’s approval of the wells already drilled that were presented as fulfilment of the commitments to be performed
in the block. After this approval, the remaining commitment would amount to US$ 3,008,000.
The Llanos 32 Block (12% working interest)
has committed to drill one exploratory well before 20 August 2018. The remaining commitment amounts to US$ 587,500 at GeoPark’s
working interest.
Argentina
On 20 August 2014, the consortium of GeoPark
and Pluspetrol was awarded two exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of the 2014 Mendoza Bidding
Round in Argentina, carried out by Empresa Mendocina de Energia S.A. ("EMESA"). The consortium consists of Pluspetrol
(Operator with a 72% working interest ("WI"), EMESA (Non-operated with a 10% WI) and GeoPark (Non-operated with an 18%
WI). As of the date of these Consolidated Financial Statements, the remaining commitments in the blocks for the first exploratory
period amount to US$ 1,200,000 at GeoPark’s working interest.
On 22 July 2015, GeoPark signed a farm-in
agreement with Wintershall for the CN-V Block in Argentina. GeoPark will operate during the exploratory phase and receive a 50%
working interest in the CN-V Block in exchange for its commitment to drill two exploratory wells, for a total of US$ 10,000,000.
As of the date of these Consolidated Financial Statements, GeoPark has already drilled and completed one of the two committed exploratory
wells for a total amount of US$ 5,455,000.
Chile
The remaining investment commitment for
the second exploratory phase in the Flamenco Block relates to the drilling of one exploratory well to be assumed 100% by GeoPark
and amounts to US$ 2,100,000. On 30 June 2017, the Chilean Ministry accepted GeoPark’s proposal to extend the second exploratory
phase for an additional period of 18 months, ending on 7 May 2019.
Note
32 Commitments (continued)
(b) Capital commitments (continued)
Chile (continued)
The investment commitment for the first
exploratory period in the Campanario and Isla Norte Blocks has already been fulfilled. The investments to be made in the second
exploratory period will be assumed 100% by GeoPark. On 29 May 2017, the Chilean Ministry accepted GeoPark’s proposal to update
the value of the commitments in both the Campanario and Isla Norte Blocks as well as the guarantees related to those commitments.
Consequently, the future investment commitments assumed by GeoPark for the second exploratory period are up to:
|
|
·
|
Campanario Block: 3 exploratory wells before
10 July 2019 (US$ 4,758,000)
|
|
|
·
|
Isla Norte Block: 2 exploratory wells before
7 May 2019 (US$ 2,855,000)
|
As of 31 December 2017, the Group has established
guarantees for its total commitments.
Brazil
The future investment commitments assumed
by GeoPark are up to:
|
|
·
|
SEAL-T-268 Block: before 15 May 2017 (US$
230,000). On 12 May 2017, the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (“ANP”) notified the
suspension of the exploratory period to fulfill the commitments in the block.
|
|
|
·
|
REC-T-94 Block: 2 exploratory wells before
12 July 2017 (US$ 2,300,000). An exploratory well was drilled and completed in April 2017. On 12 July 2017, the
ANP
notified the suspension of the exploratory period to fulfill the commitments in the block.
|
|
|
·
|
REC-T-93 Block: 3D seismic before 20 December
2018 (US$ 50,000).
|
|
|
·
|
REC-T-128 Block: 1 exploratory well before
20 December 2018 (US$ 2,690,000).
|
|
|
·
|
POT-T-747 Block: 1 exploratory well before
20 December 2018 (US$ 1,840,000). An exploratory well was drilled in December 2017.
|
|
|
·
|
POT-T-882 Block: 35 sq km of 2D seismic
before 20 December 2018 (US$ 480,000).
|
|
|
·
|
POT-T-619 Block: 1 well before 16 September
2018 (US$ 700,000).
|
(c) Operating lease commitments –
Group company as lessee
The Group leases various plant and machinery
under non-cancellable operating lease agreements.
The Group also leases offices under non-cancellable
operating lease agreements. The lease terms are between 2 and 3 years, and most of lease agreements are renewable at the end of
the lease period at market rate.
Note
32 Commitments (continued)
(c) Operating lease commitments –
Group company as lessee (continued)
During 2017 a total amount of US$ 46,195,000
(US$ 47,871,000 in 2016 and US$ 16,731,000 in 2015) was charged to the income statement and US$ 34,160,000 of operating leases
were capitalised as Property, plant and equipment related to rental of drilling equipment and machinery (US$ 32,058,000 in 2016
and US$ 7,102,000 in 2015).
The future aggregate minimum lease payments
under non-cancellable operating leases are as follows:
|
Amounts in US$ ’000
|
2017
|
2016
|
2015
|
|
Operating lease commitments
|
|
|
|
|
Falling due within 1 year
|
32,180
|
67,752
|
12,878
|
|
Falling due within 1 – 3 years
|
5,777
|
14,031
|
8,257
|
|
Falling due within 3 – 5 years
|
2,793
|
5,066
|
2,456
|
|
Falling due over 5 years
|
-
|
114
|
309
|
|
Total minimum lease payments
|
40,750
|
86,963
|
23,900
|
Note
33 Related parties
Controlling interest
The main shareholders of GeoPark Limited,
a company registered in Bermuda, as of 31 December 2017, are:
|
Shareholder
|
Common shares
|
Percentage of outstanding
common shares
|
|
James F. Park
(a)
|
7,891,269
|
13.02%
|
|
Gerald E. O’Shaughnessy
(b)
|
7,193,316
|
11.87%
|
|
Manchester Financial Group, LP
|
5,103,439
|
8.42%
|
|
IFC Equity Investments
(c)
|
3,422,476
|
5.65%
|
|
Juan Cristóbal Pavez
(d)
|
2,961,520
|
4.89%
|
|
Other shareholders
|
34,024,199
|
56.15%
|
|
|
60,596,219
|
100.00%
|
(a)
Held by Energy Holdings,
LLC, which is controlled by James F. Park, a member of our Board of Directors.
(b)
Beneficially owned by Mr.
O’Shaughnessy directly and indirectly through GP Investments LLP, GPK Holdings, and other investment vehicles.
(c)
IFC Equity Investments voting
decisions are made through a portfolio management process which involves consultation from investment officers, credit officers,
managers and legal staff.
(d)
Held through Socoservin Overseas
Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 83,716
common shares held by him personally.
Note
33 Related parties (continued)
Balances outstanding and transactions
with related parties
|
Account (Amounts in ´000)
|
Transaction in the year
|
Balances at year end
|
Related Party
|
Relationship
|
|
2017
|
|
|
|
|
|
To be recovered from co-venturers
|
-
|
2,455
|
Joint Operations
|
Joint Operations
|
|
Prepayments and other receivables
|
-
|
56
|
LGI
|
Partner
|
|
Payables account
|
-
|
(31,184)
|
LGI
|
Partner
|
|
To be paid to co-venturers
|
-
|
(10,015)
|
Joint Operations
|
Joint Operations
|
|
Financial results
|
2,224
|
-
|
LGI
|
Partner
|
|
Geological and geophysical expenses
|
170
|
-
|
Carlos Gulisano
|
Non-Executive Director
(a)
|
|
Administrative expenses
|
411
|
-
|
Pedro Aylwin
|
Executive Director
(b)
|
|
2016
|
|
|
|
|
|
To be recovered from co-venturers
|
-
|
3,311
|
Joint Operations
|
Joint Operations
|
|
Prepayments and other receivables
|
-
|
42
|
LGI
|
Partner
|
|
Payables account
|
-
|
(27,801)
|
LGI
|
Partner
|
|
To be paid to co-venturers
|
-
|
(1,614)
|
Joint Operations
|
Joint Operations
|
|
Financial results
|
1,587
|
-
|
LGI
|
Partner
|
|
Geological and geophysical expenses
|
113
|
-
|
Carlos Gulisano
|
Non-Executive Director
(a)
|
|
Administrative expenses
|
371
|
-
|
Pedro Aylwin
|
Executive Director
(b)
|
|
2015
|
|
|
|
|
|
To be recovered from co-venturers
|
-
|
4,634
|
Joint Operations
|
Joint Operations
|
|
Prepayments and other receivables
|
-
|
38
|
LGI
|
Partner
|
|
Payables account
|
-
|
(21,045)
|
LGI
|
Partner
|
|
To be paid to co-venturers
|
-
|
(113)
|
Joint Operations
|
Joint Operations
|
|
Financial results
|
1,560
|
-
|
LGI
|
Partner
|
|
Geological and geophysical expenses
|
101
|
-
|
Carlos Gulisano
|
Non-Executive Director
(a)
|
|
Administrative expenses
|
66
|
-
|
Carlos Gulisano
|
Non-Executive Director
(a)
|
|
Administrative expenses
|
377
|
-
|
Pedro Aylwin
|
Executive Director
(b)
|
(a)
Corresponding to consultancy
services.
(b)
Corresponding to wages and
salaries for US$ 271,000 (US$ 246,000 in 2016 and US$ 317,000 in 2015) and bonus for US$ 140,000 (US$ 125,000 in 2016 and US$ 60,000
in 2015).
Note
33 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
34 Fees paid to Auditors
|
Amounts in US$ '000
|
2017
|
2016
|
2015
|
|
Audit fees
|
726
|
487
|
557
|
|
Audit related fees
|
137
|
-
|
-
|
|
Tax services fees
|
212
|
134
|
129
|
|
Non-audit services fees
|
39
|
-
|
-
|
|
Fees paid to auditors
|
1,114
|
621
|
686
|
Non-audit services fees relate to consultancy
and other services for 2017.
Note
35 Business transactions
Entry in Peru
The Group has executed a Joint Investment
Agreement and Joint Operating Agreement with Petróleos del Peru S.A. (“Petroperu”) to acquire an interest in
and operate the Morona Block located in northern Peru. GeoPark will assume a 75% working interest (“WI”) of the Morona
Block, with Petroperu retaining a 25% WI. The transaction has been approved by the Board of Directors of both Petroperu and GeoPark.
The agreement was subject to Peru regulatory approval, which was completed on 1 December 2016 following the issuance of Supreme
Decree 031-2016-MEM.
The Morona Block, also known as Lote 64,
covers an area of 1.9 million acres on the western side of the Marañón Basin, one of the most prolific hydrocarbon
basins in Peru. It contains the Situche Central oil field, which has been delineated by two wells (with short term tests of approximately
2,400 and 5,200 bopd of 35-36° API oil each) and by 3D seismic.
In accordance with the terms of the agreement,
GeoPark has committed to carry Petroperu on a work program that provides for testing and start-up production of one of the existing
wells in the field, subject to certain technical and economic conditions being met. During 2017, GeoPark recognised an initial
consideration owed to Petroperu that could be up to US$ 10,684,000, subject to GeoPark’s review and approval of supporting
documentation. This amount will be offset by the Petroperu’s interest in the operation expenses to be incurred by GeoPark
in the block. Expected capital expenditures in 2018 for the Morona Block are mainly related to facility maintenance and environmental
and engineering studies.
Note
35 Business transactions (continued)
Swap operation
On 19 November 2015, the Colombian subsidiary
agreed to exchange its 10% non-operating economic interest in Cerrito Block for additional interests held by Trayectoria, the counterpart
in the Yamú Block, operated by GeoPark, that includes a 10% economic interest in all of the Yamú fields. According
to the terms of the swap operation, GeoPark had written off a receivable with Trayectoria.
Following this transaction, GeoPark continued
to be the operator and have an 89.5% interest in the Carupana Field and 100% in Yamú and Potrillo Fields. The Group recognised,
during 2015, a loss of US$ 296,000 generated by this transaction.
Acquisition of Tiple Block
GeoPark executed a joint operation agreement
related to certain exploration activities in a new high-potential exploration acreage (“Tiple Block Acreage”) in the
Llanos Basin in Colombia, through a partnership with CEPSA Colombia S.A. (a subsidiary of CEPSA SAU, the Spanish integrated energy
and petrochemical company).
The Tiple Block Acreage is located adjacent
to GeoPark’s Llanos 34 Block (GeoPark operated, 45% WI). This exploration area covers approximately 21,000 acres and has
full 3D seismic coverage.
The agreement provides for GeoPark to drill
one exploration well, which is scheduled to be drilled in the first half of 2018. The total estimated investment amounts to between
US$ 7,000,000 and US$ 8,000,000 (including drilling, completion, civil works and other facilities).
Incremental interest in Llanos 32 Block
On 22 August 2017, GeoPark acquired an additional
2.5% interest in the Llanos 32 Block. No gain or loss has been generated by this transaction.
Zamuro Farm-in agreement
GeoPark executed a farm-in agreement to
drill the Zamuro exploration prospect, which is located in the Llanos 32 block (GeoPark non-operated, 12.5% WI). The farm-in agreement
provides for the drilling of an exploration well to be funded by GeoPark and, in the event of a commercial discovery, GeoPark would
increase its economic interest to 56.25% in the Zamuro field area. The well is scheduled to be drilled in the second half of 2018.
Note
35 Business transactions (continued)
Acquisition of the Aguada Baguales, El
Porvenir and Puesto Touquet blocks
On 18 December 2017, GeoPark executed an
asset purchase agreement to acquire a 100% working interest and operatorship of the Aguada Baguales, El Porvenir and Puesto Touquet
blocks, which are located in the Neuquen Basin, for a total consideration of US$ 52,000,000. Closing of the transaction is subject
to customary regulatory approvals, and is expected in the first quarter 2018.
As of the date of these Consolidated Financial
Statements, GeoPark has recorded the security deposit of US$ 15,600,000 granted to the seller within “Other financial assets”
in the Consolidated Statement of Financial Position. No other amounts are recorded in relation with this transaction until its
closing.
Note
36 Impairment test on Property, plant and
equipment
Oil price crisis started in the second half
of 2014 and prices fell dramatically, WTI and Brent, the main international oil price markers, fell more than 60% between October
2014 and February 2016. Because of those market conditions, during 2015, the Group undertook a decisive cost cutting program to
ensure its ability to both maximize the work program and preserve its liquidity. The main decisions included:
|
|
-
|
Reduction of its capital investment taking advantage of the discretionary work program.
|
|
|
-
|
Deferment of capital projects by regulatory authority and partner agreement.
|
|
|
-
|
Renegotiation and reduction of oil and gas service contracts, including drilling and civil work
contractors, as well as transportation trucking and pipeline costs.
|
|
|
-
|
Operating cost improved efficiencies and temporary suspension of certain marginal producing oil
and gas fields.
|
During February 2015, the Group reduced
its workforce significantly. This reduction streamlined certain internal functions and departments for creating a more efficient
workforce in the current economic environment. As a result, the Group achieved cost savings associated with the reduction of full-time
and temporary employees, excluding one-time termination costs. Continuous efforts and actions to reduce costs and preserve liquidity
have continued since.
As a result of the situation described,
the Group recognised an impairment loss of US$ 149,574,000 in 2015 after evaluating the recoverability of its fixed assets
affected by oil price drop, as such situation constitutes an impairment indicator according to IAS 36 and, consequently, it triggers
the need of assessing fair value of the assets involved against their carrying amount.
The Management of the Group considers as
Cash Generating Unit (CGU) each of the blocks in which the Group has working or economic interests. The blocks with no material
investment on fixed assets or with operations that are not linked to oil prices were not subject to impairment test.
Note
36 Impairment test on Property, plant and
equipment (continued)
During 2016 and 2017 the impairment tests
were reviewed. The main assumptions taken into account for the impairment tests for the blocks below mentioned were:
|
|
-
|
The future oil prices have been calculated taking into consideration the oil curves prices available
in the market, provided by international advisory companies, weighted through internal estimations in accordance with price curves
used by D&M;
|
|
|
-
|
Three price scenarios were projected and weighted in order to minimize misleading: low price, middle
price and high price (see below table “Oil price scenarios”);
|
|
|
-
|
The table “Oil price scenarios” was based on Brent future price estimations; the Group
adjusted this marker price on its model valuation to reflect the effective price applicable in each location (see Note 3 “Price
risk”);
|
|
|
-
|
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 (see below table “Oil price scenarios”);
|
|
|
-
|
The levels of production have been linked to certified risked 1P, 2P and 3P reserves (see Note
4);
|
|
|
-
|
Production and structure costs were estimated considering internal historical data according to
GeoPark’s own records and aligned to 2018 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 and Production
facilities and machinery;
|
|
|
-
|
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).
|
Table Oil price scenarios
(a)
:
|
|
Amounts in US$ per Bbl.
|
|
Year
|
Low price (15%)
|
Middle price (60%)
|
High price (25%)
|
Weighted market price used for the impairment test
|
|
2018
|
64.9
|
64.9
|
64.9
|
64.9
|
|
2019
|
53.2
|
62.5
|
71.7
|
63.4
|
|
2020
|
54.4
|
63.9
|
73.4
|
64.9
|
|
Over 2021
|
54.3
|
63.7
|
73.2
|
64.7
|
(a)
The percentages indicated
between brackets represent the Group estimation regarding each price scenario.
As a consequence of the evaluation no additional
impairment loss was recognised in 2017. In 2016, part of the impairment recorded in Colombia was reversed for an amount of US$
5,664,000 due to increase in estimated market prices and improvements in cost structure.
Note
37 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 31 December 2008. This information includes
the Group’s oil and gas production activities carried out in Chile, Colombia, Brazil, Argentina and Peru.
Table 1 - Costs incurred in exploration,
property acquisitions and development
(a)
The following table presents those costs
capitalised as well as expensed that were incurred during each of the years ended as of 31 December 2017, 2016 and 2015. 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
|
Chile
|
Colombia
|
Argentina
|
Brazil
|
Peru
|
Total
|
|
Year ended 31 December 2017
|
|
|
|
|
|
|
|
Acquisition of properties
|
|
|
|
|
|
|
|
Proved
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Unproved
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Total property acquisition
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Exploration
|
3,283
|
37,017
|
8,080
|
5,207
|
743
|
54,330
|
|
Development
|
10,231
|
49,268
|
167
|
1,210
|
14,074
|
74,950
|
|
Total costs incurred
|
13,514
|
86,285
|
8,247
|
6,417
|
14,817
|
129,280
|
|
Amounts in US$ '000
|
Chile
|
Colombia
|
Argentina
|
Brazil
|
Peru
|
Total
|
|
Year ended 31 December 2016
|
|
|
|
|
|
|
|
Acquisition of properties
|
|
|
|
|
|
|
|
Proved
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Unproved
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Total property acquisition
|
|
|
|
|
|
|
|
Exploration
|
5,519
|
15,233
|
1,894
|
2,555
|
-
|
25,201
|
|
Development
|
4,566
|
12,500
|
-
|
191
|
-
|
17,257
|
|
Total costs incurred
|
10,085
|
27,733
|
1,894
|
2,746
|
-
|
42,458
|
|
Amounts in US$ '000
|
Chile
|
Colombia
|
Argentina
|
Brazil
|
Peru
|
Total
|
|
Year ended 31 December 2015
|
|
|
|
|
|
|
|
Acquisition of properties
|
|
|
|
|
|
|
|
Proved
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Unproved
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Total property acquisition
|
|
|
|
|
|
|
|
Exploration
|
3,598
|
14,845
|
1,103
|
2,562
|
-
|
22,108
|
|
Development
|
13,315
|
14,752
|
56
|
3,780
|
-
|
31,903
|
|
Total costs incurred
|
16,913
|
29,597
|
1,159
|
6,342
|
-
|
54,011
|
(a)
Includes capitalised
amounts related to asset retirement obligations.
Note
37 Supplemental information on oil and
gas activities (unaudited – continued)
Table 2 - Capitalised costs related to oil
and gas producing activities
The following table presents the capitalised
costs as at 31 December 2017, 2016 and 2015, for proved and unproved oil and gas properties, and the related accumulated depreciation
as of those dates.
|
Amounts in US$ '000
|
Chile
|
Colombia
|
Argentina
|
Brazil
|
Total
|
|
At 31 December 2017
|
|
|
|
|
|
|
Proved properties
(a)
|
|
|
|
|
|
|
Equipment, camps and other facilities
|
80,611
|
69,906
|
843
|
6,036
|
157,396
|
|
Mineral interest and wells
|
397,031
|
291,050
|
11,159
|
77,264
|
776,504
|
|
Other uncompleted projects
(b)
|
12,508
|
11,290
|
48
|
70
|
23,916
|
|
Unproved properties
|
49,702
|
4,106
|
2,975
|
7,585
|
64,368
|
|
Gross capitalised costs
|
539,852
|
376,352
|
15,025
|
90,955
|
1,022,184
|
|
Accumulated depreciation
|
(253,764)
|
(228,793)
|
(5,700)
|
(39,509)
|
(527,766)
|
|
Total net capitalised costs
|
286,088
|
147,559
|
9,325
|
51,446
|
494,418
|
|
|
(a)
|
Includes capitalised amounts related to asset retirement
obligations.
|
|
|
(b)
|
Do not include Peru capitalised costs.
|
|
Amounts in US$ '000
|
Chile
|
Colombia
|
Argentina
|
Brazil
|
Total
|
|
At 31 December 2016
|
|
|
|
|
|
|
Proved properties
(a)
|
|
|
|
|
|
|
Equipment, camps and other facilities
|
80,611
|
46,785
|
843
|
4,174
|
132,413
|
|
Mineral interest and wells
|
380,037
|
230,100
|
4,849
|
77,255
|
692,241
|
|
Other uncompleted projects
|
18,274
|
12,534
|
36
|
2,082
|
32,926
|
|
Unproved properties
|
48,908
|
4,503
|
1,894
|
6,468
|
61,773
|
|
Gross capitalised costs
|
527,830
|
293,922
|
7,622
|
89,979
|
919,353
|
|
Accumulated depreciation
|
(230,917)
|
(190,025)
|
(5,692)
|
(29,803)
|
(456,437)
|
|
Total net capitalised costs
|
296,913
|
103,897
|
1,930
|
60,176
|
462,916
|
|
|
(a)
|
Includes capitalised amounts related to asset retirement
obligations and impairment loss reversal in Colombia for US$ 5,664,000.
|
|
Amounts in US$ '000
|
Chile
|
Colombia
|
Argentina
|
Brazil
|
Total
|
|
At 31 December 2015
|
|
|
|
|
|
|
Proved properties
(a)
|
|
|
|
|
|
|
Equipment, camps and other facilities
|
79,040
|
42,852
|
843
|
2,097
|
124,832
|
|
Mineral interest and wells
|
367,722
|
213,480
|
4,849
|
62,941
|
648,992
|
|
Other uncompleted projects
|
21,830
|
7,703
|
290
|
-
|
29,823
|
|
Unproved properties
|
70,062
|
8,180
|
-
|
8,758
|
87,000
|
|
Gross capitalised costs
|
538,654
|
272,215
|
5,982
|
73,796
|
890,647
|
|
Accumulated depreciation
|
(201,138)
|
(160,759)
|
(5,654)
|
(14,236)
|
(381,787)
|
|
Total net capitalised costs
|
337,516
|
111,456
|
328
|
59,560
|
508,860
|
|
|
(a)
|
Includes capitalised amounts related to asset retirement
obligations and impairment loss in Chile and Colombia for US$ 104,515,000 and US$ 45,059,000, respectively.
|
Note
37 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 31 December
2017, 2016 and 2015. Income tax for the years presented was calculated utilizing the statutory tax rates.
|
Amounts in US$ '000
|
Chile
|
Colombia
|
Argentina
|
Brazil
|
Total
|
|
Year ended 31 December 2017
|
|
|
|
|
|
|
Revenue
|
32,738
|
263,076
|
70
|
34,238
|
330,122
|
|
Production costs, excluding depreciation
|
|
|
|
|
|
|
Operating costs
|
(19,685)
|
(42,677)
|
(325)
|
(7,603)
|
(70,290)
|
|
Royalties
|
(1,314)
|
(24,236)
|
(13)
|
(3,134)
|
(28,697)
|
|
Total production costs
|
(20,999)
|
(66,913)
|
(338)
|
(10,737)
|
(98,987)
|
|
Exploration expenses
(a)
|
(1,404)
|
(3,856)
|
(707)
|
(3,985)
|
(9,952)
|
|
Accretion expense
(b)
|
(994)
|
(683)
|
-
|
(930)
|
(2,607)
|
|
Impairment loss reversal for non-financial assets
|
-
|
-
|
-
|
-
|
-
|
|
Depreciation, depletion and amortization
|
(22,705)
|
(38,721)
|
(8)
|
(10,659)
|
(72,093)
|
|
Results of operations before income tax
|
(13,364)
|
152,903
|
(983)
|
7,927
|
146,483
|
|
Income tax benefit (expense)
|
2,005
|
(61,161)
|
344
|
(2,695)
|
(61,507)
|
|
Results of oil and gas operations
|
(11,359)
|
91,742
|
(639)
|
5,232
|
84,976
|
|
Amounts in US$ '000
|
Chile
|
Colombia
|
Argentina
|
Brazil
|
Total
|
|
Year ended 31 December 2016
|
|
|
|
|
|
|
Revenue
|
36,723
|
126,228
|
-
|
29,719
|
192,670
|
|
Production costs, excluding depreciation
|
|
|
|
|
|
|
Operating costs
|
(20,674)
|
(29,326)
|
-
|
(5,738)
|
(55,738)
|
|
Royalties
|
(1,495)
|
(7,281)
|
-
|
(2,721)
|
(11,497)
|
|
Total production costs
|
(22,169)
|
(36,607)
|
-
|
(8,459)
|
(67,235)
|
|
Exploration expenses
(a)
|
(21,060)
|
(11,690)
|
-
|
(5,636)
|
(38,386)
|
|
Accretion expense
(b)
|
(897)
|
(459)
|
-
|
(1,198)
|
(2,554)
|
|
Impairment loss reversal for non-financial assets
|
-
|
5,664
|
-
|
-
|
5,664
|
|
Depreciation, depletion and amortization
|
(29,890)
|
(29,439)
|
-
|
(12,785)
|
(72,114)
|
|
Results of operations before income tax
|
(37,293)
|
53,697
|
-
|
1,641
|
18,045
|
|
Income tax benefit (expense)
|
5,594
|
(21,479)
|
-
|
(558)
|
(16,443)
|
|
Results of oil and gas operations
|
(31,699)
|
32,218
|
-
|
1,083
|
1,602
|
Note
37 Supplemental information on oil and
gas activities (unaudited – continued)
Table 3 - Results of operations for oil
and gas producing activities (continued)
|
Amounts in US$ '000
|
Chile
|
Colombia
|
Argentina
|
Brazil
|
Total
|
|
Year ended 31 December 2015
|
|
|
|
|
|
|
Revenue
|
44,808
|
131,897
|
597
|
32,388
|
209,690
|
|
Production costs, excluding depreciation
|
|
|
|
|
|
|
Operating costs
|
(26,731)
|
(40,384)
|
(1,414)
|
(5,058)
|
(73,587)
|
|
Royalties
|
(1,973)
|
(8,150)
|
(34)
|
(2,998)
|
(13,155)
|
|
Total production costs
|
(28,704)
|
(48,534)
|
(1,448)
|
(8,056)
|
(86,742)
|
|
Exploration expenses
(a)
|
(30,499)
|
(7,132)
|
(1,159)
|
(1,103)
|
(39,893)
|
|
Accretion expense
(b)
|
(789)
|
(890)
|
-
|
(896)
|
(2,575)
|
|
Impairment loss for non-financial assets
|
(104,515)
|
(45,059)
|
-
|
-
|
(149,574)
|
|
Depreciation, depletion and amortization
|
(37,664)
|
(50,675)
|
(91)
|
(13,401)
|
(101,831)
|
|
Results of operations before income tax
|
(157,363)
|
(20,393)
|
(2,101)
|
8,932
|
(170,925)
|
|
Income tax benefit (expense)
|
23,604
|
7,953
|
735
|
(3,037)
|
29,255
|
|
Results of oil and gas operations
|
(133,759)
|
(12,440)
|
(1,366)
|
5,895
|
(141,670)
|
(a)
Do not include Peru costs.
(b)
Represents accretion of ARO liability.
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 31 December 2017, 2016 and 2015 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).
Note
37 Supplemental information on oil and
gas activities (unaudited – continued)
Table 4 - Reserve quantity information (continued)
Reserves engineering is a subjective process
of estimation of hydrocarbon accumulation, which cannot be accurately measured, and the reserve estimation depends on the quality
of available information and the interpretation and judgment of the engineers and geologists. Therefore, the reserves estimations,
as well as future production profiles, are often different than the quantities of hydrocarbons which are finally recovered. The
accuracy of such estimations depends, in general, on the assumptions on which they are based.
The estimated GeoPark net proved reserves
for the properties evaluated as of 31 December 2017, 2016 and 2015 are summarised as follows, expressed in thousands of barrels
(Mbbl) and millions of cubic feet (MMcf):
|
|
As of 31 December 2017
|
As of 31 December 2016
|
As of 31 December 2015
|
|
|
Oil and condensate (Mbbl)
|
Natural gas
(MMcf)
|
Oil and condensate (Mbbl)
|
Natural gas
(MMcf)
|
Oil and condensate (Mbbl)
|
Natural gas
(MMcf)
|
|
Net proved developed
|
|
|
|
|
|
|
|
Chile
(a)
|
720.0
|
8,688.0
|
547.0
|
6,610.0
|
498.0
|
4,922.0
|
|
Colombia
(b)
|
21,101.0
|
-
|
9,502.0
|
-
|
8,177.8
|
-
|
|
Brazil
(c)
|
76.0
|
23,821.0
|
72.0
|
29,525.0
|
120.0
|
36,158.0
|
|
Peru
(d)
|
9,502.0
|
-
|
9,316.0
|
-
|
-
|
-
|
|
Total consolidated
|
31,399.0
|
32,509.0
|
19,437.0
|
36,135.0
|
8,795.8
|
41,080.0
|
|
|
|
|
|
|
|
|
|
Net proved undeveloped
|
|
|
|
|
|
|
|
Chile
(e)
|
3,423.0
|
11,329.0
|
6,052.0
|
29,690.0
|
5,455.8
|
31,593.0
|
|
Colombia
(f)
|
44,398.0
|
-
|
27,838.0
|
-
|
22,245.5
|
-
|
|
Brazil
(c)
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Peru
(d)
|
9,215.0
|
-
|
9,305.0
|
-
|
-
|
-
|
|
Total consolidated
|
57,036.0
|
11,329.0
|
43,195.0
|
29,690.0
|
27,701.3
|
31,593.0
|
|
|
|
|
|
|
|
|
|
Total proved reserves
|
88,435.0
|
43,838.0
|
62,632.0
|
65,825.0
|
36,497.1
|
72,673.0
|
|
|
(a)
|
Fell Block accounts for 98% of the reserves
(99% in 2016 and 91% in 2015) (LGI owns a 20% interest) and Flamenco Block accounts for 2% (1% in 2016 and 9% in 2015) (LGI owns
31.2% interest).
|
|
|
(b)
|
Llanos 34 Block, Cuerva Block and Yamu
Block account for 98%, 1% and 1% (Llanos 34 Block and Llanos 32 Block account for 99% and 1% in 2016, and Llanos 34 Block and Cuerva
Block account for 94% and 3% in 2015) of the proved developed reserves, respectively (LGI owns a 20% interest).
|
|
|
(c)
|
BCAM-40 Block accounts for 100% of the
reserves.
|
|
|
(d)
|
Morona Block accounts for 100% of the reserves.
|
|
|
(e)
|
Fell Block accounts for 97% of the reserves
(99% in 2016 and 100% in 2015) (LGI owns a 20% interest), Flamenco Block accounts for 3% in 2017 (1% in 2016 and nil in 2015) (LGI
owns 31.2% interest).
|
|
|
(f)
|
Llanos 34, Cuerva Block and Yamu Block
account for 97%, 2% and 1% (Llanos 34 Block accounts for 100% in 2016 and Llanos 34 Block and Cuerva Block account for 95% and
4% in 2015) of the proved undeveloped reserves, respectively (LGI owns a 20% interest).
|
Note
37 Supplemental information on oil and
gas activities (unaudited – continued)
Table 4 - Reserve quantity information (continued)
The amounts of proved reserves disclosed
herein as of 31 December 2017 include 13,934.1 thousand barrels of crude oil condensate (8,796.2 in 2016 and 7,281.3 in 2015)
and natural gas liquids and 4,317.8 million cubic feet of natural gas (7,356.0 in 2016 and 7,345.8 in 2015) corresponding
to non-controlling interest held by LGI.
Table 5 - Net proved reserves of oil,
condensate and natural gas
Net proved reserves (developed and undeveloped)
of oil and condensate:
|
Thousands of barrels
|
Chile
|
Colombia
|
Brazil
|
Peru
|
Total
|
|
Reserves as of 31 December 2014
|
6,441.9
|
24,735.3
|
130.0
|
-
|
31,307.2
|
|
Increase (decrease) attributable to:
|
|
|
|
|
|
|
Revisions
(a)
|
119.0
|
(225.0)
|
7.6
|
-
|
(98.4)
|
|
Extensions and discoveries
(b)
|
100.0
|
10,489.0
|
-
|
-
|
10,589.0
|
|
Production
|
(707.1)
|
(4,576.0)
|
(17.6)
|
-
|
(5,300.7)
|
|
Reserves as of 31 December 2015
|
5,953.8
|
30,423.3
|
120.0
|
-
|
36,497.1
|
|
Increase (decrease) attributable to:
|
|
|
|
|
|
|
Revisions
(c)
|
1,148.0
|
5,779.0
|
(34.0)
|
-
|
6,893.0
|
|
Extensions and discoveries
(d)
|
-
|
6,311.0
|
-
|
-
|
6,311.0
|
|
Purchase of Minerals in place
(e)
|
-
|
-
|
-
|
18,621.0
|
18,621.0
|
|
Production
|
(502.8)
|
(5,173.3)
|
(14.0)
|
-
|
(5,690.1)
|
|
Reserves as of 31 December 2016
|
6,599.0
|
37,340.0
|
72.0
|
18,621.0
|
62,632.0
|
|
Increase (decrease) attributable to:
|
|
|
|
|
|
|
Revisions
(f)
|
(2,109.0)
|
6,315.0
|
19.0
|
96.0
|
4,321.0
|
|
Extensions and discoveries
(g)
|
-
|
29,047.0
|
-
|
-
|
29,047.0
|
|
Production
|
(347.0)
|
(7,203.0)
|
(15.0)
|
-
|
(7,565.0)
|
|
Reserves as of 31 December 2017
|
4,143.0
|
65,499.0
|
76.0
|
18,717.0
|
88,435.0
|
|
|
(a)
|
For the year ended 31 December 2015, the Group’s oil and condensate proved reserves were
revised downwards by 0.1 mmbbl. The primary factors leading to the above were:
|
- The impact of lower average
oil prices resulting in a 2 mmbbl decrease in reserves from the La Cuerva and Yamu blocks in Colombia, and a 1 mmbbl decrease in
reserves related to a change in a previously adopted development plan in the Fell Block in Chile.
- Such decrease was partially
offset by better than expected performance from existing wells, of which 2 mmbbl was from the Llanos 34 Block in Colombia and 1
mmbbl from the Fell Block in Chile.
|
|
(b)
|
In Colombia, the extensions and discoveries are primarily due to the Tilo, Jacana, and Chachalaca
field discoveries in the Llanos 34 Block.
|
|
|
(c)
|
For the year ended 31 December 2016, the Group’s oil and condensate proved reserves were
revised upward by 7 mmbbl. The primary factors leading to the above were:
|
- Better than expected performance
from existing wells, resulting in an increase of 9 mmbbl, of which 8 mmbbl was from the Tigana, Jacana and other minor fields in
the Llanos 34 Block, and 1 mmbbl was from the Fell Block in Chile.
- Such increase was partially
offset by lower average oil prices impacting the La Cuerva and Yamu blocks in Colombia, resulting in a 2 mmbbl decrease.
|
|
(d)
|
In Colombia, the extensions and discoveries are primarily due to the Jacana field appraisal wells
in the Llanos 34 Block.
|
|
|
(e)
|
In December 2016, we obtained final regulatory approval
for our acquisition of the Morona Block in Peru. The Joint Investment and Operating Agreement dated 1 October 2014 and its amendments
were closed on 1 December 2016 following the issuance of Supreme Decree 031-2016-MEM.XXX.
|
|
|
(f)
|
For the year ended 31 December 2017, the Group’s oil and condensate proved reserves were
revised upward by 4.3 mmbbl. The primary factors leading to the above were:
|
- Better than expected performance
from existing wells, from the Tigana and Jacana fields in the Llanos 34 Block, resulting in an increase of 3.8 mmbbl.
- The impact of higher average
oil prices resulting in a 2.5 mmbbl and 0.4 mmbbl increase in reserves from the blocks in Colombia and Chile, respectively.
- Such increase was partially
offset by a decrease in reserves mainly related to a change in a previously adopted development plan in the Fell Block in Chile,
resulting in a 2.4 mmbbl decrease.
|
|
(g)
|
In Colombia, the extensions and discoveries are primary due to the Chiricoca, Jacamar, and Curucucu
field discoveries in the Llanos 34 Block and the Tigana and Jacana field extensions in the Llanos 34 Block.
|
Note
37 Supplemental information on oil and
gas activities (unaudited – continued)
Table 5 - Net proved reserves of oil,
condensate and natural gas (continued)
Net proved reserves (developed and undeveloped)
of natural gas:
|
Millions of cubic feet
|
Chile
|
Brazil
|
Total
|
|
Reserves as of 31 December 2014
|
33,970.0
|
40,464.0
|
74,434.0
|
|
Increase (decrease) attributable to:
|
|
|
|
|
Revisions
(a)
|
(2,807.6)
|
2,907.0
|
99.4
|
|
Extensions and discoveries
(b)
|
9,378.0
|
-
|
9,378.0
|
|
Production
|
(4,025.4)
|
(7,213.0)
|
(11,238.4)
|
|
Reserves as of 31 December 2015
|
36,515.0
|
36,158.0
|
72,673.0
|
|
Increase (decrease) attributable to:
|
|
|
|
|
Revisions
(c)
|
5,078.0
|
(319.0)
|
4,759.0
|
|
Production
|
(5,293.0)
|
(6,314.0)
|
(11,607.0)
|
|
Reserves as of 31 December 2016
|
36,300.0
|
29,525.0
|
65,825.0
|
|
Increase (decrease) attributable to:
|
|
|
|
|
Revisions
(d)
|
(13,725.0)
|
59.0
|
(13,666.0)
|
|
Extensions and discoveries
(e)
|
1,187.0
|
-
|
1,187.0
|
|
Production
|
(3,745.0)
|
(5,763.0)
|
(9,508.0)
|
|
Reserves as of 31 December 2017
|
20,017.0
|
23,821.0
|
43,838.0
|
|
|
(a)
|
For the year ended 31 December 2015, the Group’s
proved natural gas reserves were revised by 0.1 billion cubic feet. This was the combined effect of:
|
- Better than expected performance
from existing wells that resulted in an increase of 13 billion cubic feet (3 billion cubic feet from the Manati field in Brazil
and 10 billion cubic feet from the Fell Block in Chile).
- The above was partially offset
by a decrease of 13 billion cubic feet due to lower average gas prices in the Fell and Tierra del Fuego (TdF) blocks in Chile (totalling
3 billion cubic feet) and changes in previously adopted development plan in the Fell Block in Chile (totalling 10 billion cubic
feet).
|
|
(b)
|
In Chile, the extensions and discoveries are primary
due to the Ache Field discovery and from the extension well in the Fell Block.
|
|
|
(c)
|
For the year ended 31 December 2016, the Group’s
proved natural gas reserves were revised upwards by 5 billion cubic feet. This increase was mainly driven by better than expected
performance from existing wells, primarily the Ache field in the Fell Block in Chile, resulting in an addition of 9 billion cubic
feet. This increase was partially offset by a reduction of 4 billion cubic feet in the Pampa Larga field, also in the Fell Block.
|
|
|
(d)
|
For the year ended 31 December 2017, the Group’s
proved natural gas reserves were revised downwards by 13.7 billion cubic feet. This was the combined effect of:
|
- Removal of proved undeveloped
reserves due to changes in previously adopted development plan in the Fell Block in Chile and unsuccessful proved undeveloped
executions in the Fell Block in Chile (totalling 21.3 billion cubic feet).
- The above was partially offset
by an increase of 6.8 billion cubic feet due to a better performance in the proved developed producing reserves in the Fell Block
in Chile and the impact of higher average prices that resulted in an increase of 0.8 billion cubic feet.
|
|
(e)
|
In Chile, the extensions and discoveries are primary
due to the Uaken Field discovery in the Fell Block.
|
Revisions refer to changes in interpretation
of discovered accumulations and some technical and logistical needs in the area obliged to modify the timing and development plan
of certain fields under appraisal and development phases.
Note
37 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 2017, 2016
and 2015 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.
Note
37 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 (continued)
|
Amounts in US$ '000
|
Chile
|
Colombia
|
Brazil
|
Peru
|
Total
|
|
At 31 December 2017
|
|
|
|
|
|
|
Future cash inflows
|
284,711
|
2,434,954
|
157,527
|
1,047,540
|
3,924,732
|
|
Future production costs
|
(131,788)
|
(531,751)
|
(56,311)
|
(466,110)
|
(1,185,960)
|
|
Future development costs
|
(57,690)
|
(187,414)
|
(7,524)
|
(235,920)
|
(488,548)
|
|
Future income taxes
|
(656)
|
(558,226)
|
(10,442)
|
(107,294)
|
(676,618)
|
|
Undiscounted future net cash flows
|
94,577
|
1,157,563
|
83,250
|
238,216
|
1,573,606
|
|
10% annual discount
|
(19,338)
|
(343,561)
|
(13,293)
|
(147,682)
|
(523,874)
|
|
Standardized measure of discounted future net cash flows
|
75,239
|
814,002
|
69,957
|
90,534
|
1,049,732
|
|
At 31 December 2016
|
|
|
|
|
|
|
Future cash inflows
|
394,993
|
873,771
|
200,713
|
941,463
|
2,410,940
|
|
Future production costs
|
(186,700)
|
(229,593)
|
(74,116)
|
(497,187)
|
(987,596)
|
|
Future development costs
|
(149,785)
|
(69,996)
|
(16,352)
|
(234,328)
|
(470,461)
|
|
Future income taxes
|
(8,344)
|
(191,096)
|
(21,041)
|
(69,698)
|
(290,179)
|
|
Undiscounted future net cash flows
|
50,164
|
383,086
|
89,204
|
140,250
|
662,704
|
|
10% annual discount
|
(14,709)
|
(113,584)
|
(15,688)
|
(109,321)
|
(253,302)
|
|
Standardized measure of discounted future net cash flows
|
35,455
|
269,502
|
73,516
|
30,929
|
409,402
|
|
At 31 December 2015
|
|
|
|
|
|
|
Future cash inflows
|
403,199
|
1,032,339
|
221,206
|
-
|
1,656,744
|
|
Future production costs
|
(186,933)
|
(309,394)
|
(99,832)
|
-
|
(596,159)
|
|
Future development costs
|
(112,312)
|
(99,305)
|
(16,360)
|
-
|
(227,977)
|
|
Future income taxes
|
(17,904)
|
(195,957)
|
(16,837)
|
-
|
(230,698)
|
|
Undiscounted future net cash flows
|
86,050
|
427,683
|
88,177
|
-
|
601,910
|
|
10% annual discount
|
(17,895)
|
(127,586)
|
(15,861)
|
-
|
(161,342)
|
|
Standardized measure of discounted future net cash flows
|
68,155
|
300,097
|
72,316
|
-
|
440,568
|
Note
37 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
|
Chile
|
Colombia
|
Brazil
|
Peru
|
Total
|
|
Present value at 31 December 2014
|
227,658
|
584,071
|
112,145
|
-
|
923,874
|
|
Sales of hydrocarbon , net of production costs
|
(20,948)
|
(97,152)
|
(37,428)
|
-
|
(155,528)
|
|
Net changes in sales price and production costs
|
(256,828)
|
(547,379)
|
(27,404)
|
-
|
(831,611)
|
|
Changes in estimated future development costs
|
28,227
|
(20,123)
|
542
|
-
|
8,646
|
|
Extensions and discoveries less related costs
|
23,595
|
174,951
|
-
|
-
|
198,546
|
|
Development costs incurred
|
15,093
|
29,965
|
4,872
|
-
|
49,930
|
|
Revisions of previous quantity estimates
|
(5,463)
|
(14,528)
|
4,845
|
-
|
(15,146)
|
|
Net changes in income taxes
|
28,611
|
101,576
|
1,573
|
-
|
131,760
|
|
Accretion of discount
|
28,210
|
88,716
|
13,171
|
-
|
130,097
|
|
Present value at 31 December 2015
|
68,155
|
300,097
|
72,316
|
-
|
440,568
|
|
Sales of hydrocarbon, net of production costs
|
(15,127)
|
(91,163)
|
(20,945)
|
-
|
(127,235)
|
|
Net changes in sales price and production costs
|
(16,854)
|
(171,131)
|
16,366
|
-
|
(171,619)
|
|
Changes in estimated future development costs
|
(49,763)
|
14,941
|
542
|
-
|
(34,280)
|
|
Extensions and discoveries less related costs
|
-
|
76,641
|
-
|
-
|
76,641
|
|
Development costs incurred
|
9,417
|
17,302
|
2,214
|
-
|
28,933
|
|
Revisions of previous quantity estimates
|
22,765
|
70,180
|
(1,872)
|
-
|
91,073
|
|
Purchase of Minerals in place
|
-
|
-
|
-
|
30,929
|
30,929
|
|
Net changes in income taxes
|
8,256
|
3,030
|
(4,020)
|
-
|
7,266
|
|
Accretion of discount
|
8,606
|
49,605
|
8,915
|
-
|
67,126
|
|
Present value at 31 December 2016
|
35,455
|
269,502
|
73,516
|
30,929
|
409,402
|
|
Sales of hydrocarbon, net of production costs
|
(14,251)
|
(198,631)
|
(26,979)
|
-
|
(239,861)
|
|
Net changes in sales price and production costs
|
26,928
|
289,199
|
(3,000)
|
69,962
|
383,089
|
|
Changes in estimated future development costs
|
79,078
|
(124,053)
|
8,385
|
(9,725)
|
(46,315)
|
|
Extensions and discoveries less related costs
|
-
|
49,574
|
-
|
-
|
49,574
|
|
Development costs incurred
|
7,146
|
67,571
|
-
|
-
|
74,717
|
|
Revisions of previous quantity estimates
|
(69,594)
|
673,622
|
603
|
1,133
|
605,764
|
|
Purchase of Minerals in place
|
|
|
|
|
|
|
Net changes in income taxes
|
6,097
|
(258,842)
|
7,976
|
(11,828)
|
(256,597)
|
|
Accretion of discount
|
4,380
|
46,060
|
9,456
|
10,063
|
69,959
|
|
Present value at 31 December 2017
|
75,239
|
814,002
|
69,957
|
90,534
|
1,049,732
|
The amounts of the standardized measure
of discounted future net cash flows herein for the year ended 31 December 2017, 2016 and 2015 include $178.1 million, $61.4 million
and $73.9 million that correspond to the non-controlling interest held by LGI.