Summary of Significant Accounting Policies

 

General information

 

The Company is incorporated in Bermuda (registered address: Cumberland House, 9^th Floor, 1 Victoria Street, Hamilton, Bermuda). On 25 March 2014, the Company's common shares were admitted, with a standard listing, to the Official List of the United Kingdom Listing Authority ("UKLA") and to trading on the London Stock Exchange's Main Market for listed securities. Previously, the Company was quoted on Alternative Investment Market ("AIM"), a market operated by the London Stock Exchange. In 2008, the Company established a Level 1 American Depositary Receipt programme in conjunction with the Bank of New York Mellon, which has been appointed as the depositary bank. The Company serves as the holding company for the Group, which is engaged in oil and gas exploration and production, operating in the Kurdistan Region of Iraq. During 2018 the company was still operating in Algeria, however it formally exited the country in January 2019.

 

Adoption of new and revised Standards

 

Amendments to International Financial Reporting Standards ("IFRS") that are mandatorily effective for the current year

 

In the current year, the Group has applied a number of amendments to IFRSs issued by the International Accounting Standards Board (IASB) that are mandatorily effective for an accounting period that begins on or after 1 January 2018. Their adoption has not had any material impact on the disclosures or on the amounts reported in these financial statements.

 

IFRS 9 Financial instruments	The Group has adopted the IFRS 9 for the first time in the current year. The standard requires an entity to address the classification, measurement and recognition of financial assets and liabilities. The impact of this adoption has not had a material impact on the Group's financial statements. In applying IFRS 9 on trade receivables the expected credit loss is not determined to be material.
IFRS 15 Revenue from contracts	The Group has adopted IFRS 15 for the first time in the current year. The Group's accounting policy under IFRS 15 is that revenue is recognised when the Group satisfies a performance obligation by transferring oil to our customer and completing transportation services on their behalf. The application of IFRS 15 is not determined to be material.

New and revised IFRSs in issue but not yet effective

 

At the date of authorisation of these financial statements, The Group has not applied the following new and revised IFRSs that have been issued but are not yet effective and in some cases had not yet been adopted by the EU:

IFRS 16	Leases
IFRS 17	Insurance Contracts
IFRS 9 IAS 28 (amendments)	Prepayment Features with Negative Compensation Long-term interests in Associates and Joint Ventures
Annual Improvements Standards 2015-17	Amendments to IFRS 3 Business combinations, IFRS 11 Joint Arrangements Cycle IAS 12 Income taxes and IAS 23 Borrowing costs
IAS 19 (amendments)	Employee benefits, plan amendments, curtail or settlement.
IFRS 10 and IAS 28 (amendments)	Sale or Contribution of Assets between an Investor and its Associate or Joint Venture
Annual Improvements to IFRSs 2014-2016 Cycle	Amendments to IFRS 1 First-time Adoption of International Financial     Reporting Standards and IFRS 28 Investments in Associates and Joint Ventures
IFRIC 23	Uncertainty over Income Tax Treatments

 

The directors do not expect that the adoption of the Standards listed above will have a material impact on the financial statements of the Group in future periods, except as noted below:

 

 

 

 

IFRS 16 Leases

 

IFRS 16 introduces a comprehensive model for the identification of lease arrangements and accounting treatments for both lessors and lessees. IFRS 16 will supersede the current lease guidance including IAS 17 Leases and the related interpretations when it becomes effective for accounting periods beginning on or after 1 January 2019. The date for the initial application of IFRS for the Group will be 1 January 2019.

 

IFRS 16 will change how the Group accounts for leases previously classified as operating leases under IAS 17, which were off balance sheet.

 

On initial application of IFRS 16 the Group will;-

 

a)    Recognise right-of-use assets and lease liabilities, initially measured at the present value of the future lease payments;

 

b)    Recognise depreciation of right-to-use assets and interest on lease liabilities in the consolidated statement of profit and loss;

 

c)     Separate the total amount of cash paid into a principal portion(presented within financing activities) and (interest presented within operating activities) in the consolidated cash flow statement.

 

 

Under the transition rules of IFRS16 the Group has chosen to adopt the cumulative catch-up approach. The Group will not restate any prior year figures and make any necessary adjustments between assets and liabilities through opening retained earnings.  The Group does not expect the implementation of IFRS 16 to have a material impact on the financial statements.

 

The impact of IFRS 16 on the Group has set out in the table below:

 

Date of assessment	Assets	Liabilities	Net Assets	Expenses	Retained Earnings
	$'000	$'000	$'000	$'000	$'000
1 January 2019	979	(979)	-	-	-
Year Ended 31 December 2019	221	(14)	207	8	8
Year Ended 31 December 2020	234	(255)	(21)	(10)	(2)
Year Ended 31 December 2021	47	(54)	(7)	(14)	(16)
Year Ended 31 December 2022	-	-	-	7	(9)

 

Statement of compliance

 

The financial statements have been prepared in accordance with IFRS as adopted by the European Union.

 

Basis of accounting

 

The financial statements have been prepared under the historical cost basis, except for the valuation of hydrocarbon inventory and the valuation of certain financial instruments, which have been measured at fair value, and on the going concern basis. Equity-settled share-based payments are initially recognised at fair value, but are not subsequently revalued. The principal accounting policies adopted are set out below.

 

Going Concern

The Group's business activities, together with the factors likely to affect its future development, performance and position are set out in the Chairman's Statement, the Executive Review and the Operational Review. The financial position of the Group at the year end and its cash flows and liquidity position are included in the Financial Review. 

 

The Group continues to closely monitor and manage its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Shaikan block, costs contingencies, disruptions to revenue receipts, etc. The Group has taken appropriate action to reduce its cost base and has $196 million of net cash as at 27 March  2019. The Group's forecasts, taking into account the risks applicable, show that the Group has sufficient financial headroom for the 12 months from the date of approval of the 2018 Annual Report and Accounts.

 

Based on the analysis performed, the directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Thus, they continue to adopt the going concern basis of accounting in preparing the annual financial statements.

 

Basis of consolidation

 

The consolidated financial statements incorporate the financial statements of the Company and enterprises controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved where the Company has the power to govern the financial and operating policies of an investee entity, so as to obtain benefits from its activities.

 

Non-IFRS measures

 

The Group uses certain measures to assess the financial performance of its business. Some of these measures are termed "non-IFRS measures" because they exclude amounts that are included in, or include amounts that are excluded from, the most directly comparable measure calculated and presented in accordance with IFRS, or are calculated using financial measures that are not calculated in accordance with IFRS. These non-IFRS measures include financial measures such as operating costs and non-financial measures such as gross average production.

 

The Group uses such measures to measure and monitor operating performance and liquidity, in presentations to the Board and as a basis for strategic planning and forecasting. The directors believe that these and similar measures are used widely by certain investors, securities analysts and other interested parties as supplemental measures of performance and liquidity.

 

The non-IFRS measures may not be comparable to other similarly titled measures used by other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of the Group's operating results as reported under IFRS. An explanation of the relevance of each of the non-IFRS measures and a description of how they are calculated is set out below. Additionally, a reconciliation of the non-IFRS measures to the most directly comparable measures calculated and presented in accordance with IFRS and a discussion of their limitations is set out below, where applicable. The Group does not regard these non-IFRS measures as a substitute for, or superior to, the equivalent measures calculated and presented in accordance with IFRS or those calculated using financial measures that are calculated in accordance with IFRS.

 

Operating costs

 

Operating costs is a useful indicator of the Group's costs incurred to produce Shaikan oil. Operating costs, in comparison with cost of sales, exclude certain non-cash accounting adjustments, contractual PSC payments and transportation costs.   

 

 

	Year Ended 31 December 2018	Year Ended 31 December 2017
	$ million	$ million
Cost of sales	154.5	127.0
Depreciation of oil & gas assets	(70.7)	(79.8)
Production bonus	(16.0)	-
Capacity building payments	(17.0)	(17.2)
Transportation costs	(14.3)	(2.4)
Working capital movement	(5.8)	1.2
Operating costs	30.7	28.8

 

 

Gross operating costs per barrel (unaudited)

 

Gross operating costs are divided by gross production to arrive at operating costs per bbl. 

 

	Year Ended 31 December 2018	Year Ended 31 December 2017
Gross production (MMbbls)	11.5	12.9
Gross operating costs ($ million)	36.8	35.4
Gross operating costs per barrel ($ per bbl)	3.2	2.7

 

 

 

EBITDA

 

EBITDA is a useful indicator of the Group's profitability, which excludes the impact of costs attributable to income tax (expense)/credit, finance costs, interest revenue, depreciation, depletion and amortisation and other gains and losses.

 

	Year Ended 31 December 2018	Year Ended 31 December 2017
	$ million	$ million
Profit from operations	78.2	24.1
Depreciation of oil & gas assets	70.7	79.8
Depreciation and amortisation	0.4	0.4
EBITDA	149.3	104.3

 

Capital Investment

 

Capital investment is the value of the Group's additions to oil and gas assets excluding any movements in decommissioning assets.

	Year Ended 31 December 2018	Year Ended 31 December 2017
	$ million	$ million
Additions to oil and gas assets	35.7	8.1
Capital Investment	35.7	8.1

 

Net Cash

 

Net Cash is a useful indicator of the Group's indebtedness, financial flexibility and capital structure because it indicates the level of cash and cash equivalents less cash borrowings within the Group's business. Net cash is defined as current and non-current borrowings plus non-cash adjustments, less cash and cash equivalents. Non-cash adjustments include unamortised arrangement fees and other adjustments.

	Year Ended 31 December 2018	Year Ended 31 December 2017
	$ million	$ million
Outstanding New Notes	(100.0)	(100.0)
Non-cash adjustments	(4.4)	(2.0)
Cash and cash equivalents	295.6	160.5
Net Cash	191.2	58.5

 

 

 

 

 

Joint arrangements

 

The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are classified as joint operations in accordance with IFRS 11. The Group accounts for its share of the results and net assets of these joint operations. Where the Group acts as Operator of the joint operation, the gross liabilities and receivables (including amounts due to or from non-operating partners) of the joint operation are included in the Group's balance sheet.

 

 

Sales revenue

 

The recognition of revenue, particularly the recognition of revenue from export sales of crude oil, is considered to be a key accounting judgement.

 

All oil is sold to the KRG, who in turn resell the oil either  export in the pipeline at PF-2, at Fishkhabour or by trucking it to domestic customers. The selling price is determined in accordance with the principles of the crude oil export sales agreement ("Crude Oil Sales Agreement"), based on the Brent crude price less a quality discount and transportation costs. The sales agreement also specifies the delivery point, KRG's contribution to transportation costs and payment terms relating to export sales of crude oil. The Crude Oil Sales Agreement has been governing Shaikan crude oil sales from 1 October 2017 onwards.

 

As the payment mechanism for sales is developing within the Kurdistan Region of Iraq, the Group currently considers that revenue can best be reliably measured when the cash receipt is assured. The assessment of whether cash receipt is reasonably assured is based on management's evaluation of the reliability of the KRG's payments to the international oil companies operating in the Kurdistan Region of Iraq.

 

The value of sales revenue is determined after taking account of the following:

 

·      For the crude oil sales via Fishkhabour route, the point of sale is the point that the crude oil is unloaded into the export pipeline at Fishkhabour;

·      For the crude oil sales via Atrush feeder line, the point of sale is the point that the crude oil in injected into the Atrush feeder line;

·      The point of sale for domestic sales is at the Shaikan facility;

·      GKP recognises revenue for its share of the revenue on a cash-assured basis and these amounts of recognised revenue may be lower than the Company's entitlement under the Shaikan PSC, giving rise to unrecognised revenue amounts;

·      From 15 November 2017 onwards, the Group has performed transportation services in respect of the KRG's share of export oil sales. It recharges all of these transportation costs at nil mark-up to the KRG and these recharged transportation costs are recognised as revenue; and

·      Under the Shaikan PSC and the bilateral agreement between GKPI and the MNR signed on 16 March 2016 ("Bilateral Agreement"), the Group is entitled to offset certain costs (including capacity building payments and production bonuses) against amounts owed by the KRG to GKPI. In these instances, the Group recognises revenue and a reduction in the liability to the KRG.

 

To the extent that revenue arises from test production during an evaluation programme, an amount is charged from exploration and evaluation costs to cost of sales so as to reflect a zero net margin.

 

Income tax arising from the Company's activities under its production sharing contract is settled by the KRG on behalf of the Company.  However, the Company is not able to measure the amount of income tax that has been paid on its behalf and, therefore, the notional income tax amounts have not been included in revenue or in the tax charge.

 

Interest Revenue

 

Interest revenue is accrued on a time basis, by reference to the principal outstanding and at the effective rate of interest applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount on initial recognition.

 

Property, plant and equipment other than oil and gas assets

 

Property, plant and equipment ("PPE") are stated at cost less accumulated depreciation and any accumulated impairment losses.  Depreciation is provided at rates calculated to write each asset down to its estimated residual value over its expected useful life as follows:

 

Fixtures and equipment

-

20% straight-line

 

Intangible assets other than oil and gas assets

 

Intangible assets, other than oil and gas assets, have finite useful lives and are measured at cost and amortised over their expected useful economic lives as follows:

 

Computer software

-

33% straight-line

 

Oil and gas assets

 

Pre-licence costs

Costs incurred prior to having obtained the legal rights to explore an area are expensed directly to the income statement as they are incurred.

 

Exploration and evaluation costs

The Group follows the successful efforts method of accounting for exploration and evaluations ("E&E") costs.  Expenditures directly associated with evaluation or appraisal activities are initially capitalised as intangible asset in cost pools by well, field or exploration area, as appropriate. Such costs include licence acquisition, technical services and studies, seismic acquisition, exploration and appraisal well drilling, payments to contractors, interest payable and directly attributable administration and overhead costs.    

 

These costs are then written off as exploration costs in the income statement unless the existence of economically recoverable reserves has been established and there are no indicators of impairment.

 

E&E costs are transferred to development and production assets within property, plant and equipment upon the approval of a development programme by the relevant authorities and the determination of commercial reserves existence. 

 

Development and production assets

Development and production assets are accumulated on a field-by-field basis and represent the cost of developing the commercial reserves discovered and bringing them into production, together with the E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined above.

 

The cost of development and production assets includes the cost of acquisition and purchases of such assets, directly attributable overheads, and costs for future restoration and decommissioning. These costs are capitalised as part of the property, plant and equipment and depreciated based on the Group's depreciation of oil and gas assets policy.

 

Depreciation of oil and gas assets

The net book values of producing assets are depreciated generally on a field-by-field basis using the unit of production ("UOP") basis which uses the ratio of oil and gas production in the period to the remaining commercial reserves plus the production in the period. Production associated with unrecognised export sales revenue is included in the DD&A calculation. Costs used in the calculation comprise the net book value of the field, and any further anticipated costs to develop such reserves.

 

Commercial reserves are proven and probable ("2P") reserves together with, where considered appropriate, a risked portion of 2C contingent resources, which are estimated using standard recognised evaluation techniques. The estimate is regularly reviewed by independent consultants.

 

 

Impairment of PPE and intangible non-current assets

At each balance sheet date, the Group reviews the carrying amounts of its tangible and intangible assets to determine whether there is any indication that those assets have suffered an impairment loss.  If any such indication exists, the recoverable amount of the asset, or group of assets, is estimated in order to determine the extent of the impairment loss (if any). 

 

For assets which do not generate cash flows that are independent from other assets, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs.

 

Recoverable amount is the higher of fair value less costs to sell and value in use.  In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which the estimates of future cash flows have not been adjusted.

 

Any impairment identified is immediately recognised as an expense.

 

 

Borrowing costs

 

Borrowing costs directly relating to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are capitalised and added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.

 

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation.

 

All other borrowing costs are recognised in the income statement in the period in which they are incurred.

 

Taxation

 

The tax expense represents the sum of the tax currently payable and deferred tax.

 

The tax currently payable is based on taxable profit for the year. Current tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities, based on tax rates and laws that are enacted or substantively enacted by the balance sheet date.

 

As described in the revenue accounting policy section above, it is not possible to calculate the amount of notional tax to be shown in relation to any tax liabilities settled on behalf of the Group by the KRG.

 

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit,and is accounted for using the balance sheet liability method.  Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised.  Such assets and liabilities are not recognised if the temporary difference arises from the initial recognition of goodwill or from the initial recognition of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit.

 

The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part assets to be recovered.

 

Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realised based on tax laws and rates that have been enacted or substantively enacted by the balance sheet date.  Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also recognised in equity.

 

 

Foreign currencies

 

The individual financial statements of each company are presented in the currency of the primary economic environment in which it operates (its functional currency). For the purpose of the consolidated financial statements, the results and the financial position of the Group are expressed in US dollars, which is the functional currency of the Group, and the presentation currency for the consolidated financial statements.

 

In preparing the financial statements of the individual companies, transactions in currencies other than the entity's functional currency are recorded at the rates of exchange prevailing on the dates of the transactions. At each balance sheet date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing on the balance sheet date.  Non-monetary assets and liabilities carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the date when the fair value was determined.  Gains and losses arising on retranslation are included in the income statement for the year.

 

On consolidation, the assets and liabilities of the Group's foreign operations which use functional currencies other than US dollars are translated at exchange rates prevailing on the balance sheet date.  Income and expense items are translated at the average exchange rates for the period.  Exchange differences arising, if any, are recognised in other comprehensive income and accumulated in equity in the Group's translation reserve.  On the disposal of a foreign operation, such translation differences are reclassified to profit or loss.

  

Inventories

 

Inventories, except for hydrocarbon inventories, are valued at the lower of cost and net realisable value. Hydrocarbon inventories are recorded at net realisable value with changes in hydrocarbon inventories being adjusted through cost of sales.

 

Financial instruments

 

Financial assets and financial liabilities are recognised on the Group's balance sheet when the Group has become a party to the contractual provisions of the instrument. 

 

Trade receivables

Trade receivables are measured at amortised cost using the effective interest method less any impairment.

 

Cash and cash equivalents

Cash and cash equivalents comprise cash on hand and demand deposits and other short-term highly liquid investments that are readily convertible to a known amount of cash and are subject to an insignificant risk of changes in value.

 

Liquid investments

Liquid investments comprise short-term liquid investments with maturities of three to twelve months.

 

Financial assets at fair value through profit and loss

Financial assets are held at fair value through profit and loss ("FVTPL") when the financial asset is either held for trading or it is designated at FVTPL.  Financial assets at FVTPL are stated at fair value, with any gains or losses arising on re-measurement recognised in profit or loss.  The net gain or loss recognised in profit or loss incorporates any dividend or interest earned on the financial asset and is included in the other gains and losses line in the income statement.

 

Derivative financial instruments

The Group may enter into derivative financial instruments including foreign exchange forward contracts to manage its exposure to foreign exchange rate risk.

 

Derivatives are initially recognised at fair value at the date a derivative contract is entered into and are subsequently re-measured to their fair value at each balance sheet date.  The resulting gain or loss is recognised in the profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship.

 

A derivative with a positive fair value is recognised as a financial asset whereas a derivative with a negative fair value is recognised as a liability.  A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than twelve months and it is not expected to be realised or settled within twelve months.  Other derivatives are presented as current assets or current liabilities.

 

Impairment of financial assets

Financial assets, other than those valued at FVTPL, are assessed for indicators of impairment at each balance sheet date.  Financial assets are impaired where there is objective evidence that, as a result of one or more events that occurred after the initial recognition of the financial asset, the estimated future cash flows of the investment have been impacted.

 

For certain categories of financial asset, such as trade receivables, assets that are assessed not to be impaired individually are subsequently assessed for impairment on a collective basis.  Objective evidence of impairment for a portfolio of receivables could include the Group's past experience of collecting payments, an increase in the number of delayed payments in the portfolio past the average credit period, as well as observable changes in local or national economic conditions that correlate with default on receivables.

 

Financial liabilities and equity

Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into.  An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities.

 

Equity instruments

Equity instruments issued by the Company are recorded at the proceeds received, net of direct issue costs, which are charged to share premium.

 

Borrowings

Interest-bearing loans and overdrafts are recorded at the fair value of proceeds received, net of transaction costs.  Finance charges, including premiums payable on settlement or redemption, are accounted for on an accrual basis and are added to the carrying amount of the instrument to the extent that they are not settled in the year in which they arise. The liability is carried at amortised cost using the effective interest rate method until maturity.

 

Trade payables

Trade payables are stated at amortised cost.  The average maturity for trade and other payables is one to three months.

 

Provisions

 

Provisions are recognised when the Group has a present obligation as a result of a past event which it is probable will result in an outflow of economic benefits that can be reliably estimated.

 

Decommissioning provision

Provision for decommissioning is recognised in full when damage is done to the site and an obligation to restore the site to its original condition exists. The amount recognised is the present value of the estimated future expenditure for restoring the sites of drilled wells and related facilities to their original status.  A corresponding amount equivalent to the provision is also recognised as part of the cost of the related oil and gas asset.  The amount recognised is reassessed each year in accordance with local conditions and requirements.  Any change in the present value of the estimated expenditure is dealt with prospectively. The unwinding of the discount is included as a finance cost.

 

Share-based payments

 

Equity-settled share-based payments to employees and others providing similar services are measured at the fair value of the entity instruments at the grant date. Details regarding the determination of the fair value of equity-settled share-based transactions are set out in Note 22. The fair value determined at the grant date of the equity-settled share-based payments is expensed on a straight- line basis over the vesting period, based on the Group's estimate of equity instruments that will eventually vest. At each balance sheet date, the Group revises its estimate of the number of equity instruments expected to vest as a result of the effect of non-market based vesting conditions. The impact of the revision of the original estimates, if any, is recognised in profit or loss such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to equity reserve.

 

For cash-settled share-based payments, a liability is recognised for the goods or services acquired, measured initially at the fair value of the liability. At each balance sheet date until the liability is settled, and at the date of settlement, the fair value of the liability is re-measured, with any changes in fair value recognised in profit or loss for the period. Details regarding the determination of the fair value of cash-settled share-based transactions are set out in Note 22.

 

Leasing

 

Rentals payable under operating leases are charged to the income statement on a straight-line basis over the term of the relevant lease.

 

Critical accounting estimates and judgements

 

In the application of the Group's accounting policies, which are described above, the directors are required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.

 

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period or in the period of revision and future periods if the revision affects both current and future periods.

 

Key estimates

 

 

Reserves estimates

Commercial reserves are determined using estimates of oil-in-place, recovery factors and future oil prices.  Future development costs are estimated using assumptions as to numbers of wells required to produce the commercial reserves, the cost of such wells and associated production facilities and other capital and operating costs.  Reserves estimates principally affect the depreciation, depletion and amortisation charges, as well as impairment assessments.

 

Carrying value of producing assets

 

Oil and gas assets within property, plant and equipment are held at historical cost value, less accumulated depreciation and impairments.

 

Producing assets are tested for impairment whenever indicators of impairment exist. Management assesses whether such indicators exist, with reference to the criteria specified in IAS 36 Impairment of Assets, at least annually. 

As at 31 December 2017, an internal valuation of the Shaikan field was performed, providing further support in relation to the conclusion that no indicators of impairment existed.

 

The assumptions and estimates in the valuation model include:

 

-       Commodity prices that are based on latest internal forecasts, benchmarked with external sources of information, to ensure they are within the range of available analyst forecasts and the long-term corporate economic assumptions thereafter;

 

-       Discount rates that are adjusted to reflect risks specific to individual assets and the region;

 

-       Commercial reserves and the related production and payment profiles; and

 

-       Timing of revenue receipts.

 

Operating costs and capital expenditure are based on financial budgets and internal management forecasts. Cost assumptions incorporate management experience and expectations, as well as the nature and location of the operation and the risks associated therewith. Underlying input cost assumptions are consistent with related output price assumptions.

 

In line with the Group's accounting policy on impairment, management performs an impairment review of the Group's oil and gas assets annually with reference to indicators as set out in IAS 36.  The Group assesses its group of assets called cash generating units (CGU) for impairment if events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Where indicators are present, management calculates the recoverable amount using key assumptions such as future oil and gas prices, estimated production volume, pre-tax discount rates that reflect the current market assessment of the time value of money and risks specific to the asset, commercial reserves, inflation and transportation fees. The key assumptions are subject to change based on the current market trends and economic conditions.  The CGU's recoverable amount is the higher of the fair value less cost of disposal and value in use. Where the CGU's recoverable amount is lower than the carrying amount, the CGU is considered impaired and is written down to its recoverable amount.  The Group's sole CGU at 31 December 2018 was Shaikan with a carrying value of $379.7 million.  No impairment indicator was identified as at 31 December 2018.

 

Reserves estimates

Commercial reserves are determined using estimates of oil-in-place, recovery factors and future oil prices.  Future development costs are estimated using assumptions as to numbers of wells required to produce the commercial reserves, the cost of such wells and associated production facilities, and other capital and operating costs.  Reserves estimates principally affect the depreciation, depletion and amortisation charges, as well as impairment assessments.

 

 

Significant accounting judgement

 

Revenue

The recognition of revenue, particularly the recognition of revenue from exports, is considered to be a key accounting judgement.  The Group began commercial production from the Shaikan field in July 2013 and historically made sales to both the domestic and export markets.  However, as the payment mechanism for sales to the export market continues to develop within the Kurdistan Region of Iraq, the Group considers that revenue can be only reliably measured when the cash receipt is assured. The assessment of whether cash receipts are reasonably assured is based on management's evaluation of the reliability of the MNR's payments to the international oil companies operating in the Kurdistan Region of Iraq.  The Group also recognised payables to the MNR that were offset against amounts receivable from the MNR for previously unrecognised revenue in line with the terms of the Shaikan PSC.

 

The judgement is not to recognise revenue in excess of the sum of the cash receipt that is assured and the amount of payables to the MNR that can be offset against amounts due for previously unrecognised revenue in line with the terms of the Shaikan PSC, despite the Group being entitled to additional revenue under the terms of the Shaikan PSC. Any future agreements between the Company and the KRG might change the amounts of revenue recognised.

 

Notes to the Consolidated Financial Statements

 

1.   Segment information

 

For the purposes of resource allocation and assessment of segment performance, the Group is organised into three regional business units - Algeria, Kurdistan and the Corporate. These geographical segments are the basis on which the Group reports its segmental information.  The chief operating decision maker is the Chief Executive Officer. He is assisted by the Chief Financial Officer and senior management team. 

 

The accounting policies of the reportable segments are consistent with the Group's accounting policies. 

 

Each segment is described in more detail below:

 

-       Kurdistan Region of Iraq: the Kurdistan segment consists of the Shaikan asset and the Erbil office, which provides support to the operations in Kurdistan;

 

-       Algeria:  the Algerian segment consists of the Algiers office and the Group's operations in Algeria. This activity has now been exited in January 2019.

 

-       Corporate: the corporate segment consists of the Group's UK and Bermuda offices. It represents all overhead and administration costs incurred that are of a corporate nature and elimination of intercompany income and charges which cannot be directly linked to one of the above segments.

 

 

 

 

31 December 2018	Algeria	Kurdistan	Corporate	Total
	$'000	$'000	$'000	$'000
Revenue
Oil sales	-	243,711	-	243,711
Transportation revenue	-	6,843	-	6,843
Inter-segment sales	-	-	-	-
Total revenue		250,554	-	250,554
Cost of sales
Production costs	-	(69,479)	-	(69,479)
Oil and gas assets depreciation expense	-	(70,744)	-	(70,744)
Transportation costs	-	(14,311)	-	(14,311)
Gross profit	-	96,020	-	96,020
General and administrative expenses
Allocated general and administrative expenses	(153)	(7,776)	(9,500)	(17,429)
Depreciation and amortisation expense	-	(105)	(279)	(384)
Profit / (loss) from operations	(153)	88,139	(9,779)	78,207
Interest revenue	-	3,713	728	4,441
Finance costs	-	(723)	(13,150)	(13,873)
Other gains and losses	10,205	39	681	10,925
Profit / (loss) before tax	10,052	91,168	(21,520)	79,700
Tax benefit	-	-	189	189
Profit / (loss) after tax	10,052	91,168	(21,331)	79,889
Capital expenditure	-	36,316	109	36,425
Total assets	-	686,636	72,209	758,845

 

 

During 2018, the allocated general and administrative expenses of $17.4 million (2017: $20.6 million) included costs that are recoverable under the terms of the Shaikan PSC amounting to $7.3 million (2017: $5.4 million).

 

 

 

31 December 2017	Algeria	Kurdistan	Corporate	Total
	$'000	$'000	$'000	$'000
Revenue
Oil sales	-	171,203	-	171,203
Transport revenue	-	1,169	-	1,169
Total revenue		172,372	-	172,372
Cost of sales
Production costs	-	(44,765)	-	(44,765)
Oil and gas assets depreciation expense	-	(79,785)	-	(79,785)
Transportation costs	-	(2,446)	-	(2,446)
Gross profit	-	45,376	-	45,376
General and administrative expenses
Allocated general and administrative expenses	(63)	(5,387)	(15,157)	(20,607)
Depreciation and amortisation expense	-	(145)	(280)	(425)
Profit / (loss) from operations	(63)	39,844	(15,437)	24,344
Interest revenue	-	432	270	702
Finance income/ (costs)	-	(714)	(10,309)	(11,023)
Other gains	-	323	(281)	42
Profit / (loss) before tax	(63)	39,885	(25,757)	14,065
Tax expense	-	-	61	61
Profit / (Loss) after tax	(63)	39,885	(25,696)	14,126
Capital expenditure	-	43,578	-	43,578
Total assets	31	582,192	75,072	657,295

 

 

The 2017 segemental analysis has been restated to combine corporate activities under one heading

 

Geographical information

 

The Group's information about its segment assets (non-current assets excluding deferred tax assets and other financial assets) by geographical location is detailed below:

 

	2018 $'000	2017 $'000
Kurdistan	380,339	417,024
United Kingdom	282	512
	380,621	417,536

 

Information about major customers

 

Included in revenues arising from the Kurdistan segment are revenues of approximately $250.6 million which arose from sales to the Group's largest customer (2017: $172.4 million).

 

 2. Revenue

 

	2018 $'000	2017 $'000
Oil sales	243,711	171,203
Transportation revenue	6,843	1,169
	250,554	172,372

 

The Group accounting policy for revenue recognition is set out in the Summary of Significant Accounting Policies, with revenue recognised on a cash-assured basis.

 

During 2018, the cash-assured values recognised as oil sales were the invoiced revenue for the year amounting to $227.5 million (2017: $156.3 million). The MNR liability offset revenue recognised was $16.2 million (2017: $14.9 million). The oil sales price was calculated using the monthly Brent price less an average discount of $22.3 (2017: $20.3) per barrel for quality, pipeline tariff and transportation costs.

 

From 15 November 2017 onwards, the Group has performed transportation services in respect of the KRG's share of export oil sales. It recharges all of these transportation costs at nil mark-up to the KRG.

 

Interest revenue has been presented as part of net finance costs (note 7).

 

 

3.             Cost of Sales

 

	2018 $'000	2017 $'000
Oil production costs	69,479	44,765
Depreciation of oil and gas assets	70,744	79,785
Transportation costs	14,311	2,446
	154,534	126,996

 

Oil production costs represent the Group's share of gross production expenditure for the Shaikan field for the year and include capacity building charges of $17.0 million (2017: $17.2 million) and Shaikan PSC production bonus of $16.0 million (2017: nil).  All costs are included with no deferral of costs associated with unrecognised sales in accordance with the Group's revenue policy. Production and depreciation, depletion and amortisation ("DD&A") costs related to revenue arrears recognised in 2018 and 2017 have been charged to the income statement in prior periods when the oil was lifted.

 

A unit-of-production method has been used to calculate the DD&A charge for the year. This is based on full entitlement production, commercial reserves and costs for Shaikan. Commercial reserves are proven and probable ("2P") reserves, estimated using standard recognised evaluation techniques. Production and reserves entitlement associated with unrecognised sales in accordance with the Group's revenue policy have been included in the full year DD&A calculation.

 

The breakdown of the 2017 comparative has been restated by $1.3 million to accurately show the full transportation costs, as part of this had previously been shown in oil production costs.

 

4.             General and Administration costs

 

	2018 $'000	2017 $'000
Depreciation and amortisation	383	425
Auditor's remuneration for audit fees (see below)	252	219
Operating lease rentals	2,044	2,924
Other general and admin costs (including staff costs)	15,134	17,736
	17,813	21,304

 

 

 

	2018 $'000	2017 $'000
Fees payable to the Company's auditor for the audit of the Company's annual accounts	224	192
Fees payable to the Company's auditor for other services to the Group
- audit of the Company's subsidiaries pursuant to legislation	28	27
Total audit fees	252	219
Corporate finance services	-	5
Other assurance services (half year review)	70	67
Total fees	322	291

 

 

5. Staff costs

 

The average number of employees and contractors (including Executive directors) employed by the Group was as follows:

 

	2018 Number	2017 Number
Office and management	76	76
Technical and operational	295	277
	371	353
Staff costs in respect of those employees were as follows:
	2018 $'000	2017 $'000
Wages and salaries	25,582	22,444
Social security costs	2,263	1,672
Share-based payment (see note 22)	1,842	2,712
	29,687	26,828

 

The Group have restated the staff costs note to include the costs relating to contractors. These staff members are long term workers in key positions and therefore this presentation is a more accurate statement of the Group's staff costs.

 

A proportion of these costs is allocated to operating costs and a proportion is capitalised as Oil and gas assets under the Group's accounting policy for Property, plant and equipment, with the remainder classified as an administrative overhead costs in the income statement. The net staff cost recognised in the income statement is $25.6m (2017: $23.1m)

 

 6. Other gains

 

	2018 $'000	2017 $'000
Other gains	10,215	272
Exchange gains	710	42
	10,925	314

 

The Company has received final clearance from Sonatrach in relation to the Ferkane Permit (Block 126). This officially marks Gulf Keystone's exit from its Algerian operations, which resulted in a $10.2 million release of past liabilities recognised in other gains in 2018.

 

In 2017, other gains consisted of the release of the decommissioning liability relating to the Ber Bahr block of $0.3 million.
 

 

7. Finance costs and finance revenue

 

	2018 $'000	2017 $'000
Notes interest charged during the year (see note 16)	(13,150)	(10,309)
Unwinding of discount on provisions (see note 17)	(723)	(714)
Total finance costs	(13,873)	(11,023)
Finance revenue	4,441	702
Net finance costs	(9,432)	(10,321)

 

8. Tax

	2018 $'000	2017 $'000
Current year charged	-	-
Adjustment in respect of prior year	-	-
Deferred UK corporation tax credit (see note 18)	189	61
Tax credit attributable to the Company and its subsidiaries	189	61

 

Under current Bermudian laws, the Group is not required to pay taxes in Bermuda on either income or capital gains. The Group has received an undertaking from the Minister of Finance in Bermuda exempting it from any such taxes at least until the year 2035.

 

In the Kurdistan Region of Iraq, the Group is subject to corporate income tax on its income from petroleum operations under the Kurdistan PSCs. The rate of corporate income tax is currently 15% on total income. Under the Shaikan PSC, any corporate income tax arising from petroleum operations will be paid from the KRG's share of petroleum profits. Due to the uncertainty over the payment mechanism for oil sales in Kurdistan, it has not been possible to measure reliably the taxation due that has been paid on behalf of the Group by the KRG and therefore the notional tax amounts have not been included in revenue or in the tax charge. This is an accounting presentational issue and there is no taxation to be paid.

 

UK corporation tax is calculated at 19.00% (2017: 19.25%) of the estimated assessable profit for the year of the UK subsidiary. 

Deferred tax is provided for due to the temporary differences, which give rise to such a balance in jurisdictions subject to income tax.  During the current period no taxable profits were made in respect of the Group's Kurdistan PSC, nor were there any temporary differences on which deferred tax is required to be provided. As a result, no corporate income tax or deferred tax has been provided for Kurdistan in the period.

All deferred tax arises in the UK.

The income / (expense) for the year can be reconciled to the profit / (loss) per the income statement as follows:

	2018 $'000	2017 $'000
Profit before tax	79,700	14,065
Tax at the Bermudian tax rate of 0% (2017:0%)	-	-
Effect of different tax rates of subsidiaries operating in other jurisdictions	189	61
Tax credit for the year	189	61

 

 

 

9. Profit  per share

 

The calculation of the basic and diluted profit/(loss) per share is based on the following data:

		2018 $'000		2017 $'000
Profit
Profit after tax for the purposes of basic and diluted profit per share		79,889		14,126
	2018 Number (000s)		2017 Number (000s)
Number of shares
Basic weighted average number of shares	229,317		229,317

 

 

The Group followed the steps specified by IAS 33 in determining whether potential common shares are dilutive or anti-dilutive.

 

Reconciliation of dilutive shares:

	2018 Number (000s)	2017 Number (000's)
Number of shares
Basic number of ordinary shares outstanding	229,317	229,317
Effect of dilutive potential ordinary shares	6,528	1,595
Diluted number of ordinary shares outstanding	235,845	230,912

 

The average number of ordinary shares in issue excludes shares held by Employee Benefit Trustee ("EBT") and the Exit Event Trustee.

 

The diluted number of ordinary shares outstanding including share options is calculated on the assumption of conversion of all potentially dilutive ordinary shares. During the year ended 31 December 2018, there were 0.3 million (2017: 0.5m) share options that were excluded from the calculation of diluted earnings because they were anti-dilutive.

 

10. Intangible assets

 

	Computer software $'000	Total $'000
Year ended 31 December 2017
Opening net book value	99	99
Amortisation charge	(47)	(47)
Foreign currency translation differences	11	11
Closing net book value	63	63
At 31 December 2017
Cost	1,064	1,064
Accumulated amortisation	(1,001)	(1,001)
Net book value	63	63

 

Year ended 31 December 2018
Opening net book value	63	63
Additions	66	66
Disposals at cost	(29)	(29)
Amortisation charge	(46)	(46)
Amortisation of disposals	29	29
Foreign currency translation differences	1	1
Closing net book value	84	84
At 31 December 2018
Cost	1,102	1,102
Accumulated amortisation	(1,018)	(1,018)
Net book value	84	84

 

The amortisation charge of $46,000 (2017: $47,000) for computer software has been included in general and administrative expenses (note 4).

 

 

 

11. Property, plant and equipment

 

	Oil and Gas Assets $'000		Fixtures and Equipment $'000	Total $'000
Year ended 31 December 2017
Opening net book value	488,634		745	489,379
Additions	8,059		114	8,173
Depreciation charge	(79,785)		(378)	(80,163)
Foreign currency translation differences	-		84	84
Closing net book value	416,908		565	417,473
At 31 December 2017
Cost	693,146		5,941	699,087
Accumulated depreciation	(276,238)		(5,376)	(281,614)
Net book value	416,908		565	417,473

 

Year ended 31 December 2018
Opening net book value	416,908	565	417,473
Additions	35,715	644	36,359
Disposals at cost	(126,584)	(399)	(126,983)
Revision to decommissioning charge	(2,229)	-	(2,229)
Depreciation charge	(70,744)	(337)	(71,081)
Depreciation on disposals	126,584	399	126,983
Foreign currency translation differences	-	15	15
Closing net book value	379,650	887	380,537
At 31 December 2018
Cost	600,048	6,201	606,249
Accumulated depreciation	(220,398)	(5,314)	(225,712)
Net book value	379,650	887	380,537

 

The net book value of oil and gas assets at 31 December 2018 is comprised of property, plant and equipment relating to the Shaikan block and has a carrying value of $379.7 million (2017: $416.9 million).

 

The additions to the Shaikan asset during the year include costs for the work on the export pipelines from both production facilities to the main export pipeline, SH-1 workover, work in preparation to the upcoming drilling campaign, production facilities improvement work and various studies and reservoir engineering.

 

The DD&A charge of $70.7 million on oil and gas assets (2017: $79.8 million) has been included within cost of sales (note 3). The depreciation charge of $0.3 million on fixtures and equipment (2017: $0.4 million) has been included in general and administrative expenses (note 4).

 

Additions during the year include capitalised staff costs of $4.0m (2017: $1.6m).

 

For details of the key assumptions and judgements underlying the impairment assessment and the depreciation, depletion and amortisation charge, refer to the "Critical accounting estimates and judgments" section of the Summary of Significant Accounting Policies.

 

 

12. Group companies

 

Details of the Company's subsidiaries and joint operations at 31 December 2018 is as follows:

 

Name of subsidiary	Place of incorporation	Proportion of ownership interest	Principal activity
Gulf Keystone Petroleum (UK) Limited 6th floor New Fetter Place 8-10 New Fetter Lane London EC4A 1AZ	United Kingdom	100%	Management services, including geological, geophysical and engineering services
Gulf Keystone Petroleum International Limited Cumberland House 9th floor, 1 Victoria Street PO Box 1561 Hamilton HMFX Bermuda	Bermuda	100%	Exploration and evaluation activities in Kurdistan

 

 

Name of joint operation	Place of incorporation	Proportion of ownership interest	Principal activity
Shaikan	Kurdistan	80%(1)	Production and development activities

 

 

⁽¹⁾ 75% is held directly by Gulf Keystone Petroleum International Limited, with 5% held in trust for Texas Keystone, Inc. ("TKI") until formal transfer of the share is completed.

 

 

During the year the following subsidiaries were dissolved:

 

Gulf Keystone Petroleum Numidia Limited

Gulf Keystone Petroleum HBH Limited

Shaikan Petroleum Limited

 

13.          Inventories

	2018 $'000	2017 $'000
Warehouse stocks and materials	13,534	14,569
Crude oil	656	2,621
	14,190	17,190

 

Inventories at 31 December 2018 include write downs to net realisable value of $0.6 million (2017: $0.4 million).

 

 

14. Trade and other receivables

 

	2018 $'000	2017 $'000
Trade receivables	61,251	57,887
Other receivables	5,405	3,260
Prepayments and accrued income	1,253	563
	67,909	61,710

 

Trade receivables comprise invoiced amounts due from the MNR for crude oil sales totalling $53.2 million as at 31 December 2018 (2017: $57.9 million), which have all been received subsequent to the year end. This included past due trade receivables of $40.9 million (2017: $42.6 million). During 2018, the Group purchased a share of Shaikan revenue arrears from MOL amounting to $9.1 million. In line with the requirements of IFRS 9, the fair value of this receivable stood at $8.0 million as at 31 December 2018. The adjustment to the fair value is recognised in Cost of sales (note 3).

 

Included within Other receivables for 2018 is an amount of $0.4 million (2017: $0.4 million) being the deposits for leased assets which are receivable after more than one year. There are no receivables from related parties as at 31 December 2018 (2017: $nil) (see note 23). No impairments of other receivables have been recognised during the year (2017: $nil).

 

The directors consider that the carrying amount of trade and other receivables approximates to their fair value and no amounts are provided against them.

15. Trade and other payables

 

Trade and other payables principally comprise amounts outstanding for trade purchases and ongoing costs.  

 

The directors consider that the carrying amount of trade payables approximates their fair value.

 

	2018 $'000	2017 $'000
Trade payables	11,857	2,687
Other payables	19,552	26,168
Accrued expenses	50,069	28,183
	81,478	57,038

 

There is $4.4 million interest payable included in Accrued expenses as at 31 December 2018 (2017: $2.0m) (see note 16).

 

In 2018, Other payables included $10 million (2017: $10 million) in relation to the Sheikh Adi PSC bonus that was payable on the declaration of commerciality. It is likely that this liability will be offset against unrecognised Shaikan revenue arrears, in accordance with the principles agreed under the Bilateral Agreement between the Group and the MNR.  In 2017, the other payables balance also included $16.2 million of payments received in excess of the Group's revenue entitlements from the MNR under the Bilateral Agreement. In 2018, this amount was transferred to revenue as an offset of past revenue arrears.

 

 

16. Long term borrowings and warrants

 

 

	2018 $'000	2017 $'000
Liability component at 1 January	99,084	98,886
Interest charged during the year	13,150	10,309
Interest paid during the year	(7,713)	(10,111)
Exchange or redemption of Reinstated Notes	(100,000)	-
Issue of New Notes at fair value	97,635	-
Liability component at 31 December	102,156	99,084

 

Liability component reported in:

 

	2018 $'000	2017 $'000
Current liabilities: (see note 15)	4,361	2,017
Non-current liabilities	97,795	97,067
	102,156	99,084

 

On 14 October 2016, the Company issued $100 million of guaranteed notes ("Reinstated Notes").  The unsecured Reinstated Notes were guaranteed by Gulf Keystone Petroleum International Limited, one of the Company's subsidiaries, and their key terms are summarised as follows:

 

-        maturity date was 18 October 2021. At any time prior to maturity, the Reinstated Notes were redeemable in part or full at par and could therefore be refinanced without any prepayment penalty;

-        the Company had the option to defer its interest payments until the maturity of the Reinstated Notes in payment in kind at 13% or pay in cash at 10% until 18 October 2018. From 19 October 2018, the Company would be mandatorily liable to pay interest in cash at 10%; and

-        the Company was permitted to raise up to $45 million of additional indebtedness at any time on market terms to fund capital and operating expenditure.

 

In July 2018, the Group redeemed all of the $100 million Reinstated Notes at a price equal to 100 per cent of the principal, plus accrued and unpaid interest on the Notes up to and including the Redemption Date. The Group also successfully completed the private placement of a 5-year senior unsecured $100 million bond issue (the "New Notes"). The unsecured New Notes are guaranteed by Gulf Keystone Petroleum International Limited and Gulf Keystone Petroleum (UK) Limited, two of the Company's subsidiaries, and their key terms are summarised as follows:

 

-        maturity date is 25 July 2023;

-        at any time prior to maturity, the New Notes are redeemable in part or full with a prepayment penalty;

-        the interest rate is 10% per annum with semi-annual payment dates; and

-        the Company is permitted to raise up to $200 million of additional indebtedness at any time on market terms to fund capital and operating expenditure.

 

The New Notes are traded on the Norwegian Stock Exchange and the fair value at the prevailing market price as at the balance sheet date was:

 

	Market price	2018 $'000	2017 $'000
New Notes	$102.75	102,750	-
Reinstated Notes	$0.98241	-	98,241
		102,750	98,241

 

As of 31 December 2018, the Group's remaining contractual liability comprising principal and interest based on undiscounted cash flows at the maturity date of the New Notes is as follows:

 

 

 

	2018 $'000	2017 $'000
Within one year	10,000	10,000
Within two to five years	135,639	130,000
	145,639	140,000

 

 

17. Provisions

 

	2018 $'000	2017 $'000
Current provisions	4,155	7,197
Non-current provisions	22,600	24,107
	26,755	31,304

 

	Current Provisions (Algeria)	Non-current Provisions (Kurdistan)	Total
Decommissioning provision	$'000	$'000	$'000
At 1 January 2018	7,197	24,107	31,304
New provisions and changes in estimates	-	(2,230)	(2,230)
Unwinding of discount	-	723	723
Release of provisions	(3,042)	-	(3,042)
At 31 December 2018	4,155	22,600	26,755

 

The provision for decommissioning is based on the net present value of the Group's share of expenditure which may be incurred in the removal and decommissioning of the wells and facilities currently in place and restoration of the sites to their original state. The expenditure on the Shaikan block in Kurdistan is expected to take place over the next 25 years.

 

In January 2019, the Group made a payment of $4.2 million in final settlement of all Algerian decommissioning liabilities.

 

 

18. Deferred tax asset

 

The following are the major deferred tax liabilities and assets recognised by the Group and movements thereon during the current and prior reporting periods. The deferred tax assets arise in the United Kingdom.

 

	Accelerated tax depreciation   $'000	Share-based payments   $'000	Tax losses carried forward $'000	Total     $'000
At 1 January 2017	(82)	36	356	310
(Charge)/credit to income statement	21	92	(52)	61
Exchange differences	(7)	8	31	32
At 31 December 2017	(68)	136	335	403
(Charge)/credit to income statement	37	202	(50)	189
Exchange differences	1	(18)	(16)	(33)
At 31 December 2018	(30)	320	269	559

 

 

19. Share capital

 

	2018 $'000	2017 $'000
Authorised
Common shares of $1 each (2017: $1 each)	231,605	231,605
Non-voting shares of $0.01 each	500	500
Preferred shares of $1,000 each	20,000	20,000
Series A Preferred shares of $1,000 each	40,000	40,000
	292,105	292,105

 

 

	Common shares
			Share		Share
	No. of shares	Amount		capital		premium
	000	$'000		$'000		$'000
Balance 31 December 2016	229,430	1,150,158		229,430		920,728
Balance 31 December 2017	229,430	1,150,158		229,430		920,728
Balance 31 December 2018	229,430	1,150,158		229,430		920,728

 

 

At 31 December 2018, a total of 0.1 million common shares at $1.0 each were held by the EBT (2017: 0.1 million at $1.0 each) and 0.1 million shares at $1.0 each were held by the Exit Event Trustee (2017: 0.1 million at $1.0 each). All 0.2 million common shares were included within reserves (2017: 0.2 million).

 

Rights attached to share capital

The holders of the common shares have the following rights (subject to the other provisions of the Byelaws):

 

(i)	entitled to one vote per common share;
(ii)	entitled to receive notice of, and attend and vote at, general meetings of the Company;
(iii)	entitled to dividends or other distributions; and
(iv)	in the event of a winding-up or dissolution of the Company, whether voluntary or involuntary or for a reorganisation or otherwise or upon a distribution of capital, entitled to receive the amount of capital paid up on their common shares and to participate further in the surplus assets of the Company only after payment of the Series A Liquidation Value (as defined in the Byelaws) on the Series A Preferred Shares.

 

20. Reconciliation of Profit from operations to Cash generated from operations

 

	2018 $'000	2017 $'000
Profit from operations	78,207	24,072
Adjustments for:
Depreciation, depletion and amortisation of property, plant and equipment	71,081	80,163
Amortisation of intangible assets	46	47
Other gains or losses	-	(11)
Share-based payment expense	1,785	2,710
(Increase)/ decrease in inventories	3,000	(1,219)
(Increase) in receivables	(4,330)	(20,125)
Increase/ (decrease) in payables	11,695	(337)
Cash generated from operations	161,483	85,300

 

 

The increase in receivable includes $8.0m relating to the purchase of a share of Shaikan revenue arrears from MOL

 

 

21. Commitments

 

Operating lease commitments - the Group as a lessee

	2018 $'000	2017 $'000
Minimum lease payments under operating leases recognised as expense for the year	2,019	2,924

 

At the balance sheet date, the Group had outstanding total commitments under non-cancellable operating leases, which fall due as follows:

 

	2018 $'000	2017 $'000
Within one year	2,264	1,144
Within two to five years	1,608	1,519
	3,872	2,663

 

Operating lease payments represent rentals payable by the Group for certain of its office and residence properties, facilities and vehicle rentals in the United Kingdom and the Kurdistan Region of Iraq. The non-cancellable operating leases within Kurdistan are up to one year in duration.

 

Exploration and development commitments

 

Due to the nature of the Group's operations in exploring and evaluating areas of interest and development of assets, it is difficult to accurately forecast the nature or amount of future expenditure.

 

Expenditure commitments on current permits for the Group could be reduced by selective relinquishment of exploration tenure, by the sale of assets or by the renegotiation of expenditure commitments. Capital commitments of $29.9 million are expected in the year ending 31 December 2019 for the Group (2018: $nil).

 

 

22. Share-based payments

 

	2018 $'000	2017 $'000
Share options charge	1,842	2,710
	1,842	2,710

 

 

Value Creation Plan

 

The VCP was approved by shareholders in December 2016 and, as of 31 December 2018, one award of Performance Units has been made to the CEO and CFO.  No further awards of Performance Units are envisaged. Any outstanding awards under the VCP will be allowed to run-off and vest subject to the Company achieving the performance criteria of 8% compound annual growth in TSR on each of five annual Measurement Dates and the plan limits in place, in accordance with the VCP rules.  As such, it may be possible that additional conversions of the Performance Units into nil-cost options may occur in future (up to but not later than 2022).

 

 

Following the first measurement date on 15 May 2018, nil-cost options over 1,681,839 shares were granted to each of the CEO and CFO.  The Executive Directors are not eligible to participate in any other long-term incentive scheme until the VCP has ended

 

	2018		2017
	Number of share options '000	Weighted average exercise price (in pence)	Number of share options '000	Weighted average exercise price (in pence)
Outstanding at 1 January	-	-	-	-
Granted during the year	3,364	-	-	-
Outstanding at 31 December	3,364	-	-	-
Exercisable at 31 December	-	-	-	-

 

Depending on the achievement of the performance criteria, the nil-cost options will vest as follows: 50% in May 2020, 25% in May 2021, and 25% in May 2022.

 

A charge of $0.6 million (2017: $1.1 million) in relation to the VCP is included in the total share options charge.

 

Staff Retention Plan

 

At the 2016 Annual General Meeting, shareholders approved the adoption of the Gulf Keystone Petroleum 2016 Staff Retention Plan ("SRP"), which is designed to reward members of staff through the grant of share options at a zero exercise price.

 

The exercise of the awarded options is not subject to any performance conditions and can be exercised at any time after the three year vesting period but within ten years after the date of grant. If options are not exercised within ten years, the options will lapse and will not be exercisable. If an employee leaves the company during the three years from the date of grant, the options will lapse on the date notice to leave is given to the company. Should an employee be regarded as a good leaver, the options may be exercised at any time within a period of six months from departure date.

 

	2018		2017
	Number of share options '000	Weighted average exercise price (in pence)	Number of share options '000	Weighted average exercise price (in pence)
Outstanding at 1 January	1,595	-	1,402	-
Granted during the year	-	-	611	-
Exercised during the year	-	-	(325)	-
Forfeited during the year	(155)	-	(93)	-
Outstanding at 31 December	1,440	-	1,595	-
Exercisable at 31 December	-	-	-	-

 

 

The options outstanding at 31 December 2018 had a weighted average remaining contractual life of 8 years.

 

During 2018 no options (2017: 611,000) were granted to employees under the Group's SRP.

 

The inputs into the stochastic (binomial) valuation model were as follows:

 

	2018	2017
Weighted average opening share price on date of grant (in pence)	n/a	119.47

 

The expected volatility was calculated as 97.2% for the January 2017 awards, 94.0% for the early July 2017 awards, 94.1% for the July 2017 awards and has been based on the Company's share price volatility averaged for the three years prior to grant date.

 

The expected weighted average term of the SRP options is 3 years. The risk free rate for the options awarded was 0.26% for January 2017 awards, 0.43% for early July 2017 and 0.32% for late July 2017.

 

The weighted average fair value of the options granted in 2017 was £1.19.

 

The Company has not made a dividend payment to date and, as there was no expectation of making payments in the immediate future following grants of the SRP options in 2016 and 2017 the dividend yield variable has been set at zero for all grants.

 

A charge of $0.8 million (2017: $0.9 million) in relation to the SRP is included in the total share options charge.

 

Share options outstanding at the end of the year have the following expiry date and exercise prices:

Expiry date	Exercise price (pence)			Options ('000)
	2018	2017	2018		2017
11 December 2026	-	-	939		994
09 January 2027	-	-	250		350
30 June 2027	-	-	206		206
30 July 2027	-	-	45		45
			1,440		1,595

 

Long Term Incentive option plan

 

At the 2016 Annual General Meeting, shareholders approved the adoption of the Gulf Keystone Petroleum 2016 Long Term Incentive Plan ("LTIP"), which is designed to reward members of staff through the grant of share options at a zero exercise price, that vests three years after grant, subject to the fulfilment of specified performance conditions. These performance conditions attached to the 2018 LTIP grant are 50% Group's  Total Shareholder Return ("TSR") over the vesting period and 50% the Group's TSR relative to a bespoke group of comparators.

 

	2018		2017
	Number of share options '000	Weighted average exercise price (in pence)	Number of share options '000	Weighted average exercise price (in pence)
Outstanding at 1 January	-	-	-	-
Granted during the year	1,786	-	-	-
Forfeited during the year	(172)	-	-	-
Outstanding at 31 December	1,614	-	-	-
Exercisable at 31 December	-	-	-	-

 

A charge of $0.5 million (2017: nil million) in relation to the LTIP is included in the total share options charge.

 

Equity-settled share option plan

 

The Group's share option plan provides for an exercise price at least equal to the closing market price of the Group shares on the date prior to grant.  Awards made under the Group's share option plan have a vesting period of at least three years except for awards made under the legacy Long Term Incentive Plan, which vest in equal tranches over a minimum of three years subsequent to the achievement of a number of operational and market-based performance conditions.  Options expire if they remain unexercised after a period of 10 years from the date of grant. The options granted in 2015 were made under the recruitment remuneration policy, vest in three equal tranches over two years, and expire if they remain unexercised after a period of 7 years from the date of grant. Options are forfeited if the employee leaves the Group before the options vest. The company has not made any awards during 2018 under this scheme.

 

 

	2018		2017
	Number of share options '000	Weighted average exercise price (in pence)	Number of share options '000	Weighted average exercise price (in pence)
Outstanding at 1 January	360	10,149.7	360	10,190.0
Expired during the year	(34)	-	-	-
Outstanding at 31 December	326	11,492.6	360	10,149.7
Exercisable at 31 December	326	11,492.6	360	10,149.7

 

No options were exercised, granted or cancelled in 2018 (2017: nil).

 

The options outstanding at 31 December 2018 had a weighted average exercise price of £115 (2017: £102) and a weighted average remaining contractual life of 2 years (2017: 3 years).

 

A charge of nil (2017: $0.69 million) in relation to the equity-settled share option plan is included in the total share options charge.

 

Share options outstanding at the end of the year have the following expiry date and exercise prices:

 

Expiry date	Exercise price (pence)		Options ('000)
	2018	2017	2018	2017
13 February 2018	3,000	3,000	-	11.0
24 September 2018	3,000	3,000	-	20.1
15 March 2019	3,000	3,000	15.9	15.9
30 July 2019	3,000	3,000	10.0	10.0
24 Jun 2020	7,500	7,500	156.3	156.3
22 September 2020	14,750	14,750	2.5	2.5
10 October 2020	17,500	17,500	-	2.5
6 February 2021	17,500	17,500	94.4	94.4
19 June 2021	14,625	14,625	5.5	5.5
7 July 2021	14,625	14,625	2.5	2.5
14 July 2021	14,625	14,625	2.5	2.5
21 July 2021	14,625	14,625	5.0	5.0
19 September 2021	15,250	15,250	2.5	2.5
26 October 2021	14,625	14,625	2.5	2.5
21 January 2022	5,500	5,500	15.0	15.0
20 March 2022	19,450	19,450	4.0	4.0
20 March 2022	25,000	25,000	2.5	2.5
8 July 2023	15,875	15,875	2.5	2.5
24 April 2024	9,975	9,975	2.5	2.5
			326.1	359.7

 

 

Exit Event Awards

 

In March 2012, the Remuneration Committee recommended that the Company make cash settled awards to certain Executive Directors and employees conditional on the occurrence of an Exit Event (as defined below) up to a maximum amount equivalent to the value of 0.1 million common shares (adjusted for consolidation on 100:1 basis) at the time of an Exit Event. A trustee (the "Exit Event Trustee") was appointed to hold and, subject to the occurrence of an Exit Event, to sell sufficient common shares to satisfy the Exit Event Awards.

 

As at 31 December 2018, the Exit Event Trustee held 0.1 million common shares to satisfy any future Exit Event Awards to full-time employees of the Company and subsidiary companies, subject to the occurrence of an Exit Event, with such beneficiaries to be determined in due course. Any Exit Event awards previously made to the Directors and employees of the Group have expired.

 

An Exit Event envisages a sale of either the Company or a substantial proportion (i.e. more than 50%) of its assets.

 

23. Related party transactions

 

The Group has a related party relationship with its subsidiaries. The Company and its subsidiaries, in the ordinary course of business, enter into various sales, purchase and service transactions with joint operations in which the Group has a material interest. These transactions are under terms that are no less favourable to the Group than those arranged with third parties.

 

Remuneration of key management personnel

 

The remuneration of the Directors and Officers, the key management personnel of the Group, is set out below in aggregate for each of the categories specified in IAS 24 Related Party Disclosures.  Those identified as key management personnel include the Directors of the Company and the following key personnel:

 

 

J Barker - HR Director

S Catterall - Chief Operations Officer

B Demont - Development Manager - Kurdistan Region of Iraq

N Kernoha - Head of Finance

W McAvock - Financial Controller

G Papineau-Legris - Commercial Director

A Robinson - Legal Director & Company Secretary

 

The values below are calculated in accordance with IAS 19 and IFRS 2.

	2018 $'000	2017 $'000
Short-term employee benefits	5,444	6,514
Share-based payment - options	1,132	1,630
	6,576	8,144

 

Further information about the remuneration of individual Directors is provided in the Directors' Emoluments section of the Remuneration Committee Report.

 

24.          Financial instruments

	2018 $'000	2017 $'000
Financial assets
Cash and cash equivalents	295,566	160,456
Loans and receivables	66,656	61,148
	362,222	221,604
Financial liabilities
Trade and other payables	81,478	57,038
Borrowings	97,795	97,067
	179,273	154,105

 

All loans and payables, except for the New Notes, are due to be settled within one year and are classified as current liabilities.

 

The maturity profile and fair values of the New Notes are disclosed in note 16. The maturity profile of all other financial liabilities is indicated by their classification in the balance sheet as "Current" or "Non-current".  Further information relevant to the Group's liquidity position is disclosed in the Directors' Report under "Going Concern".

 

Fair values of financial assets and liabilities

 

With the exception of the New Notes, the Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value. The fair value of the New Notes, as determined using market values at 31 December 2018, was $102.8 million (2017: Reinstated Notes $98.2 million) compared to the carrying value of $97.8 million (2017: Reinstated Notes $97.1 million).

 

No material financial assets are impaired at the balance sheet date. All financial assets and liabilities, with the exception of derivatives, are measured at amortised cost.

 

Capital Risk Management

 

The Group manages its capital to ensure that the entities within the Group will be able to continue as going concerns while maximising the return to stakeholders through the optimisation of the debt and equity balance. The capital structure of the Group consists of cash, cash equivalents, New Notes and equity attributable to equity holders of the parent. Equity comprises issued capital, reserves and accumulated losses as disclosed in Note 19, the Consolidated Statement of Comprehensive Income and the Consolidated Statement of Changes in Equity.

 

Capital Structure

 

The Group's Board of Directors reviews the capital structure on a regular basis and will make adjustments in light of changes in economic conditions. As part of this review, the Board considers the cost of capital and the risks associated with each class of capital. 

 

Significant Accounting Policies

 

Details of the significant accounting policies and methods adopted, including the criteria for recognition, the basis of measurement and the basis on which income and expenses are recognised, in respect of each class of financial asset, financial liability and equity instrument, as well as the impact of adoption of IFRS 9, are disclosed in the Summary of Significant Accounting Policies.

 

 

Financial Risk Management Objectives

 

The Group's management monitors and manages the financial risks relating to the operations of the Group. These financial risks include market risk (including commodity price, currency and fair value interest rate risk), credit risk, liquidity risk and cash flow interest rate risk.

 

The Group currently has no currency risk or other hedges against financial risks as the benefit of entering into such agreements is not considered to be significant enough to outweigh the significant cost and administrative burden associated with such hedging contracts. The Group does not use derivative financial instruments for speculative purposes.

 

The risks are closely reviewed by the Board on a regular basis and steps are taken where necessary to ensure these risks are minimised.

 

Market risk

 

The Group's activities expose it primarily to the financial risks of changes in foreign currency exchange rates, oil prices and changes in interest rates in relation to the Group's cash balances.

 

There have been no changes to the Group's exposure to other market risks or any changes to the manner in which the Group manages and measures the risk.  The Group does not hedge against the effects of movement in oil prices or foreign currency rates. The risks are monitored by the Board on a regular basis.

 

 The Group conducts and manages its business predominantly in US dollars, the operating currency of the industry in which it operates. The Group also purchases the operating currencies of the countries in which it operates routinely on the spot market. Cash balances are held in other currencies to meet immediate operating and administrative expenses or to comply with local currency regulations.

 

At 31 December 2018, a 10% weakening or strengthening of the US dollar against the other currencies in which the Group's monetary assets and monetary liabilities are denominated would not have a material effect on the Group's net current assets or profit before tax.

 

Interest rate risk management

 

The Group's policy on interest rate management is agreed at the Board level and is reviewed on an ongoing basis.  The current policy is to maintain a certain amount of funds in the form of cash for short-term liabilities and have the rest on relatively short-term deposits, usually between one and three months, to maximise returns and accessibility. The Group must pay interest on its New Notes semi-annually in cash at 10%.

 

Based on the exposure to the interest rates for cash and cash equivalents at the balance sheet date, a 0.5% increase or decrease in interest rates would not have a material impact on the Group's profit for the year or the previous year.  A rate of 0.5% is used as it represents management's assessment of a reasonable change in interest rates.

 

Credit risk management

 

Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Group. As at 31 December 2018, the maximum exposure to credit risk from a trade receivable outstanding from one customer is $61 million (2017: $60 million). 

 

The credit risk on liquid funds is limited because the counterparties for a significant portion of the cash and cash equivalents at the balance sheet date are banks with good credit ratings assigned by international credit-rating agencies.

 

Liquidity risk management

 

Ultimate responsibility for liquidity risk management rests with the Board of Directors.  It is the Group's policy to finance its business by means of internally generated funds, external share capital and debt.  In common with many exploration companies, the Group raises finance for its exploration and appraisal activities in discrete tranches to finance its activities for limited periods.  The Group seeks to raise further funding as and when required.

 

25. Contingent liabilities

 

The Group has a contingent liability of $27 million (2017: $27 million) in relation to the proceeds from the sale of test production in the period prior to the approval of the Shaikan Field Development Plan ("FDP") in July 2013. The Shaikan PSC does not appear to address expressly any party's rights to this pre-FDP petroleum. This suggests that there must have been some other agreement, understanding or arrangement between GKP and the KRG as to how this pre-FDP petroleum would be lifted and sold. The sales were made based on sales contracts with domestic offtakers which were approved by the KRG. The Group believes that the receipts from these sales of pre-FDP petroleum are for the account of the Contractor (GKP and MOL), rather than the KRG and accordingly recorded them as test revenue in prior years. However, the KRG has requested a repayment of these amounts and the Group is currently involved in negotiations to resolve this matter. The Group has received external legal advice and does not consider that a probable material payment is payable to the KRG.  This contingent liability forms part of the ongoing Shaikan PSC amendment negotiations and it is likely that it will be settled as part of those negotiations.