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"decimals": -3,
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"decimals": -3,
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"f6800": {
"value": "Note 01 Corporate information
\nThe consolidated \ufb01nancial statements of the company and
\nits subsidiaries (together \u201cthe group\u201d) for the year ended 31
\nDecember 2022 was authorised for issue in accordance with a
\nresolution of the directors on 28 April 2023.
\nPetroNor E&P ASA is a \u2018for pro\ufb01t entity\u2019 and is a company
\nlimited by shares incorporated in Norway. Its shares are
\npublicly traded on the Oslo B\u00f8rs (code: PNOR), the main
\nregulated marketplace of the Oslo Stock Exchange, Norway.
\nThe principal activities of the group are the exploration and
\nproduction of crude oil. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6801": {
"value": "Note 01 Corporate information
\nThe consolidated \ufb01nancial statements of the company and
\nits subsidiaries (together \u201cthe group\u201d) for the year ended 31
\nDecember 2022 was authorised for issue in accordance with a
\nresolution of the directors on 28 April 2023.
\nPetroNor E&P ASA is a \u2018for pro\ufb01t entity\u2019 and is a company
\nlimited by shares incorporated in Norway. Its shares are
\npublicly traded on the Oslo B\u00f8rs (code: PNOR), the main
\nregulated marketplace of the Oslo Stock Exchange, Norway.
\nThe principal activities of the group are the exploration and
\nproduction of crude oil.
\nNote 02
Basis of preparation
\nPetroNor E&P ASA\u2019s consolidated \ufb01nancial statements have
\nbeen prepared in accordance with International Financial
\nReporting Standards (IFRS) which have been adopted by the
\nEU and are mandatory for \ufb01nancial years beginning on or after
\n1 January 2022, and Norwegian disclosure requirements listed
\nin the Norwegian Accounting Act as of 31 December 2022. The
\nconsolidated \ufb01nancial statements have been prepared on a
\nhistorical cost basis. The consolidated \ufb01nancial statements
\nhave been prepared on the basis of uniform accounting
\nprinciples for similar transactions and events under otherwise
\nsimilar circumstances.
\nThe consolidated \ufb01nancial statements are presented in
\nUnited States Dollars, which is the functional currency for all
\nthe material subsidiaries, and all values are rounded to the
\nthousand dollars unless otherwise stated.
\nGOING CONCERN
\nThe board of directors con\ufb01rms that the consolidated \ufb01nancial
\nstatements have been prepared pursuant to the going
\nconcern assumption, and that this assumption was realistic
\nas at the balance sheet date. The going concern assumption
\nis based upon the \ufb01nancial position of the company and the
\ndevelopment plans currently in place. In the board of directors\u2019
\nview, the annual accounts give a true and fair view of the
\ngroup\u2019s assets and liabilities, \ufb01nancial position and results.
\nPetroNor E&P ASA is the parent company of the PetroNor
\nGroup. Its consolidated \ufb01nancial statements have been
\nprepared on the assumption that PetroNor will continue as
\na going concern. The group recognises that in order to fund
\non-going operations and pursue organic and inorganic growth
\nopportunities it will require additional funding. This funding
\nmay be sourced through joint venture equity or share issues or
\nthrough debt \ufb01nance.
\nThe going concern basis assumes the continuity of normal
\nbusiness activity and the realisation of assets and the
\nsettlement of liabilities in the normal course of business. The
\nunderlying business of the group created a net pro\ufb01t after tax
\nof USD 34.3 million for the year ended 31 December 2022, with
\nstrong production from the Congo assets in the \ufb01rst quarter of
\n2023. As at 31 December 2022, the group had a cash balance
\nof USD 24.8 million (2021 USD 31.8 million). The company
\nhas listed on the main exchange of Oslo B\u00f8rs, successfully
\nre\ufb01nanced its debt, achieved high production levels following
\na successful in-\ufb01ll drilling campaign and continues to seek
\nfor potential partners to join the company on its exploration
\nportfolio. This demonstrates that the business has continued
\nto operate e\ufb00ectively, and businesses are willing to engage
\nwith the company and this has enabled the directors of
\nPetroNor (\u201cthe directors\u201d) to form the opinion that the
\ncompany will be in a position to continue to meet its liabilities
\nand obligations for a period of at least twelve months from the
\ndate of signing this report.
\nThese consolidated \ufb01nancial statements do not include any
\nadjustments relating to the recoverability and classi\ufb01cation of
\nrecorded asset amounts or to the amounts and classi\ufb01cation
\nof liabilities that might be necessary should the group not
\ncontinue as a going concern.
\nThe following \ufb01nancial review is based on the consolidated
\n\ufb01nancial statements of PetroNor E&P ASA and its subsidiaries.
\nThe statements have been prepared in accordance with
\nInternational Financial Reporting Standards (IFRS) as adopted
\nby the EU as well as Norwegian accounting legislation.
\nIn the view of the board, the statement of comprehensive
\nincome, statement of changes in equity, statement of \ufb01nancial
\nposition and cash\ufb02ow provide satisfactory information about
\nthe operations, \ufb01nancial results and position of the group and
\nthe parent company at 31 December 2022.
\n
Note 03
Significant accounting judgements, estimates, and assumptions
\nThe directors evaluate estimates and judgements
\nincorporated in the consolidated \ufb01nancial statements based
\non historical knowledge and the best available current
\ninformation. Estimates assume a reasonable expectation of
\nfuture events and are based on current trends and economic
\ndata, obtained both externally and within the group.
\nManagement has identi\ufb01ed the following critical accounting
\npolicies for which signi\ufb01cant judgements, estimates, and
\nassumptions are made. Actual results may di\ufb00er from these
\nestimates under di\ufb00erent assumptions and conditions and
\nmay materially a\ufb00ect \ufb01nancial results or the \ufb01nancial position
\nreported in future period.
\nFurther details of the nature of these assumptions and
\nconditions may be found in the relevant notes to the \ufb01nancial
\nstatements.
\nHYDROCARBON RESERVE AND RESOURCE ESTIMATES
\nHydrocarbon reserves are estimates of the amount of
\nhydrocarbons that can be economically and legally extracted
\nfrom the group\u2019s oil and gas properties. The group estimates
\nits commercial reserves and resources based on information
\ncompiled by appropriately quali\ufb01ed persons relating to the
\ngeological and technical data on the size, depth, shape and
\ngrade of the hydrocarbon body and suitable production
\ntechniques and recovery rates. Commercial reserves are
\ndetermined using estimates of oil and gas in place, recovery
\nfactors and future commodity prices, the latter having an
\nimpact on the total amount of recoverable reserves and the
\nproportion of the gross reserves which are attributable to the
\nhost government under the terms of the production-sharing
\nagreements. Future development costs are estimated using
\nassumptions as to the number of wells required to produce
\nthe commercial reserves, the cost of such wells and associated
\nproduction facilities, and other capital costs. The current long-
\nterm Brent oil price assumption used in the estimation of
\ncommercial reserves is USD 60/bbl. The carrying amount of
\noil and gas properties and licenses at 31 December 2022 are
\nshown in note 16 and 17.
\nThe group estimates and reports hydrocarbon reserves in
\nline with the principles contained in the Society of Petroleum
\nEngineers (SPE) Petroleum Resources Management Reporting
\nSystem (PRMS) framework. As the economic assumptions used
\nmay change and as additional geological information is obtained
\nduring the operation of a \ufb01eld, estimates of recoverable
\nreserves may change. Such changes may impact the group\u2019s
\nreported \ufb01nancial position and results, which include:
\n\u25a0
The carrying value of oil and gas properties may be a\ufb00ected
\ndue to changes in estimated future cash \ufb02ows, note 16;
\n\u25a0
Depreciation and amortisation charges in the statement
\nof pro\ufb01t or loss and other comprehensive income may
\nchange where such charges are determined using the unit
\nof production (UOP) method, or where the useful life of the
\nrelated assets change, note 16;
\n\u25a0
Provisions for decommissioning are subject to re-estimation
\n\u2013 where changes to reserves estimates a\ufb00ect expectations
\nabout when such activities will occur and the associated cost
\nof these activities, note 21.
\nTAXES
\nThe group operates in several tax jurisdictions, and
\nconsequently, its income is subject to various rates and rules
\nof taxation. As a result, the company\u2019s e\ufb00ective tax rate
\nmay vary signi\ufb01cantly depending upon the pro\ufb01tability of
\noperations in the di\ufb00erent jurisdictions.
\nThe group recognises the net future tax bene\ufb01t related to
\ndeferred income tax assets to the extent that it is probable
\nthat the deductible temporary di\ufb00erences will reverse in the
\nforeseeable future. Assessing the recoverability of deferred
\nincome tax assets requires the group to make signi\ufb01cant
\nestimates related to expectations of future taxable income.
\nEstimates of future taxable income are based on forecast cash
\n\ufb02ows from operations and the application of existing tax laws
\nin each jurisdiction, to the extent that future cash \ufb02ows and
\ntaxable income di\ufb00er signi\ufb01cantly from estimates. The ability of
\nthe group to realise the net deferred tax assets recorded at the
\ndate of the statement of \ufb01nancial position could be impacted.
\nAdditionally, future changes in tax laws in the jurisdictions in
\nwhich the group operates could limit the ability of the group to
\nobtain tax deductions in future periods.
\nAdditional information on the accounting policy for taxes is
\nexplained further in note 10 and 31M.
\nDECOMMISSIONING COSTS
\nDecommissioning costs will be incurred by the group at the
\nend of the operating life of some of the group\u2019s facilities and
\nproperties. The group assesses its retirement obligation at
\neach reporting date. The ultimate decommissioning costs are
\nuncertain and cost estimates can vary in response to many
\nfactors, including changes to relevant legal requirements, the
\nemergence of new restoration techniques or experience at
\nother production sites. The expected timing, extent and amount
\nof expenditure can also change, for example in response to
\nchanges in reserves or changes in laws and regulations or
\ntheir interpretation. Therefore, signi\ufb01cant estimates and
\nassumptions are made in determining the provision for
\ndecommissioning costs. As a result, there could be signi\ufb01cant
\nadjustments to the provisions established which would
\na\ufb00ect future \ufb01nancial results. The provision at reporting date
\nrepresents the management\u2019s best estimate of the present
\nvalue of the future decommissioning costs required. Additional
\ninformation is provided in note 21.
\nIMPAIRMENT OF OIL AND GAS ASSETS AND TECHNICAL
\nGOODWILL
\nManagement must determine whether there are circumstances
\nindicating a possible impairment of the group\u2019s oil and gas
\nassets. Changes in the circumstances or expectations of
\nfuture performance of an individual asset or a group of assets
\nmay be an indicator that the asset is impaired, requiring the
\ncarrying amount to be written down to its recoverable amount.
\nAssessment for indicators of impairment includes assessments
\nof expected future cash \ufb02ows, future oil and gas prices, cost
\npro\ufb01les, indicators that the asset will be uneconomic to develop,
\ngeological evaluation and the date of expiration of the licences.
\nImpairments other than impairments of goodwill are reversed
\nwhere impairment indicators are no longer present.
\n
PetroNor has recognised \u201ctechnical goodwill\u201d arising on
\nthe OML 113 business combination. Technical goodwill is
\ncommonly used in the oil and gas industry to describe a
\ncategory of goodwill arising as an o\ufb00setting amount to
\ndeferred tax recognised in business combinations. The
\ntechnical goodwill has been allocated to the OML 113
\nNigeria cash generating unit (CGU) and will be assessed for
\nimpairment where there are indications that the CGU is
\nimpaired. Goodwill is not depreciated and hence, impairment
\nof technical goodwill is expected on a recurring basis,
\nunless there are positive changes in underlying economic
\nassumptions for the asset. When performing the impairment
\ntest for technical goodwill, deferred tax recognised in relation
\nto the acquired assets in a business combination reduces the
\nnet carrying value prior to the eventual impairment charges.
\nWhen deferred tax from the initial recognition decreases,
\nmore goodwill is exposed for impairment. After initial
\nrecognition, depreciation of values calculated in the purchase
\nprice allocations from business combinations will result in
\ndecreased deferred tax liability.
\nNote 04
Revenue
\nAmounts in USD thousand
2022
2021
\nRevenue from contracts with customers
\nRevenue from sales of petroleum products
72,837
57,601
\nOther revenue
\nAssignment of tax oil
47,579
33,102
\nAssignment of royalties
25,650
15,760
\nTotal revenue
146,066
106,463
\nQuantity of oil lifted (barrels)
800,177
831,089
\nAverage selling price (USD per barrel)
90.99
69.31
\nQuantity of net oil produced after royalty, cost oil and tax oil (barrels)
900,495
821,536
\nAll revenue from the sales of petroleum products in 2022
\nis generated, recognised and transferred at a point in time.
\nInvoices are due for settlement thirty days from the bill
\nof lading, the point at which crude oil had been loaded
\nonto vessel for shipment. All group revenue is derived
\nfrom production in the Republic of Congo from the PNGF
\nSud o\ufb00shore asset. The group presents pro\ufb01t oil tax and
\nroyalties on a grossed-up basis as an income tax expense
\nwith corresponding increase in oil and gas revenues and any
\nassociated royalties are included in cost of sales. Refer to note
\n31K for additional information.
\nNote 05
Cost of sales
\nAmounts in USD thousand
2022
2021
\nOperating expenses
16,636
14,303
\nRoyalty
25,650
15,760
\nDepreciation and amortisation of oil and gas properties
9,134
4,385
\nProvision for diversi\ufb01ed investment
1,710
-
\nMovement in oil inventory
(6,920)
137
\nTotal
46,210
34,585
\nProvision for diversi\ufb01ed investment expenditure has been reclassi\ufb01ed from administrative expenses to cost of sales in 2022.
\nNote 06
Other operating income
\nAmounts in USD thousand
2022
2021
\nOther
-
865
\nTotal
-
865
\n
Note 07
Exploration expenses
\nAmounts in USD thousand
2022
2021
\nImpairment reversal
(2,519)
-
\nSeismic data acquisition
889
2,270
\nTotal
(1,630)
2,270
\nImpairment on inventory was reversed in the period to re\ufb02ect current market conditions in the drilling sector (refer to note 12).
\nCosts not capitalised to intangible assets under group policies are expensed including seismic costs and the allocated time writing
\ncosts.
\nNote 08
Administrative expenses
\nAmounts in USD thousand
Note
2022
2021
\nEmployee bene\ufb01t expenses
8A
5,581
5,435
\nTravelling expenses
559
218
\nLegal and professional expenses
5,209
2,620
\nCorporate social responsibility
1,500
1,500
\nProvision for diversi\ufb01ed investment
-
1,051
\nBusiness development
478
486
\nOther expenses
1,051
1,821
\nTotal
14,378
13,131
\nProvision for diversi\ufb01ed investment expenditure has been reclassi\ufb01ed from administrative expenses to cost of sales in 2022.
\n8A.
EMPLOYEE BENEFIT EXPENSES
\nAmounts in USD thousand
2022
2021
\nSalaries
4,834
4,793
\nShort-term non-monetary bene\ufb01ts
490
304
\nDe\ufb01ned contribution pension cost
43
41
\nSocial-security contributions and similar taxes
214
297
\nTotal
5,581
5,435
\nPetroNor is required to have an occupational pension
\nscheme in accordance with the Norwegian law on required
\noccupational pension (\u201cLov om obligatorisk tjenestepensjon\u201d).
\nThe Norwegian subsidiary that employs sta\ufb00 PetroNor E&P
\nServices AS contributes to an external de\ufb01ned contribution
\nscheme and therefore no pension liability is recognised in the
\nstatement of \ufb01nancial position.
\nUnder the Pensions Act 2008, every employer in the UK
\nmust put certain sta\ufb00 into a workplace pension scheme and
\ncontribute towards it,
\nPetroNor E&P Services Limited the subsidiary that employs
\nsta\ufb00 in the UK, contributes into an external de\ufb01ned
\ncontribution scheme. As such, no pension liability is
\nrecognised in the statement of \ufb01nancial position in relation to
\nthe company\u2019s UK-based employees.
\nThere are currently no share-based payment incentive
\nschemes in place for employees.
\nThe cost of non-cash bene\ufb01ts to employees is disclosed as
\nshort-term non-monetary bene\ufb01ts above.
\n
8B.
AUDITORS\u2019 REMUNERATION
\nAmounts in USD thousand
2022
2021
\nPaid or payable to BDO
\nAudit review of \ufb01nancial statements
\nBDO AS
178
-
\nBDO Network \ufb01rms
131
130
\nTotal
309
130
\nOther non-assurance services
\nBDO related practices
19
12
\nTotal
19
12
\nPaid or payable to other audit \ufb01rms
\nAudit or review of \ufb01nancial reports
47
138
\nOther non-assurance services
104
141
\nTotal
151
279
\nFees, excluding VAT, to the auditors are included in administration expenses.
\nNote 09
Finance expenses
\nAmounts in USD thousand
Note
2022
2021
\nUnwinding of discount on decommissioning liability
21
842
995
\nLoan structuring fee
165
-
\nFinance cost on lease liabilities
18
36
8
\nInterest on loans
20
1,042
2,038
\nOther interest
1,237
-
\nTotal
3,322
3,041
\nNote 10
Tax expense
\nAmounts in USD thousand
2022
2021
\nPetroleum revenue tax expense
\nCurrent income tax charge
47,579
33,102
\nTotal tax expense reported in the consolidated statement of comprehensive income
47,579
33,102
\nThe income tax expense is only related to the subsidiary in
\nCongo and represents the assignment of tax oil on the revenue
\nfrom sales of petroleum products, note 4. There was no
\nincome tax expense in the other subsidiaries\u2019 jurisdictions nor
\nin the parent\u2019s jurisdiction as these companies are in taxable
\nloss positions in both 2022 and 2021. Average e\ufb00ective tax rate
\nfor the year was 33 per cent (2021: 31 per cent) based on gross
\nrevenue of the group.
\n
Note 11
Earnings per share
\nAmounts in USD thousand
2022
2021
\nPro\ufb01t attributable to ordinary shareholders
\nPro\ufb01t from continuing operations attributable to the ordinary equity holders used in
\ncalculating basic/diluted pro\ufb01t per share
26,887
12,314
\nPro\ufb01t attributable to the ordinary equity holders used in calculating
\nbasic/diluted pro\ufb01t per share
26,887
12,314
\nWeighted average number of ordinary shares outstanding during
\nthe period used in the calculation of earnings per share
\nBasic
1,372,236,921
1,160,438,253
\nDiluted
1,372,729,890
1,161,827,723
\nEarnings per share
\nBasic
1.96
1.06
\nDiluted
1.96
1.06
\nOptions on issue are considered to be potential ordinary shares
\nand have been included in the determination of diluted loss per
\nshare only to the extent to which they are dilutive. There are nil
\noptions as at 31 December 2022 (2021: 1,389,470).
\nNote 12
Inventories
\nAmounts in USD thousand
2022
2021
\nCrude oil inventory
7,475
554
\nMaterials and supplies
11,349
5,673
\nTotal
18,824
6,227
\nCrude oil inventory is valued at cost of USD 29.43 per
\nbbl (2021: USD 22.84 bbl). This is derived from the direct
\nproduction costs USD 51.2 million (2021: 34.6 million) and the
\nunit production cost USD 1.74 million (2021: 1.51 million).
\nThe crude oil inventory and the material and supplies
\ninventory are valued at the lower of cost and net realisable
\nvalue. Cost is determined using the weighted average method.
\nNet realisable value is the estimated selling price, less
\napplicable selling expenses. The cost of inventory includes all
\ncosts related to bringing the inventory to its current condition,
\nincluding processing costs, labour costs, supplies, direct
\nand allocated indirect operating overhead and depreciation
\nexpense, where applicable, including allocation of \ufb01xed and
\nvariable costs to inventory.
\nIn the current accounting period inventory for the Guinea-
\nBissau drilling campaign was written back up to cost as current
\nmarket conditions indicate that the net realisable value
\nexceeds the cost.
\n
Note 13
Trade and other receivables
\nAmounts in USD thousand
2022
2021
\nRecoverability less than one year
\nTrade receivables
-
13,431
\nOther receivables
1,171
389
\nTotal
1,171
13,820
\nRecoverability more than one year
\nAdvance against decommissioning cost
29,432
26,837
\nTotal
29,432
26,837
\nIn addition to the booking of decommissioning cost asset and
\nliability, the contractors group and the Congolese Government
\nhave decided to set up funds for the decommissioning cost
\nin an escrow account which is managed by the operator. The
\nadvances of the funds for the year are made on the basis of
\nan average rate of USD 1.60 per barrel produced (2021: USD
\n3.68 per barrel). Refer to note 21 for further details on the
\ndecommissioning liability.
\nThe group has adopted the simpli\ufb01ed approach allowable
\nunder IFRS 9 Financial Instruments where the group measures
\nthe provision for impairment for trade receivables and
\namounts due from related parties at an amount equal to
\nlifetime ECL. The ECL on trade receivables are estimated using
\na provision matrix by reference to past default experience of
\nthe debtor and an analysis of the debtors\u2019 current \ufb01nancial
\nposition, adjusted for factors that are speci\ufb01c to the debtors\u2019
\ngeneral economic conditions and forward looking elements of
\nthe industry in which the debtors operate and an assessment
\nof both the current as well as the forecast direction of
\nconditions at the reporting date.
\nNote 14
Cash and cash equivalents
\nAmounts in USD thousand
2022
2021
\nCash in bank
24,775
31,673
\nRestricted cash
41
82
\nTotal
24,816
31,755
\nRestricted cash at 31 December 2022 represents ringfenced
\ncash payable to Norwegian authorities.
\nThe following table represents the changes in liabilities arising
\nfrom \ufb01nancing activities through cash \ufb02ows and non-cash
\nchanges:
\nAmounts in USD thousand
\nNon-current
\nborrowings
\nCurrent
\nborrowings
Total
\nAt 1 January 2022
-
13,079
13,079
\nCash \ufb02ows
5,500
(7,579)
(2,079)
\nNon-cash \ufb02ows
-
-
-
\nAs at 31 December 2022
5,500
5,500
11,000
\nAt 1 January 2021
14,912
4,000
18,912
\nCash \ufb02ows
(1,833)
(4000)
(5,833)
\nNon-cash \ufb02ows
-
-
-
\nMovement non-current to current
(13,079)
13,079
-
\nAs at 31 December 2021
-
13,079
13,079
\n
Note 15
Segment information
\nFor management purposes, the group is organised into one
\nmain operating segment, which involves exploration and
\nproduction of hydrocarbons. All of the group's activities are
\ninterrelated, and discrete \ufb01nancial information is reported
\nto chief operating decision maker as a single segment.
\nAccordingly, all signi\ufb01cant operating decisions are based upon
\nanalysis of the group as one segment. The \ufb01nancial results
\nfrom this segment are equivalent to the \ufb01nancial statements
\nof the group as a whole.
\nThe group only has one operating segment, being exploration
\nand production of hydrocarbons.
\nThe analysis of the location of non-current assets is as follows:
\nAmounts in USD thousand
2022
2021
\nCongo
98,876
69,564
\nThe Gambia
4,507
3,507
\nGuinea-Bissau
667
314
\nNigeria
35,226
3
\nNorway
380
62
\nTotal
139,656
73,450
\nNote 16
Property, plant, and equipment
\nPRODUCTION ASSETS AND EQUIPMENT
\nAmounts in USD thousand
2022
2021
\nCost
\nAt 1 January
53,204
33,445
\nAdditions
36,681
19,759
\nDisposals
-
-
\nAt 31 December
89,885
53,204
\nDepreciation
\nAt 1 January
13,807
9,962
\nCharge for the year
8,599
3,845
\nDepreciation on disposals
-
-
\nAt 31 December
22,406
13,807
\nNet carrying amount
\nAt 31 December
67,479
39,397
\nProduction assets and equipment are carried at the following values:
\nAmounts in USD thousand
2022
2021
\nOil & gas CAPEX
62,544
33,968
\nDecommissioning costs
4,900
5,396
\nOther
35
33
\nTotal
67,479
39,397
\nPPE assets are distributed geographically as follow:
\nAmounts in USD thousand
2022
2021
\nCongo
66,542
39,377
\nNigeria
927
-
\nOther
10
20
\nTotal
67,479
39,397
\n
Note 17
Intangible assets
\nLICENCES AND APPROVALS
\nAmounts in USD thousand
2022
2021
\nCost
\nAt 1 January
11,210
10,396
\nAdditions in relation to business combinations (refer to note 26)
24,268
-
\nAdditions
2,353
814
\nAt 31 December
37,831
11,210
\nAccumulated amortisation and impairment
\nAt 1 January
4,038
3,461
\nAmortisation
541
577
\nImpairment
-
-
\nAt 31 December
4,579
4,038
\nNet carrying value
\nAt 1 January
7,172
6,935
\nAt 31 December
33,252
7,172
\nGOODWILL
\nAmounts in USD thousand
2022
2021
\nCost
\nAt 1 January
-
-
\nAdditions in relation to business combinations (refer to note 25)
9,031
-
\nImpairment
-
-
\nAt 31 December
9,031
-
\nGOODWILL
\nGoodwill of USD 9.0 million at 31 December 2022 consists of
\ntechnical goodwill related to the acquisition that occurred
\nduring the year, note 26. Technical goodwill is subject to
\nimpairment testing whenever there is an indicator that the
\nCGU to which it is allocated is impaired. Technical goodwill
\nhas been allocated to the OML 113 CGU and impairment
\nassessments will be based on the underlying economics
\nfor the asset. When performing the impairment test for
\ntechnical goodwill, deferred tax recognized in relation to the
\nacquired assets in a business combination reduces the net
\ncarrying value prior to the eventual impairment charges.
\nWhen deferred tax from the initial recognition decreases,
\nmore goodwill is exposed for impairment. After initial
\nrecognition, depreciation of values calculated in the purchase
\nprice allocations from business combinations will result in
\ndecreased deferred tax liability.
\nLICENCE OVERVIEW
\nCongo
\nIn 2017, subsidiary company Hemla E&P Congo SA acquired
\ninterests in three development and production permits
\n(Tchendo: 20 per cent; Tchibouela: 20 per cent and Tchibeli-
\nLitanzi: 20 per cent) which will respectively end in December
\n2037, for each of them, with possible extensions for 5 years.
\nAll these three licenses are called or named collectively
\n\u201cPNGF Sud\u201d and together comprise an area of 482.28km
\n2
\n. The
\noperator of the licences is Perenco, and the carrying value as
\nat 31 December 2022 is USD 2.8 million. This number is net of
\ndepletion, the Congo intangible assets are the only intangibles
\nin active use and being amortised.
\nNigeria
\nThe corporate acquisition from Panoro Energy ASA during
\nyear, added an economic interest in the OML 113 \ufb01eld of
\n12.1913 per cent that is operated by Yinka Folawiyo Petroleum.
\nThere were two producing wells prior to suspending
\nproduction in November 2021 due to the terminated contract
\nwith the FPSO, the Aje-4 with oil production and Aje-5ST2
\nwith oil and gas production. The licence was renewed in 2018
\nand has a twenty-year term. The current strategy is to update
\nthe \ufb01eld development plan to expedite gas development and
\noverall redevelopment of the venture. As at 31 December
\n2022, the carrying value of the licence was USD 24.3 million.
\nThe Gambia
\nThe A4 licence area is 1,376km
\n2
\nand is operated by company
\nsubsidiary PetroNor E&P Gambia Ltd. PetroNor secured a new
\nexploration licence (PEPLA) on 18 November 2022 and entered
\ninto the \ufb01rst exploration period which has a duration of three
\nyears. PetroNor hold 90 per cent equity with the Gambia
\nNational Petroleum Company as partner (10 per cent equity).
\nAs at 31 December 2022, the carrying value of the A4 licence is
\nUSD 4.5 million.
\n
Guinea-Bissau
\nAs at 31 December 2022, 78.57 per cent interest of the Sinapa
\nand Esperan\u00e7a licences are held and operated by PetroNor
\nsubsidiary PetroNor E&P AB. Post year end it was con\ufb01rmed
\nthat 21.43 per cent previously held by FAR Ltd
had been
\ntransferred to PetroNor. The combined licences cover an area
\nof 4,963km
\n2
\nand have USD 0.6 million carrying value in the
\n\ufb01nancial statements as at 31 December 2022. The current
\nexploration phase runs to October 2023.
\nSenegal
\nAs at the date of this report, the company\u2019s subsidiary
\nAfrican Petroleum Senegal Limited awaits the decision of
\nthe arbitration proceedings with the International Centre for
\nthe Settlement of Investment Disputes (ICSID) regarding the
\ninterests in the Senegal O\ufb00shore Sud Profond and Ru\ufb01sque
\nO\ufb00shore Profond blocks in Senegal (ICSID case ARB/18/24).
\nThe combined licences cover an area of 15,796km
\n2
\nand due to
\nthe arbitration process have nil carrying value in the \ufb01nancial
\nstatements as at 31 December 2022. Please refer to board
\ndirector\u2019s report for additional information on the arbitration
\nstatus.
\nIntangible assets are valued in accordance with group
\naccounting policies and are assessed for indications of
\nimpairment in accordance with IAS 36. There were no
\nindicators of impairment as at 31 December 2022 for the
\nlicence costs within the group. Refer to note 30I for additional
\ninformation.
\nRESERVES
\nThe group has adopted a policy of regional reserve reporting
\nusing external third-party companies to audit its work and
\ncertify reserves and resources. Reserve and contingent
\nresource estimates comply with the de\ufb01nitions set by the
\nPetroleum Resources Management System (\u201cPRMS\u201d) issued
\nby the Society of Petroleum Engineers (\u201cSPE\u201d), the American
\nAssociation of Petroleum Geologists (\u201cAAPG\u201d), the World
\nPetroleum Council (\u201cWPC\u201d) and the Society of Petroleum
\nEvaluation Engineers (\u201cSPEE\u201d) in March 2007. AGR Petroleum
\nServices AS provided the 3
\nrd
\nparty veri\ufb01cations of the PNGF
\nSud reserves. CPR Tracs International Limited provided the 3
\nrd
\nparty veri\ufb01cation of the Aje reserves.
\nThe following is a summary of key results from the reserve
\nreports (net of the group\u2019s share):
\nAsset
1P reserves
2P reserves
3P reserves
\nMMbbls
MMbbls
MMbbls
\nPNGF Sud
12.5
18.5
24.7
\nAje
-
-
-
\nTotal
12.5
18.5
24.7
\nDe\ufb01nitions:
\n1P) Proved reserves
\nProved reserves are those quantities of petroleum, which by
\nanalysis of geoscience and engineering data, can be estimated
\nwith reasonable certainty to be commercially recoverable,
\nfrom a given date forward, from known reservoirs and
\nunder de\ufb01ned economic conditions, operating methods, and
\ngovernment regulations.
\n2P) Proved plus probable reserves
\nProbable reserves are those additional reserves which analysis
\nof geoscience and engineering data indicate are less likely to
\nbe recovered than proved reserves but more certain to be
\nrecovered than possible reserves.
\n3P) Proved plus probable plus possible reserves
\nPossible reserves are those additional reserves which analysis
\nof geoscience and engineering data indicate are less likely to
\nbe recovered than probable reserves.
\nNote 18
Leases
\nAmounts in USD thousand
\nRight-of-use assets
\nO\ufb03ce building
Lease liabilities
\nAt 1 January 2022
44
58
\nAdditions
564
492
\nAmortisation expense
(146)
-
\nInterest expense
-
36
\nPayments made
-
(127)
\nAt 31 December 2022
462
459
\nAgeing of lease liabilities
\nCurrent
179
\nNon-current
280
\n
Amounts in USD thousand
\nRight-of-use assets
\nO\ufb03ce building
Lease liabilities
\nAt 1 January 2021
212
225
\nAdditions
-
-
\nAmortisation expense
(168)
-
\nInterest expense
-
8
\nPayments made
-
(175)
\nAt 31 December 2021
44
58
\nAgeing of lease liabilities
\nCurrent
-
58
\nNon-current
-
-
\nAmounts recognised in pro\ufb01t and loss
\nAmounts in USD thousand
31 December 2022
31 December 2021
\nAmortisation expense on right-of-use assets
146
168
\nInterest expense on lease liabilities
36
8
\nExpense relating to short-term lease
-
-
\nTotal
182
176
\nThe total cash out\ufb02ow for leases amount to USD 163,000 for the year.
\nNote 19
Trade and other payables
\nAmounts in USD thousand
Note
2022
2021
\nAmounts due less than one year
\nTrade payables
15,437
22,014
\nDue to related parties
25D
2,019
3,449
\nTaxes and state payables
787
120
\nOther payables and accrued liabilities
2,508
4,472
\nTotal
20,751
30,055
\nAmounts due more than one year
\nOther payables
8,738
-
\nTotal
8,738
-
\nNote 20
Loans and borrowings
\nAmounts in USD thousand
2022
2021
\nAt 1 January
13,079
18,912
\nReceived
11,000
-
\nPrincipal repayment
(13,079)
(5,833)
\nInterest on loan accrued
1,042
1,539
\nInterest on loan paid
(1,042)
(1,539)
\nAt 31 December
11,000
13,079
\nAgeing of loans payable
\nCurrent
5,500
13,079
\nNon-current
5,500
-
\nTotal
11,000
13,079
\n
In 2020, PetroNor agreed a USD 15 million facility with 12
\nmonths grace period and maturity date in October 2022. The
\nloan was to be repaid in monthly instalments after the initial
\ngrace period and carried an interest rate of 9 per cent plus
\none-month LIBOR payable monthly if the oil price was below
\nUSD 40 per bbl and 12.5 per cent if the oil price was above USD
\n40 per bbl. The loan was secured against:
\n\u25a0
The assignment of receivables by subsidiary company
\nHemla E&P Congo SA (\u201cHEPCO\u201d);
\n\u25a0
Pledge over one of the bank accounts of subsidiary company
\nHemla Africa Holding AS (\u201cHAH\u201d);
\n\u25a0
Pledge over one of the bank accounts of subsidiary company
\nHEPCO;
\n\u25a0
Pledge over shares in subsidiary companies, HAH and
\nHEPCO;
\n\u25a0
Assignment of inter-company loan agreement between HAH
\nand HEPCO; and
\n\u25a0
Corporate guarantees by PetroNor E&P Ltd (Australia) and
\nits subsidiaries PetroNor E&P Ltd (Cyprus) and HEPCO.
\nOn 29 December 2022, HAH and Acqua Diversi\ufb01ed Holdings
\nSPC entered into an amended agreement to advance an
\nadditional USD 11.0 million to be repaid in eight quarterly
\ninstalments of USD 1.375 million. The remaining principal of
\nUSD 2.5 million was repaid along with outstanding interest
\nand arrangement fees for the amended facility. The amended
\nfacility carries an interest rate of 11.0 per cent, and due to the
\ngroup corporate restructure in February 2022, in addition to
\nthe previous security provided, a corporate guarantee was
\nprovided by the new parent company PetroNor E&P ASA.
\nThe Acqua Diversi\ufb01ed Holdings SPC loan has the following
\ncovenants and undertakings:
\n\u25a0
Cash equal to the quarterly instalments must be maintained
\non speci\ufb01c bank accounts of HAH or HEPCO on a recurring
\nbasis;
\n\u25a0
At least USD 6.0 million from HEPCO oil sales must be paid
\ninto the collection account on a 3-month rolling basis;
\n\u25a0
PetroNor to maintain shareholding level in excess of 70 per
\ncent in subsidiary company HAH;
\n\u25a0
HAH to maintain shareholding level in excess of 74.25 per
\ncent in subsidiary company HEPCO;
\n\u25a0
HAH shareholder equity ratio shall not be less than 30 per
\ncent;
\n\u25a0
HAH duty to report on \ufb01nancial statements, pledged bank
\naccount activity and oil inventory;
\n\u25a0
Restrictions on distributions to HAH shareholders, unless
\nsu\ufb03cient liquidity with cash balances exceeding USD 10.0
\nmillion immediately before any such distribution, and
\ndistribution does not exceed 75 per cent consolidated HAH
\nnet pro\ufb01t in any year.
\nSeparately on 28 September 2020, subsidiary company HAH
\npaid a USD 3.9 million dividend to minority interest and related
\nparty Symero Ltd. An amount equal to the dividend was
\nimmediately loaned to the top company of the group at the
\ntime, PetroNor E&P Ltd (Australia), by Symero Ltd with interest
\nrates matching those already provided by external \ufb01nancing
\nand no security was provided for the loan. The maturity date
\nwas matched to the USD 15 million facility. On 21 December
\n2022, the principal balance of USD 3.9 million was repaid to
\nSymero Ltd.
\nAll covenants were complied with and there were no
\nnoti\ufb01cations of breaches during the year for both loans
\npayable to Acqua Diversi\ufb01ed Holdings SPC and Symero Ltd.
\nNote 21
Provisions
\nDECOMMISSIONING LIABILITY
\nIn accordance with joint venture agreements and legislation,
\nthe wellheads, production assets, pipelines and other
\ninstallations may have to be dismantled and removed from oil
\nand natural gas \ufb01elds when the production ceases. The exact
\ntiming of the obligations is uncertain and depends on the rate
\nthe reserves of the \ufb01eld are depleted.
\nBased on the existing production pro\ufb01le of the PNGF Sud \ufb01eld
\nand the size of the reserves, it is expected that expenditure
\non retirement is likely to be after more than ten years. The
\ncurrent bases for the provision are a discount rate of 6.5
\nper cent (2021: 6.5 per cent) and an in\ufb02ation rate of 1.6 per
\ncent (2021: 1.6 per cent). The initial decommissioning liability
\n(ARO) study was prepared internally by the operator Perenco
\nand was presented to ARO committee in 2018. The company
\nreassessed the applicable discount rate during 2022 based
\non the rates of government bonds issued in the Congo during
\nthe year. The impact of the change in discount factor was not
\nconsidered material.
\nWith the acquisition of the Panoro interest in the OML 113
\nventure, PetroNor added a decommissioning provision of USD
\n3.7million. The acquired OML113 assets are discounted at 2.50
\nper cent with an in\ufb02ation rate of 2.0 per cent.
\nThe following table presents a reconciliation of the beginning
\nand ending aggregate amounts of the obligations associated
\nwith the retirement of oil and natural gas properties:
\nAmounts in USD thousand
Note
2022
2021
\nAt 1 January
16,302
15,307
\nArising during the year
3,768
-
\nUnwinding of discount on decommissioning
9
842
995
\nAt 31 December
20,912
16,302
\n
Note 22
Deferred tax liabilities
\nAmounts in USD thousand
\nProperty, plant, and equipment,
\nand intangible assets
Total
\nDeferred tax liabilities
(9,031)
(9,031)
\nNet asset/(liability) at 31 December 2022
(9,031)
(9,031)
\nAmounts in USD thousand
\nProperty, plant, and equipment,
\nand intangible assets
Total
\nDeferred tax liabilities
-
-
\nNet asset/(liability) at 31 December 2021
-
-
\nChanges in net deferred tax liabilities during the year were as follows:
\nAmounts in USD thousand
2022
2021
\nNet deferred tax liability at 1 January
-
-
\nAcquisitions and disposals
(9,031)
-
\nNet deferred tax liability at 31 December
(9,031)
-
\nDeferred tax assets have not been brought to account in
\nrespect of tax losses and unrecognised capital allowances
\nbecause as at 31 December 2022 it is uncertain when future
\ntaxable amounts will be available to utilise those temporary
\ndi\ufb00erences and losses. As at 31 December 2022, the carried
\nforward gross tax loss is USD 132 million (2021: USD 116
\nmillion). Tax losses carried forward has increased by USD 16
\nmillion year on year, this is predominantly due to tax losses
\nincurred in Norway (USD 10 million), United Kingdom (USD 1.3
\nmillion), Sweden (USD 1.1 million), other entities (3.6 million).
\nCarried forward losses from previous periods do not have
\nan expiry date. The deferred tax liability has arisen upon fair
\nvalue adjustments as part of a business combination (refer to
\nnote 26 for additional detail).
\nNote 23
Share capital
\nOrdinary shares participate in dividends and the proceeds on
\nwinding up of the company in proportion to the number of
\nshares held and in proportion to the amount paid up on the
\nshares held.
\nAt shareholders\u2019 meetings, each ordinary share entitles the
\nholder to one vote in proportion to the paid-up amount of the
\nshare when a poll is called, otherwise each shareholder has
\none vote on a show of hands.
\nReconciliation of movement in shares on issue
\nNumber of fully paid ordinary shares
2022
2021
\nBalance at the beginning of the year
1,326,991,006
971,665,288
\nIssue of shares
96,577,537
355,325,718
\nBalance at 31 December
1,423,568,543
1,326,991,006
\n
Reconciliation of movements in issued capital
\nAmounts in USD thousand
2022
2021
\nOpening balance
62,115
17,735
\nReversal of shares as part of redomicile
\n1
\n(62,115)
-
\nIssue of shares in PetroNor E&P ASA as part of redomicile
\n1
\n149
-
\nShare capital issued as consideration for business combination
\n2
\n10
-
\nIssue of ordinary shares
-
45,943
\nShare issue costs
-
(1,563)
\nBalance at end of the period
159
62,115
\n1)
On 24 February 2022, the company issued 1,326,991,006 ordinary shares as part of the implementation of the scheme of arrangement and redomicile from
\nAustralia to Norway. Shares are issued at the nominal value of 0.001 NOK and translated to 0.01 USD using the rate of exchange on the day of issue.
\n2)
On 13 July 2022, PetroNor E&P ASA completed the acquisition of Pan-Petroleum Nigeria Holding BV and Pan-Petroleum Services Holdings BV that hold 100
\nper cent of the shares in Pan-Petroleum AJE Ltd. The upfront consideration was USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor
\nshares. The shares were issued at the nominal value of 0.001 NOK USD using the daily exchange rate published by the Bank of England. Refer to note 26 for
\nadditional information.
\nShare premium
\nShare premium reserve represents excess of subscription
\nvalue of the shares over the nominal amount.
\nAmounts in USD thousand
2022
2021
\nOpening balance
-
-
\nIssue of shares as part of redomicile
61,966
-
\nShare capital issued as consideration for business combination
9,990
-
\nBalance at end of the period
71,956
-
\nThe issued share capital for PetroNor E&P Ltd (Australia)
\nformerly the parent entity in 2021 is adjusted downwards to
\nre\ufb02ect historic fair value adjustments on two reverse takeover
\nevents so as to re\ufb02ect group share capital. The like for like share
\nexchange and relisting on the Oslo B\u00f8rs is a continuation of
\nthe business and so group share capital remains unchanged
\nfollowing the issue of 1,326,991,006 shares.
\nCAPITAL MANAGEMENT
\nThe management controls the capital of the company in order
\nto maximise the return to shareholders and ensure that the
\ncompany can fund its operations and continue as a going
\nconcern. Capital is de\ufb01ned as issued share capital.
\nThe management e\ufb00ectively manages the company\u2019s capital
\nby assessing the company\u2019s \ufb01nancial risks and adjusting its
\ncapital structure in response to changes in these risks and
\nin the market. These responses include the management of
\nexpenditure and debt levels, distributions to shareholders and
\nshare and option issues. There have been no changes in the
\nstrategy adopted by the management to control the capital of
\nthe company since the prior reporting period.
\nThe management monitors capital requirements through cash
\n\ufb02ow forecasting. The management may seek further capital if
\nrequired through the issue of capital or changes in the capital
\nstructure. To maintain the listing on the Oslo B\u00f8rs, PetroNor
\nmust continue to satisfy requirements on capital set by the
\nExchange. These requirements include a free \ufb02oat in excess of
\n25 per cent and a minimum number of shareholders.
\nNote 24
Reserves
\nThe movement in reserves are re\ufb02ected in the statement of
\nchanges in equity.
\nForeign currency translation reserve
\nThe foreign currency translation reserve is used to recognise
\nforeign currency exchange di\ufb00erences arising on translation of
\nfunctional currency to presentation currency.
\nRetained earnings
\nAll other net gains and losses and transactions with owners
\nnot recognised elsewhere.
\nDividends
\nNo dividends were declared during the year by the parent
\ncompany.
\n24A.
OPTIONS
\nHolders of options do not have any voting or dividend rights
\nin relation to the options. Share options are valued using
\nthe stochastic Black-Scholes model. The inputs to the model
\nare the weighted average share price, the expected average
\nexercise price, expected life, the risk free rate of return and the
\nexpected volatility. All options are fully vested and so no costs
\nwere charged in the current accounting period (2021 nil).
\n
The following table reconciles the outstanding share options
\ngranted, exercised, and forfeited during the year:
\n2022
2021
\nNumber of
\noptions
\nWeighted average
\nexercise price
\nequivalent USD
\nNumber of
\noptions
\nWeighted average
\nexercise price
\nequivalent USD
\nBalance at beginning of the period
1,389,470
0.79
1,389,470
0.81
\nLapsed
(1,389,470)
0.79
-
-
\nBalance at end of the year
-
-
1,389,470
0.79
\nExercisable at end of the year
-
-
1,389,470
0.79
\nAs at 31 December 2022, all share options have expired.
\nNote 25
Related party transactions
\n25A.
SUBSIDIARIES
\nThe principal subsidiaries of the PetroNor E&P ASA, all of
\nwhich have been included in these consolidated \ufb01nancial
\nstatements, are as follows:
\nProportion of e\ufb00ective ownership
\ninterest at 31 December
\nName
\nCountry of
\nincorporation
\nPrincipal place
\nof business
2022
2021
\nPetroNor E&P Pty Limited
\n(Previously called PetroNor E&P Ltd)
Australia
Australia
100%
100%
\nPetroNor E&P Ltd
Cyprus
Cyprus
100%
100%
\nPetroNor E&P Services AS
Norway
Norway
100%
100%
\nPetroNor E&P Services Ltd
United Kingdom
United Kingdom
100%
100%
\nPetroNor E&P AB
Sweden
Guinea-Bissau
100%
100%
\nPetroNor E&P Ltd
Nigeria
Nigeria
100%
100%
\nPetroNor E&P Gambia Ltd
Cayman Islands
The Gambia
100%
100%
\nHemla Africa Holding AS
Norway
Norway
100%
100%
\nHemla E&P Congo SA
Congo
Congo
84.15%
84.15%
\nAfrican Petroleum Corporation Ltd
Cayman Islands
United Kingdom
100%
100%
\nAfrican Petroleum Senegal Ltd
Cayman Islands
Senegal
90%
90%
\nAfrican Petroleum Senegal SAU
Senegal
Senegal
90%
90%
\nAje Production AS
Norway
Norway
100%
100%
\nAje Services Holding BV (Previously called
\nPan-Petroleum Services Holding BV)
Netherlands
Netherlands
100%
-
\nAje Nigeria Holding BV (Previously called
\nPan-Petroleum Services Holding BV)
Netherlands
Netherlands
100%
-
\nAje Production Ltd (Previously called
\nPan-Petroleum Aje Ltd)
Nigeria
Nigeria
100%
-
\nMaterial non-controlling interests
\nSet out below is summarised \ufb01nancial information for the
\nsubsidiary that has non-controlling interests that are material
\nto the group. The amounts disclosed for the subsidiary are
\nbefore inter-company eliminations.
\n
Summarised statement of \ufb01nancial position
\nHemla E&P Congo SA
\nAmounts in USD thousand
2022
2021
\nCurrent asset
28,363
37,936
\nCurrent liabilities
11,210
31,130
\nCurrent net assets
17,153
6,806
\nNon-current assets
98,876
69,577
\nNon-current liabilities
20,804
16,302
\nNon-current net assets/(liabilities)
78,072
53,275
\nNet assets
95,225
60,081
\nAccumulated NCI
16,091
10,215
\nSummarised statement of comprehensive income
\nHemla E&P Congo SA
\nAmounts in USD thousand
2022
2021
\nRevenue
146,067
106,464
\nPro\ufb01t for the period
45,503
31,685
\nOther comprehensive income
-
-
\nTotal comprehensive income for the year
45,503
31,685
\nPro\ufb01t allocated to NCI
7,461
8,714
\nDividends paid to NCI
1,585
-
\nSummarised cash \ufb02ows
\nHemla E&P Congo SA
\nAmounts in USD thousand
2022
2021
\nCash \ufb02ows from operating activities
41,847
39,360
\nCash \ufb02ows from investing activities
(38,349)
(25,331)
\nCash \ufb02ows from \ufb01nancing activities
(10,028)
(6,047)
\nNet (decrease)/increase in cash and cash equivalents
(6,530)
8,312
\n25B.
BOARD AND KEY MANAGEMENT PERSONNEL
\nREMUNERATION
\nKey management personnel are those persons having
\nauthority and responsibility for planning, directing, and
\ncontrolling the activities of the group, including the directors
\nlisted on page 47, and the following other key personnel:
\nJens Pace
Interim chief executive o\ufb03cer
\nClaus Frimann-Dahl
Chief technical o\ufb03cer
\nEmad Sultan
Strategy and contracts manager
\nMichael Barrett
Exploration manager
\nChris Butler
Group \ufb01nancial controller
\n
As at the approval date of this report the base salary and fees
\nfor the following members of key management is as follows:
\nIndividual
Title
Group entity
\nBase salary and fees
\n/per annum
\nTotal base salary and
\nfees USD equivalent
\nE Alhomouz
Chair
\nPetroNor E&P Services AS
\n1
\nUSD 174,000
\n294,000
\nHemla E&P Congo SA
USD 120,000
\nJ Iskander
Director
\n2
\nNil
Nil
\nI Tybring-Gjedde
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nG Kielland
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nJ Norman-Hansen
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nA Fawzi
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nJ Pace
Interim CEO
PetroNor E&P Services AS
GBP 360,000
443,000
\nE Sultan
Strategy & contracts manager
PetroNor E&P Services AS
USD 240,000
240,000
\nC Frimann-Dahl
Chief technical o\ufb03cer
PetroNor E&P Services AS
NOK 2,500,000
253,000
\nM Barrett
Exploration o\ufb03cer
PetroNor E&P Services Ltd
GBP 215,000
264,000
\nC Butler
Group \ufb01nancial controller
\nPetroNor E&P Services Ltd
GBP 140,000
\n238,000
\nHemla E&P Congo SA
USD 66,000
\n1)
Fees are charged by related party Petromal LLC and are not paid to the individual; above \ufb01gures represent the company\u2019s fair value estimate of associated
\ncosts for the individual\u2019s services.
\n2)
J Iskander elected not to be remunerated, as he is not considered an independent director due to connections to the largest company shareholder.
\nFX rates used:
NOK 1.00 : USD 0.1038
|
GBP 1.00 : USD 1.23
\nRemuneration of board and key management 2022
\nAmounts in USD
Designation
\nSalary and
\nfees
Bonus
\nOther cash
\nbene\ufb01ts
\nPost-employment
\nbene\ufb01ts
Total
\nE Alhomouz
\n1
\nChair
294,000
-
-
-
294,000
\nJ Iskander
Director
-
-
-
-
-
\nI Smines Tybring
\nGjedde
Director
34,598
-
-
-
34,598
\nG Kielland
Director
34,598
-
-
-
34,598
\nA Neuling
\n2
\nDirector
5,728
-
-
-
5,728
\nR Steinepreis
\n2
\nDirector
5,728
-
-
-
5,728
\nJ Pace
Interim CEO
443,500
-
-
-
443,500
\nC Frimann-Dahl
Chief technical o\ufb03cer
253,080
-
769
20,524
274,373
\nM Barrett
Exploration o\ufb03cer
279,445
-
884
2,080
282,409
\nC Butler
Group \ufb01nancial controller
173,059
92,177
5,747
17,306
288,289
\nE Sultan
Strategy & contracts manager
233,000
-
-
-
233,000
\nA Hicks
\n2
\nCompany secretary
3,598
-
-
-
3,598
\nTotal
1,760,334
92,177
7,400
39,910
1,899,821
\n1)
USD 174,000 of the fees above is not paid to the individual, these fees charged on an arms-length basis are included in a monthly lump sum charged by
\nrelated party Petromal LLC, above \ufb01gures represent the company\u2019s fair value estimate of associated costs for the individual\u2019s services.
\n2)
Indviduals are directors or management of the previous Australian top company, the above \ufb01gure represents their remuneration up until the group
\nrestructure on 24 February 2022.
\n
Remuneration of of board and key management 2021
\nAmounts in USD
Designation
\nSalary and
\nfees
Bonus
\nOther cash
\nbene\ufb01ts
\nPost-
\nemployment
\nbene\ufb01ts
Total
\nE Alhomouz
\n1
\nChair
294,000
-
-
-
294,000
\nJ Iskander
Director
-
-
-
-
-
\nJens Pace
\n2
\nDirector & Interim CEO
47,909
-
-
-
47,909
\nI Smines Tybring Gjedde
Director
38,001
-
-
-
38,001
\nG Kielland
\n3
\nDirector
25,994
-
-
-
25,994
\nA Neuling
Director
26,787
-
-
-
26,787
\nR Steinepreis
Director
32,546
-
-
-
32,546
\nG Ludvigsen
\n4
\nDirector & business development manager
385,210
-
110
-
385,320
\nK S\u00f8vold
\n5
\nExec director & CEO
354,118
-
821
21,721
376,659
\nC Frimann-Dahl
Chief technical o\ufb03cer
221,648
-
780
20,732
243,160
\nM Barrett
Exploration o\ufb03cer
296,475
-
2,598
-
299,073
\nC Butler
Group \ufb01nancial controller
174,825
-
3,724
17,483
196,032
\nE Sultan
Strategy & contracts manager
\n3
\n168,000
-
-
-
168,000
\nA Hicks
Company secretary
27,035
-
-
-
27,035
\nTOTAL
2,092,548
-
8,033
59,935
2,160,516
\n1)
USD 174,000 of salary and fees is not paid to the individual, these fees charged on an arms-length basis are included in a monthly lump sum charged by
\nrelated party Petromal LLC, above \ufb01gures represent the company\u2019s fair value estimate of associated costs for the individual\u2019s services.
\n2)
On 16 December 2021, Mr Pace was appointed as interim CEO and subsequently resigned as a board member.
\n3)
Appointed 1 February 2021
\n4)
Following his resignation as a board member on 1 February 2021, G Ludvigsen continued to provide services charged on an arms-length by a related party
\nHagan AS.
\n5) From 16 December 2021, individuals no longer considered key management personnel as decision making responsibilities removed.
\nShare holdings by directors and other key management personnel
\nBalance
\n1 January 2022
\nShares
\npurchased
\nGranted as
\nremuneration
\nNet change
\nother
\nBalance
\n31 December 2022
\nJ Pace
1,498,858
-
-
(33,334)
1,465,524
\nM Barrett
1,151,687
-
-
-
1,151,667
\nC Butler
234,316
-
-
-
234,296
\nC Frimann-Dahl
604,545
-
-
-
604,545
\nTotal
3,498,406
-
-
(33,334)
3,456,072
\nAs at 31 December 2022, Eyas Alhomouz held no shares
\npersonally but holds in\ufb02uence over 481,481,666 shares (2021:
\n481,481,666 shares) as the CEO of signi\ufb01cant shareholder
\nPetromal LLC. 109,520,419 of the shares held by Petromal LLC
\nare recorded in the name of nominee company, Clearstream
\nBanking S.A. on behalf of Petromal LLC.
\nOther directors and key management not included in the
\nabove table held no shares during the current year.
\nNo warrants or options were held by directors or key
\nmanagement personnel during the current year.
\n25C.
SIGNIFICANT SHAREHOLDERS
\nShareholder
Place of incorporation
\nOwnership
\n31 December 2022
\nOwnership
\n31 December 2021
\nPetromal LLC \u2013 Sole Proprietorship LLC
UAE
33.82%
36.28%
\nSymero Ltd
Cyprus
9.75%
10.47%
\nNOR Energy AS
Norway
9.49%
10.45%
\nAmbolt Invest AS
Norway
6.15%
6.61%
\nGulshagen III AS
Norway
3.16%
3.39%
\nGulshagen IV AS
Norway
3.16%
3.39%
\n
Symero Ltd is a company owned by NOR Energy AS, which
\nin turn is controlled jointly by former key management of
\nPetroNor, Knut S\u00f8vold, and Gerhard Ludvigsen.
\nGulshagen III AS and Gulshagen IV AS are also controlled by
\nKnut S\u00f8vold.
\nAmbolt Invest AS is a company controlled by Jarle Norman-
\nHansen who was appointed as a board member on 26 January
\n2023.
\n25D.
TRANSACTIONS AND PERIOD-END BALANCES WITH RELATED PARTIES
\nTransactions with related parties included in the consolidated statement of comprehensive income:
\nAmounts in USD thousand
2022
2021
\nPetromal \u2013 Sole Proprietorship LLC
289
554
\nAdministrative expenses
289
554
\nPetromal LLC is the largest shareholder in the company and
\nsince 2017 has had an agreement to provide technical and
\nproject management services to the PetroNor group.
\nBalances due from and due to related parties disclosed in the consolidated statement of \ufb01nancial position:
\nAmounts in USD thousand
2022
2021
\nOther payable to NOR Energy AS
1,283
2,136
\nOther payable to Petromal \u2013 Sole Proprietorship LLC
736
1,281
\nOther payable to Symero Ltd
-
32
\nTotal payables to related parties (note 19)
2,019
3,449
\nLoan payable Symero Ltd
-
3,912
\nLoan payable to related parties (note 20)
-
3,912
\nAmounts due from / to related parties included in the
\nconsolidated statement of \ufb01nancial position (other than the
\nloans to related parties) are interest-free and have no \ufb01xed
\nrepayment terms. The outstanding payable balances as at 31
\nDecember 2022 were settled during Q1 2023.
\nNote 26
Acquisition of subsidiaries
\nOn 13 July 2022, PetroNor completed the corporate acquisition
\nof both Pan-Petroleum Nigeria Holding BV and Pan-Petroleum
\nServices Holdings BV, who together hold 100 per cent of the
\nshares in Pan-Petroleum AJE Ltd, from Panoro Energy ASA. The
\ntransaction has allowed PetroNor to assume a 6.502 per cent
\nparticipating interest, 16.255 per cent cost bearing interest
\nand economic interest of 12.1913 per cent in O\ufb00shore Mining
\nLicence no.113 (OML113).
\nPan-Petroleum AJE Ltd participates in the exploration and
\nproduction of hydrocarbons in the Aje oil and gas \ufb01eld.
\nUnder IFRS 3 \u2013 Business combinations, an acquirer has a
\nmaximum of twelve months from the date of acquisition
\nto \ufb01nalise the acquisition accounting. The adjustment
\nperiod ends when the acquirer has gathered all necessary
\ninformation, subject to the twelve-month maximum. The
\npurchase price allocation is still subject to \ufb01nalisation pending
\nreceipt of further accounting data from counterparties.
\nThe group has assessed and determined the transaction is a
\nbusiness combination under IFRS 3 \u2013 Business combinations.
\nInformation is respect of the assets and liabilities acquired and
\nthe fair value allocations to the assets is as follows:
\n
ASSETS ACQUIRED
\nAmounts in USD thousand
\nCurrent assets
\nTrade and other receivables
5
\nCash and bank balances
52
\n57
\nNon current assets
\nIntangible assets
34,299
\nProduction assets and equipment
926
\nSum
35,225
\nTotal assets
35,282
\nCurrent liabilities
\nTrade and other payables
(2,745)
\nNon-current liabilities
\nProvisions
(3,768)
\nDeferred tax liability
(9,031)
\nOther payables
(8,738)
\nSum
(21,537)
\nTotal liabilities
(24,282)
\nNet assets
11,000
\nSatis\ufb01ed by:
\nConsideration shares
10,000
\nAssignment fee
1,000
\nTotal
11,000
\nThe assets acquired have been acquired with the intention
\nto redevelop the \ufb01eld. The immediate e\ufb00ect on the income
\nstatement will not be material to the group. In the current
\nperiod post acquisition, the charge to the income statement
\nwas USD 249,000.
\nThe upfront consideration for the transaction was USD 10
\nmillion paid via the allotment and issue of 96,577,537 new
\nPetroNor shares.
The volume of PetroNor shares has been
\ndetermined with reference to the contractually determined
\n30-day volume weighted average price (\u201cVWAP\u201d) of PetroNor
\nshares listed on the Oslo B\u00f8rs. The calculation was based on
\n30 business trading days between 2 May 2022 and 8 July 2022.
\nAn additional consideration of USD 0.10 per 1,000 cubic feet
\nof the AJE Natural Gas Sales Volume is to be paid to Panoro
\nEnergy ASA once the conditions stipulated within the SPA are
\nmet. This conditional consideration shall not exceed USD 16.67
\nmillion.
\nNon-cash adjustment
\nThe consolidated statement of cash \ufb02ows includes a non-
\ncash adjustment for the corporate transaction to acquire the
\ninterest in OML 113. The acquisition of the subsidiaries has
\nnot resulted in cash \ufb02ows and therefore the statement of cash
\n\ufb02ows has been adjusted as follows:
\nFor the year ended 31 December 2022:
\nAmounts in USD thousand
\nPurchases of property, plant, and equipment
925
\nIntangible assets
33,299
\nTrade and other payables
(2,630)
\nOther non-current payables
(8,738)
\nProvisions
(3,769)
\nDeferred tax liability
(9,031)
\nIssue of share capital
(10,052)
\nThe goodwill recognised in the transaction of USD 9 million
\nis classi\ufb01ed as technical goodwill due to the requirement
\nto recognise deferred taxes for the temporary di\ufb00erences
\nbetween the assigned values and the tax bases of assets
\nacquired and liabilities assumed in a business combination.
\nA provision has been made in accordance with IAS 12 for
\ndeferred tax corresponding to the tax rate (50 per cent tax
\noil) multiplied by the di\ufb00erence between the fair values of the
\nacquired assets and the transferred tax depreciation basis.
\nThe o\ufb00setting entry to this deferred tax is technical goodwill.
\nThis goodwill is not deductible for tax purposes.
\n
Note 27
Risk management
\nThe group\u2019s principal \ufb01nancial liabilities comprise accounts
\npayable and amounts due to related parties. The main
\npurpose of these \ufb01nancial instruments is to manage short-
\nterm cash \ufb02ow and raise \ufb01nance for the group\u2019s capital
\nexpenditure program. The group has various \ufb01nancial assets
\nsuch as accounts receivable and cash.
\nIt is, and has been throughout the year ending 31 December
\n2022, the group\u2019s policy that no speculative trading in
\nderivatives shall be undertaken.
\nThe main risks that could adversely a\ufb00ect the group\u2019s
\n\ufb01nancial assets, liabilities or future cash \ufb02ows are credit risk,
\nliquidity risk, interest rate risk and foreign currency risk. The
\nmanagement reviews and agrees policies for managing each of
\nthese risks which are summarised below.
\nThe following discussion also includes a sensitivity analysis
\nthat is intended to illustrate the sensitivity to changes in the
\nmarket variables on the group\u2019s \ufb01nancial instruments and
\nshows the impact on pro\ufb01t or loss and shareholders\u2019 equity,
\nwhere applicable. Financial instruments a\ufb00ected by market
\nrisk include accounts receivable, accounts payable and
\naccrued liabilities.
\nThe sensitivity has been prepared for periods ending 31
\nDecember 2022 using the amounts of debt and other \ufb01nancial
\nassets and liabilities held as at those reporting dates.
\nCREDIT RISK
\nCredit risk refers to the risk that a counterparty will default
\non its contractual obligations resulting in \ufb01nancial loss to
\nthe group. As at 31 December 2022, the group\u2019s maximum
\nexposure to credit risk without taking into account any
\ncollateral held or other credit enhancements, which will cause
\na \ufb01nancial loss to the group due to failure to discharge an
\nobligation by the counterparties and \ufb01nancial guarantees
\nprovided by the group arises from the carrying amount of
\nthe respective recognised \ufb01nancial assets as stated in the
\nstatement of \ufb01nancial position.
\nTo minimise credit risk, the group has tasked its management
\nto develop and maintain the group\u2019s credit risk gradings
\nto categorise exposures according to their degree of risk
\nof default. The credit rating information is supplied by
\nindependent rating agencies where available and, if not
\navailable, the management uses other publicly available
\n\ufb01nancial information and the group\u2019s own trading records
\nto rate its major customers and other debtors. The group\u2019s
\nexposure and the credit ratings of its counterparties
\nare continuously monitored, and the aggregate value
\nof transactions concluded is spread amongst approved
\ncounterparties.
\nThe company\u2019s current credit risk grading framework
\ncomprises the following categories:
\nCategory
Description
Basis for recognising expected credit losses
\nPerforming
The counterparty has a low risk of default and does
\nnot have any past-due amounts
\n12-month ECL
\nDoubtful
Amount is >30 days past due or there has been a
\nsigni\ufb01cant increase in credit risk since initial recognition
\nLifetime ECL \u2013 not credit-impaired
\nIn default
Amount is >90 days past due or there is evidence
\nindicating the asset is credit-impaired
\nLifetime ECL \u2013 credit-impaired
\nWrite-o\ufb00
There is evidence indicating that the debtor is in
\nsevere \ufb01nancial di\ufb03culty and the company has no
\nrealistic prospect of recovery
\nAmount is written o\ufb00
\nThe group\u2019s principal customers are substantial oil and gas
\ncompanies and as such credit risk is considered to be low.
\nThere is no history of credit loss, non-payment or default. The
\nrisk on liquid funds is limited because the counterparties are
\nbanks with high credit ratings. The asset retirement obligation
\ncash is held in an Escrow bank account managed by the
\noperator.
\n
The tables below detail the credit quality of the company\u2019s
\n\ufb01nancial assets as well as the company\u2019s maximum exposure
\nto credit risk by credit risk rating grades.
\nAmounts in USD thousand
Note
\nExternal
\ncredit
\nrating
\nInternal
\ncredit
\nrating
\n12-month or
\nlifetime ECL
\nGross
\ncarrying
\namount
\nLoss
\nallowance
\nNet
\ncarrying
\namount
\n31 December 2022
\nTrade receivables
13
N/a
(i)
Lifetime ECL
1,174
-
1,174
\nDue from related parties
13, 25D
N/a
-
Lifetime ECL
-
-
-
\nAdvance against decommissioning cost
13
N/a
-
Lifetime ECL
29,432
-
29,432
\nCash and cash equivalents
14
Aa3/B
N/a
12-month ECL
24,816
-
24,816
\n31 December 2021
\nTrade receivables
13
N/a
(i)
Lifetime ECL
13,431
-
13,431
\nDue from related parties
13, 25D
N/a
-
Lifetime ECL
-
-
-
\nAdvance against decommissioning cost
13
N/a
-
Lifetime ECL
26,837
-
26,837
\nCash and cash equivalents
14
Aa3/B
N/a
12-month ECL
31,755
-
31,755
\n(i) For trade receivables and amounts due from related parties, the group has applied the simpli\ufb01ed approach in IFRS 9 to measure the loss allowance at
\nlifetime ECL. The expected credit losses are estimated using a provision matrix by reference to past default experience of the debtor and an analysis of the
\ndebtor\u2019s current \ufb01nancial position, adjusted for factors that are speci\ufb01c to the debtors, general economic conditions of the industry in which the debtors
\noperate and an assessment of both the current as well as the forecast direction of conditions at the reporting date.
\nLIQUIDITY RISK
\nThe group seeks to limit its liquidity risk by ensuring \ufb01nancial
\nsupport is available from the shareholders. The group\u2019s terms
\nof sales requires amounts to be paid within 45 to 60 days of
\nthe date of approval of progress billings. Trade payables are
\nnormally settled within 90 to 120 days of the date of receipt of
\ninvoice.
\nThe table below summarises the maturity pro\ufb01le of the
\ngroup\u2019s \ufb01nancial liabilities at 31 December 2022 based on
\ncontractual undiscounted payments.
\nAmounts in USD thousand
Note
On demand
\nLess than
\n1 month
\nBetween
\n1 and 3
\nmonths
\nBetween
\n3 months
\nand 1 year
\nMore than
\n1 year
Total
\n31 December 2022
\nTrade accounts payable
19
-
18,732
-
-
-
18,732
\nAmounts due to related parties
25D
2,019
-
-
-
-
2,019
\nLoan payable
20
-
-
1,375
4,125
5,500
11,000
\nOther payable
19
-
-
-
-
8,738
8,738
\nTotal
2,019
18,732
1,375
4,125
14,238
40,489
\nAmounts in USD thousand
Note
On demand
\nLess than
\n1 month
\nBetween
\n1 and 3
\nmonths
\nBetween
\n3 months
\nand 1 year
\nMore than
\n1 year
Total
\n31 December 2021
\nTrade accounts payable
19
21,944
-
5
65
22,014
\nAmounts due to related parties
25D
3,449
-
-
-
-
3,449
\nLoan payable
20
-
-
2,500
10,579
-
13,079
\nOther payable
19
-
-
-
-
-
-
\nTotal
3,449
21,944
2,500
10,584
65
38,542
\nThe company had USD 24.8 million (2021: 31.8 million) in
\nunrestricted cash as of 31 December 2022. Should additional
\nfunding be required in the future for additional capital
\nexpenditure for new development phases or working capital
\nrequirements, the company has various alternatives available
\nwhich it can explore to ful\ufb01l such additional requirements.
\nThe options include, amongst others, debt \ufb01nancing, o\ufb00take
\nprepayment structures. As a result, the \ufb01nancial statements
\nhave been prepared under the assumption of going concern
\nand realisation of assets and settlement of debt in normal
\noperations.
\n
As a result of the acquisition of the interest in the OML 113
\nlicence, PetroNor has inherited an other payable of USD 8.7
\nmillion which relates to costs not yet agreed. The \ufb01nal amount
\nis not expected to be settled within the next twelve months,
\ntherefore this has been classi\ufb01ed as a non-current liability.
\nINTEREST RATE RISK
\nThe group is exposed to interest rate risk on its interest-
\nbearing assets and liabilities and seeks to limit this risk by
\nobtaining favourable interest rates.
\n31 December 2022
31 December 2021
\nAmounts in USD thousand
+150bp
-150bp
+150bp
-150bp
\nLoans payable
(165)
165
(196)
196
\nThe new facility put in place does not include the oil pricing
\nsensitivity previously applied thus providing more certainty to
\ninterest costs.
\nCURRENCY RISK
\nThe group operates internationally and is exposed to risk
\narising from various currency exposures, primarily with
\nrespect to the Norwegian Kroner (NOK), and the Great British
\nPound (GBP). The group has transactional currency exposures.
\nSuch exposure arises from sales or purchases in currencies
\nother than the respective functional currency.
\nThe group reports its consolidated results in USD; any
\nchange in exchange rates between its operating subsidiaries\u2019
\nfunctional currencies and the USD a\ufb00ects its consolidated
\nstatement of comprehensive income and statement of
\n\ufb01nancial position when the results of those operating
\nsubsidiaries are translated into USD for reporting purposes.
\nGroup companies are required to manage their foreign
\nexchange risk against their functional currency.
\nA 20 per cent strengthening or weakening of the USD against
\nthe following currencies at 31 December 2022 would have
\nincreased/(decreased) equity and pro\ufb01t or loss by the amounts
\nshown below.
\nThe group\u2019s assessment of what a reasonable potential change
\nin foreign currencies that it is currently exposed to have been
\nchanged as a result of the changes observed in the world
\n\ufb01nancial markets. This hypothetical analysis assumes that all
\nother variables, including interest rates and commodity prices,
\nremain constant.
\n31 December 2022
31 December 2021
\nAmounts in USD thousand
+20%
-20%
+20%
-20%
\nUSD vs NOK
\nCash
106
(107)
1,040
(1,044)
\nReceivables
260
(260)
-
-
\nPayables
(423)
423
(92)
92
\nTotal
(57)
57
948
(952)
\nUSD vs GBP
\nCash
(17)
17
3
(3)
\nReceivables
(3)
3
8
(8)
\nPayables
7
(7)
(6)
6
\nTotal
(13)
13
5
5
\nCAPITAL RISK
\nThe primary objective of the group\u2019s capital management is
\nto continuously evaluate measures to strengthen its \ufb01nancial
\nbasis and to ensure that the group is fully funded for its
\ncommitted 2023 activities. The group manages its capital
\nstructure and makes adjustments to it in light of changes
\nin economic conditions. In order to maintain or change the
\ncapital structure, the group may adjust the amount of dividend
\npayments to shareholders, return capital to shareholders or
\nissue new shares.
\nThe group is continuously evaluating the capital structure, with
\nthe aim of having an optimal mix of equity and debt capital to
\nreduce the group\u2019s cost of capital and looking at avenues to
\nprocure capital in the forthcoming years.
\n
Note 28
Financial instruments
\nFinancial instruments comprise \ufb01nancial assets and \ufb01nancial
\nliabilities.
\nFinancial assets consist of bank balances and cash, amounts
\ndue from related parties and trade and some other
\nreceivables. Financial liabilities consist of amounts due to
\nrelated parties, loans payable, trade account payables and
\nsome other liabilities.
\nFair value through
\npro\ufb01t or loss
\nAmortised
\ncost
\nFair value through other
\ncomprehensive income
\nAmounts in USD thousand
2022
2021
2022
2021
2022
2021
\nFinancial assets
\nCash and cash equivalents
-
-
24,816
31,755
-
-
\nTrade and other receivables
-
-
1,171
13,820
-
-
\nOther receivables
-
-
29,432
26,837
-
-
\nTotal
-
-
55,419
72,412
-
-
\nFinancial Liabilities
\nTrade and other payables
-
-
29,489
30,055
-
-
\nLoans and borrowings
-
-
11,000
13,079
-
-
\nTotal
-
-
40,489
43,134
-
-
\nThe fair values of the group's \ufb01nancial instruments are not
\nmaterially di\ufb00erent from their carrying amounts at the
\nreporting date largely due to the short-term maturities of
\nthese instruments.
\nNote 29
Commitments and contingencies
\nCOMMITMENTS
\nProduction asset commitments
\nAs at 31 December 2022, the group had approved the budget
\nfor PNGF Sud operations in Congo that included planned capex
\nexpenditure for the coming year of USD 45.6 million (2021 USD
\n50.6 million) representing HEPCO's equity interest funding
\ncommitment in the licence.
\nExploration commitments
\nThe company has entered into obligations in respect of
\nits exploration projects. Outlined below are the minimum
\nexpenditures required as at 31 December:
\nAmounts in USD thousand
2022
2021
\nWithin one year
\n1
\n40,000
40,000
\n1)
The commitment in Senegal includes USD 40 million for an exploration
\nwell in each licence, however this assumes that the company is successful
\nin retaining the legal title for these licences and that the company then
\ndrills these wells with 90 per cent equity.
\nCONTINGENCIES
\nIn December 2021, the National Authority for Investigation
\nand Prosecution of Economic and Environmental Crime in
\nNorway (\u00d8kokrim) initiated an investigation into allegations of
\ncorruption and brought criminal charges against individuals
\nassociated with the company. \u00d8kokirm has con\ufb01rmed that
\nneither PetroNor nor any of its subsidiaries has been charged.
\nThe US Department of Justice also began its own investigation
\ninto the allegations based on information received from
\n\u00d8kokrim.
\nTo mitigate potential corporate liability risks, the board has
\ntaken various remediation steps, as outlined in the director\u2019s
\nreport, including obtaining independent legal advice and
\nimplementing a compliance action plan. Despite the ongoing
\ninvestigations, the company has continued to operate
\ne\ufb00ectively, but has incurred costs in addressing this issue
\nand fully cooperating with the investigating authorities.
\nThe company is not aware of the status or duration of
\nthe investigations into the individuals involved, and the
\nuncertainty surrounding the outcome could potentially impact
\nthe group\u2019s ability to conduct transactions with both new and
\nexisting partners.
\n
As part of the transaction to acquire the interest in OML 113
\nconditional consideration has been assessed as a potential
\ncontingency to the group. An additional consideration
\nof USD 0.10 per 1,000 cubic feet of the AJE Natural Gas
\nSales Volume is to be paid to Panoro Energy ASA once the
\nconditions stipulated within the SPA are met. This conditional
\nconsideration shall not exceed USD 16.67 million.
\nNote 30
Events subsequent to reporting date
\nOn 26 January 2023, two new directors were appointed to the
\nboard. The appointments were pursuant to recommendations
\nfrom the nomination committee. The two new directors, Mrs.
\nAzza Fawzi and Mr. Jarle Norman-Hansen, take the company\u2019s
\nboard to a total of six directors.
\nIn the O\ufb03cial Gazette of Guinea-Bissau (Boletim O\ufb01cial 45), it
\nwas announced that following the withdrawal of FAR Limited
\nfrom the Sinapa and Esperan\u00e7a licences o\ufb00shore Guinea-
\nBissau their equity interest had been awarded to PetroNor.
\nAt the start of February, 317,904 bbls of oil were lifted from
\nthe Djeno Terminal, this sale generated a cash in\ufb02ow of USD
\n24.1 million. On 1 April 2023, a further 260,362 bbls of oil were
\nlifted generating USD 21.2 million of cash in\ufb02ow.
\nIn a CPR update prepared by AGR Petroleum Services AS on
\nthe Company\u2019s PNGF Sud assets, the end of year 2P reserves
\nwere updated to 18.5 Mmbbl with 2C reserves to 23.5 Mmbbl.
\nExcept for the above, the company has not identi\ufb01ed any
\nevents with signi\ufb01cant accounting impacts that have occurred
\nbetween the end of the reporting period and the date of this
\nreport.
\nNote 31
Summary of accounting policies
\nAccounting policies are selected and applied in a manner
\nwhich ensures that the resulting \ufb01nancial information satis\ufb01es
\nthe concepts of relevance and reliability, thereby ensuring that
\nthe substance of the underlying transactions or other events
\nis reported.
\nThe following is a summary of the material accounting policies
\nadopted by the group in the preparation of the consolidated
\n\ufb01nancial statements. The accounting policies have been
\nconsistently applied, unless otherwise stated.
\n31A.
ADOPTION OF NEW AND REVISED ACCOUNTING
\nSTANDARDS
\nIASB has issued several amendments to standards or
\ninterpretations to standards e\ufb00ective as of 1 January 2022.
\nPetroNor have adopted these standards in the \ufb01nancial year,
\nthe impacts were not material to PetroNor\u2019s consolidated
\n\ufb01nancial statements upon adoption.
\nImpacts of other standards and amendments to standards,
\nand interpretations of standards, issued but not yet e\ufb00ective
\nare under assessment by PetroNor.
\n31B.
CONSOLIDATION
\nThe consolidated \ufb01nancial statements comprise the \ufb01nancial
\nstatements of PetroNor E&P ASA (\u201cthe company\u201d, formerly
\nPetroNor E&P Ltd) and its subsidiaries for the year ended 31
\nDecember 2022 (together the group).
\nAn entity has been assessed as being controlled by the group
\nwhen the groups is exposed, or has the rights, to variable
\nreturns from its involvement with the entity and has the
\nability to a\ufb00ect those returns through its power over the
\nentity. Speci\ufb01cally, the group controls an entity if and only if
\nthe group has:
\n\u25a0
Power over the entity (i.e., existing rights that give it the
\ncurrent ability to direct the relevant activities of the entity)
\n\u25a0
Exposure, or rights, to variable returns from its involvement
\nwith the entity, and
\n\u25a0
The ability to use its power over the entity to a\ufb00ect its
\nreturns
\nWhen the group has less than a majority of the voting or
\nsimilar rights of an entity, the group considers all relevant facts
\nand circumstances in assessing whether it has power over an
\nentity, including:
\n\u25a0
The contractual arrangement with the other vote holders of
\nthe entity
\n\u25a0
Rights arising from other contractual arrangements
\n\u25a0
The group\u2019s voting rights and potential voting rights
\nThe group reassesses whether or not it controls an entity if
\nfacts and circumstances indicate that there are changes to
\none or more of the three elements of control. Consolidation
\nof a subsidiary begins when the group obtains control over
\nthe subsidiary and ceases when the group loses control of
\nthe subsidiary. Business combinations are accounted for by
\nusing the acquisition method. Assets, liabilities, income, and
\nexpenses of a subsidiary acquired or disposed of during the
\nyear are included in the statement of comprehensive income
\nfrom the date the group gains control until the date the group
\nceases to control the subsidiary.
\nPro\ufb01t or loss and each component of other comprehensive
\nincome (OCI) are attributed to the equity holders of the parent
\nof the group and to the non-controlling interests, even if this
\nresults in the non-controlling interests having a de\ufb01cit balance.
\nWhen necessary, adjustments are made to the \ufb01nancial
\nstatements of subsidiaries to bring their accounting policies
\n
into line with the group\u2019s accounting policies. All intra-group
\nassets and liabilities, equity, income, expenses, and cash \ufb02ows
\nrelating to transactions between members of the group are
\neliminated in full on consolidation.
\nA change in the ownership interest of a subsidiary, without a
\nloss of control, is accounted for as an equity transaction.
\nIf the group loses control over a subsidiary, it:
\n\u25a0
Derecognises the assets (including goodwill) and liabilities of
\nthe subsidiary.
\n\u25a0
Derecognises the carrying amount of any non-controlling
\ninterests
\n\u25a0
Derecognises the cumulative translation di\ufb00erences
\nrecorded in equity
\n\u25a0
Recognises the fair value of the consideration received
\n\u25a0
Recognises the fair value of any investment retained
\n\u25a0
Recognises any surplus or de\ufb01cit in pro\ufb01t or loss
\n\u25a0
Reclassi\ufb01es the parent\u2019s share of components previously
\nrecognised in OCI to pro\ufb01t or loss or retained earnings, as
\nappropriate, as would be required if the group had directly
\ndisposed of the related assets or liabilities.
\nJoint operations
\nA joint arrangement is a joint operation whereby the group and
\nthe other parties that have joint control over the arrangement,
\nhave contractual rights to the assets and obligation for the
\nliabilities relating to the arrangement. All decisions about the
\nrelevant activities require unanimous consent.
\nWhen assessing if a joint arrangement is joint operation,
\nthe group assesses the structure of the arrangement, the
\nlegal form, the contractual agreement and other facts and
\ncircumstances.
\nThe group recognises its assets, liabilities, revenue and
\nexpenses and its relative share of assets, liabilities, revenue,
\nand expenses of the joint operation.
\nWhen the group enters into transactions with a joint operation
\nin which it is a joint operator, the group recognises gains and
\nlosses resulting from such a transaction only to the extent of
\nthe other parties\u2019 interests in the joint operation.
\n31C.
SEGMENT REPORTING
\nAn operating segment is a component of an entity that
\nengages in business activities from which it may earn revenues
\nand incur expenses (including revenues and expenses relating
\nto transactions with other components of the same entity),
\nwhose operating results are regularly reviewed by the entity\u2019s
\nchief operating decision-makers to make decisions about
\nresources to be allocated to the segments and assess their
\nperformance and for which discrete \ufb01nancial information is
\navailable. This includes start-up operations which are yet to
\nearn revenues.
\nOperating segments have been identi\ufb01ed based on the
\ninformation available to chief operating decision-makers \u2013
\nbeing the board and the executive management team.
\nInformation about other business activities and operating
\nsegments that are below the quantitative criteria are
\ncombined and disclosed in a separate category called \u201call other
\nsegments\u201d.
\n31D.
FOREIGN CURRENCY TRANSLATION
\nFunctional and presentation currency
\nThe company has applied United States Dollars, being the
\nfunctional currency of all major subsidiaries in the group, as
\nits presentation currency. Where the functional currencies
\nof entities within the consolidated group di\ufb00er from United
\nStates Dollars, they have been translated into United States
\nDollars. The functional currency of PetroNor E&P ASA is
\nNorwegian Kroner.
\nTransactions and balances
\nTransactions in foreign currencies are initially recorded in the
\nfunctional currency by applying the exchange rates ruling at
\nthe date of the transaction. Monetary assets and liabilities
\ndenominated in foreign currencies are retranslated at the
\nrate of exchange ruling at the reporting date and any gains or
\nlosses are recognised in the income statement.
\nNon-monetary items that are measured in terms of historical
\ncost in the foreign currency are translated using the exchange
\nrate as at the date of the initial transaction. Non-monetary
\nitems measured at fair value in a foreign currency are
\ntranslated using the exchange rates at the date when the fair
\nvalue was determined.
\nTranslation of group companies' functional currency to
\npresentation currency
\nOn consolidation, the assets and liabilities of foreign
\noperations are translated into United States Dollars at the rate
\nof exchange prevailing at the reporting date and their income
\nand expenditure are translated at exchange rates prevailing
\nat the dates of the transactions. The exchange di\ufb00erences
\narising on translation for consolidation are recognised in other
\ncomprehensive income. On disposal of a foreign operation, the
\ncomponent of other comprehensive income relating to that
\nparticular foreign operation is recognised in pro\ufb01t or loss.
\n31E.
CASH AND CASH EQUIVALENTS
\nCash and cash equivalents include cash on hand, deposits held
\nat call with banks, other short-term highly liquid investments
\nwith original maturities of three months or less, and bank
\noverdrafts. Bank overdrafts are shown within short-term
\nborrowings in current liabilities on the Statement of Financial
\nPosition.
\n31F.
TRADE RECEIVABLES
\nTrade receivables are amounts due from customers for goods
\nsold or services performed in the ordinary course of business.
\nThey are generally due for settlement within 30 to 90 days
\nand therefore are all classi\ufb01ed as current. Trade receivables
\nare recognised initially at the amount of consideration that
\nis unconditional unless they contain signi\ufb01cant \ufb01nancing
\ncomponents, when they are recognised at fair value. The
\ngroup holds the trade receivables with the objective to collect
\nthe contractual cash \ufb02ows and therefore measures them
\nsubsequently at amortised cost using the e\ufb00ective interest
\nmethod.
\nTrade receivables are written o\ufb00 when there is no reasonable
\nexpectation of recovery. Indicators that there is no reasonable
\nexpectation of recovery include, amongst others, the failure
\nof a debtor to engage in a repayment plan with the group, and
\na failure to make contractual payments for a period of greater
\nthan 120 days past due.
\n
Impairment losses on trade receivables and contract assets
\nare presented as net impairment losses within operating
\npro\ufb01t. Subsequent recoveries of amounts previously written
\no\ufb00 are credited against the same line item.
\n31G.
INVENTORY
\nThe crude oil inventory and the material and supplies
\ninventory are valued at the lower of cost and net realisable
\nvalue. Cost is determined using the weighted average method.
\nNet realisable value is the estimated selling price, less
\napplicable selling expenses. The cost of inventory includes all
\ncosts related to bringing the inventory to its current condition,
\nincluding processing costs, labour costs, supplies, direct
\nand allocated indirect operating overhead and depreciation
\nexpense, where applicable, including allocation of \ufb01xed and
\nvariable costs to inventory.
\n31H.
TANGIBLE ASSETS
\nProperty, plant, and equipment
\nOil & gas production assets
\nOil and gas production assets are aggregated exploration and
\nevaluation tangible assets and development expenditures
\nassociated with the production of proved reserves.
\nThe cost of development and production assets also includes
\nthe cost of acquisitions and purchases of such assets, directly
\nattributable overheads and the cost of recognising provisions
\nfor future restoration and decommissioning.
\nWhere major and identi\ufb01able parts of the production assets
\nhave di\ufb00erent useful lives, they are accounted for as separate
\nitems of property, plant, and equipment. Costs of minor
\nrepairs and maintenance are expensed as incurred. Oil and
\ngas production assets have a \ufb01nite life.
\nDepreciation
\nOil and gas properties are depreciated using the unit-of-
\nproduction method. Unit of production rates are based on 1P
\nproved reserves, which are oil, gas and other mineral reserves
\nestimated to be recovered from existing facilities using current
\noperating methods. Oil and gas volumes are considered
\nproduced once they have been measured through meters at
\ncustody transfer or sales transaction points at the outlet valve
\non the \ufb01eld storage tank.
\nField infrastructure exceeding beyond the life of the \ufb01eld is
\ndepreciated over the useful life of the infrastructure using a
\nstraight-line method.
\nProperty, plant, and equipment not associated with
\nexploration and production activities are carried at cost less
\naccumulated depreciation. These assets are also evaluated for
\nimpairment. Depreciation of other assets is calculated on a
\nstraight-line basis as follows:
\nComputer equipment
20 \u2013 33.33%
\nFurniture, \ufb01xtures, & \ufb01ttings
10 \u2013 33.33%
\nMotor vehicles
20%
\n31I.
INTANGIBLE ASSETS
\nExploration and evaluation activity involves the search for
\nhydrocarbon resources, the determination of technical
\nfeasibility and the assessment of commercial viability of an
\nidenti\ufb01ed resource. For each area of interest, expenditure
\nincurred in the acquisition of rights to explore and all costs
\ndirectly associated with holding the licence such as rental,
\ntraining and corporate and social responsibility are capitalised
\nas exploration and evaluation intangible assets. Signature
\nbonuses required by licence agreements are capitalised as
\nexploration and evaluation intangible assets. Other costs
\ndirectly associated with the licence are expensed as incurred.
\nExploration, evaluation, and development expenditure is
\nrecorded at historical cost and allocated to cost pools on
\nan area of interest. Expenditure on an area of interest is
\ncapitalised and carried forward where rights to tenure of the
\narea of interest are current and:
\n\u25a0
it is expected to be recouped through successful
\ndevelopment and exploitation of the area of interest or
\nalternatively by its sale; or
\n\u25a0
exploration and evaluation activities are continuing in
\nan area of interest but at reporting date have not yet
\nreached a stage which permits a reasonable assessment
\nof the existence or otherwise of economically recoverable
\nreserves.
\nAccumulated costs in respect of areas of interest which are
\nabandoned are written o\ufb00 in full against pro\ufb01t in the period in
\nwhich the decision to abandon the area is made.
\nProjects are advanced to development status when it is
\nexpected that further expenditure can be recouped through
\nsale or successful development and exploitation of the area of
\ninterest.
\nAll capitalised costs are subject to commercial and
\nmanagement review, as well as review for indicators of
\nimpairment at least once a year. This is to con\ufb01rm the
\ncontinued intent to develop or otherwise extract value from
\nthe discovery. When this is no longer the case, the costs are
\nwritten o\ufb00 through the statement of pro\ufb01t or loss and other
\ncomprehensive income.
\nWhen proved reserves of oil and natural gas are identi\ufb01ed
\nand development is sanctioned by management, the relevant
\ncapitalised expenditure is \ufb01rst assessed for impairment and
\n(if required) any impairment loss is recognised, then the
\nremaining balance is transferred to oil and gas properties.
\nProceeds from disposal or farm-out transactions of intangible
\nexploration assets are used to reduce the carrying amount of
\nthe assets. When proceeds exceed the carrying amount, the
\ndi\ufb00erence is recognised as a gain. When the group disposes of
\nits full interests, gains or losses are recognised in accordance
\nwith the policy for recognising gains or losses on sale of plant,
\nproperty, and equipment.
\nGenerally Intangible assets can be viewed inde\ufb01nite as
\nthey will be retained on the balance sheet until impaired or
\ntransferred to oil and gas properties. Certain licence related
\ncosts capitalised as intangible assets are deemed to have a
\n\ufb01nite life and are accreted over the life of the licence area.
\nDepreciation
\nLicence related costs capitalised as Intangible assets are
\ndepreciated using the unit-of-production method. Unit-of
\nproduction rates are based on 1P proved reserves, which are
\noil, gas and other mineral reserves estimated to be recovered
\nfrom existing facilities using current operating methods. Oil
\n
and gas volumes are considered produced once they have
\nbeen measured through meters at custody transfer or sales
\ntransaction points at the outlet valve on the \ufb01eld storage tank.
\nTechnical goodwill
\nTechnical goodwill recognised in business combinations
\nis allocated to each CGU for the purposes of impairment
\ntesting. Impairment is tested on an annual basis or when
\nthere are impairment indicators. Indicators may be speci\ufb01c
\nto an individual CGU or groups of CGUs to which the technical
\ngoodwill is related. When conducting impairment testing,
\ndeferred tax recognised in relation to the acquired licences
\nreduces the net carrying value prior to the impairment
\ncharges.
\nImpairment is recognised if the recoverable amount of the
\nCGU (or groups of CGUs) to which the technical goodwill relates
\nto is less than the carrying amount.
\nImpairment of goodwill cannot be reversed in future periods.
\n31J.
BORROWING COSTS
\nBorrowing costs that are directly attributable to the
\nacquisition, construction or production of a qualifying non-
\ncurrent asset are added to the cost of the asset during the
\nperiod of time that is required to complete and prepare the
\nasset for its intended use. Borrowing costs are capitalised to
\nthe extent that funds are borrowed speci\ufb01cally for the purpose
\nof obtaining a qualifying asset. To the extent that funds are
\nborrowed generally and used for the purpose of obtaining a
\nqualifying asset, the amount of borrowing costs eligible for
\ncapitalisation is determined by applying a capitalisation rate to
\nthe expenditures on that asset. All other borrowing costs are
\nexpensed as incurred.
\n31K.
REVENUE
\n(i)
Revenue from petroleum products
\nRevenue from the sale of crude oil is recognised when a
\ncustomer obtains control (\u201csales\u201d or \u201clifting\u201d method), normally
\nthis is when title passes at point of delivery. Revenues from
\nproduction of oil properties are recognised based on actual
\nvolumes lifted and sold to customers during the period.
\n(ii)
Other revenue
\nUnder a production sharing contract, where the group is
\nrequired to pay pro\ufb01t oil tax and royalties on production
\nof crude oil, such payments are settled in kind (where the
\ngovernment lift the crude it is entitled to). The group presents
\na gross-up of the pro\ufb01t oil tax as an income tax expense with
\na corresponding increase in oil and gas revenues and any
\nassociated royalties are included in the cost of sales.
\nThe group assesses whether it acts as a principal or agent in
\neach of its revenue arrangements. The group has concluded
\nthat in all sales transactions it acts as a principal.
\n(iii)
Variable consideration
\nIf the consideration in a contract includes a variable amount,
\nthe group recognises this amount as revenue only to the
\nextent that it is highly probable that a signi\ufb01cant reversal will
\nnot occur in the future.
\n(iv)
Interest
\nInterest income is recognised on a time-proportional basis
\nusing the e\ufb00ective interest method. This is a method of
\ncalculating the amortised cost of a \ufb01nancial asset and
\nallocating the interest income over the relevant period using
\nthe e\ufb00ective interest rate, which is the rate that exactly
\ndiscounts the estimated future cash receipts through the
\nexpected useful life of the \ufb01nancial asset to the net carrying
\namount of the \ufb01nancial asset.
\n31L.
LEASES
\nThe group as lessee
\nThe group assesses whether contract is or contains a lease,
\nat inception of the contract. The group recognises a right-of-
\nuse asset and a corresponding lease liability with respect to all
\nlease arrangements in which it is the lessee, except for short-
\nterm leases (de\ufb01ned as leases with a lease term of 12 months
\nor less) and leases of low value assets. For these leases, the
\ngroup recognises the lease payments as an operating expense
\non a straight-line basis over the term of the lease unless
\nanother systematic basis is more representative of the time
\npattern in which economic bene\ufb01ts from the leased assets are
\nconsumed.
\nThe lease liability is initially measured at the present value of
\nthe lease payments that are not paid at the commencement
\ndate, discounted by using the rate implicit in the lease. If
\nthis rate cannot be readily determined, the group uses its
\nincremental borrowing rate.
\nLease payments included in the measurement of the lease
\nliability comprise:
\n\u25a0
\ufb01xed lease payments (including in-substance \ufb01xed
\npayments), less any lease incentives;
\n\u25a0
variable lease payments that depend on an index or
\nrate, initially measured using the index or rate at the
\ncommencement date;
\n\u25a0
the amount expected to be payable by the lessee under
\nresidual value guarantees;
\n\u25a0
the exercise price of purchase options, if the lessee is
\nreasonably certain to exercise the options; and
\n\u25a0
payments of penalties for terminating the lease, if the lease
\nterm re\ufb02ects the exercise of an option to terminate the
\nlease.
\nThe lease liability is presented as a separate line item in the
\nstatement of \ufb01nancial position.
\nThe lease liability is subsequently measured by increasing
\nthe carrying amount to re\ufb02ect interest on the lease liability
\n(using e\ufb00ective interest method) and by reducing the carrying
\namount to re\ufb02ect the lease payments made.
\nThe group remeasures the lease liability (and makes a
\ncorresponding adjustment to the related right-of-use asset)
\nwhenever:
\n\u25a0
the lease term has changed or there is a change in the
\nassessment of exercise of a purchase option, in which case
\nthe lease liability is remeasured by discounting the revised
\nlease payments using a revised discount rate.
\n\u25a0
the lease payments change due to changes in an index or
\nrate or a change in expected payment under a guaranteed
\nresidual value, in which cases the lease liability is
\nremeasured by discounting the revised lease payments
\nusing the initial discount rate (unless the lease payments
\n
change is due to a change in a \ufb02oating interest rate, in which
\ncase a revise discount rate is used).
\n\u25a0
a lease contract is modi\ufb01ed, and the lease modi\ufb01cation is
\nnot accounted for as a separate lease, in which case the
\nlease liability is remeasured by discounting the revised lease
\npayments using a revised discount rate.
\nThe group did not make any such adjustments during the
\nperiods presented.
\nRight of use assets
\nThe group measures the right-of use asset at cost, less any
\naccumulated depreciation and impairment losses, adjusted for
\nany remeasurement of lease liabilities. The cost of the right-of-
\nuse asset comprise:
\n\u25a0
The amount of the initial measurement of the lease liability
\nrecognised
\n\u25a0
Any lease payments made at or before the commencement
\ndate, less any incentives received
\n\u25a0
Any initial direct costs incurred by the group. An estimate
\nof the costs to be incurred by the group in dismantling and
\nremoving the underlying asset, restoring the site on which it
\nis located or restoring the underlying asset to the condition
\nrequired by the terms and conditions of the lease, unless
\nthose costs are incurred to produce inventories.
\nThe group applies the depreciation requirements in IAS 16
\nProperty, Plant and Equipment in depreciating the right-of-use
\nasset, except that the right-of-use asset is depreciated from
\nthe commencement date to the earlier of the lease term and
\nthe remaining useful life of the right-of-use asset.
\nThe group applies IAS 36 Impairment of Assets to determine
\nwhether the right-of-use asset is impaired and to account for
\nany impairment loss identi\ufb01ed.
\nVariable rents that do not depend on an index or rate are not
\nincluded in the measurement of the lease liability and the
\nright-of-use asset. The related payments are recognised as
\nan expense in the period in which the event or condition that
\ntriggers those payments occurs and are included in the line
\n\u2018Administrative expenses\u2019 in the statement of pro\ufb01t or loss.
\n31M.
TAXES
\nThe income tax expense or bene\ufb01t for the period consists of
\ntwo components: current and deferred tax.
\nThe current income tax payable or recoverable is calculated
\nusing the tax rates and legislation that have been enacted or
\nsubstantively enacted at year-end in each of the jurisdictions
\nand includes any adjustments for taxes payable or recovery in
\nrespect of prior periods.
\nDeferred tax assets and liabilities are determined using
\nthe balance sheet liability method based on temporary
\ndi\ufb00erences between the carrying value of assets and liabilities
\nfor \ufb01nancial reporting purposes and their tax bases. In
\ncalculating the deferred tax assets and liabilities, the tax
\nrates used are those that have been enacted or substantively
\nenacted by year-end in each of the jurisdictions and that
\nare expected to apply when the assets are recovered, or the
\nliabilities are settled.
\nRevenue-based taxes
\nIn addition to corporate income taxes, the group\u2019s
\nconsolidated \ufb01nancial statements also include and recognise
\nas income taxes, other types of taxes on net income such as
\ncertain revenue-based taxes.
\nProduction-sharing arrangements
\nAccording to the production-sharing arrangement (PSA)
\nin certain licences, the share of the pro\ufb01t oil to which the
\ngovernment is entitled in any calendar year in accordance
\nwith the PSA is deemed to include a portion representing the
\ncorporate income tax imposed upon and due by the group.
\nThis amount will be paid directly by the government on behalf
\nof the group to the appropriate tax authorities.
\nThe income tax expense
\nThe current income tax is calculated using the PSA, paid in
\nbarrels and booked as income tax and also shown as revenue.
\nSales tax
\nRevenues, expenses and assets are recognised net of the
\namount of sales tax except:
\nWhere the sales tax incurred on a purchase of assets or
\nservices is not recoverable from the taxation authority, in
\nwhich case, the sales tax is recognised as part of the cost
\nof acquisition of the asset or as part of the expense item as
\napplicable.
\nReceivables and payables that are stated with the amount of
\nsales tax included.
\nThe net amount of sales tax recoverable from, or payable to,
\nthe taxation authority is included as part of receivables or
\npayables in the statement of \ufb01nancial position.
\nCurrent and deferred tax balances attributable to amounts
\nrecognised directly in equity are also recognised directly in
\nequity.
\n31N.
EMPLOYEE BENEFITS
\nProvision is made for bene\ufb01ts accruing to employees in
\nrespect of wages and salaries, annual leave, and long service
\nleave when it is probable that settlement will be required, and
\nthey are capable of being measured reliably. Provisions made
\nin respect of employee bene\ufb01ts expected to be settled within
\n12 months are measured at their nominal values using the
\nremuneration rate expected to apply at the time of settlement.
\nProvisions made in respect of employee bene\ufb01ts, which are
\nnot due to be settled within 12 months are determined using
\nthe projected unit credit method.
\n31O.
DEFINED CONTRIBUTION PENSION PLAN
\nThe group pays contributions into de\ufb01ned contribution plans.
\nObligations for contributions to de\ufb01ned contribution pension
\nplans are recognised as an expense in the income statement in
\nthe periods during which services are rendered by employees.
\n31P.
TRADE AND OTHER PAYABLES
\nTrade and other payables are carried at amortised cost and
\ndue to their short-term nature, they are not discounted.
\n31Q.
PROVISIONS
\n(i)
General
\nProvisions are recognised when the group has a present
\nobligation (legal or constructive) as a result of a past event, it
\nis probable that an out\ufb02ow of resources embodying economic
\n
bene\ufb01ts will be required to settle the obligation and a reliable
\nestimate can be made of the amount of the obligation.
\nWhere the group expects some or all of the provision to be
\nreimbursed, for example under an insurance contract, the
\nreimbursement is recognised as a separate asset but only
\nwhen the reimbursement is virtually certain. The expense
\nrelating to any provision is recognised through pro\ufb01t and loss
\nnet of any reimbursement. If the e\ufb00ect of the time value of
\nmoney is material, provisions are discounted using a current
\npre-tax rate that re\ufb02ects, where appropriate, the risks speci\ufb01c
\nto the liability. Where discounting is used, the increase in the
\nprovision due to the passage of time is recognised as interest
\nexpense. The present obligation under onerous contracts is
\nrecognised as a provision.
\n(ii)
Decommissioning liability
\nA decommissioning liability is recognised when the group has
\na present legal or constructive obligation as a result of past
\nevents, and it is probable that an out\ufb02ow of resources will be
\nrequired to settle the obligation, and a reliable estimate of the
\namount of obligation can be made. A corresponding amount
\nequivalent to the obligation is also recognised as part of the
\ncost of the related production plant and equipment. The
\namount recognised in the estimated cost of decommissioning,
\ndiscounted to its present value. Changes in the estimated
\ntiming of decommissioning or decommissioning cost estimates
\nare dealt with prospectively by recording an adjustment to
\nthe provision, and a corresponding adjustment to production
\nplant and equipment. The unwinding of the discount on the
\ndecommissioning liability is included as a \ufb01nance cost.
\nAn escrow account is maintained by the operator of the PNGF
\nSud licence and is governed by a joint operating agreement
\nand the Congolese Government rules. The group\u2019s share, paid
\nagainst the decommissioning liability until the balance sheet
\ndate, is classi\ufb01ed as an advance against decommissioning
\nliability in current assets.
\n31R.
SHARE CAPITAL
\nContributed equity is recognised at the fair value of the
\nconsideration received by the group, less any capital raising
\ncosts in relation to the issue.
\nIncremental costs directly attributable to the issue of new
\nshares or options are shown in equity as a deduction, net of
\ntax, from the proceeds.
\n31S.
DIVIDEND DISTRIBUTION
\nDividend distribution to the company\u2019s shareholders is
\nrecognised as a liability in the group\u2019s \ufb01nancial statements
\nin the period in which the dividends are declared and
\nappropriately authorised or approved by the company\u2019s
\nshareholders\u2019 general meeting. Interim dividends proposed
\nby the board of directors are recognised as liabilities upon
\ndeclaration.
\n31T.
FINANCIAL INSTRUMENTS
\nA \ufb01nancial instrument is any contract that gives rise to a
\n\ufb01nancial asset of any one entity and a \ufb01nancial liability or
\nequity instrument of another entity.
\n(i)
Financial assets
\nFinancial assets are classi\ufb01ed, at initial recognition, as
\nsubsequently measured at amortised cost, fair value through
\nother comprehensive income (OCI), and fair value through
\npro\ufb01t or loss, as appropriate.
\nThe classi\ufb01cation of \ufb01nancial assets at initial recognition
\ndepends on the \ufb01nancial asset\u2019s contractual cash \ufb02ow
\ncharacteristics and the group\u2019s business model for managing
\nthem. With the exception of trade receivables that do not
\ncontain a signi\ufb01cant \ufb01nancing component or for which the
\ngroup has applied the practical expedient, the group initially
\nmeasures a \ufb01nancial asset at its fair value plus, in the case
\nof \ufb01nancial assets not subsequently measured at fair value
\nthrough pro\ufb01t or loss, transaction costs that are attributable
\nto the acquisition of the \ufb01nancial asset.
\nIn order for a \ufb01nancial asset to be classi\ufb01ed and measured at
\namortised cost or fair value through OCI, it needs to give rise
\nto cash \ufb02ows that are solely payments of principal and interest
\n(SPPI) on the principal amount outstanding. This assessment is
\nreferred to as the SPPI test and is performed at an instrument
\nlevel.
\nThe group\u2019s business model for managing \ufb01nancial assets
\nrefers to how it manages its \ufb01nancial assets in order to
\ngenerate cash \ufb02ows. The business model determines whether
\ncash \ufb02ows will result from collecting contractual cash \ufb02ows,
\nselling the \ufb01nancial assets, or both.
\nPurchases or sales of \ufb01nancial assets that require delivery
\nof assets within a time frame established by regulation
\nor convention in the marketplace (regular way trades) are
\nrecognised on the trade date, i.e., the date that the group
\ncommits to purchase or sell the asset.
\nFinancial assets are recognised initially at fair value,
\nnormally being the transaction price. In the case of \ufb01nancial
\nassets not at fair value through pro\ufb01t or loss, directly
\nattributable transaction costs are also included. The
\nsubsequent measurement of \ufb01nancial assets depends on
\ntheir classi\ufb01cation, as set out below. The group derecognizes
\n\ufb01nancial assets when the contractual rights to the cash \ufb02ows
\nexpire or the \ufb01nancial asset is transferred to a 3
\nrd
\nparty. This
\nincludes the derecognition of receivables for which discounting
\narrangements are entered into. The classi\ufb01cation depends on
\nthe business model for managing the \ufb01nancial assets and the
\ncontractual cash \ufb02ow characteristics of the \ufb01nancial asset.
\nSubsequent measurement
\n\u25a0
For purposes of subsequent measurement, \ufb01nancial assets
\nare classi\ufb01ed in 4 categories:
\n\u25a0
Financial assets at amortised cost (debt instruments)
\n\u25a0
Financial assets at fair value through OCI with recycling of
\ncumulative gains and losses (debt instruments)
\n\u25a0
Financial assets designated at fair value through OCI with no
\nrecycling of cumulative gains and losses upon derecognition
\n(equity instruments)
\n\u25a0
Financial assets at fair value through pro\ufb01t or loss
\n\u25a0
The group has not designated any \ufb01nancial assets at fair
\nvalue through pro\ufb01t or loss.
\n\u25a0
Financial assets at amortised cost (debt instruments)
\n\u25a0
The group measures \ufb01nancial assets at amortised cost if
\nboth of the following conditions are met:
\n\u25a0
The \ufb01nancial asset is held within a business model with
\nthe objective to hold \ufb01nancial assets in order to collect
\ncontractual cash \ufb02ows;
\nAnd
\n\u25a0
The contractual terms of the \ufb01nancial asset give rise on
\n
speci\ufb01ed dates to cash \ufb02ows that are solely payments of
\nprincipal and interest on the principal amount outstanding;
\nFinancial assets at amortised cost are subsequently measured
\nusing the e\ufb00ective interest (EIR) method and are subject to
\nimpairment. Gains and losses are recognised in pro\ufb01t or loss
\nwhen the asset is derecognised, modi\ufb01ed or impaired.
\nCash equivalents
\nCash equivalents are short-term, highly liquid investments that
\nare readily convertible to known amounts of cash, are subject
\nto insigni\ufb01cant risk of changes in value and generally have a
\nmaturity of three months or less from the date of acquisition.
\nCash equivalents are classi\ufb01ed as \ufb01nancial assets measured at
\namortised cost.
\nLoans granted
\nLoans granted that have \ufb01xed or determinable payments that
\nare not quoted in an active market are classi\ufb01ed as \ufb01nancial
\nassets at amortised cost and are measured at amortised cost
\nusing the e\ufb00ective interest method, less any impairment.
\nInterest income is recognised by applying the e\ufb00ective interest
\nrate.
\nLoans granted to related parties are normally interest-free
\nand do not have a \ufb01xed repayment structure. These loans
\nare classi\ufb01ed as \ufb01nancial assets at amortised cost and are
\nmeasured at amortised cost using the e\ufb00ective interest
\nmethod, less any impairment. E\ufb00ective interest rate being zero
\nin this case.
\nDerecognition
\nA \ufb01nancial asset (or, where applicable, a part of a \ufb01nancial
\nasset or part of a group of similar \ufb01nancial assets) is primarily
\nderecognised (i.e., removed from the group\u2019s consolidated
\nstatement of \ufb01nancial position) when:
\nThe rights to receive cash \ufb02ows from the asset have expired or
\nthe group has transferred its rights to receive cash \ufb02ows from
\nthe asset or has assumed an obligation to pay the received
\ncash \ufb02ows in full without material delay to a third party under
\na \u2018pass-through\u2019 arrangement; and either (a) the group has
\ntransferred substantially all the risks and rewards of the
\nasset, or (b) the group has neither transferred nor retained
\nsubstantially all the risks and rewards of the asset, but has
\ntransferred control of the asset.
\nWhen the group has transferred its rights to receive cash
\n\ufb02ows from an asset or has entered into a pass-through
\narrangement, it evaluates if, and to what extent, it has retained
\nthe risks and rewards of ownership. When it has neither
\ntransferred nor retained substantially all of the risks and
\nrewards of the asset, nor transferred control of the asset,
\nthe group continues to recognise the transferred asset to the
\nextent of its continuing involvement. In that case, the group
\nalso recognises an associated liability. The transferred asset
\nand the associated liability are measured on a basis that
\nre\ufb02ects the rights and obligations that the group has retained.
\nImpairment of \ufb01nancial assets
\nThe group recognises an allowance for expected credit losses
\n(ECLs) for all debt instruments not held at fair value through
\npro\ufb01t or loss. ECLs are based on the di\ufb00erence between the
\ncontractual cash \ufb02ows due in accordance with the contract and
\nall the cash \ufb02ows that the group expects to receive, discounted
\nat an approximation of the original e\ufb00ective interest rate. The
\nexpected cash \ufb02ows will include cash \ufb02ows from the sale of
\ncollateral held or other credit enhancements that are integral
\nto the contractual terms.
\nECLs are recognised in two stages. For credit exposures
\nfor which there has not been a signi\ufb01cant increase in credit
\nrisk since initial recognition, ECLs are provided for credit
\nlosses that result from default events that are possible
\nwithin the next 12 months (a 12-month ECL). For those credit
\nexposures for which there has been a signi\ufb01cant increase
\nin credit risk since initial recognition, a loss allowance is
\nrequired for credit losses expected over the remaining life
\nof the exposure, irrespective of the timing of the default (a
\nlifetime ECL).
\nFor trade receivables and contract assets, the group applies a
\nsimpli\ufb01ed approach in calculating ECLs. Therefore, the group
\ndoes not track changes in credit risk, but instead recognises a
\nloss allowance based on lifetime ECLs at each reporting date.
\nThe group has established a provision matrix that is based
\non its historical credit-loss experience, adjusted for forward-
\nlooking factors speci\ufb01c to the debtors and the economic
\nenvironment.
\nThe group considers a \ufb01nancial asset in default when
\ncontractual payments are 90 days past due. However, in
\ncertain cases, the group may also consider a \ufb01nancial asset
\nto be in default when internal or external information
\nindicates that the group is unlikely to receive the outstanding
\ncontractual amounts in full before taking into account any
\ncredit enhancements held by the group. A \ufb01nancial asset
\nis written o\ufb00 when there is no reasonable expectation of
\nrecovering the contractual cash \ufb02ows.
\n(ii)
Financial liabilities
\nInitial recognition and measurement
\nFinancial liabilities are classi\ufb01ed, at initial recognition, as
\n\ufb01nancial liabilities at fair value through pro\ufb01t or loss, \ufb01nancial
\nliabilities at amortised cost, payables, or as derivatives
\ndesignated as hedging instruments in an e\ufb00ective hedge, as
\nappropriate.
\nAll \ufb01nancial liabilities are recognised initially at fair value and,
\nin the case of loans and borrowings and payables, net of
\ndirectly attributable transaction costs.
\nThe group\u2019s \ufb01nancial liabilities include trade and other
\npayables, loans and borrowings including bank overdrafts, and
\nderivative \ufb01nancial instruments.
\nSubsequent measurement
\nAfter initial recognition, interest-bearing loans and borrowings
\nare subsequently measured at amortised cost using the EIR
\nmethod. Gains and losses are recognised in pro\ufb01t or loss
\nwhen the liabilities are derecognised as well as through the EIR
\namortisation process.
\nAmortised cost is calculated by taking into account any
\ndiscount or premium on acquisition and fees or costs that are
\nan integral part of the EIR. The EIR amortisation is included as
\n\ufb01nance costs in the statement of pro\ufb01t or loss.
\n
This category generally applies to interest-bearing loans and
\nborrowings. For more information, refer to note 20.
\nPayables are measure at their nominal amount when the e\ufb00ect
\nof discounting is not material.
\nForeign exchange gains and losses
\nFor \ufb01nancial liabilities that are denominated in a foreign
\ncurrency and are measured at amortised cost at the end of each
\nreporting period, the foreign exchange gains and losses are
\ndetermined based on the amortised cost of the instruments.
\nThese foreign exchange gains and losses are recognised in
\nthe \u2018foreign exchange gain/(loss)\u2019 line item in pro\ufb01t or loss for
\n\ufb01nancial liabilities that are not part of a designated hedging
\nrelationship. For those which are designated as a hedging
\ninstrument for a hedge of foreign currency risk foreign exchange
\ngains and losses are recognised in other comprehensive income
\nand accumulated in a separate component of equity.
\nThe fair value of \ufb01nancial liabilities denominated in a foreign
\ncurrency is determined in that foreign currency and translated
\nat the spot rate at the end of the reporting period. For \ufb01nancial
\nliabilities that are measured as at FVTPL, the foreign exchange
\ncomponent forms part of the fair value gains or losses and is
\nrecognised in pro\ufb01t or loss for \ufb01nancial liabilities that are not
\npart of a designated hedging relationship.
\nDerecognition of \ufb01nancial liabilities
\nThe group derecognises \ufb01nancial liabilities when, and only
\nwhen, the group\u2019s obligations are discharged, cancelled or
\nhave expired. The di\ufb00erence between the carrying amount of
\nthe \ufb01nancial liability derecognised and the consideration paid
\nand payable is recognised in pro\ufb01t or loss.
\nWhen the group exchanges with the existing lender one debt
\ninstrument into another one with substantially di\ufb00erent
\nterms, such exchange is accounted for as an extinguishment
\nof the original \ufb01nancial liability and the recognition of a new
\n\ufb01nancial liability. Similarly, the group accounts for substantial
\nmodi\ufb01cation of terms of an existing liability or part of it as
\nan extinguishment of the original \ufb01nancial liability and the
\nrecognition of a new liability. It is assumed that the terms are
\nsubstantially di\ufb00erent if the discounted present value of the
\ncash \ufb02ows under the new terms, including any fees paid net of
\nany fees received and discounted using the original e\ufb00ective
\nrate is at least 10 per cent di\ufb00erent from the discounted
\npresent value of the remaining cash \ufb02ows of the original
\n\ufb01nancial liability. If the modi\ufb01cation is not substantial, the
\ndi\ufb00erence between: (1) the carrying amount of the liability
\nbefore the modi\ufb01cation; and (2) the present value of the cash
\n\ufb02ows after modi\ufb01cation is recognised in pro\ufb01t or loss as the
\nmodi\ufb01cation gain or loss within other gains and losses.
\n(iii)
Fair value measurement
\nThe group measures derivatives at fair value at each balance
\nsheet date and, for the purposes of impairment testing,
\nuses fair value less costs to sell (FVLCD) to determine the
\nrecoverable amount of some of its non-\ufb01nancial assets.
\nFair value is the price that would be received to sell an asset
\nor paid to transfer a liability in an orderly transaction between
\nmarket participants at the measurement date. The fair value
\nmeasurement is based on the presumption that the transaction
\nto sell the asset or transfer the liability takes place either:
\n\u25a0
In the principal market for the asset or liability
\nOr
\n\u25a0
In the absence of a principal market, in the most
\nadvantageous market for the asset or liability
\nThe principal or the most advantageous market must be
\naccessible by the group.
\nThe fair value of an asset or a liability is measured using the
\nassumptions that market participants would use when pricing
\nthe asset or liability, assuming that market participants act in
\ntheir economic best interest.
\nA fair value measurement of a non-\ufb01nancial asset takes into
\naccount a market participant's ability to generate economic
\nbene\ufb01ts by using the asset in its highest and best use or by
\nselling it to another market participant that would use the
\nasset in its highest and best use.
\nThe group uses valuation techniques that are appropriate in
\nthe circumstances and for which su\ufb03cient data are available to
\nmeasure fair value, maximising the use of relevant observable
\ninputs and minimising the use of unobservable inputs.
\nAll assets and liabilities, for which fair value is measured
\nor disclosed in the \ufb01nancial statements, are categorised
\nwithin the fair value hierarchy, described as follows, based
\non the lowest-level input that is signi\ufb01cant to the fair value
\nmeasurement as a whole:
\nLevel 1
\u2013 Quoted (unadjusted) market prices in active
\nmarkets for identical assets or liabilities
\nLevel 2
\u2013 Valuation techniques for which the lowest-level
\ninput that is signi\ufb01cant to the fair value measurement is
\ndirectly or indirectly observable
\nLevel 3
\u2013 Valuation techniques for which the lowest-level
\ninput that is signi\ufb01cant to the fair value measurement is
\nunobservable
\n(iv)
O\ufb00setting of \ufb01nancial instruments
\nFinancial assets and \ufb01nancial liabilities are o\ufb00set, and the net
\namount is reported in the consolidated statement of \ufb01nancial
\nposition if there is a currently enforceable legal right to o\ufb00set
\nthe recognised amounts and there is an intention to settle
\non a net basis, to realise the assets and settle the liabilities
\nsimultaneously.
\n31U.
JOINT ARRANGEMENTS
\nJoint arrangements are arrangements of which two or more
\nparties have joint control. Joint control is the contractual agreed
\nsharing of control of the arrangement which exists only when
\ndecisions about the relevant activities require unanimous
\nconsent of the parties sharing control. Joint arrangements are
\nclassi\ufb01ed as either a joint operation or joint venture, based
\non the rights and obligations arising from the contractual
\nobligations between the parties to the arrangement.
\nTo the extent the joint arrangement provides the company
\nwith rights to the individual assets and obligations arising from
\nthe joint arrangement, the arrangement is classi\ufb01ed as a joint
\noperation and as such, the company recognises its:
\n
\u25a0
Assets, including its share of any assets held jointly;
\n\u25a0
Liabilities, including its share of any liabilities incurred
\njointly;
\n\u25a0
Revenue from the sale of its share of the output arising from
\nthe joint operation;
\n\u25a0
Share of revenue from the sale of the output by the joint
\noperation; and
\n\u25a0
Expenses, including its share of any expenses incurred
\njointly.
\nTo the extent the joint arrangement provides the company
\nwith rights to the net assets of the arrangement, the
\ninvestment is classi\ufb01ed as a joint venture and accounted for
\nusing the equity method. Under the equity method, the cost of
\nthe investment is adjusted by the post-acquisition changes in
\nthe company\u2019s share of the net assets of the venture.
\n31V.
CURRENT VERSUS NON-CURRENT CLASSIFICATION
\nThe group presents assets and liabilities in the statement of
\n\ufb01nancial position based on current/non-current classi\ufb01cation.
\nAn asset is current when it is either:
\n\u25a0
Expected to be realised or intended to be sold or consumed
\nin the normal operating cycle;
\n\u25a0
Held primarily for the purpose of trading;
\n\u25a0
Expected to be realised within 12 months after the reporting
\nperiod;
\n\u25a0
Cash or cash equivalent unless restricted from being
\nexchanged or used to settle a liability for at least 12 months
\nafter the reporting period.
\nAll other assets are classi\ufb01ed as non-current.
\nA liability is current when either:
\n\u25a0
It is expected to be settled in the normal operating cycle
\n\u25a0
It is held primarily for the purpose of trading
\n\u25a0
It is due to be settled within 12 months after the reporting
\nperiod
\n\u25a0
There is no unconditional right to defer the settlement of the
\nliability for at least 12 months after the reporting period
\nThe group classi\ufb01es all other liabilities as non-current.
\nDeferred tax assets and liabilities are classi\ufb01ed as non-current
\nassets and liabilities.
\n31W.
BUSINESS COMBINATIONS AND GOODWILL
\nIn order to consider an acquisition as a business combination,
\nthe acquired asset or groups of assets must constitute
\na business (an integrated set of operations and assets
\nconducted and managed for the purpose of providing
\na return to the investors). The combination consists of
\ninputs and processes applied to these inputs that have the
\nability to create output. Acquired businesses are included
\nin the \ufb01nancial statements from the transaction date. The
\ntransaction date is de\ufb01ned as the date on which the company
\nachieves control over the \ufb01nancial and operating assets. This
\ndate may di\ufb00er from the actual date on which the assets
\nare transferred. Comparative \ufb01gures are not adjusted for
\nacquired, sold or liquidated businesses. On acquisition of
\na licence that involves the right to explore for and produce
\npetroleum resources, it is considered in each case whether
\nthe acquisition should be treated as a business combination
\nor an asset purchase. Generally, purchases of licences in
\na development or production phase will be regarded as a
\nbusiness combination. Business combinations are accounted
\nfor using the acquisition method. The cost of an acquisition is
\nmeasured as the aggregate of the consideration transferred,
\nmeasured at acquisition date fair value and the amount of
\nany non-controlling interest (NCI) in the acquiree. For each
\nbusiness combination, the group elects whether to measure
\nNCI in the acquiree at fair value or at the proportionate share
\nof the acquiree\u2019s identi\ufb01able net assets. Acquisition related
\ncosts are expensed as incurred and included in administrative
\nexpenses.
\nThe initial accounting for a business combination can be
\nchanged if new information about the fair value at the
\nacquisition date is present. The allocation can be amended
\nwithin 12 months of the acquisition date [provided that the
\ninitial accounting at the acquisition date was determined
\nprovisionally]. The non-controlling interest is set to the non-
\ncontrolling interest\u2019s share of identi\ufb01able assets and liabilities
\n[alternative fair value]. The measurement principle is done
\nfor each business combination separately. When the group
\nacquires a business, it assesses the assets and liabilities
\nassumed for appropriate classi\ufb01cation and designation
\nin accordance with the contractual terms, economic
\ncircumstances and pertinent conditions as at the acquisition
\ndate. This includes the separation of embedded derivatives
\nin host contracts by the acquiree. Those acquired petroleum
\nreserves and resources that can be reliably measured are
\nrecognised separately in the assessment of fair values on
\nacquisition. Other potential reserves, resources and rights,
\nfor which fair values cannot be reliably measured, are not
\nrecognised separately, but instead are subsumed in goodwill.
\nGoodwill is recognised as the aggregate of the consideration
\ntransferred and the amount of any non-controlling interest
\nand deducted by the net of the acquisition-date amounts of
\nthe identi\ufb01able assets acquired and the liabilities assumed.
\nGoodwill is not depreciated but is tested at least annually for
\nimpairment. In connection with this, goodwill is allocated to
\ncash-generating units or groups of cash-generating units that
\nare expected to bene\ufb01t from synergies from the business
\ncombination.
\nTechnical goodwill is recognised due to the requirement
\nto recognise deferred tax for the di\ufb00erence between the
\nassigned fair values and the related tax base. In accordance
\nwith IAS 12, a provision is made for deferred tax corresponding
\nto the tax rate multiplied by the di\ufb00erence between the
\nfair values of the acquired assets and the transferred tax
\ndepreciation basis.
\nIf the fair value of the equity exceeds the acquisition cost in a
\nbusiness combination, the di\ufb00erence is recognised as income
\nimmediately on the acquisition date. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfNotesAndOtherExplanatoryInformationExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6806": {
"value": "The consolidated \ufb01nancial statements of the company and its subsidiaries (together \u201cthe group\u201d) for the year ended 31
\nDecember 2022 was authorised for issue in accordance with a
\nresolution of the directors on 28 April 2023.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAuthorisationOfFinancialStatementsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6813": {
"value": "PetroNor E&P ASA ",
"dimensions": {
"concept": "ifrs-full:NameOfUltimateParentOfGroup",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6814": {
"value": "PetroNor E&P ASA ",
"dimensions": {
"concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6815": {
"value": "company limited by shares",
"dimensions": {
"concept": "ifrs-full:LegalFormOfEntity",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6818": {
"value": "Norway",
"dimensions": {
"concept": "ifrs-full:PrincipalPlaceOfBusiness",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6819": {
"value": "Norway",
"dimensions": {
"concept": "ifrs-full:CountryOfIncorporation",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6820": {
"value": "Norway",
"dimensions": {
"concept": "ifrs-full:DomicileOfEntity",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6824": {
"value": "The principal activities of the group are the exploration and production of crude oil.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfNatureOfEntitysOperationsAndPrincipalActivities",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6829": {
"value": "Note 02 Basis of preparation
\nPetroNor E&P ASA\u2019s consolidated \ufb01nancial statements have
\nbeen prepared in accordance with International Financial
\nReporting Standards (IFRS) which have been adopted by the
\nEU and are mandatory for \ufb01nancial years beginning on or after
\n1 January 2022, and Norwegian disclosure requirements listed
\nin the Norwegian Accounting Act as of 31 December 2022. The
\nconsolidated \ufb01nancial statements have been prepared on a
\nhistorical cost basis. The consolidated \ufb01nancial statements
\nhave been prepared on the basis of uniform accounting
\nprinciples for similar transactions and events under otherwise
\nsimilar circumstances.
\nThe consolidated \ufb01nancial statements are presented in
\nUnited States Dollars, which is the functional currency for all
\nthe material subsidiaries, and all values are rounded to the
\nthousand dollars unless otherwise stated.
\nGOING CONCERN
\nThe board of directors con\ufb01rms that the consolidated \ufb01nancial
\nstatements have been prepared pursuant to the going
\nconcern assumption, and that this assumption was realistic
\nas at the balance sheet date. The going concern assumption
\nis based upon the \ufb01nancial position of the company and the
\ndevelopment plans currently in place. In the board of directors\u2019
\nview, the annual accounts give a true and fair view of the
\ngroup\u2019s assets and liabilities, \ufb01nancial position and results.
\nPetroNor E&P ASA is the parent company of the PetroNor
\nGroup. Its consolidated \ufb01nancial statements have been
\nprepared on the assumption that PetroNor will continue as
\na going concern. The group recognises that in order to fund
\non-going operations and pursue organic and inorganic growth
\nopportunities it will require additional funding. This funding
\nmay be sourced through joint venture equity or share issues or
\nthrough debt \ufb01nance.
\nThe going concern basis assumes the continuity of normal
\nbusiness activity and the realisation of assets and the
\nsettlement of liabilities in the normal course of business. The
\nunderlying business of the group created a net pro\ufb01t after tax
\nof USD 34.3 million for the year ended 31 December 2022, with
\nstrong production from the Congo assets in the \ufb01rst quarter of
\n2023. As at 31 December 2022, the group had a cash balance
\nof USD 24.8 million (2021 USD 31.8 million). The company
\nhas listed on the main exchange of Oslo B\u00f8rs, successfully
\nre\ufb01nanced its debt, achieved high production levels following
\na successful in-\ufb01ll drilling campaign and continues to seek
\nfor potential partners to join the company on its exploration
\nportfolio. This demonstrates that the business has continued
\nto operate e\ufb00ectively, and businesses are willing to engage
\nwith the company and this has enabled the directors of
\nPetroNor (\u201cthe directors\u201d) to form the opinion that the
\ncompany will be in a position to continue to meet its liabilities
\nand obligations for a period of at least twelve months from the
\ndate of signing this report.
\nThese consolidated \ufb01nancial statements do not include any
\nadjustments relating to the recoverability and classi\ufb01cation of
\nrecorded asset amounts or to the amounts and classi\ufb01cation
\nof liabilities that might be necessary should the group not
\ncontinue as a going concern.
\nThe following \ufb01nancial review is based on the consolidated
\n\ufb01nancial statements of PetroNor E&P ASA and its subsidiaries.
\nThe statements have been prepared in accordance with
\nInternational Financial Reporting Standards (IFRS) as adopted
\nby the EU as well as Norwegian accounting legislation.
\nIn the view of the board, the statement of comprehensive
\nincome, statement of changes in equity, statement of \ufb01nancial
\nposition and cash\ufb02ow provide satisfactory information about
\nthe operations, \ufb01nancial results and position of the group and
\nthe parent company at 31 December 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6833": {
"value": "PetroNor E&P ASA\u2019s consolidated \ufb01nancial statements have been prepared in accordance with International Financial
\nReporting Standards (IFRS) which have been adopted by the
\nEU and are mandatory for \ufb01nancial years beginning on or after
\n1 January 2022, and Norwegian disclosure requirements listed
\nin the Norwegian Accounting Act as of 31 December 2022. The
\nconsolidated \ufb01nancial statements have been prepared on a
\nhistorical cost basis. The consolidated \ufb01nancial statements
\nhave been prepared on the basis of uniform accounting
\nprinciples for similar transactions and events under otherwise
\nsimilar circumstances.",
"dimensions": {
"concept": "ifrs-full:StatementOfIFRSCompliance",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6834": {
"value": "PetroNor E&P ASA\u2019s consolidated \ufb01nancial statements have been prepared in accordance with International Financial
\nReporting Standards (IFRS) which have been adopted by the
\nEU and are mandatory for \ufb01nancial years beginning on or after
\n1 January 2022, and Norwegian disclosure requirements listed
\nin the Norwegian Accounting Act as of 31 December 2022. The
\nconsolidated \ufb01nancial statements have been prepared on a
\nhistorical cost basis. The consolidated \ufb01nancial statements
\nhave been prepared on the basis of uniform accounting
\nprinciples for similar transactions and events under otherwise
\nsimilar circumstances.
\nThe consolidated \ufb01nancial statements are presented in
\nUnited States Dollars, which is the functional currency for all
\nthe material subsidiaries, and all values are rounded to the
\nthousand dollars unless otherwise stated. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesAccountingEstimatesAndErrorsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6835": {
"value": "PetroNor E&P ASA\u2019s consolidated \ufb01nancial statements have been prepared in accordance with International Financial
\nReporting Standards (IFRS) which have been adopted by the
\nEU and are mandatory for \ufb01nancial years beginning on or after
\n1 January 2022, and Norwegian disclosure requirements listed
\nin the Norwegian Accounting Act as of 31 December 2022. The
\nconsolidated \ufb01nancial statements have been prepared on a
\nhistorical cost basis. The consolidated \ufb01nancial statements
\nhave been prepared on the basis of uniform accounting
\nprinciples for similar transactions and events under otherwise
\nsimilar circumstances.
\nThe consolidated \ufb01nancial statements are presented in
\nUnited States Dollars, which is the functional currency for all
\nthe material subsidiaries, and all values are rounded to the
\nthousand dollars unless otherwise stated. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6857": {
"value": "GOING CONCERN The board of directors con\ufb01rms that the consolidated \ufb01nancial
\nstatements have been prepared pursuant to the going
\nconcern assumption, and that this assumption was realistic
\nas at the balance sheet date. The going concern assumption
\nis based upon the \ufb01nancial position of the company and the
\ndevelopment plans currently in place. In the board of directors\u2019
\nview, the annual accounts give a true and fair view of the
\ngroup\u2019s assets and liabilities, \ufb01nancial position and results.
\nPetroNor E&P ASA is the parent company of the PetroNor
\nGroup. Its consolidated \ufb01nancial statements have been
\nprepared on the assumption that PetroNor will continue as
\na going concern. The group recognises that in order to fund
\non-going operations and pursue organic and inorganic growth
\nopportunities it will require additional funding. This funding
\nmay be sourced through joint venture equity or share issues or
\nthrough debt \ufb01nance.
\nThe going concern basis assumes the continuity of normal
\nbusiness activity and the realisation of assets and the
\nsettlement of liabilities in the normal course of business. The
\nunderlying business of the group created a net pro\ufb01t after tax
\nof USD 34.3 million for the year ended 31 December 2022, with
\nstrong production from the Congo assets in the \ufb01rst quarter of
\n2023. As at 31 December 2022, the group had a cash balance
\nof USD 24.8 million (2021 USD 31.8 million). The company
\nhas listed on the main exchange of Oslo B\u00f8rs, successfully
\nre\ufb01nanced its debt, achieved high production levels following
\na successful in-\ufb01ll drilling campaign and continues to seek
\nfor potential partners to join the company on its exploration
\nportfolio. This demonstrates that the business has continued
\nto operate e\ufb00ectively, and businesses are willing to engage
\nwith the company and this has enabled the directors of
\nPetroNor (\u201cthe directors\u201d) to form the opinion that the
\ncompany will be in a position to continue to meet its liabilities
\nand obligations for a period of at least twelve months from the
\ndate of signing this report.
\nThese consolidated \ufb01nancial statements do not include any
\nadjustments relating to the recoverability and classi\ufb01cation of
\nrecorded asset amounts or to the amounts and classi\ufb01cation
\nof liabilities that might be necessary should the group not
\ncontinue as a going concern.
\nThe following \ufb01nancial review is based on the consolidated
\n\ufb01nancial statements of PetroNor E&P ASA and its subsidiaries.
\nThe statements have been prepared in accordance with
\nInternational Financial Reporting Standards (IFRS) as adopted
\nby the EU as well as Norwegian accounting legislation.
\nIn the view of the board, the statement of comprehensive
\nincome, statement of changes in equity, statement of \ufb01nancial
\nposition and cash\ufb02ow provide satisfactory information about
\nthe operations, \ufb01nancial results and position of the group and
the parent company at 31 December 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGoingConcernExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6880": {
"value": "2022-12-31",
"dimensions": {
"concept": "ifrs-full:DateOfEndOfReportingPeriod2013",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6930": {
"value": "Note 03 Significant accounting judgements, estimates, and assumptions
\nThe directors evaluate estimates and judgements
\nincorporated in the consolidated \ufb01nancial statements based
\non historical knowledge and the best available current
\ninformation. Estimates assume a reasonable expectation of
\nfuture events and are based on current trends and economic
\ndata, obtained both externally and within the group.
\nManagement has identi\ufb01ed the following critical accounting
\npolicies for which signi\ufb01cant judgements, estimates, and
\nassumptions are made. Actual results may di\ufb00er from these
\nestimates under di\ufb00erent assumptions and conditions and
\nmay materially a\ufb00ect \ufb01nancial results or the \ufb01nancial position
\nreported in future period.
\nFurther details of the nature of these assumptions and
\nconditions may be found in the relevant notes to the \ufb01nancial
\nstatements.
\nHYDROCARBON RESERVE AND RESOURCE ESTIMATES
\nHydrocarbon reserves are estimates of the amount of
\nhydrocarbons that can be economically and legally extracted
\nfrom the group\u2019s oil and gas properties. The group estimates
\nits commercial reserves and resources based on information
\ncompiled by appropriately quali\ufb01ed persons relating to the
\ngeological and technical data on the size, depth, shape and
\ngrade of the hydrocarbon body and suitable production
\ntechniques and recovery rates. Commercial reserves are
\ndetermined using estimates of oil and gas in place, recovery
\nfactors and future commodity prices, the latter having an
\nimpact on the total amount of recoverable reserves and the
\nproportion of the gross reserves which are attributable to the
\nhost government under the terms of the production-sharing
\nagreements. Future development costs are estimated using
\nassumptions as to the number of wells required to produce
\nthe commercial reserves, the cost of such wells and associated
\nproduction facilities, and other capital costs. The current long-
\nterm Brent oil price assumption used in the estimation of
\ncommercial reserves is USD 60/bbl. The carrying amount of
\noil and gas properties and licenses at 31 December 2022 are
\nshown in note 16 and 17.
\nThe group estimates and reports hydrocarbon reserves in
\nline with the principles contained in the Society of Petroleum
\nEngineers (SPE) Petroleum Resources Management Reporting
\nSystem (PRMS) framework. As the economic assumptions used
\nmay change and as additional geological information is obtained
\nduring the operation of a \ufb01eld, estimates of recoverable
\nreserves may change. Such changes may impact the group\u2019s
\nreported \ufb01nancial position and results, which include:
\n\u25a0
The carrying value of oil and gas properties may be a\ufb00ected
\ndue to changes in estimated future cash \ufb02ows, note 16;
\n\u25a0
Depreciation and amortisation charges in the statement
\nof pro\ufb01t or loss and other comprehensive income may
\nchange where such charges are determined using the unit
\nof production (UOP) method, or where the useful life of the
\nrelated assets change, note 16;
\n\u25a0
Provisions for decommissioning are subject to re-estimation
\n\u2013 where changes to reserves estimates a\ufb00ect expectations
\nabout when such activities will occur and the associated cost
\nof these activities, note 21.
\nTAXES
\nThe group operates in several tax jurisdictions, and
\nconsequently, its income is subject to various rates and rules
\nof taxation. As a result, the company\u2019s e\ufb00ective tax rate
\nmay vary signi\ufb01cantly depending upon the pro\ufb01tability of
\noperations in the di\ufb00erent jurisdictions.
\nThe group recognises the net future tax bene\ufb01t related to
\ndeferred income tax assets to the extent that it is probable
\nthat the deductible temporary di\ufb00erences will reverse in the
\nforeseeable future. Assessing the recoverability of deferred
\nincome tax assets requires the group to make signi\ufb01cant
\nestimates related to expectations of future taxable income.
\nEstimates of future taxable income are based on forecast cash
\n\ufb02ows from operations and the application of existing tax laws
\nin each jurisdiction, to the extent that future cash \ufb02ows and
\ntaxable income di\ufb00er signi\ufb01cantly from estimates. The ability of
\nthe group to realise the net deferred tax assets recorded at the
\ndate of the statement of \ufb01nancial position could be impacted.
\nAdditionally, future changes in tax laws in the jurisdictions in
\nwhich the group operates could limit the ability of the group to
\nobtain tax deductions in future periods.
\nAdditional information on the accounting policy for taxes is
\nexplained further in note 10 and 31M.
\nDECOMMISSIONING COSTS
\nDecommissioning costs will be incurred by the group at the
\nend of the operating life of some of the group\u2019s facilities and
\nproperties. The group assesses its retirement obligation at
\neach reporting date. The ultimate decommissioning costs are
\nuncertain and cost estimates can vary in response to many
\nfactors, including changes to relevant legal requirements, the
\nemergence of new restoration techniques or experience at
\nother production sites. The expected timing, extent and amount
\nof expenditure can also change, for example in response to
\nchanges in reserves or changes in laws and regulations or
\ntheir interpretation. Therefore, signi\ufb01cant estimates and
\nassumptions are made in determining the provision for
\ndecommissioning costs. As a result, there could be signi\ufb01cant
\nadjustments to the provisions established which would
\na\ufb00ect future \ufb01nancial results. The provision at reporting date
\nrepresents the management\u2019s best estimate of the present
\nvalue of the future decommissioning costs required. Additional
\ninformation is provided in note 21.
\nIMPAIRMENT OF OIL AND GAS ASSETS AND TECHNICAL
\nGOODWILL
\nManagement must determine whether there are circumstances
\nindicating a possible impairment of the group\u2019s oil and gas
\nassets. Changes in the circumstances or expectations of
\nfuture performance of an individual asset or a group of assets
\nmay be an indicator that the asset is impaired, requiring the
\ncarrying amount to be written down to its recoverable amount.
\nAssessment for indicators of impairment includes assessments
\nof expected future cash \ufb02ows, future oil and gas prices, cost
\npro\ufb01les, indicators that the asset will be uneconomic to develop,
\ngeological evaluation and the date of expiration of the licences.
\nImpairments other than impairments of goodwill are reversed
\nwhere impairment indicators are no longer present.
\n
PetroNor has recognised \u201ctechnical goodwill\u201d arising on
\nthe OML 113 business combination. Technical goodwill is
\ncommonly used in the oil and gas industry to describe a
\ncategory of goodwill arising as an o\ufb00setting amount to
\ndeferred tax recognised in business combinations. The
\ntechnical goodwill has been allocated to the OML 113
\nNigeria cash generating unit (CGU) and will be assessed for
\nimpairment where there are indications that the CGU is
\nimpaired. Goodwill is not depreciated and hence, impairment
\nof technical goodwill is expected on a recurring basis,
\nunless there are positive changes in underlying economic
\nassumptions for the asset. When performing the impairment
\ntest for technical goodwill, deferred tax recognised in relation
\nto the acquired assets in a business combination reduces the
\nnet carrying value prior to the eventual impairment charges.
\nWhen deferred tax from the initial recognition decreases,
\nmore goodwill is exposed for impairment. After initial
\nrecognition, depreciation of values calculated in the purchase
\nprice allocations from business combinations will result in
\ndecreased deferred tax liability. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6931": {
"value": "Note 03 Significant accounting judgements, estimates, and assumptions
\nThe directors evaluate estimates and judgements
\nincorporated in the consolidated \ufb01nancial statements based
\non historical knowledge and the best available current
\ninformation. Estimates assume a reasonable expectation of
\nfuture events and are based on current trends and economic
\ndata, obtained both externally and within the group.
\nManagement has identi\ufb01ed the following critical accounting
\npolicies for which signi\ufb01cant judgements, estimates, and
\nassumptions are made. Actual results may di\ufb00er from these
\nestimates under di\ufb00erent assumptions and conditions and
\nmay materially a\ufb00ect \ufb01nancial results or the \ufb01nancial position
\nreported in future period.
\nFurther details of the nature of these assumptions and
\nconditions may be found in the relevant notes to the \ufb01nancial
\nstatements.
\nHYDROCARBON RESERVE AND RESOURCE ESTIMATES
\nHydrocarbon reserves are estimates of the amount of
\nhydrocarbons that can be economically and legally extracted
\nfrom the group\u2019s oil and gas properties. The group estimates
\nits commercial reserves and resources based on information
\ncompiled by appropriately quali\ufb01ed persons relating to the
\ngeological and technical data on the size, depth, shape and
\ngrade of the hydrocarbon body and suitable production
\ntechniques and recovery rates. Commercial reserves are
\ndetermined using estimates of oil and gas in place, recovery
\nfactors and future commodity prices, the latter having an
\nimpact on the total amount of recoverable reserves and the
\nproportion of the gross reserves which are attributable to the
\nhost government under the terms of the production-sharing
\nagreements. Future development costs are estimated using
\nassumptions as to the number of wells required to produce
\nthe commercial reserves, the cost of such wells and associated
\nproduction facilities, and other capital costs. The current long-
\nterm Brent oil price assumption used in the estimation of
\ncommercial reserves is USD 60/bbl. The carrying amount of
\noil and gas properties and licenses at 31 December 2022 are
\nshown in note 16 and 17.
\nThe group estimates and reports hydrocarbon reserves in
\nline with the principles contained in the Society of Petroleum
\nEngineers (SPE) Petroleum Resources Management Reporting
\nSystem (PRMS) framework. As the economic assumptions used
\nmay change and as additional geological information is obtained
\nduring the operation of a \ufb01eld, estimates of recoverable
\nreserves may change. Such changes may impact the group\u2019s
\nreported \ufb01nancial position and results, which include:
\n\u25a0
The carrying value of oil and gas properties may be a\ufb00ected
\ndue to changes in estimated future cash \ufb02ows, note 16;
\n\u25a0
Depreciation and amortisation charges in the statement
\nof pro\ufb01t or loss and other comprehensive income may
\nchange where such charges are determined using the unit
\nof production (UOP) method, or where the useful life of the
\nrelated assets change, note 16;
\n\u25a0
Provisions for decommissioning are subject to re-estimation
\n\u2013 where changes to reserves estimates a\ufb00ect expectations
\nabout when such activities will occur and the associated cost
\nof these activities, note 21.
\nTAXES
\nThe group operates in several tax jurisdictions, and
\nconsequently, its income is subject to various rates and rules
\nof taxation. As a result, the company\u2019s e\ufb00ective tax rate
\nmay vary signi\ufb01cantly depending upon the pro\ufb01tability of
\noperations in the di\ufb00erent jurisdictions.
\nThe group recognises the net future tax bene\ufb01t related to
\ndeferred income tax assets to the extent that it is probable
\nthat the deductible temporary di\ufb00erences will reverse in the
\nforeseeable future. Assessing the recoverability of deferred
\nincome tax assets requires the group to make signi\ufb01cant
\nestimates related to expectations of future taxable income.
\nEstimates of future taxable income are based on forecast cash
\n\ufb02ows from operations and the application of existing tax laws
\nin each jurisdiction, to the extent that future cash \ufb02ows and
\ntaxable income di\ufb00er signi\ufb01cantly from estimates. The ability of
\nthe group to realise the net deferred tax assets recorded at the
\ndate of the statement of \ufb01nancial position could be impacted.
\nAdditionally, future changes in tax laws in the jurisdictions in
\nwhich the group operates could limit the ability of the group to
\nobtain tax deductions in future periods.
\nAdditional information on the accounting policy for taxes is
\nexplained further in note 10 and 31M.
\nDECOMMISSIONING COSTS
\nDecommissioning costs will be incurred by the group at the
\nend of the operating life of some of the group\u2019s facilities and
\nproperties. The group assesses its retirement obligation at
\neach reporting date. The ultimate decommissioning costs are
\nuncertain and cost estimates can vary in response to many
\nfactors, including changes to relevant legal requirements, the
\nemergence of new restoration techniques or experience at
\nother production sites. The expected timing, extent and amount
\nof expenditure can also change, for example in response to
\nchanges in reserves or changes in laws and regulations or
\ntheir interpretation. Therefore, signi\ufb01cant estimates and
\nassumptions are made in determining the provision for
\ndecommissioning costs. As a result, there could be signi\ufb01cant
\nadjustments to the provisions established which would
\na\ufb00ect future \ufb01nancial results. The provision at reporting date
\nrepresents the management\u2019s best estimate of the present
\nvalue of the future decommissioning costs required. Additional
\ninformation is provided in note 21.
\nIMPAIRMENT OF OIL AND GAS ASSETS AND TECHNICAL
\nGOODWILL
\nManagement must determine whether there are circumstances
\nindicating a possible impairment of the group\u2019s oil and gas
\nassets. Changes in the circumstances or expectations of
\nfuture performance of an individual asset or a group of assets
\nmay be an indicator that the asset is impaired, requiring the
\ncarrying amount to be written down to its recoverable amount.
\nAssessment for indicators of impairment includes assessments
\nof expected future cash \ufb02ows, future oil and gas prices, cost
\npro\ufb01les, indicators that the asset will be uneconomic to develop,
\ngeological evaluation and the date of expiration of the licences.
\nImpairments other than impairments of goodwill are reversed
\nwhere impairment indicators are no longer present.
\n
PetroNor has recognised \u201ctechnical goodwill\u201d arising on
\nthe OML 113 business combination. Technical goodwill is
\ncommonly used in the oil and gas industry to describe a
\ncategory of goodwill arising as an o\ufb00setting amount to
\ndeferred tax recognised in business combinations. The
\ntechnical goodwill has been allocated to the OML 113
\nNigeria cash generating unit (CGU) and will be assessed for
\nimpairment where there are indications that the CGU is
\nimpaired. Goodwill is not depreciated and hence, impairment
\nof technical goodwill is expected on a recurring basis,
\nunless there are positive changes in underlying economic
\nassumptions for the asset. When performing the impairment
\ntest for technical goodwill, deferred tax recognised in relation
\nto the acquired assets in a business combination reduces the
\nnet carrying value prior to the eventual impairment charges.
\nWhen deferred tax from the initial recognition decreases,
\nmore goodwill is exposed for impairment. After initial
\nrecognition, depreciation of values calculated in the purchase
\nprice allocations from business combinations will result in
\ndecreased deferred tax liability. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfChangesInAccountingEstimatesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7018": {
"value": "DECOMMISSIONING COSTS Decommissioning costs will be incurred by the group at the
\nend of the operating life of some of the group\u2019s facilities and
\nproperties. The group assesses its retirement obligation at
\neach reporting date. The ultimate decommissioning costs are
\nuncertain and cost estimates can vary in response to many
\nfactors, including changes to relevant legal requirements, the
\nemergence of new restoration techniques or experience at
\nother production sites. The expected timing, extent and amount
\nof expenditure can also change, for example in response to
\nchanges in reserves or changes in laws and regulations or
\ntheir interpretation. Therefore, signi\ufb01cant estimates and
\nassumptions are made in determining the provision for
\ndecommissioning costs. As a result, there could be signi\ufb01cant
\nadjustments to the provisions established which would
\na\ufb00ect future \ufb01nancial results. The provision at reporting date
\nrepresents the management\u2019s best estimate of the present
\nvalue of the future decommissioning costs required. Additional
\ninformation is provided in note 21. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7097": {
"value": "Note 04 Revenue
\nAmounts in USD thousand
2022
2021
\nRevenue from contracts with customers
\nRevenue from sales of petroleum products
72,837
57,601
\nOther revenue
\nAssignment of tax oil
47,579
33,102
\nAssignment of royalties
25,650
15,760
\nTotal revenue
146,066
106,463
\nQuantity of oil lifted (barrels)
800,177
831,089
\nAverage selling price (USD per barrel)
90.99
69.31
\nQuantity of net oil produced after royalty, cost oil and tax oil (barrels)
900,495
821,536
\nAll revenue from the sales of petroleum products in 2022
\nis generated, recognised and transferred at a point in time.
\nInvoices are due for settlement thirty days from the bill
\nof lading, the point at which crude oil had been loaded
\nonto vessel for shipment. All group revenue is derived
\nfrom production in the Republic of Congo from the PNGF
\nSud o\ufb00shore asset. The group presents pro\ufb01t oil tax and
\nroyalties on a grossed-up basis as an income tax expense
\nwith corresponding increase in oil and gas revenues and any
\nassociated royalties are included in cost of sales. Refer to note
\n31K for additional information. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRevenueExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7098": {
"value": "Note 04 Revenue
\nAmounts in USD thousand
2022
2021
\nRevenue from contracts with customers
\nRevenue from sales of petroleum products
72,837
57,601
\nOther revenue
\nAssignment of tax oil
47,579
33,102
\nAssignment of royalties
25,650
15,760
\nTotal revenue
146,066
106,463
\nQuantity of oil lifted (barrels)
800,177
831,089
\nAverage selling price (USD per barrel)
90.99
69.31
\nQuantity of net oil produced after royalty, cost oil and tax oil (barrels)
900,495
821,536",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7142": {
"value": "Note 05 Cost of sales
\nAmounts in USD thousand
2022
2021
\nOperating expenses
16,636
14,303
\nRoyalty
25,650
15,760
\nDepreciation and amortisation of oil and gas properties
9,134
4,385
\nProvision for diversi\ufb01ed investment
1,710
-
\nMovement in oil inventory
(6,920)
137
\nTotal
46,210
34,585
\nProvision for diversi\ufb01ed investment expenditure has been reclassi\ufb01ed from administrative expenses to cost of sales in 2022. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCostOfSalesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7169": {
"value": "Note 06 Other operating income
\nAmounts in USD thousand
2022
2021
\nOther
-
865
\nTotal
-
865",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7200": {
"value": "Note 07 Exploration expenses
\nAmounts in USD thousand
2022
2021
\nImpairment reversal
(2,519)
-
\nSeismic data acquisition
889
2,270
\nTotal
(1,630)
2,270
\nImpairment on inventory was reversed in the period to re\ufb02ect current market conditions in the drilling sector (refer to note 12).
\nCosts not capitalised to intangible assets under group policies are expensed including seismic costs and the allocated time writing
\ncosts.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForExplorationAndEvaluationExpenditures",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7220": {
"value": "Note 08 Administrative expenses
\nAmounts in USD thousand
Note
2022
2021
\nEmployee bene\ufb01t expenses
8A
5,581
5,435
\nTravelling expenses
559
218
\nLegal and professional expenses
5,209
2,620
\nCorporate social responsibility
1,500
1,500
\nProvision for diversi\ufb01ed investment
-
1,051
\nBusiness development
478
486
\nOther expenses
1,051
1,821
\nTotal
14,378
13,131
\nProvision for diversi\ufb01ed investment expenditure has been reclassi\ufb01ed from administrative expenses to cost of sales in 2022.
\n8A.
EMPLOYEE BENEFIT EXPENSES
\nAmounts in USD thousand
2022
2021
\nSalaries
4,834
4,793
\nShort-term non-monetary bene\ufb01ts
490
304
\nDe\ufb01ned contribution pension cost
43
41
\nSocial-security contributions and similar taxes
214
297
\nTotal
5,581
5,435
\nPetroNor is required to have an occupational pension
\nscheme in accordance with the Norwegian law on required
\noccupational pension (\u201cLov om obligatorisk tjenestepensjon\u201d).
\nThe Norwegian subsidiary that employs sta\ufb00 PetroNor E&P
\nServices AS contributes to an external de\ufb01ned contribution
\nscheme and therefore no pension liability is recognised in the
\nstatement of \ufb01nancial position.
\nUnder the Pensions Act 2008, every employer in the UK
\nmust put certain sta\ufb00 into a workplace pension scheme and
\ncontribute towards it,
\nPetroNor E&P Services Limited the subsidiary that employs
\nsta\ufb00 in the UK, contributes into an external de\ufb01ned
\ncontribution scheme. As such, no pension liability is
\nrecognised in the statement of \ufb01nancial position in relation to
\nthe company\u2019s UK-based employees.
\nThere are currently no share-based payment incentive
\nschemes in place for employees.
\nThe cost of non-cash bene\ufb01ts to employees is disclosed as
\nshort-term non-monetary bene\ufb01ts above.
\n
8B.
AUDITORS\u2019 REMUNERATION
\nAmounts in USD thousand
2022
2021
\nPaid or payable to BDO
\nAudit review of \ufb01nancial statements
\nBDO AS
178
-
\nBDO Network \ufb01rms
131
130
\nTotal
309
130
\nOther non-assurance services
\nBDO related practices
19
12
\nTotal
19
12
\nPaid or payable to other audit \ufb01rms
\nAudit or review of \ufb01nancial reports
47
138
\nOther non-assurance services
104
141
\nTotal
151
279
\nFees, excluding VAT, to the auditors are included in administration expenses.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGeneralAndAdministrativeExpenseExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7254": {
"value": "8A. EMPLOYEE BENEFIT EXPENSES
\nAmounts in USD thousand
2022
2021
\nSalaries
4,834
4,793
\nShort-term non-monetary bene\ufb01ts
490
304
\nDe\ufb01ned contribution pension cost
43
41
\nSocial-security contributions and similar taxes
214
297
\nTotal
5,581
5,435
\nPetroNor is required to have an occupational pension
\nscheme in accordance with the Norwegian law on required
\noccupational pension (\u201cLov om obligatorisk tjenestepensjon\u201d).
\nThe Norwegian subsidiary that employs sta\ufb00 PetroNor E&P
\nServices AS contributes to an external de\ufb01ned contribution
\nscheme and therefore no pension liability is recognised in the
\nstatement of \ufb01nancial position.
\nUnder the Pensions Act 2008, every employer in the UK
\nmust put certain sta\ufb00 into a workplace pension scheme and
\ncontribute towards it,
\nPetroNor E&P Services Limited the subsidiary that employs
\nsta\ufb00 in the UK, contributes into an external de\ufb01ned
\ncontribution scheme. As such, no pension liability is
\nrecognised in the statement of \ufb01nancial position in relation to
\nthe company\u2019s UK-based employees.
\nThere are currently no share-based payment incentive
\nschemes in place for employees.
\nThe cost of non-cash bene\ufb01ts to employees is disclosed as
\nshort-term non-monetary bene\ufb01ts above.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7315": {
"value": "8B. AUDITORS\u2019 REMUNERATION
\nAmounts in USD thousand
2022
2021
\nPaid or payable to BDO
\nAudit review of \ufb01nancial statements
\nBDO AS
178
-
\nBDO Network \ufb01rms
131
130
\nTotal
309
130
\nOther non-assurance services
\nBDO related practices
19
12
\nTotal
19
12
\nPaid or payable to other audit \ufb01rms
\nAudit or review of \ufb01nancial reports
47
138
\nOther non-assurance services
104
141
\nTotal
151
279
Fees, excluding VAT, to the auditors are included in administration expenses.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7353": {
"value": "Note 09 Finance expenses
\nAmounts in USD thousand
Note
2022
2021
\nUnwinding of discount on decommissioning liability
21
842
995
\nLoan structuring fee
165
-
\nFinance cost on lease liabilities
18
36
8
\nInterest on loans
20
1,042
2,038
\nOther interest
1,237
-
\nTotal
3,322
3,041",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceCostExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7354": {
"value": "Note 09 Finance expenses
\nAmounts in USD thousand
Note
2022
2021
\nUnwinding of discount on decommissioning liability
21
842
995
\nLoan structuring fee
165
-
\nFinance cost on lease liabilities
18
36
8
\nInterest on loans
20
1,042
2,038
\nOther interest
1,237
-
\nTotal
3,322
3,041",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7386": {
"value": "Note 10 Tax expense
\nAmounts in USD thousand
2022
2021
\nPetroleum revenue tax expense
\nCurrent income tax charge
47,579
33,102
\nTotal tax expense reported in the consolidated statement of comprehensive income
47,579
33,102
\nThe income tax expense is only related to the subsidiary in
\nCongo and represents the assignment of tax oil on the revenue
\nfrom sales of petroleum products, note 4. There was no
\nincome tax expense in the other subsidiaries\u2019 jurisdictions nor
\nin the parent\u2019s jurisdiction as these companies are in taxable
\nloss positions in both 2022 and 2021. Average e\ufb00ective tax rate
\nfor the year was 33 per cent (2021: 31 per cent) based on gross
\nrevenue of the group.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7426": {
"value": "Note 11 Earnings per share
\nAmounts in USD thousand
2022
2021
\nPro\ufb01t attributable to ordinary shareholders
\nPro\ufb01t from continuing operations attributable to the ordinary equity holders used in
\ncalculating basic/diluted pro\ufb01t per share
26,887
12,314
\nPro\ufb01t attributable to the ordinary equity holders used in calculating
\nbasic/diluted pro\ufb01t per share
26,887
12,314
\nWeighted average number of ordinary shares outstanding during
\nthe period used in the calculation of earnings per share
\nBasic
1,372,236,921
1,160,438,253
\nDiluted
1,372,729,890
1,161,827,723
\nEarnings per share
\nBasic
1.96
1.06
\nDiluted
1.96
1.06
\nOptions on issue are considered to be potential ordinary shares
\nand have been included in the determination of diluted loss per
\nshare only to the extent to which they are dilutive. There are nil
\noptions as at 31 December 2022 (2021: 1,389,470).",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7462": {
"value": "Note 12 Inventories
\nAmounts in USD thousand
2022
2021
\nCrude oil inventory
7,475
554
\nMaterials and supplies
11,349
5,673
\nTotal
18,824
6,227
\nCrude oil inventory is valued at cost of USD 29.43 per
\nbbl (2021: USD 22.84 bbl). This is derived from the direct
\nproduction costs USD 51.2 million (2021: 34.6 million) and the
\nunit production cost USD 1.74 million (2021: 1.51 million).
\nThe crude oil inventory and the material and supplies
\ninventory are valued at the lower of cost and net realisable
\nvalue. Cost is determined using the weighted average method.
\nNet realisable value is the estimated selling price, less
\napplicable selling expenses. The cost of inventory includes all
\ncosts related to bringing the inventory to its current condition,
\nincluding processing costs, labour costs, supplies, direct
\nand allocated indirect operating overhead and depreciation
\nexpense, where applicable, including allocation of \ufb01xed and
\nvariable costs to inventory.
\nIn the current accounting period inventory for the Guinea-
\nBissau drilling campaign was written back up to cost as current
\nmarket conditions indicate that the net realisable value
\nexceeds the cost. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInventoriesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7514": {
"value": "Note 13 Trade and other receivables
\nAmounts in USD thousand
2022
2021
\nRecoverability less than one year
\nTrade receivables
-
13,431
\nOther receivables
1,171
389
\nTotal
1,171
13,820
\nRecoverability more than one year
\nAdvance against decommissioning cost
29,432
26,837
\nTotal
29,432
26,837
\nIn addition to the booking of decommissioning cost asset and
\nliability, the contractors group and the Congolese Government
\nhave decided to set up funds for the decommissioning cost
\nin an escrow account which is managed by the operator. The
\nadvances of the funds for the year are made on the basis of
\nan average rate of USD 1.60 per barrel produced (2021: USD
\n3.68 per barrel). Refer to note 21 for further details on the
\ndecommissioning liability.
\nThe group has adopted the simpli\ufb01ed approach allowable
\nunder IFRS 9 Financial Instruments where the group measures
\nthe provision for impairment for trade receivables and
\namounts due from related parties at an amount equal to
\nlifetime ECL. The ECL on trade receivables are estimated using
\na provision matrix by reference to past default experience of
\nthe debtor and an analysis of the debtors\u2019 current \ufb01nancial
\nposition, adjusted for factors that are speci\ufb01c to the debtors\u2019
\ngeneral economic conditions and forward looking elements of
\nthe industry in which the debtors operate and an assessment
\nof both the current as well as the forecast direction of
\nconditions at the reporting date.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7559": {
"value": "Note 14 Cash and cash equivalents
\nAmounts in USD thousand
2022
2021
\nCash in bank
24,775
31,673
\nRestricted cash
41
82
\nTotal
24,816
31,755
\nRestricted cash at 31 December 2022 represents ringfenced
\ncash payable to Norwegian authorities.
\nThe following table represents the changes in liabilities arising
\nfrom \ufb01nancing activities through cash \ufb02ows and non-cash
\nchanges:
\nAmounts in USD thousand
\nNon-current
\nborrowings
\nCurrent
\nborrowings
Total
\nAt 1 January 2022
-
13,079
13,079
\nCash \ufb02ows
5,500
(7,579)
(2,079)
\nNon-cash \ufb02ows
-
-
-
\nAs at 31 December 2022
5,500
5,500
11,000
\nAt 1 January 2021
14,912
4,000
18,912
\nCash \ufb02ows
(1,833)
(4000)
(5,833)
\nNon-cash \ufb02ows
-
-
-
\nMovement non-current to current
(13,079)
13,079
-
\nAs at 31 December 2021
-
13,079
13,079",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7560": {
"value": "Note 14 Cash and cash equivalents
\nAmounts in USD thousand
2022
2021
\nCash in bank
24,775
31,673
\nRestricted cash
41
82
\nTotal
24,816
31,755
\nRestricted cash at 31 December 2022 represents ringfenced
\ncash payable to Norwegian authorities.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRestrictedCashAndCashEquivalentsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7643": {
"value": "Note 15 Segment information
\nFor management purposes, the group is organised into one
\nmain operating segment, which involves exploration and
\nproduction of hydrocarbons. All of the group's activities are
\ninterrelated, and discrete \ufb01nancial information is reported
\nto chief operating decision maker as a single segment.
\nAccordingly, all signi\ufb01cant operating decisions are based upon
\nanalysis of the group as one segment. The \ufb01nancial results
\nfrom this segment are equivalent to the \ufb01nancial statements
\nof the group as a whole.
\nThe group only has one operating segment, being exploration
\nand production of hydrocarbons.
\nThe analysis of the location of non-current assets is as follows:
\nAmounts in USD thousand
2022
2021
\nCongo
98,876
69,564
\nThe Gambia
4,507
3,507
\nGuinea-Bissau
667
314
\nNigeria
35,226
3
\nNorway
380
62
\nTotal
139,656
73,450 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7681": {
"value": "Note 16 Property, plant, and equipment
\nPRODUCTION ASSETS AND EQUIPMENT
\nAmounts in USD thousand
2022
2021
\nCost
\nAt 1 January
53,204
33,445
\nAdditions
36,681
19,759
\nDisposals
-
-
\nAt 31 December
89,885
53,204
\nDepreciation
\nAt 1 January
13,807
9,962
\nCharge for the year
8,599
3,845
\nDepreciation on disposals
-
-
\nAt 31 December
22,406
13,807
\nNet carrying amount
\nAt 31 December
67,479
39,397
\nProduction assets and equipment are carried at the following values:
\nAmounts in USD thousand
2022
2021
\nOil & gas CAPEX
62,544
33,968
\nDecommissioning costs
4,900
5,396
\nOther
35
33
\nTotal
67,479
39,397
\nPPE assets are distributed geographically as follow:
\nAmounts in USD thousand
2022
2021
\nCongo
66,542
39,377
\nNigeria
927
-
\nOther
10
20
\nTotal
67,479
39,397",
"dimensions": {
"concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7685": {
"value": "Amounts in USD thousand
2022
2021
\nCost
\nAt 1 January
53,204
33,445
\nAdditions
36,681
19,759
\nDisposals
-
-
\nAt 31 December
89,885
53,204
\nDepreciation
\nAt 1 January
13,807
9,962
\nCharge for the year
8,599
3,845
\nDepreciation on disposals
-
-
\nAt 31 December
22,406
13,807
\nNet carrying amount
\nAt 31 December
67,479
39,397
Amounts in USD thousand 2022
2021
\nCost
\nAt 1 January
11,210
10,396
\nAdditions in relation to business combinations (refer to note 26)
24,268
-
\nAdditions
2,353
814
\nAt 31 December
37,831
11,210
\nAccumulated amortisation and impairment
\nAt 1 January
4,038
3,461
\nAmortisation
541
577
\nImpairment
-
-
\nAt 31 December
4,579
4,038
\nNet carrying value
\nAt 1 January
7,172
6,935
\nAt 31 December
33,252
7,172
Amounts in USD thousand
\nRight-of-use assets
\nO\ufb03ce building
Lease liabilities
\nAt 1 January 2022
44
58
\nAdditions
564
492
\nAmortisation expense
(146)
-
\nInterest expense
-
36
\nPayments made
-
(127)
\nAt 31 December 2022
462
459
\nAgeing of lease liabilities
\nCurrent
179
\nNon-current
280
Amounts in USD thousand
\nRight-of-use assets
\nO\ufb03ce building
Lease liabilities
\nAt 1 January 2021
212
225
\nAdditions
-
-
\nAmortisation expense
(168)
-
\nInterest expense
-
8
\nPayments made
-
(175)
\nAt 31 December 2021
44
58
\nAgeing of lease liabilities
\nCurrent
-
58
\nNon-current
-
-
\nAmounts recognised in pro\ufb01t and loss
\nAmounts in USD thousand
31 December 2022
31 December 2021
\nAmortisation expense on right-of-use assets
146
168
\nInterest expense on lease liabilities
36
8
\nExpense relating to short-term lease
-
-
\nTotal
182
176
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7770": {
"value": "Note 17 Intangible assets
\nLICENCES AND APPROVALS
\nAmounts in USD thousand
2022
2021
\nCost
\nAt 1 January
11,210
10,396
\nAdditions in relation to business combinations (refer to note 26)
24,268
-
\nAdditions
2,353
814
\nAt 31 December
37,831
11,210
\nAccumulated amortisation and impairment
\nAt 1 January
4,038
3,461
\nAmortisation
541
577
\nImpairment
-
-
\nAt 31 December
4,579
4,038
\nNet carrying value
\nAt 1 January
7,172
6,935
\nAt 31 December
33,252
7,172
\nGOODWILL
\nAmounts in USD thousand
2022
2021
\nCost
\nAt 1 January
-
-
\nAdditions in relation to business combinations (refer to note 25)
9,031
-
\nImpairment
-
-
\nAt 31 December
9,031
-
\nGOODWILL
\nGoodwill of USD 9.0 million at 31 December 2022 consists of
\ntechnical goodwill related to the acquisition that occurred
\nduring the year, note 26. Technical goodwill is subject to
\nimpairment testing whenever there is an indicator that the
\nCGU to which it is allocated is impaired. Technical goodwill
\nhas been allocated to the OML 113 CGU and impairment
\nassessments will be based on the underlying economics
\nfor the asset. When performing the impairment test for
\ntechnical goodwill, deferred tax recognized in relation to the
\nacquired assets in a business combination reduces the net
\ncarrying value prior to the eventual impairment charges.
\nWhen deferred tax from the initial recognition decreases,
\nmore goodwill is exposed for impairment. After initial
\nrecognition, depreciation of values calculated in the purchase
\nprice allocations from business combinations will result in
\ndecreased deferred tax liability.
\nLICENCE OVERVIEW
\nCongo
\nIn 2017, subsidiary company Hemla E&P Congo SA acquired
\ninterests in three development and production permits
\n(Tchendo: 20 per cent; Tchibouela: 20 per cent and Tchibeli-
\nLitanzi: 20 per cent) which will respectively end in December
\n2037, for each of them, with possible extensions for 5 years.
\nAll these three licenses are called or named collectively
\n\u201cPNGF Sud\u201d and together comprise an area of 482.28km
\n2
\n. The
\noperator of the licences is Perenco, and the carrying value as
\nat 31 December 2022 is USD 2.8 million. This number is net of
\ndepletion, the Congo intangible assets are the only intangibles
\nin active use and being amortised.
\nNigeria
\nThe corporate acquisition from Panoro Energy ASA during
\nyear, added an economic interest in the OML 113 \ufb01eld of
\n12.1913 per cent that is operated by Yinka Folawiyo Petroleum.
\nThere were two producing wells prior to suspending
\nproduction in November 2021 due to the terminated contract
\nwith the FPSO, the Aje-4 with oil production and Aje-5ST2
\nwith oil and gas production. The licence was renewed in 2018
\nand has a twenty-year term. The current strategy is to update
\nthe \ufb01eld development plan to expedite gas development and
\noverall redevelopment of the venture. As at 31 December
\n2022, the carrying value of the licence was USD 24.3 million.
\nThe Gambia
\nThe A4 licence area is 1,376km
\n2
\nand is operated by company
\nsubsidiary PetroNor E&P Gambia Ltd. PetroNor secured a new
\nexploration licence (PEPLA) on 18 November 2022 and entered
\ninto the \ufb01rst exploration period which has a duration of three
\nyears. PetroNor hold 90 per cent equity with the Gambia
\nNational Petroleum Company as partner (10 per cent equity).
\nAs at 31 December 2022, the carrying value of the A4 licence is
\nUSD 4.5 million.
\n
Guinea-Bissau
\nAs at 31 December 2022, 78.57 per cent interest of the Sinapa
\nand Esperan\u00e7a licences are held and operated by PetroNor
\nsubsidiary PetroNor E&P AB. Post year end it was con\ufb01rmed
\nthat 21.43 per cent previously held by FAR Ltd
had been
\ntransferred to PetroNor. The combined licences cover an area
\nof 4,963km
\n2
\nand have USD 0.6 million carrying value in the
\n\ufb01nancial statements as at 31 December 2022. The current
\nexploration phase runs to October 2023.
\nSenegal
\nAs at the date of this report, the company\u2019s subsidiary
\nAfrican Petroleum Senegal Limited awaits the decision of
\nthe arbitration proceedings with the International Centre for
\nthe Settlement of Investment Disputes (ICSID) regarding the
\ninterests in the Senegal O\ufb00shore Sud Profond and Ru\ufb01sque
\nO\ufb00shore Profond blocks in Senegal (ICSID case ARB/18/24).
\nThe combined licences cover an area of 15,796km
\n2
\nand due to
\nthe arbitration process have nil carrying value in the \ufb01nancial
\nstatements as at 31 December 2022. Please refer to board
\ndirector\u2019s report for additional information on the arbitration
\nstatus.
\nIntangible assets are valued in accordance with group
\naccounting policies and are assessed for indications of
\nimpairment in accordance with IAS 36. There were no
\nindicators of impairment as at 31 December 2022 for the
\nlicence costs within the group. Refer to note 30I for additional
\ninformation.
\nRESERVES
\nThe group has adopted a policy of regional reserve reporting
\nusing external third-party companies to audit its work and
\ncertify reserves and resources. Reserve and contingent
\nresource estimates comply with the de\ufb01nitions set by the
\nPetroleum Resources Management System (\u201cPRMS\u201d) issued
\nby the Society of Petroleum Engineers (\u201cSPE\u201d), the American
\nAssociation of Petroleum Geologists (\u201cAAPG\u201d), the World
\nPetroleum Council (\u201cWPC\u201d) and the Society of Petroleum
\nEvaluation Engineers (\u201cSPEE\u201d) in March 2007. AGR Petroleum
\nServices AS provided the 3
\nrd
\nparty veri\ufb01cations of the PNGF
\nSud reserves. CPR Tracs International Limited provided the 3
\nrd
\nparty veri\ufb01cation of the Aje reserves.
\nThe following is a summary of key results from the reserve
\nreports (net of the group\u2019s share):
\nAsset
1P reserves
2P reserves
3P reserves
\nMMbbls
MMbbls
MMbbls
\nPNGF Sud
12.5
18.5
24.7
\nAje
-
-
-
\nTotal
12.5
18.5
24.7
\nDe\ufb01nitions:
\n1P) Proved reserves
\nProved reserves are those quantities of petroleum, which by
\nanalysis of geoscience and engineering data, can be estimated
\nwith reasonable certainty to be commercially recoverable,
\nfrom a given date forward, from known reservoirs and
\nunder de\ufb01ned economic conditions, operating methods, and
\ngovernment regulations.
\n2P) Proved plus probable reserves
\nProbable reserves are those additional reserves which analysis
\nof geoscience and engineering data indicate are less likely to
\nbe recovered than proved reserves but more certain to be
\nrecovered than possible reserves.
\n3P) Proved plus probable plus possible reserves
\nPossible reserves are those additional reserves which analysis
\nof geoscience and engineering data indicate are less likely to
\nbe recovered than probable reserves.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7771": {
"value": "Note 17 Intangible assets
\nLICENCES AND APPROVALS
\nAmounts in USD thousand
2022
2021
\nCost
\nAt 1 January
11,210
10,396
\nAdditions in relation to business combinations (refer to note 26)
24,268
-
\nAdditions
2,353
814
\nAt 31 December
37,831
11,210
\nAccumulated amortisation and impairment
\nAt 1 January
4,038
3,461
\nAmortisation
541
577
\nImpairment
-
-
\nAt 31 December
4,579
4,038
\nNet carrying value
\nAt 1 January
7,172
6,935
\nAt 31 December
33,252
7,172
\nGOODWILL
\nAmounts in USD thousand
2022
2021
\nCost
\nAt 1 January
-
-
\nAdditions in relation to business combinations (refer to note 25)
9,031
-
\nImpairment
-
-
\nAt 31 December
9,031
-
\nGOODWILL
\nGoodwill of USD 9.0 million at 31 December 2022 consists of
\ntechnical goodwill related to the acquisition that occurred
\nduring the year, note 26. Technical goodwill is subject to
\nimpairment testing whenever there is an indicator that the
\nCGU to which it is allocated is impaired. Technical goodwill
\nhas been allocated to the OML 113 CGU and impairment
\nassessments will be based on the underlying economics
\nfor the asset. When performing the impairment test for
\ntechnical goodwill, deferred tax recognized in relation to the
\nacquired assets in a business combination reduces the net
\ncarrying value prior to the eventual impairment charges.
\nWhen deferred tax from the initial recognition decreases,
\nmore goodwill is exposed for impairment. After initial
\nrecognition, depreciation of values calculated in the purchase
\nprice allocations from business combinations will result in
\ndecreased deferred tax liability.
\nLICENCE OVERVIEW
\nCongo
\nIn 2017, subsidiary company Hemla E&P Congo SA acquired
\ninterests in three development and production permits
\n(Tchendo: 20 per cent; Tchibouela: 20 per cent and Tchibeli-
\nLitanzi: 20 per cent) which will respectively end in December
\n2037, for each of them, with possible extensions for 5 years.
\nAll these three licenses are called or named collectively
\n\u201cPNGF Sud\u201d and together comprise an area of 482.28km
\n2
\n. The
\noperator of the licences is Perenco, and the carrying value as
\nat 31 December 2022 is USD 2.8 million. This number is net of
\ndepletion, the Congo intangible assets are the only intangibles
\nin active use and being amortised.
\nNigeria
\nThe corporate acquisition from Panoro Energy ASA during
\nyear, added an economic interest in the OML 113 \ufb01eld of
\n12.1913 per cent that is operated by Yinka Folawiyo Petroleum.
\nThere were two producing wells prior to suspending
\nproduction in November 2021 due to the terminated contract
\nwith the FPSO, the Aje-4 with oil production and Aje-5ST2
\nwith oil and gas production. The licence was renewed in 2018
\nand has a twenty-year term. The current strategy is to update
\nthe \ufb01eld development plan to expedite gas development and
\noverall redevelopment of the venture. As at 31 December
\n2022, the carrying value of the licence was USD 24.3 million.
\nThe Gambia
\nThe A4 licence area is 1,376km
\n2
\nand is operated by company
\nsubsidiary PetroNor E&P Gambia Ltd. PetroNor secured a new
\nexploration licence (PEPLA) on 18 November 2022 and entered
\ninto the \ufb01rst exploration period which has a duration of three
\nyears. PetroNor hold 90 per cent equity with the Gambia
\nNational Petroleum Company as partner (10 per cent equity).
\nAs at 31 December 2022, the carrying value of the A4 licence is
\nUSD 4.5 million.
\n
Guinea-Bissau
\nAs at 31 December 2022, 78.57 per cent interest of the Sinapa
\nand Esperan\u00e7a licences are held and operated by PetroNor
\nsubsidiary PetroNor E&P AB. Post year end it was con\ufb01rmed
\nthat 21.43 per cent previously held by FAR Ltd
had been
\ntransferred to PetroNor. The combined licences cover an area
\nof 4,963km
\n2
\nand have USD 0.6 million carrying value in the
\n\ufb01nancial statements as at 31 December 2022. The current
\nexploration phase runs to October 2023.
\nSenegal
\nAs at the date of this report, the company\u2019s subsidiary
\nAfrican Petroleum Senegal Limited awaits the decision of
\nthe arbitration proceedings with the International Centre for
\nthe Settlement of Investment Disputes (ICSID) regarding the
\ninterests in the Senegal O\ufb00shore Sud Profond and Ru\ufb01sque
\nO\ufb00shore Profond blocks in Senegal (ICSID case ARB/18/24).
\nThe combined licences cover an area of 15,796km
\n2
\nand due to
\nthe arbitration process have nil carrying value in the \ufb01nancial
\nstatements as at 31 December 2022. Please refer to board
\ndirector\u2019s report for additional information on the arbitration
\nstatus.
\nIntangible assets are valued in accordance with group
\naccounting policies and are assessed for indications of
\nimpairment in accordance with IAS 36. There were no
\nindicators of impairment as at 31 December 2022 for the
\nlicence costs within the group. Refer to note 30I for additional
\ninformation.
\nRESERVES
\nThe group has adopted a policy of regional reserve reporting
\nusing external third-party companies to audit its work and
\ncertify reserves and resources. Reserve and contingent
\nresource estimates comply with the de\ufb01nitions set by the
\nPetroleum Resources Management System (\u201cPRMS\u201d) issued
\nby the Society of Petroleum Engineers (\u201cSPE\u201d), the American
\nAssociation of Petroleum Geologists (\u201cAAPG\u201d), the World
\nPetroleum Council (\u201cWPC\u201d) and the Society of Petroleum
\nEvaluation Engineers (\u201cSPEE\u201d) in March 2007. AGR Petroleum
\nServices AS provided the 3
\nrd
\nparty veri\ufb01cations of the PNGF
\nSud reserves. CPR Tracs International Limited provided the 3
\nrd
\nparty veri\ufb01cation of the Aje reserves.
\nThe following is a summary of key results from the reserve
\nreports (net of the group\u2019s share):
\nAsset
1P reserves
2P reserves
3P reserves
\nMMbbls
MMbbls
MMbbls
\nPNGF Sud
12.5
18.5
24.7
\nAje
-
-
-
\nTotal
12.5
18.5
24.7
\nDe\ufb01nitions:
\n1P) Proved reserves
\nProved reserves are those quantities of petroleum, which by
\nanalysis of geoscience and engineering data, can be estimated
\nwith reasonable certainty to be commercially recoverable,
\nfrom a given date forward, from known reservoirs and
\nunder de\ufb01ned economic conditions, operating methods, and
\ngovernment regulations.
\n2P) Proved plus probable reserves
\nProbable reserves are those additional reserves which analysis
\nof geoscience and engineering data indicate are less likely to
\nbe recovered than proved reserves but more certain to be
\nrecovered than possible reserves.
\n3P) Proved plus probable plus possible reserves
\nPossible reserves are those additional reserves which analysis
\nof geoscience and engineering data indicate are less likely to
\nbe recovered than probable reserves.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7777": {
"value": "Amounts in USD thousand 2022
2021
\nCost
\nAt 1 January
11,210
10,396
\nAdditions in relation to business combinations (refer to note 26)
24,268
-
\nAdditions
2,353
814
\nAt 31 December
37,831
11,210
\nAccumulated amortisation and impairment
\nAt 1 January
4,038
3,461
\nAmortisation
541
577
\nImpairment
-
-
\nAt 31 December
4,579
4,038
\nNet carrying value
\nAt 1 January
7,172
6,935
\nAt 31 December
33,252
7,172
\nGOODWILL
\nAmounts in USD thousand
2022
2021
\nCost
\nAt 1 January
-
-
\nAdditions in relation to business combinations (refer to note 25)
9,031
-
\nImpairment
-
-
\nAt 31 December
9,031
- ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7817": {
"value": "GOODWILL Amounts in USD thousand
2022
2021
\nCost
\nAt 1 January
-
-
\nAdditions in relation to business combinations (refer to note 25)
9,031
-
\nImpairment
-
-
\nAt 31 December
9,031
-
\nGOODWILL
\nGoodwill of USD 9.0 million at 31 December 2022 consists of
\ntechnical goodwill related to the acquisition that occurred
\nduring the year, note 26. Technical goodwill is subject to
\nimpairment testing whenever there is an indicator that the
\nCGU to which it is allocated is impaired. Technical goodwill
\nhas been allocated to the OML 113 CGU and impairment
\nassessments will be based on the underlying economics
\nfor the asset. When performing the impairment test for
\ntechnical goodwill, deferred tax recognized in relation to the
\nacquired assets in a business combination reduces the net
\ncarrying value prior to the eventual impairment charges.
\nWhen deferred tax from the initial recognition decreases,
\nmore goodwill is exposed for impairment. After initial
\nrecognition, depreciation of values calculated in the purchase
\nprice allocations from business combinations will result in
\ndecreased deferred tax liability. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGoodwillExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8003": {
"value": "Note 18 Leases
\nAmounts in USD thousand
\nRight-of-use assets
\nO\ufb03ce building
Lease liabilities
\nAt 1 January 2022
44
58
\nAdditions
564
492
\nAmortisation expense
(146)
-
\nInterest expense
-
36
\nPayments made
-
(127)
\nAt 31 December 2022
462
459
\nAgeing of lease liabilities
\nCurrent
179
\nNon-current
280
\n
Amounts in USD thousand
\nRight-of-use assets
\nO\ufb03ce building
Lease liabilities
\nAt 1 January 2021
212
225
\nAdditions
-
-
\nAmortisation expense
(168)
-
\nInterest expense
-
8
\nPayments made
-
(175)
\nAt 31 December 2021
44
58
\nAgeing of lease liabilities
\nCurrent
-
58
\nNon-current
-
-
\nAmounts recognised in pro\ufb01t and loss
\nAmounts in USD thousand
31 December 2022
31 December 2021
\nAmortisation expense on right-of-use assets
146
168
\nInterest expense on lease liabilities
36
8
\nExpense relating to short-term lease
-
-
\nTotal
182
176
\nThe total cash out\ufb02ow for leases amount to USD 163,000 for the year.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLeasesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8102": {
"value": "Note 19 Trade and other payables
\nAmounts in USD thousand
Note
2022
2021
\nAmounts due less than one year
\nTrade payables
15,437
22,014
\nDue to related parties
25D
2,019
3,449
\nTaxes and state payables
787
120
\nOther payables and accrued liabilities
2,508
4,472
\nTotal
20,751
30,055
\nAmounts due more than one year
\nOther payables
8,738
-
\nTotal
8,738
-",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8106": {
"value": "Amounts in USD thousand Note
2022
2021
\nAmounts due less than one year
\nTrade payables
15,437
22,014
\nDue to related parties
25D
2,019
3,449
\nTaxes and state payables
787
120
\nOther payables and accrued liabilities
2,508
4,472
\nTotal
20,751
30,055
\nAmounts due more than one year
\nOther payables
8,738
-
\nTotal
8,738
-",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8138": {
"value": "Note 20 Loans and borrowings
\nAmounts in USD thousand
2022
2021
\nAt 1 January
13,079
18,912
\nReceived
11,000
-
\nPrincipal repayment
(13,079)
(5,833)
\nInterest on loan accrued
1,042
1,539
\nInterest on loan paid
(1,042)
(1,539)
\nAt 31 December
11,000
13,079
\nAgeing of loans payable
\nCurrent
5,500
13,079
\nNon-current
5,500
-
\nTotal
11,000
13,079
\n
In 2020, PetroNor agreed a USD 15 million facility with 12
\nmonths grace period and maturity date in October 2022. The
\nloan was to be repaid in monthly instalments after the initial
\ngrace period and carried an interest rate of 9 per cent plus
\none-month LIBOR payable monthly if the oil price was below
\nUSD 40 per bbl and 12.5 per cent if the oil price was above USD
\n40 per bbl. The loan was secured against:
\n\u25a0
The assignment of receivables by subsidiary company
\nHemla E&P Congo SA (\u201cHEPCO\u201d);
\n\u25a0
Pledge over one of the bank accounts of subsidiary company
\nHemla Africa Holding AS (\u201cHAH\u201d);
\n\u25a0
Pledge over one of the bank accounts of subsidiary company
\nHEPCO;
\n\u25a0
Pledge over shares in subsidiary companies, HAH and
\nHEPCO;
\n\u25a0
Assignment of inter-company loan agreement between HAH
\nand HEPCO; and
\n\u25a0
Corporate guarantees by PetroNor E&P Ltd (Australia) and
\nits subsidiaries PetroNor E&P Ltd (Cyprus) and HEPCO.
\nOn 29 December 2022, HAH and Acqua Diversi\ufb01ed Holdings
\nSPC entered into an amended agreement to advance an
\nadditional USD 11.0 million to be repaid in eight quarterly
\ninstalments of USD 1.375 million. The remaining principal of
\nUSD 2.5 million was repaid along with outstanding interest
\nand arrangement fees for the amended facility. The amended
\nfacility carries an interest rate of 11.0 per cent, and due to the
\ngroup corporate restructure in February 2022, in addition to
\nthe previous security provided, a corporate guarantee was
\nprovided by the new parent company PetroNor E&P ASA.
\nThe Acqua Diversi\ufb01ed Holdings SPC loan has the following
\ncovenants and undertakings:
\n\u25a0
Cash equal to the quarterly instalments must be maintained
\non speci\ufb01c bank accounts of HAH or HEPCO on a recurring
\nbasis;
\n\u25a0
At least USD 6.0 million from HEPCO oil sales must be paid
\ninto the collection account on a 3-month rolling basis;
\n\u25a0
PetroNor to maintain shareholding level in excess of 70 per
\ncent in subsidiary company HAH;
\n\u25a0
HAH to maintain shareholding level in excess of 74.25 per
\ncent in subsidiary company HEPCO;
\n\u25a0
HAH shareholder equity ratio shall not be less than 30 per
\ncent;
\n\u25a0
HAH duty to report on \ufb01nancial statements, pledged bank
\naccount activity and oil inventory;
\n\u25a0
Restrictions on distributions to HAH shareholders, unless
\nsu\ufb03cient liquidity with cash balances exceeding USD 10.0
\nmillion immediately before any such distribution, and
\ndistribution does not exceed 75 per cent consolidated HAH
\nnet pro\ufb01t in any year.
\nSeparately on 28 September 2020, subsidiary company HAH
\npaid a USD 3.9 million dividend to minority interest and related
\nparty Symero Ltd. An amount equal to the dividend was
\nimmediately loaned to the top company of the group at the
\ntime, PetroNor E&P Ltd (Australia), by Symero Ltd with interest
\nrates matching those already provided by external \ufb01nancing
\nand no security was provided for the loan. The maturity date
\nwas matched to the USD 15 million facility. On 21 December
\n2022, the principal balance of USD 3.9 million was repaid to
\nSymero Ltd.
\nAll covenants were complied with and there were no
\nnoti\ufb01cations of breaches during the year for both loans
\npayable to Acqua Diversi\ufb01ed Holdings SPC and Symero Ltd.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBorrowingsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8142": {
"value": "Amounts in USD thousand 2022
2021
\nAt 1 January
13,079
18,912
\nReceived
11,000
-
\nPrincipal repayment
(13,079)
(5,833)
\nInterest on loan accrued
1,042
1,539
\nInterest on loan paid
(1,042)
(1,539)
\nAt 31 December
11,000
13,079
\nAgeing of loans payable
\nCurrent
5,500
13,079
\nNon-current
5,500
-
\nTotal
11,000
13,079",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8271": {
"value": "Note 21 Provisions
\nDECOMMISSIONING LIABILITY
\nIn accordance with joint venture agreements and legislation,
\nthe wellheads, production assets, pipelines and other
\ninstallations may have to be dismantled and removed from oil
\nand natural gas \ufb01elds when the production ceases. The exact
\ntiming of the obligations is uncertain and depends on the rate
\nthe reserves of the \ufb01eld are depleted.
\nBased on the existing production pro\ufb01le of the PNGF Sud \ufb01eld
\nand the size of the reserves, it is expected that expenditure
\non retirement is likely to be after more than ten years. The
\ncurrent bases for the provision are a discount rate of 6.5
\nper cent (2021: 6.5 per cent) and an in\ufb02ation rate of 1.6 per
\ncent (2021: 1.6 per cent). The initial decommissioning liability
\n(ARO) study was prepared internally by the operator Perenco
\nand was presented to ARO committee in 2018. The company
\nreassessed the applicable discount rate during 2022 based
\non the rates of government bonds issued in the Congo during
\nthe year. The impact of the change in discount factor was not
\nconsidered material.
\nWith the acquisition of the Panoro interest in the OML 113
\nventure, PetroNor added a decommissioning provision of USD
\n3.7million. The acquired OML113 assets are discounted at 2.50
\nper cent with an in\ufb02ation rate of 2.0 per cent.
\nThe following table presents a reconciliation of the beginning
\nand ending aggregate amounts of the obligations associated
\nwith the retirement of oil and natural gas properties:
\nAmounts in USD thousand
Note
2022
2021
\nAt 1 January
16,302
15,307
\nArising during the year
3,768
-
\nUnwinding of discount on decommissioning
9
842
995
\nAt 31 December
20,912
16,302",
"dimensions": {
"concept": "ifrs-full:DisclosureOfProvisionsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8336": {
"value": "Note 22 Deferred tax liabilities
\nAmounts in USD thousand
\nProperty, plant, and equipment,
\nand intangible assets
Total
\nDeferred tax liabilities
(9,031)
(9,031)
\nNet asset/(liability) at 31 December 2022
(9,031)
(9,031)
\nAmounts in USD thousand
\nProperty, plant, and equipment,
\nand intangible assets
Total
\nDeferred tax liabilities
-
-
\nNet asset/(liability) at 31 December 2021
-
-
\nChanges in net deferred tax liabilities during the year were as follows:
\nAmounts in USD thousand
2022
2021
\nNet deferred tax liability at 1 January
-
-
\nAcquisitions and disposals
(9,031)
-
\nNet deferred tax liability at 31 December
(9,031)
-
\nDeferred tax assets have not been brought to account in
\nrespect of tax losses and unrecognised capital allowances
\nbecause as at 31 December 2022 it is uncertain when future
\ntaxable amounts will be available to utilise those temporary
\ndi\ufb00erences and losses. As at 31 December 2022, the carried
\nforward gross tax loss is USD 132 million (2021: USD 116
\nmillion). Tax losses carried forward has increased by USD 16
\nmillion year on year, this is predominantly due to tax losses
\nincurred in Norway (USD 10 million), United Kingdom (USD 1.3
\nmillion), Sweden (USD 1.1 million), other entities (3.6 million).
\nCarried forward losses from previous periods do not have
\nan expiry date. The deferred tax liability has arisen upon fair
\nvalue adjustments as part of a business combination (refer to
\nnote 26 for additional detail).",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8388": {
"value": "Note 23 Share capital
\nOrdinary shares participate in dividends and the proceeds on
\nwinding up of the company in proportion to the number of
\nshares held and in proportion to the amount paid up on the
\nshares held.
\nAt shareholders\u2019 meetings, each ordinary share entitles the
\nholder to one vote in proportion to the paid-up amount of the
\nshare when a poll is called, otherwise each shareholder has
\none vote on a show of hands.
\nReconciliation of movement in shares on issue
\nNumber of fully paid ordinary shares
2022
2021
\nBalance at the beginning of the year
1,326,991,006
971,665,288
\nIssue of shares
96,577,537
355,325,718
\nBalance at 31 December
1,423,568,543
1,326,991,006
\n
Reconciliation of movements in issued capital
\nAmounts in USD thousand
2022
2021
\nOpening balance
62,115
17,735
\nReversal of shares as part of redomicile
\n1
\n(62,115)
-
\nIssue of shares in PetroNor E&P ASA as part of redomicile
\n1
\n149
-
\nShare capital issued as consideration for business combination
\n2
\n10
-
\nIssue of ordinary shares
-
45,943
\nShare issue costs
-
(1,563)
\nBalance at end of the period
159
62,115
\n1)
On 24 February 2022, the company issued 1,326,991,006 ordinary shares as part of the implementation of the scheme of arrangement and redomicile from
\nAustralia to Norway. Shares are issued at the nominal value of 0.001 NOK and translated to 0.01 USD using the rate of exchange on the day of issue.
\n2)
On 13 July 2022, PetroNor E&P ASA completed the acquisition of Pan-Petroleum Nigeria Holding BV and Pan-Petroleum Services Holdings BV that hold 100
\nper cent of the shares in Pan-Petroleum AJE Ltd. The upfront consideration was USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor
\nshares. The shares were issued at the nominal value of 0.001 NOK USD using the daily exchange rate published by the Bank of England. Refer to note 26 for
\nadditional information.
\nShare premium
\nShare premium reserve represents excess of subscription
\nvalue of the shares over the nominal amount.
\nAmounts in USD thousand
2022
2021
\nOpening balance
-
-
\nIssue of shares as part of redomicile
61,966
-
\nShare capital issued as consideration for business combination
9,990
-
\nBalance at end of the period
71,956
-
\nThe issued share capital for PetroNor E&P Ltd (Australia)
\nformerly the parent entity in 2021 is adjusted downwards to
\nre\ufb02ect historic fair value adjustments on two reverse takeover
\nevents so as to re\ufb02ect group share capital. The like for like share
\nexchange and relisting on the Oslo B\u00f8rs is a continuation of
\nthe business and so group share capital remains unchanged
\nfollowing the issue of 1,326,991,006 shares.
\nCAPITAL MANAGEMENT
\nThe management controls the capital of the company in order
\nto maximise the return to shareholders and ensure that the
\ncompany can fund its operations and continue as a going
\nconcern. Capital is de\ufb01ned as issued share capital.
\nThe management e\ufb00ectively manages the company\u2019s capital
\nby assessing the company\u2019s \ufb01nancial risks and adjusting its
\ncapital structure in response to changes in these risks and
\nin the market. These responses include the management of
\nexpenditure and debt levels, distributions to shareholders and
\nshare and option issues. There have been no changes in the
\nstrategy adopted by the management to control the capital of
\nthe company since the prior reporting period.
\nThe management monitors capital requirements through cash
\n\ufb02ow forecasting. The management may seek further capital if
\nrequired through the issue of capital or changes in the capital
\nstructure. To maintain the listing on the Oslo B\u00f8rs, PetroNor
\nmust continue to satisfy requirements on capital set by the
\nExchange. These requirements include a free \ufb02oat in excess of
\n25 per cent and a minimum number of shareholders. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8493": {
"value": "CAPITAL MANAGEMENT The management controls the capital of the company in order
\nto maximise the return to shareholders and ensure that the
\ncompany can fund its operations and continue as a going
\nconcern. Capital is de\ufb01ned as issued share capital.
\nThe management e\ufb00ectively manages the company\u2019s capital
\nby assessing the company\u2019s \ufb01nancial risks and adjusting its
\ncapital structure in response to changes in these risks and
\nin the market. These responses include the management of
\nexpenditure and debt levels, distributions to shareholders and
\nshare and option issues. There have been no changes in the
\nstrategy adopted by the management to control the capital of
\nthe company since the prior reporting period.
\nThe management monitors capital requirements through cash
\n\ufb02ow forecasting. The management may seek further capital if
\nrequired through the issue of capital or changes in the capital
\nstructure. To maintain the listing on the Oslo B\u00f8rs, PetroNor
\nmust continue to satisfy requirements on capital set by the
\nExchange. These requirements include a free \ufb02oat in excess of
25 per cent and a minimum number of shareholders. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8517": {
"value": "Note 24 Reserves
\nThe movement in reserves are re\ufb02ected in the statement of
\nchanges in equity.
\nForeign currency translation reserve
\nThe foreign currency translation reserve is used to recognise
\nforeign currency exchange di\ufb00erences arising on translation of
\nfunctional currency to presentation currency.
\nRetained earnings
\nAll other net gains and losses and transactions with owners
\nnot recognised elsewhere.
\nDividends
\nNo dividends were declared during the year by the parent
\ncompany.
\n24A.
OPTIONS
\nHolders of options do not have any voting or dividend rights
\nin relation to the options. Share options are valued using
\nthe stochastic Black-Scholes model. The inputs to the model
\nare the weighted average share price, the expected average
\nexercise price, expected life, the risk free rate of return and the
\nexpected volatility. All options are fully vested and so no costs
\nwere charged in the current accounting period (2021 nil).
\n
The following table reconciles the outstanding share options
\ngranted, exercised, and forfeited during the year:
\n2022
2021
\nNumber of
\noptions
\nWeighted average
\nexercise price
\nequivalent USD
\nNumber of
\noptions
\nWeighted average
\nexercise price
\nequivalent USD
\nBalance at beginning of the period
1,389,470
0.79
1,389,470
0.81
\nLapsed
(1,389,470)
0.79
-
-
\nBalance at end of the year
-
-
1,389,470
0.79
\nExercisable at end of the year
-
-
1,389,470
0.79
\nAs at 31 December 2022, all share options have expired.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8523": {
"value": "Foreign currency translation reserve The foreign currency translation reserve is used to recognise
\nforeign currency exchange di\ufb00erences arising on translation of
\nfunctional currency to presentation currency.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEffectOfChangesInForeignExchangeRatesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8533": {
"value": "Dividends No dividends were declared during the year by the parent
\ncompany.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDividendsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8603": {
"value": "Note 25 Related party transactions
\n25A.
SUBSIDIARIES
\nThe principal subsidiaries of the PetroNor E&P ASA, all of
\nwhich have been included in these consolidated \ufb01nancial
\nstatements, are as follows:
\nProportion of e\ufb00ective ownership
\ninterest at 31 December
\nName
\nCountry of
\nincorporation
\nPrincipal place
\nof business
2022
2021
\nPetroNor E&P Pty Limited
\n(Previously called PetroNor E&P Ltd)
Australia
Australia
100%
100%
\nPetroNor E&P Ltd
Cyprus
Cyprus
100%
100%
\nPetroNor E&P Services AS
Norway
Norway
100%
100%
\nPetroNor E&P Services Ltd
United Kingdom
United Kingdom
100%
100%
\nPetroNor E&P AB
Sweden
Guinea-Bissau
100%
100%
\nPetroNor E&P Ltd
Nigeria
Nigeria
100%
100%
\nPetroNor E&P Gambia Ltd
Cayman Islands
The Gambia
100%
100%
\nHemla Africa Holding AS
Norway
Norway
100%
100%
\nHemla E&P Congo SA
Congo
Congo
84.15%
84.15%
\nAfrican Petroleum Corporation Ltd
Cayman Islands
United Kingdom
100%
100%
\nAfrican Petroleum Senegal Ltd
Cayman Islands
Senegal
90%
90%
\nAfrican Petroleum Senegal SAU
Senegal
Senegal
90%
90%
\nAje Production AS
Norway
Norway
100%
100%
\nAje Services Holding BV (Previously called
\nPan-Petroleum Services Holding BV)
Netherlands
Netherlands
100%
-
\nAje Nigeria Holding BV (Previously called
\nPan-Petroleum Services Holding BV)
Netherlands
Netherlands
100%
-
\nAje Production Ltd (Previously called
\nPan-Petroleum Aje Ltd)
Nigeria
Nigeria
100%
-
\nMaterial non-controlling interests
\nSet out below is summarised \ufb01nancial information for the
\nsubsidiary that has non-controlling interests that are material
\nto the group. The amounts disclosed for the subsidiary are
\nbefore inter-company eliminations.
\n
Summarised statement of \ufb01nancial position
\nHemla E&P Congo SA
\nAmounts in USD thousand
2022
2021
\nCurrent asset
28,363
37,936
\nCurrent liabilities
11,210
31,130
\nCurrent net assets
17,153
6,806
\nNon-current assets
98,876
69,577
\nNon-current liabilities
20,804
16,302
\nNon-current net assets/(liabilities)
78,072
53,275
\nNet assets
95,225
60,081
\nAccumulated NCI
16,091
10,215
\nSummarised statement of comprehensive income
\nHemla E&P Congo SA
\nAmounts in USD thousand
2022
2021
\nRevenue
146,067
106,464
\nPro\ufb01t for the period
45,503
31,685
\nOther comprehensive income
-
-
\nTotal comprehensive income for the year
45,503
31,685
\nPro\ufb01t allocated to NCI
7,461
8,714
\nDividends paid to NCI
1,585
-
\nSummarised cash \ufb02ows
\nHemla E&P Congo SA
\nAmounts in USD thousand
2022
2021
\nCash \ufb02ows from operating activities
41,847
39,360
\nCash \ufb02ows from investing activities
(38,349)
(25,331)
\nCash \ufb02ows from \ufb01nancing activities
(10,028)
(6,047)
\nNet (decrease)/increase in cash and cash equivalents
(6,530)
8,312
\n25B.
BOARD AND KEY MANAGEMENT PERSONNEL
\nREMUNERATION
\nKey management personnel are those persons having
\nauthority and responsibility for planning, directing, and
\ncontrolling the activities of the group, including the directors
\nlisted on page 47, and the following other key personnel:
\nJens Pace
Interim chief executive o\ufb03cer
\nClaus Frimann-Dahl
Chief technical o\ufb03cer
\nEmad Sultan
Strategy and contracts manager
\nMichael Barrett
Exploration manager
\nChris Butler
Group \ufb01nancial controller
\n
As at the approval date of this report the base salary and fees
\nfor the following members of key management is as follows:
\nIndividual
Title
Group entity
\nBase salary and fees
\n/per annum
\nTotal base salary and
\nfees USD equivalent
\nE Alhomouz
Chair
\nPetroNor E&P Services AS
\n1
\nUSD 174,000
\n294,000
\nHemla E&P Congo SA
USD 120,000
\nJ Iskander
Director
\n2
\nNil
Nil
\nI Tybring-Gjedde
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nG Kielland
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nJ Norman-Hansen
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nA Fawzi
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nJ Pace
Interim CEO
PetroNor E&P Services AS
GBP 360,000
443,000
\nE Sultan
Strategy & contracts manager
PetroNor E&P Services AS
USD 240,000
240,000
\nC Frimann-Dahl
Chief technical o\ufb03cer
PetroNor E&P Services AS
NOK 2,500,000
253,000
\nM Barrett
Exploration o\ufb03cer
PetroNor E&P Services Ltd
GBP 215,000
264,000
\nC Butler
Group \ufb01nancial controller
\nPetroNor E&P Services Ltd
GBP 140,000
\n238,000
\nHemla E&P Congo SA
USD 66,000
\n1)
Fees are charged by related party Petromal LLC and are not paid to the individual; above \ufb01gures represent the company\u2019s fair value estimate of associated
\ncosts for the individual\u2019s services.
\n2)
J Iskander elected not to be remunerated, as he is not considered an independent director due to connections to the largest company shareholder.
\nFX rates used:
NOK 1.00 : USD 0.1038
|
GBP 1.00 : USD 1.23
\nRemuneration of board and key management 2022
\nAmounts in USD
Designation
\nSalary and
\nfees
Bonus
\nOther cash
\nbene\ufb01ts
\nPost-employment
\nbene\ufb01ts
Total
\nE Alhomouz
\n1
\nChair
294,000
-
-
-
294,000
\nJ Iskander
Director
-
-
-
-
-
\nI Smines Tybring
\nGjedde
Director
34,598
-
-
-
34,598
\nG Kielland
Director
34,598
-
-
-
34,598
\nA Neuling
\n2
\nDirector
5,728
-
-
-
5,728
\nR Steinepreis
\n2
\nDirector
5,728
-
-
-
5,728
\nJ Pace
Interim CEO
443,500
-
-
-
443,500
\nC Frimann-Dahl
Chief technical o\ufb03cer
253,080
-
769
20,524
274,373
\nM Barrett
Exploration o\ufb03cer
279,445
-
884
2,080
282,409
\nC Butler
Group \ufb01nancial controller
173,059
92,177
5,747
17,306
288,289
\nE Sultan
Strategy & contracts manager
233,000
-
-
-
233,000
\nA Hicks
\n2
\nCompany secretary
3,598
-
-
-
3,598
\nTotal
1,760,334
92,177
7,400
39,910
1,899,821
\n1)
USD 174,000 of the fees above is not paid to the individual, these fees charged on an arms-length basis are included in a monthly lump sum charged by
\nrelated party Petromal LLC, above \ufb01gures represent the company\u2019s fair value estimate of associated costs for the individual\u2019s services.
\n2)
Indviduals are directors or management of the previous Australian top company, the above \ufb01gure represents their remuneration up until the group
\nrestructure on 24 February 2022.
\n
Remuneration of of board and key management 2021
\nAmounts in USD
Designation
\nSalary and
\nfees
Bonus
\nOther cash
\nbene\ufb01ts
\nPost-
\nemployment
\nbene\ufb01ts
Total
\nE Alhomouz
\n1
\nChair
294,000
-
-
-
294,000
\nJ Iskander
Director
-
-
-
-
-
\nJens Pace
\n2
\nDirector & Interim CEO
47,909
-
-
-
47,909
\nI Smines Tybring Gjedde
Director
38,001
-
-
-
38,001
\nG Kielland
\n3
\nDirector
25,994
-
-
-
25,994
\nA Neuling
Director
26,787
-
-
-
26,787
\nR Steinepreis
Director
32,546
-
-
-
32,546
\nG Ludvigsen
\n4
\nDirector & business development manager
385,210
-
110
-
385,320
\nK S\u00f8vold
\n5
\nExec director & CEO
354,118
-
821
21,721
376,659
\nC Frimann-Dahl
Chief technical o\ufb03cer
221,648
-
780
20,732
243,160
\nM Barrett
Exploration o\ufb03cer
296,475
-
2,598
-
299,073
\nC Butler
Group \ufb01nancial controller
174,825
-
3,724
17,483
196,032
\nE Sultan
Strategy & contracts manager
\n3
\n168,000
-
-
-
168,000
\nA Hicks
Company secretary
27,035
-
-
-
27,035
\nTOTAL
2,092,548
-
8,033
59,935
2,160,516
\n1)
USD 174,000 of salary and fees is not paid to the individual, these fees charged on an arms-length basis are included in a monthly lump sum charged by
\nrelated party Petromal LLC, above \ufb01gures represent the company\u2019s fair value estimate of associated costs for the individual\u2019s services.
\n2)
On 16 December 2021, Mr Pace was appointed as interim CEO and subsequently resigned as a board member.
\n3)
Appointed 1 February 2021
\n4)
Following his resignation as a board member on 1 February 2021, G Ludvigsen continued to provide services charged on an arms-length by a related party
\nHagan AS.
\n5) From 16 December 2021, individuals no longer considered key management personnel as decision making responsibilities removed.
\nShare holdings by directors and other key management personnel
\nBalance
\n1 January 2022
\nShares
\npurchased
\nGranted as
\nremuneration
\nNet change
\nother
\nBalance
\n31 December 2022
\nJ Pace
1,498,858
-
-
(33,334)
1,465,524
\nM Barrett
1,151,687
-
-
-
1,151,667
\nC Butler
234,316
-
-
-
234,296
\nC Frimann-Dahl
604,545
-
-
-
604,545
\nTotal
3,498,406
-
-
(33,334)
3,456,072
\nAs at 31 December 2022, Eyas Alhomouz held no shares
\npersonally but holds in\ufb02uence over 481,481,666 shares (2021:
\n481,481,666 shares) as the CEO of signi\ufb01cant shareholder
\nPetromal LLC. 109,520,419 of the shares held by Petromal LLC
\nare recorded in the name of nominee company, Clearstream
\nBanking S.A. on behalf of Petromal LLC.
\nOther directors and key management not included in the
\nabove table held no shares during the current year.
\nNo warrants or options were held by directors or key
\nmanagement personnel during the current year.
\n25C.
SIGNIFICANT SHAREHOLDERS
\nShareholder
Place of incorporation
\nOwnership
\n31 December 2022
\nOwnership
\n31 December 2021
\nPetromal LLC \u2013 Sole Proprietorship LLC
UAE
33.82%
36.28%
\nSymero Ltd
Cyprus
9.75%
10.47%
\nNOR Energy AS
Norway
9.49%
10.45%
\nAmbolt Invest AS
Norway
6.15%
6.61%
\nGulshagen III AS
Norway
3.16%
3.39%
\nGulshagen IV AS
Norway
3.16%
3.39%
\n
Symero Ltd is a company owned by NOR Energy AS, which
\nin turn is controlled jointly by former key management of
\nPetroNor, Knut S\u00f8vold, and Gerhard Ludvigsen.
\nGulshagen III AS and Gulshagen IV AS are also controlled by
\nKnut S\u00f8vold.
\nAmbolt Invest AS is a company controlled by Jarle Norman-
\nHansen who was appointed as a board member on 26 January
\n2023.
\n25D.
TRANSACTIONS AND PERIOD-END BALANCES WITH RELATED PARTIES
\nTransactions with related parties included in the consolidated statement of comprehensive income:
\nAmounts in USD thousand
2022
2021
\nPetromal \u2013 Sole Proprietorship LLC
289
554
\nAdministrative expenses
289
554
\nPetromal LLC is the largest shareholder in the company and
\nsince 2017 has had an agreement to provide technical and
\nproject management services to the PetroNor group.
\nBalances due from and due to related parties disclosed in the consolidated statement of \ufb01nancial position:
\nAmounts in USD thousand
2022
2021
\nOther payable to NOR Energy AS
1,283
2,136
\nOther payable to Petromal \u2013 Sole Proprietorship LLC
736
1,281
\nOther payable to Symero Ltd
-
32
\nTotal payables to related parties (note 19)
2,019
3,449
\nLoan payable Symero Ltd
-
3,912
\nLoan payable to related parties (note 20)
-
3,912
\nAmounts due from / to related parties included in the
\nconsolidated statement of \ufb01nancial position (other than the
\nloans to related parties) are interest-free and have no \ufb01xed
\nrepayment terms. The outstanding payable balances as at 31
\nDecember 2022 were settled during Q1 2023. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8606": {
"value": "25A.
SUBSIDIARIES
\nThe principal subsidiaries of the PetroNor E&P ASA, all of
\nwhich have been included in these consolidated \ufb01nancial
\nstatements, are as follows:
\nProportion of e\ufb00ective ownership
\ninterest at 31 December
\nName
\nCountry of
\nincorporation
\nPrincipal place
\nof business
2022
2021
\nPetroNor E&P Pty Limited
\n(Previously called PetroNor E&P Ltd)
Australia
Australia
100%
100%
\nPetroNor E&P Ltd
Cyprus
Cyprus
100%
100%
\nPetroNor E&P Services AS
Norway
Norway
100%
100%
\nPetroNor E&P Services Ltd
United Kingdom
United Kingdom
100%
100%
\nPetroNor E&P AB
Sweden
Guinea-Bissau
100%
100%
\nPetroNor E&P Ltd
Nigeria
Nigeria
100%
100%
\nPetroNor E&P Gambia Ltd
Cayman Islands
The Gambia
100%
100%
\nHemla Africa Holding AS
Norway
Norway
100%
100%
\nHemla E&P Congo SA
Congo
Congo
84.15%
84.15%
\nAfrican Petroleum Corporation Ltd
Cayman Islands
United Kingdom
100%
100%
\nAfrican Petroleum Senegal Ltd
Cayman Islands
Senegal
90%
90%
\nAfrican Petroleum Senegal SAU
Senegal
Senegal
90%
90%
\nAje Production AS
Norway
Norway
100%
100%
\nAje Services Holding BV (Previously called
\nPan-Petroleum Services Holding BV)
Netherlands
Netherlands
100%
-
\nAje Nigeria Holding BV (Previously called
\nPan-Petroleum Services Holding BV)
Netherlands
Netherlands
100%
-
\nAje Production Ltd (Previously called
\nPan-Petroleum Aje Ltd)
Nigeria
Nigeria
100%
-
Note 26 Acquisition of subsidiaries On 13 July 2022, PetroNor completed the corporate acquisition
\nof both Pan-Petroleum Nigeria Holding BV and Pan-Petroleum
\nServices Holdings BV, who together hold 100 per cent of the
\nshares in Pan-Petroleum AJE Ltd, from Panoro Energy ASA. The
\ntransaction has allowed PetroNor to assume a 6.502 per cent
\nparticipating interest, 16.255 per cent cost bearing interest
\nand economic interest of 12.1913 per cent in O\ufb00shore Mining
\nLicence no.113 (OML113).
\nPan-Petroleum AJE Ltd participates in the exploration and
\nproduction of hydrocarbons in the Aje oil and gas \ufb01eld.
\nUnder IFRS 3 \u2013 Business combinations, an acquirer has a
\nmaximum of twelve months from the date of acquisition
\nto \ufb01nalise the acquisition accounting. The adjustment
\nperiod ends when the acquirer has gathered all necessary
\ninformation, subject to the twelve-month maximum. The
\npurchase price allocation is still subject to \ufb01nalisation pending
\nreceipt of further accounting data from counterparties.
\nThe group has assessed and determined the transaction is a
\nbusiness combination under IFRS 3 \u2013 Business combinations.
\nInformation is respect of the assets and liabilities acquired and
\nthe fair value allocations to the assets is as follows:
ASSETS ACQUIRED
\nAmounts in USD thousand
\nCurrent assets
\nTrade and other receivables
5
\nCash and bank balances
52
\n57
\nNon current assets
\nIntangible assets
34,299
\nProduction assets and equipment
926
\nSum
35,225
\nTotal assets
35,282
\nCurrent liabilities
\nTrade and other payables
(2,745)
\nNon-current liabilities
\nProvisions
(3,768)
\nDeferred tax liability
(9,031)
\nOther payables
(8,738)
\nSum
(21,537)
\nTotal liabilities
(24,282)
\nNet assets
11,000
\nSatis\ufb01ed by:
\nConsideration shares
10,000
\nAssignment fee
1,000
\nTotal
11,000
\nThe assets acquired have been acquired with the intention
\nto redevelop the \ufb01eld. The immediate e\ufb00ect on the income
\nstatement will not be material to the group. In the current
\nperiod post acquisition, the charge to the income statement
\nwas USD 249,000.
\nThe upfront consideration for the transaction was USD 10
\nmillion paid via the allotment and issue of 96,577,537 new
\nPetroNor shares.
The volume of PetroNor shares has been
\ndetermined with reference to the contractually determined
\n30-day volume weighted average price (\u201cVWAP\u201d) of PetroNor
\nshares listed on the Oslo B\u00f8rs. The calculation was based on
\n30 business trading days between 2 May 2022 and 8 July 2022.
\nAn additional consideration of USD 0.10 per 1,000 cubic feet
\nof the AJE Natural Gas Sales Volume is to be paid to Panoro
\nEnergy ASA once the conditions stipulated within the SPA are
\nmet. This conditional consideration shall not exceed USD 16.67
\nmillion.
\nNon-cash adjustment
\nThe consolidated statement of cash \ufb02ows includes a non-
\ncash adjustment for the corporate transaction to acquire the
\ninterest in OML 113. The acquisition of the subsidiaries has
\nnot resulted in cash \ufb02ows and therefore the statement of cash
\n\ufb02ows has been adjusted as follows:
\nFor the year ended 31 December 2022:
\nAmounts in USD thousand
\nPurchases of property, plant, and equipment
925
\nIntangible assets
33,299
\nTrade and other payables
(2,630)
\nOther non-current payables
(8,738)
\nProvisions
(3,769)
\nDeferred tax liability
(9,031)
\nIssue of share capital
(10,052)
\nThe goodwill recognised in the transaction of USD 9 million
\nis classi\ufb01ed as technical goodwill due to the requirement
\nto recognise deferred taxes for the temporary di\ufb00erences
\nbetween the assigned values and the tax bases of assets
\nacquired and liabilities assumed in a business combination.
\nA provision has been made in accordance with IAS 12 for
\ndeferred tax corresponding to the tax rate (50 per cent tax
\noil) multiplied by the di\ufb00erence between the fair values of the
\nacquired assets and the transferred tax depreciation basis.
\nThe o\ufb00setting entry to this deferred tax is technical goodwill.
\nThis goodwill is not deductible for tax purposes.
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8706": {
"value": "Material non-controlling interests Set out below is summarised \ufb01nancial information for the
\nsubsidiary that has non-controlling interests that are material
\nto the group. The amounts disclosed for the subsidiary are
\nbefore inter-company eliminations.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfNoncontrollingInterestsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f8802": {
"value": "25B. BOARD AND KEY MANAGEMENT PERSONNEL
\nREMUNERATION
\nKey management personnel are those persons having
\nauthority and responsibility for planning, directing, and
\ncontrolling the activities of the group, including the directors
\nlisted on page 47, and the following other key personnel:
\nJens Pace
Interim chief executive o\ufb03cer
\nClaus Frimann-Dahl
Chief technical o\ufb03cer
\nEmad Sultan
Strategy and contracts manager
\nMichael Barrett
Exploration manager
\nChris Butler
Group \ufb01nancial controller
\n
As at the approval date of this report the base salary and fees
\nfor the following members of key management is as follows:
\nIndividual
Title
Group entity
\nBase salary and fees
\n/per annum
\nTotal base salary and
\nfees USD equivalent
\nE Alhomouz
Chair
\nPetroNor E&P Services AS
\n1
\nUSD 174,000
\n294,000
\nHemla E&P Congo SA
USD 120,000
\nJ Iskander
Director
\n2
\nNil
Nil
\nI Tybring-Gjedde
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nG Kielland
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nJ Norman-Hansen
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nA Fawzi
Director
PetroNor E&P Services AS
NOK 250,000
26,000
\nJ Pace
Interim CEO
PetroNor E&P Services AS
GBP 360,000
443,000
\nE Sultan
Strategy & contracts manager
PetroNor E&P Services AS
USD 240,000
240,000
\nC Frimann-Dahl
Chief technical o\ufb03cer
PetroNor E&P Services AS
NOK 2,500,000
253,000
\nM Barrett
Exploration o\ufb03cer
PetroNor E&P Services Ltd
GBP 215,000
264,000
\nC Butler
Group \ufb01nancial controller
\nPetroNor E&P Services Ltd
GBP 140,000
\n238,000
\nHemla E&P Congo SA
USD 66,000
\n1)
Fees are charged by related party Petromal LLC and are not paid to the individual; above \ufb01gures represent the company\u2019s fair value estimate of associated
\ncosts for the individual\u2019s services.
\n2)
J Iskander elected not to be remunerated, as he is not considered an independent director due to connections to the largest company shareholder.
\nFX rates used:
NOK 1.00 : USD 0.1038
|
GBP 1.00 : USD 1.23
\nRemuneration of board and key management 2022
\nAmounts in USD
Designation
\nSalary and
\nfees
Bonus
\nOther cash
\nbene\ufb01ts
\nPost-employment
\nbene\ufb01ts
Total
\nE Alhomouz
\n1
\nChair
294,000
-
-
-
294,000
\nJ Iskander
Director
-
-
-
-
-
\nI Smines Tybring
\nGjedde
Director
34,598
-
-
-
34,598
\nG Kielland
Director
34,598
-
-
-
34,598
\nA Neuling
\n2
\nDirector
5,728
-
-
-
5,728
\nR Steinepreis
\n2
\nDirector
5,728
-
-
-
5,728
\nJ Pace
Interim CEO
443,500
-
-
-
443,500
\nC Frimann-Dahl
Chief technical o\ufb03cer
253,080
-
769
20,524
274,373
\nM Barrett
Exploration o\ufb03cer
279,445
-
884
2,080
282,409
\nC Butler
Group \ufb01nancial controller
173,059
92,177
5,747
17,306
288,289
\nE Sultan
Strategy & contracts manager
233,000
-
-
-
233,000
\nA Hicks
\n2
\nCompany secretary
3,598
-
-
-
3,598
\nTotal
1,760,334
92,177
7,400
39,910
1,899,821
\n1)
USD 174,000 of the fees above is not paid to the individual, these fees charged on an arms-length basis are included in a monthly lump sum charged by
\nrelated party Petromal LLC, above \ufb01gures represent the company\u2019s fair value estimate of associated costs for the individual\u2019s services.
\n2)
Indviduals are directors or management of the previous Australian top company, the above \ufb01gure represents their remuneration up until the group
\nrestructure on 24 February 2022.
\n
Remuneration of of board and key management 2021
\nAmounts in USD
Designation
\nSalary and
\nfees
Bonus
\nOther cash
\nbene\ufb01ts
\nPost-
\nemployment
\nbene\ufb01ts
Total
\nE Alhomouz
\n1
\nChair
294,000
-
-
-
294,000
\nJ Iskander
Director
-
-
-
-
-
\nJens Pace
\n2
\nDirector & Interim CEO
47,909
-
-
-
47,909
\nI Smines Tybring Gjedde
Director
38,001
-
-
-
38,001
\nG Kielland
\n3
\nDirector
25,994
-
-
-
25,994
\nA Neuling
Director
26,787
-
-
-
26,787
\nR Steinepreis
Director
32,546
-
-
-
32,546
\nG Ludvigsen
\n4
\nDirector & business development manager
385,210
-
110
-
385,320
\nK S\u00f8vold
\n5
\nExec director & CEO
354,118
-
821
21,721
376,659
\nC Frimann-Dahl
Chief technical o\ufb03cer
221,648
-
780
20,732
243,160
\nM Barrett
Exploration o\ufb03cer
296,475
-
2,598
-
299,073
\nC Butler
Group \ufb01nancial controller
174,825
-
3,724
17,483
196,032
\nE Sultan
Strategy & contracts manager
\n3
\n168,000
-
-
-
168,000
\nA Hicks
Company secretary
27,035
-
-
-
27,035
\nTOTAL
2,092,548
-
8,033
59,935
2,160,516
\n1)
USD 174,000 of salary and fees is not paid to the individual, these fees charged on an arms-length basis are included in a monthly lump sum charged by
\nrelated party Petromal LLC, above \ufb01gures represent the company\u2019s fair value estimate of associated costs for the individual\u2019s services.
\n2)
On 16 December 2021, Mr Pace was appointed as interim CEO and subsequently resigned as a board member.
\n3)
Appointed 1 February 2021
\n4)
Following his resignation as a board member on 1 February 2021, G Ludvigsen continued to provide services charged on an arms-length by a related party
\nHagan AS.
\n5) From 16 December 2021, individuals no longer considered key management personnel as decision making responsibilities removed.
\nShare holdings by directors and other key management personnel
\nBalance
\n1 January 2022
\nShares
\npurchased
\nGranted as
\nremuneration
\nNet change
\nother
\nBalance
\n31 December 2022
\nJ Pace
1,498,858
-
-
(33,334)
1,465,524
\nM Barrett
1,151,687
-
-
-
1,151,667
\nC Butler
234,316
-
-
-
234,296
\nC Frimann-Dahl
604,545
-
-
-
604,545
\nTotal
3,498,406
-
-
(33,334)
3,456,072
\nAs at 31 December 2022, Eyas Alhomouz held no shares
\npersonally but holds in\ufb02uence over 481,481,666 shares (2021:
\n481,481,666 shares) as the CEO of signi\ufb01cant shareholder
\nPetromal LLC. 109,520,419 of the shares held by Petromal LLC
\nare recorded in the name of nominee company, Clearstream
\nBanking S.A. on behalf of Petromal LLC.
\nOther directors and key management not included in the
\nabove table held no shares during the current year.
\nNo warrants or options were held by directors or key
\nmanagement personnel during the current year. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f9297": {
"value": "25D. TRANSACTIONS AND PERIOD-END BALANCES WITH RELATED PARTIES
\nTransactions with related parties included in the consolidated statement of comprehensive income:
\nAmounts in USD thousand
2022
2021
\nPetromal \u2013 Sole Proprietorship LLC
289
554
\nAdministrative expenses
289
554
\nPetromal LLC is the largest shareholder in the company and
\nsince 2017 has had an agreement to provide technical and
\nproject management services to the PetroNor group.
\nBalances due from and due to related parties disclosed in the consolidated statement of \ufb01nancial position:
\nAmounts in USD thousand
2022
2021
\nOther payable to NOR Energy AS
1,283
2,136
\nOther payable to Petromal \u2013 Sole Proprietorship LLC
736
1,281
\nOther payable to Symero Ltd
-
32
\nTotal payables to related parties (note 19)
2,019
3,449
\nLoan payable Symero Ltd
-
3,912
\nLoan payable to related parties (note 20)
-
3,912
\nAmounts due from / to related parties included in the
\nconsolidated statement of \ufb01nancial position (other than the
\nloans to related parties) are interest-free and have no \ufb01xed
\nrepayment terms. The outstanding payable balances as at 31
December 2022 were settled during Q1 2023. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForTransactionsWithRelatedPartiesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f9343": {
"value": "Note 26 Acquisition of subsidiaries
\nOn 13 July 2022, PetroNor completed the corporate acquisition
\nof both Pan-Petroleum Nigeria Holding BV and Pan-Petroleum
\nServices Holdings BV, who together hold 100 per cent of the
\nshares in Pan-Petroleum AJE Ltd, from Panoro Energy ASA. The
\ntransaction has allowed PetroNor to assume a 6.502 per cent
\nparticipating interest, 16.255 per cent cost bearing interest
\nand economic interest of 12.1913 per cent in O\ufb00shore Mining
\nLicence no.113 (OML113).
\nPan-Petroleum AJE Ltd participates in the exploration and
\nproduction of hydrocarbons in the Aje oil and gas \ufb01eld.
\nUnder IFRS 3 \u2013 Business combinations, an acquirer has a
\nmaximum of twelve months from the date of acquisition
\nto \ufb01nalise the acquisition accounting. The adjustment
\nperiod ends when the acquirer has gathered all necessary
\ninformation, subject to the twelve-month maximum. The
\npurchase price allocation is still subject to \ufb01nalisation pending
\nreceipt of further accounting data from counterparties.
\nThe group has assessed and determined the transaction is a
\nbusiness combination under IFRS 3 \u2013 Business combinations.
\nInformation is respect of the assets and liabilities acquired and
\nthe fair value allocations to the assets is as follows:
\n
ASSETS ACQUIRED
\nAmounts in USD thousand
\nCurrent assets
\nTrade and other receivables
5
\nCash and bank balances
52
\n57
\nNon current assets
\nIntangible assets
34,299
\nProduction assets and equipment
926
\nSum
35,225
\nTotal assets
35,282
\nCurrent liabilities
\nTrade and other payables
(2,745)
\nNon-current liabilities
\nProvisions
(3,768)
\nDeferred tax liability
(9,031)
\nOther payables
(8,738)
\nSum
(21,537)
\nTotal liabilities
(24,282)
\nNet assets
11,000
\nSatis\ufb01ed by:
\nConsideration shares
10,000
\nAssignment fee
1,000
\nTotal
11,000
\nThe assets acquired have been acquired with the intention
\nto redevelop the \ufb01eld. The immediate e\ufb00ect on the income
\nstatement will not be material to the group. In the current
\nperiod post acquisition, the charge to the income statement
\nwas USD 249,000.
\nThe upfront consideration for the transaction was USD 10
\nmillion paid via the allotment and issue of 96,577,537 new
\nPetroNor shares.
The volume of PetroNor shares has been
\ndetermined with reference to the contractually determined
\n30-day volume weighted average price (\u201cVWAP\u201d) of PetroNor
\nshares listed on the Oslo B\u00f8rs. The calculation was based on
\n30 business trading days between 2 May 2022 and 8 July 2022.
\nAn additional consideration of USD 0.10 per 1,000 cubic feet
\nof the AJE Natural Gas Sales Volume is to be paid to Panoro
\nEnergy ASA once the conditions stipulated within the SPA are
\nmet. This conditional consideration shall not exceed USD 16.67
\nmillion.
\nNon-cash adjustment
\nThe consolidated statement of cash \ufb02ows includes a non-
\ncash adjustment for the corporate transaction to acquire the
\ninterest in OML 113. The acquisition of the subsidiaries has
\nnot resulted in cash \ufb02ows and therefore the statement of cash
\n\ufb02ows has been adjusted as follows:
\nFor the year ended 31 December 2022:
\nAmounts in USD thousand
\nPurchases of property, plant, and equipment
925
\nIntangible assets
33,299
\nTrade and other payables
(2,630)
\nOther non-current payables
(8,738)
\nProvisions
(3,769)
\nDeferred tax liability
(9,031)
\nIssue of share capital
(10,052)
\nThe goodwill recognised in the transaction of USD 9 million
\nis classi\ufb01ed as technical goodwill due to the requirement
\nto recognise deferred taxes for the temporary di\ufb00erences
\nbetween the assigned values and the tax bases of assets
\nacquired and liabilities assumed in a business combination.
\nA provision has been made in accordance with IAS 12 for
\ndeferred tax corresponding to the tax rate (50 per cent tax
\noil) multiplied by the di\ufb00erence between the fair values of the
\nacquired assets and the transferred tax depreciation basis.
\nThe o\ufb00setting entry to this deferred tax is technical goodwill.
\nThis goodwill is not deductible for tax purposes.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f9500": {
"value": "Note 27 Risk management
\nThe group\u2019s principal \ufb01nancial liabilities comprise accounts
\npayable and amounts due to related parties. The main
\npurpose of these \ufb01nancial instruments is to manage short-
\nterm cash \ufb02ow and raise \ufb01nance for the group\u2019s capital
\nexpenditure program. The group has various \ufb01nancial assets
\nsuch as accounts receivable and cash.
\nIt is, and has been throughout the year ending 31 December
\n2022, the group\u2019s policy that no speculative trading in
\nderivatives shall be undertaken.
\nThe main risks that could adversely a\ufb00ect the group\u2019s
\n\ufb01nancial assets, liabilities or future cash \ufb02ows are credit risk,
\nliquidity risk, interest rate risk and foreign currency risk. The
\nmanagement reviews and agrees policies for managing each of
\nthese risks which are summarised below.
\nThe following discussion also includes a sensitivity analysis
\nthat is intended to illustrate the sensitivity to changes in the
\nmarket variables on the group\u2019s \ufb01nancial instruments and
\nshows the impact on pro\ufb01t or loss and shareholders\u2019 equity,
\nwhere applicable. Financial instruments a\ufb00ected by market
\nrisk include accounts receivable, accounts payable and
\naccrued liabilities.
\nThe sensitivity has been prepared for periods ending 31
\nDecember 2022 using the amounts of debt and other \ufb01nancial
\nassets and liabilities held as at those reporting dates.
\nCREDIT RISK
\nCredit risk refers to the risk that a counterparty will default
\non its contractual obligations resulting in \ufb01nancial loss to
\nthe group. As at 31 December 2022, the group\u2019s maximum
\nexposure to credit risk without taking into account any
\ncollateral held or other credit enhancements, which will cause
\na \ufb01nancial loss to the group due to failure to discharge an
\nobligation by the counterparties and \ufb01nancial guarantees
\nprovided by the group arises from the carrying amount of
\nthe respective recognised \ufb01nancial assets as stated in the
\nstatement of \ufb01nancial position.
\nTo minimise credit risk, the group has tasked its management
\nto develop and maintain the group\u2019s credit risk gradings
\nto categorise exposures according to their degree of risk
\nof default. The credit rating information is supplied by
\nindependent rating agencies where available and, if not
\navailable, the management uses other publicly available
\n\ufb01nancial information and the group\u2019s own trading records
\nto rate its major customers and other debtors. The group\u2019s
\nexposure and the credit ratings of its counterparties
\nare continuously monitored, and the aggregate value
\nof transactions concluded is spread amongst approved
\ncounterparties.
\nThe company\u2019s current credit risk grading framework
\ncomprises the following categories:
\nCategory
Description
Basis for recognising expected credit losses
\nPerforming
The counterparty has a low risk of default and does
\nnot have any past-due amounts
\n12-month ECL
\nDoubtful
Amount is >30 days past due or there has been a
\nsigni\ufb01cant increase in credit risk since initial recognition
\nLifetime ECL \u2013 not credit-impaired
\nIn default
Amount is >90 days past due or there is evidence
\nindicating the asset is credit-impaired
\nLifetime ECL \u2013 credit-impaired
\nWrite-o\ufb00
There is evidence indicating that the debtor is in
\nsevere \ufb01nancial di\ufb03culty and the company has no
\nrealistic prospect of recovery
\nAmount is written o\ufb00
\nThe group\u2019s principal customers are substantial oil and gas
\ncompanies and as such credit risk is considered to be low.
\nThere is no history of credit loss, non-payment or default. The
\nrisk on liquid funds is limited because the counterparties are
\nbanks with high credit ratings. The asset retirement obligation
\ncash is held in an Escrow bank account managed by the
\noperator.
\n
The tables below detail the credit quality of the company\u2019s
\n\ufb01nancial assets as well as the company\u2019s maximum exposure
\nto credit risk by credit risk rating grades.
\nAmounts in USD thousand
Note
\nExternal
\ncredit
\nrating
\nInternal
\ncredit
\nrating
\n12-month or
\nlifetime ECL
\nGross
\ncarrying
\namount
\nLoss
\nallowance
\nNet
\ncarrying
\namount
\n31 December 2022
\nTrade receivables
13
N/a
(i)
Lifetime ECL
1,174
-
1,174
\nDue from related parties
13, 25D
N/a
-
Lifetime ECL
-
-
-
\nAdvance against decommissioning cost
13
N/a
-
Lifetime ECL
29,432
-
29,432
\nCash and cash equivalents
14
Aa3/B
N/a
12-month ECL
24,816
-
24,816
\n31 December 2021
\nTrade receivables
13
N/a
(i)
Lifetime ECL
13,431
-
13,431
\nDue from related parties
13, 25D
N/a
-
Lifetime ECL
-
-
-
\nAdvance against decommissioning cost
13
N/a
-
Lifetime ECL
26,837
-
26,837
\nCash and cash equivalents
14
Aa3/B
N/a
12-month ECL
31,755
-
31,755
\n(i) For trade receivables and amounts due from related parties, the group has applied the simpli\ufb01ed approach in IFRS 9 to measure the loss allowance at
\nlifetime ECL. The expected credit losses are estimated using a provision matrix by reference to past default experience of the debtor and an analysis of the
\ndebtor\u2019s current \ufb01nancial position, adjusted for factors that are speci\ufb01c to the debtors, general economic conditions of the industry in which the debtors
\noperate and an assessment of both the current as well as the forecast direction of conditions at the reporting date.
\nLIQUIDITY RISK
\nThe group seeks to limit its liquidity risk by ensuring \ufb01nancial
\nsupport is available from the shareholders. The group\u2019s terms
\nof sales requires amounts to be paid within 45 to 60 days of
\nthe date of approval of progress billings. Trade payables are
\nnormally settled within 90 to 120 days of the date of receipt of
\ninvoice.
\nThe table below summarises the maturity pro\ufb01le of the
\ngroup\u2019s \ufb01nancial liabilities at 31 December 2022 based on
\ncontractual undiscounted payments.
\nAmounts in USD thousand
Note
On demand
\nLess than
\n1 month
\nBetween
\n1 and 3
\nmonths
\nBetween
\n3 months
\nand 1 year
\nMore than
\n1 year
Total
\n31 December 2022
\nTrade accounts payable
19
-
18,732
-
-
-
18,732
\nAmounts due to related parties
25D
2,019
-
-
-
-
2,019
\nLoan payable
20
-
-
1,375
4,125
5,500
11,000
\nOther payable
19
-
-
-
-
8,738
8,738
\nTotal
2,019
18,732
1,375
4,125
14,238
40,489
\nAmounts in USD thousand
Note
On demand
\nLess than
\n1 month
\nBetween
\n1 and 3
\nmonths
\nBetween
\n3 months
\nand 1 year
\nMore than
\n1 year
Total
\n31 December 2021
\nTrade accounts payable
19
21,944
-
5
65
22,014
\nAmounts due to related parties
25D
3,449
-
-
-
-
3,449
\nLoan payable
20
-
-
2,500
10,579
-
13,079
\nOther payable
19
-
-
-
-
-
-
\nTotal
3,449
21,944
2,500
10,584
65
38,542
\nThe company had USD 24.8 million (2021: 31.8 million) in
\nunrestricted cash as of 31 December 2022. Should additional
\nfunding be required in the future for additional capital
\nexpenditure for new development phases or working capital
\nrequirements, the company has various alternatives available
\nwhich it can explore to ful\ufb01l such additional requirements.
\nThe options include, amongst others, debt \ufb01nancing, o\ufb00take
\nprepayment structures. As a result, the \ufb01nancial statements
\nhave been prepared under the assumption of going concern
\nand realisation of assets and settlement of debt in normal
\noperations.
\n
As a result of the acquisition of the interest in the OML 113
\nlicence, PetroNor has inherited an other payable of USD 8.7
\nmillion which relates to costs not yet agreed. The \ufb01nal amount
\nis not expected to be settled within the next twelve months,
\ntherefore this has been classi\ufb01ed as a non-current liability.
\nINTEREST RATE RISK
\nThe group is exposed to interest rate risk on its interest-
\nbearing assets and liabilities and seeks to limit this risk by
\nobtaining favourable interest rates.
\n31 December 2022
31 December 2021
\nAmounts in USD thousand
+150bp
-150bp
+150bp
-150bp
\nLoans payable
(165)
165
(196)
196
\nThe new facility put in place does not include the oil pricing
\nsensitivity previously applied thus providing more certainty to
\ninterest costs.
\nCURRENCY RISK
\nThe group operates internationally and is exposed to risk
\narising from various currency exposures, primarily with
\nrespect to the Norwegian Kroner (NOK), and the Great British
\nPound (GBP). The group has transactional currency exposures.
\nSuch exposure arises from sales or purchases in currencies
\nother than the respective functional currency.
\nThe group reports its consolidated results in USD; any
\nchange in exchange rates between its operating subsidiaries\u2019
\nfunctional currencies and the USD a\ufb00ects its consolidated
\nstatement of comprehensive income and statement of
\n\ufb01nancial position when the results of those operating
\nsubsidiaries are translated into USD for reporting purposes.
\nGroup companies are required to manage their foreign
\nexchange risk against their functional currency.
\nA 20 per cent strengthening or weakening of the USD against
\nthe following currencies at 31 December 2022 would have
\nincreased/(decreased) equity and pro\ufb01t or loss by the amounts
\nshown below.
\nThe group\u2019s assessment of what a reasonable potential change
\nin foreign currencies that it is currently exposed to have been
\nchanged as a result of the changes observed in the world
\n\ufb01nancial markets. This hypothetical analysis assumes that all
\nother variables, including interest rates and commodity prices,
\nremain constant.
\n31 December 2022
31 December 2021
\nAmounts in USD thousand
+20%
-20%
+20%
-20%
\nUSD vs NOK
\nCash
106
(107)
1,040
(1,044)
\nReceivables
260
(260)
-
-
\nPayables
(423)
423
(92)
92
\nTotal
(57)
57
948
(952)
\nUSD vs GBP
\nCash
(17)
17
3
(3)
\nReceivables
(3)
3
8
(8)
\nPayables
7
(7)
(6)
6
\nTotal
(13)
13
5
5
\nCAPITAL RISK
\nThe primary objective of the group\u2019s capital management is
\nto continuously evaluate measures to strengthen its \ufb01nancial
\nbasis and to ensure that the group is fully funded for its
\ncommitted 2023 activities. The group manages its capital
\nstructure and makes adjustments to it in light of changes
\nin economic conditions. In order to maintain or change the
\ncapital structure, the group may adjust the amount of dividend
\npayments to shareholders, return capital to shareholders or
\nissue new shares.
\nThe group is continuously evaluating the capital structure, with
\nthe aim of having an optimal mix of equity and debt capital to
\nreduce the group\u2019s cost of capital and looking at avenues to
\nprocure capital in the forthcoming years.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f9529": {
"value": "Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in \ufb01nancial loss to
\nthe group. As at 31 December 2022, the group\u2019s maximum
\nexposure to credit risk without taking into account any
\ncollateral held or other credit enhancements, which will cause
\na \ufb01nancial loss to the group due to failure to discharge an
\nobligation by the counterparties and \ufb01nancial guarantees
\nprovided by the group arises from the carrying amount of
\nthe respective recognised \ufb01nancial assets as stated in the
\nstatement of \ufb01nancial position.
\nTo minimise credit risk, the group has tasked its management
\nto develop and maintain the group\u2019s credit risk gradings
\nto categorise exposures according to their degree of risk
\nof default. The credit rating information is supplied by
\nindependent rating agencies where available and, if not
\navailable, the management uses other publicly available
\n\ufb01nancial information and the group\u2019s own trading records
\nto rate its major customers and other debtors. The group\u2019s
\nexposure and the credit ratings of its counterparties
\nare continuously monitored, and the aggregate value
\nof transactions concluded is spread amongst approved
\ncounterparties.
\nThe company\u2019s current credit risk grading framework
\ncomprises the following categories:
\nCategory
Description
Basis for recognising expected credit losses
\nPerforming
The counterparty has a low risk of default and does
\nnot have any past-due amounts
\n12-month ECL
\nDoubtful
Amount is >30 days past due or there has been a
\nsigni\ufb01cant increase in credit risk since initial recognition
\nLifetime ECL \u2013 not credit-impaired
\nIn default
Amount is >90 days past due or there is evidence
\nindicating the asset is credit-impaired
\nLifetime ECL \u2013 credit-impaired
\nWrite-o\ufb00
There is evidence indicating that the debtor is in
\nsevere \ufb01nancial di\ufb03culty and the company has no
\nrealistic prospect of recovery
\nAmount is written o\ufb00
\nThe group\u2019s principal customers are substantial oil and gas
\ncompanies and as such credit risk is considered to be low.
\nThere is no history of credit loss, non-payment or default. The
\nrisk on liquid funds is limited because the counterparties are
\nbanks with high credit ratings. The asset retirement obligation
\ncash is held in an Escrow bank account managed by the
\noperator.
\n
The tables below detail the credit quality of the company\u2019s
\n\ufb01nancial assets as well as the company\u2019s maximum exposure
\nto credit risk by credit risk rating grades.
\nAmounts in USD thousand
Note
\nExternal
\ncredit
\nrating
\nInternal
\ncredit
\nrating
\n12-month or
\nlifetime ECL
\nGross
\ncarrying
\namount
\nLoss
\nallowance
\nNet
\ncarrying
\namount
\n31 December 2022
\nTrade receivables
13
N/a
(i)
Lifetime ECL
1,174
-
1,174
\nDue from related parties
13, 25D
N/a
-
Lifetime ECL
-
-
-
\nAdvance against decommissioning cost
13
N/a
-
Lifetime ECL
29,432
-
29,432
\nCash and cash equivalents
14
Aa3/B
N/a
12-month ECL
24,816
-
24,816
\n31 December 2021
\nTrade receivables
13
N/a
(i)
Lifetime ECL
13,431
-
13,431
\nDue from related parties
13, 25D
N/a
-
Lifetime ECL
-
-
-
\nAdvance against decommissioning cost
13
N/a
-
Lifetime ECL
26,837
-
26,837
\nCash and cash equivalents
14
Aa3/B
N/a
12-month ECL
31,755
-
31,755
\n(i) For trade receivables and amounts due from related parties, the group has applied the simpli\ufb01ed approach in IFRS 9 to measure the loss allowance at
\nlifetime ECL. The expected credit losses are estimated using a provision matrix by reference to past default experience of the debtor and an analysis of the
\ndebtor\u2019s current \ufb01nancial position, adjusted for factors that are speci\ufb01c to the debtors, general economic conditions of the industry in which the debtors
\noperate and an assessment of both the current as well as the forecast direction of conditions at the reporting date.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCreditRiskExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f9695": {
"value": "LIQUIDITY RISK The group seeks to limit its liquidity risk by ensuring \ufb01nancial
\nsupport is available from the shareholders. The group\u2019s terms
\nof sales requires amounts to be paid within 45 to 60 days of
\nthe date of approval of progress billings. Trade payables are
\nnormally settled within 90 to 120 days of the date of receipt of
\ninvoice.
\nThe table below summarises the maturity pro\ufb01le of the
\ngroup\u2019s \ufb01nancial liabilities at 31 December 2022 based on
\ncontractual undiscounted payments.
\nAmounts in USD thousand
Note
On demand
\nLess than
\n1 month
\nBetween
\n1 and 3
\nmonths
\nBetween
\n3 months
\nand 1 year
\nMore than
\n1 year
Total
\n31 December 2022
\nTrade accounts payable
19
-
18,732
-
-
-
18,732
\nAmounts due to related parties
25D
2,019
-
-
-
-
2,019
\nLoan payable
20
-
-
1,375
4,125
5,500
11,000
\nOther payable
19
-
-
-
-
8,738
8,738
\nTotal
2,019
18,732
1,375
4,125
14,238
40,489
\nAmounts in USD thousand
Note
On demand
\nLess than
\n1 month
\nBetween
\n1 and 3
\nmonths
\nBetween
\n3 months
\nand 1 year
\nMore than
\n1 year
Total
\n31 December 2021
\nTrade accounts payable
19
21,944
-
5
65
22,014
\nAmounts due to related parties
25D
3,449
-
-
-
-
3,449
\nLoan payable
20
-
-
2,500
10,579
-
13,079
\nOther payable
19
-
-
-
-
-
-
\nTotal
3,449
21,944
2,500
10,584
65
38,542
\nThe company had USD 24.8 million (2021: 31.8 million) in
\nunrestricted cash as of 31 December 2022. Should additional
\nfunding be required in the future for additional capital
\nexpenditure for new development phases or working capital
\nrequirements, the company has various alternatives available
\nwhich it can explore to ful\ufb01l such additional requirements.
\nThe options include, amongst others, debt \ufb01nancing, o\ufb00take
\nprepayment structures. As a result, the \ufb01nancial statements
\nhave been prepared under the assumption of going concern
\nand realisation of assets and settlement of debt in normal
\noperations.
\n
As a result of the acquisition of the interest in the OML 113
\nlicence, PetroNor has inherited an other payable of USD 8.7
\nmillion which relates to costs not yet agreed. The \ufb01nal amount
\nis not expected to be settled within the next twelve months,
\ntherefore this has been classi\ufb01ed as a non-current liability.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f9977": {
"value": "Note 28 Financial instruments
\nFinancial instruments comprise \ufb01nancial assets and \ufb01nancial
\nliabilities.
\nFinancial assets consist of bank balances and cash, amounts
\ndue from related parties and trade and some other
\nreceivables. Financial liabilities consist of amounts due to
\nrelated parties, loans payable, trade account payables and
\nsome other liabilities.
\nFair value through
\npro\ufb01t or loss
\nAmortised
\ncost
\nFair value through other
\ncomprehensive income
\nAmounts in USD thousand
2022
2021
2022
2021
2022
2021
\nFinancial assets
\nCash and cash equivalents
-
-
24,816
31,755
-
-
\nTrade and other receivables
-
-
1,171
13,820
-
-
\nOther receivables
-
-
29,432
26,837
-
-
\nTotal
-
-
55,419
72,412
-
-
\nFinancial Liabilities
\nTrade and other payables
-
-
29,489
30,055
-
-
\nLoans and borrowings
-
-
11,000
13,079
-
-
\nTotal
-
-
40,489
43,134
-
-
\nThe fair values of the group's \ufb01nancial instruments are not
\nmaterially di\ufb00erent from their carrying amounts at the
\nreporting date largely due to the short-term maturities of
\nthese instruments. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f9978": {
"value": "Note 28 Financial instruments
\nFinancial instruments comprise \ufb01nancial assets and \ufb01nancial
\nliabilities.
\nFinancial assets consist of bank balances and cash, amounts
\ndue from related parties and trade and some other
\nreceivables. Financial liabilities consist of amounts due to
\nrelated parties, loans payable, trade account payables and
\nsome other liabilities.
\nFair value through
\npro\ufb01t or loss
\nAmortised
\ncost
\nFair value through other
\ncomprehensive income
\nAmounts in USD thousand
2022
2021
2022
2021
2022
2021
\nFinancial assets
\nCash and cash equivalents
-
-
24,816
31,755
-
-
\nTrade and other receivables
-
-
1,171
13,820
-
-
\nOther receivables
-
-
29,432
26,837
-
-
\nTotal
-
-
55,419
72,412
-
-
\nFinancial Liabilities
\nTrade and other payables
-
-
29,489
30,055
-
-
\nLoans and borrowings
-
-
11,000
13,079
-
-
\nTotal
-
-
40,489
43,134
-
-
\nThe fair values of the group's \ufb01nancial instruments are not
\nmaterially di\ufb00erent from their carrying amounts at the
\nreporting date largely due to the short-term maturities of
\nthese instruments. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f9979": {
"value": "Note 28 Financial instruments
\nFinancial instruments comprise \ufb01nancial assets and \ufb01nancial
\nliabilities.
\nFinancial assets consist of bank balances and cash, amounts
\ndue from related parties and trade and some other
\nreceivables. Financial liabilities consist of amounts due to
\nrelated parties, loans payable, trade account payables and
\nsome other liabilities.
\nFair value through
\npro\ufb01t or loss
\nAmortised
\ncost
\nFair value through other
\ncomprehensive income
\nAmounts in USD thousand
2022
2021
2022
2021
2022
2021
\nFinancial assets
\nCash and cash equivalents
-
-
24,816
31,755
-
-
\nTrade and other receivables
-
-
1,171
13,820
-
-
\nOther receivables
-
-
29,432
26,837
-
-
\nTotal
-
-
55,419
72,412
-
-
\nFinancial Liabilities
\nTrade and other payables
-
-
29,489
30,055
-
-
\nLoans and borrowings
-
-
11,000
13,079
-
-
\nTotal
-
-
40,489
43,134
-
-
\nThe fair values of the group's \ufb01nancial instruments are not
\nmaterially di\ufb00erent from their carrying amounts at the
\nreporting date largely due to the short-term maturities of
\nthese instruments. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10063": {
"value": "Note 29 Commitments and contingencies
\nCOMMITMENTS
\nProduction asset commitments
\nAs at 31 December 2022, the group had approved the budget
\nfor PNGF Sud operations in Congo that included planned capex
\nexpenditure for the coming year of USD 45.6 million (2021 USD
\n50.6 million) representing HEPCO's equity interest funding
\ncommitment in the licence.
\nExploration commitments
\nThe company has entered into obligations in respect of
\nits exploration projects. Outlined below are the minimum
\nexpenditures required as at 31 December:
\nAmounts in USD thousand
2022
2021
\nWithin one year
\n1
\n40,000
40,000
\n1)
The commitment in Senegal includes USD 40 million for an exploration
\nwell in each licence, however this assumes that the company is successful
\nin retaining the legal title for these licences and that the company then
\ndrills these wells with 90 per cent equity.
\nCONTINGENCIES
\nIn December 2021, the National Authority for Investigation
\nand Prosecution of Economic and Environmental Crime in
\nNorway (\u00d8kokrim) initiated an investigation into allegations of
\ncorruption and brought criminal charges against individuals
\nassociated with the company. \u00d8kokirm has con\ufb01rmed that
\nneither PetroNor nor any of its subsidiaries has been charged.
\nThe US Department of Justice also began its own investigation
\ninto the allegations based on information received from
\n\u00d8kokrim.
\nTo mitigate potential corporate liability risks, the board has
\ntaken various remediation steps, as outlined in the director\u2019s
\nreport, including obtaining independent legal advice and
\nimplementing a compliance action plan. Despite the ongoing
\ninvestigations, the company has continued to operate
\ne\ufb00ectively, but has incurred costs in addressing this issue
\nand fully cooperating with the investigating authorities.
\nThe company is not aware of the status or duration of
\nthe investigations into the individuals involved, and the
\nuncertainty surrounding the outcome could potentially impact
\nthe group\u2019s ability to conduct transactions with both new and
\nexisting partners.
\n
As part of the transaction to acquire the interest in OML 113
\nconditional consideration has been assessed as a potential
\ncontingency to the group. An additional consideration
\nof USD 0.10 per 1,000 cubic feet of the AJE Natural Gas
\nSales Volume is to be paid to Panoro Energy ASA once the
\nconditions stipulated within the SPA are met. This conditional
\nconsideration shall not exceed USD 16.67 million. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10067": {
"value": "COMMITMENTS Production asset commitments
\nAs at 31 December 2022, the group had approved the budget
\nfor PNGF Sud operations in Congo that included planned capex
\nexpenditure for the coming year of USD 45.6 million (2021 USD
\n50.6 million) representing HEPCO's equity interest funding
\ncommitment in the licence.
\nExploration commitments
\nThe company has entered into obligations in respect of
\nits exploration projects. Outlined below are the minimum
\nexpenditures required as at 31 December:
\nAmounts in USD thousand
2022
2021
\nWithin one year
\n1
\n40,000
40,000
\n1)
The commitment in Senegal includes USD 40 million for an exploration
\nwell in each licence, however this assumes that the company is successful
\nin retaining the legal title for these licences and that the company then
\ndrills these wells with 90 per cent equity.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCommitmentsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10093": {
"value": "CONTINGENCIES In December 2021, the National Authority for Investigation
\nand Prosecution of Economic and Environmental Crime in
\nNorway (\u00d8kokrim) initiated an investigation into allegations of
\ncorruption and brought criminal charges against individuals
\nassociated with the company. \u00d8kokirm has con\ufb01rmed that
\nneither PetroNor nor any of its subsidiaries has been charged.
\nThe US Department of Justice also began its own investigation
\ninto the allegations based on information received from
\n\u00d8kokrim.
\nTo mitigate potential corporate liability risks, the board has
\ntaken various remediation steps, as outlined in the director\u2019s
\nreport, including obtaining independent legal advice and
\nimplementing a compliance action plan. Despite the ongoing
\ninvestigations, the company has continued to operate
\ne\ufb00ectively, but has incurred costs in addressing this issue
\nand fully cooperating with the investigating authorities.
\nThe company is not aware of the status or duration of
\nthe investigations into the individuals involved, and the
\nuncertainty surrounding the outcome could potentially impact
\nthe group\u2019s ability to conduct transactions with both new and
\nexisting partners.
\n
As part of the transaction to acquire the interest in OML 113
\nconditional consideration has been assessed as a potential
\ncontingency to the group. An additional consideration
\nof USD 0.10 per 1,000 cubic feet of the AJE Natural Gas
\nSales Volume is to be paid to Panoro Energy ASA once the
\nconditions stipulated within the SPA are met. This conditional
\nconsideration shall not exceed USD 16.67 million. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10147": {
"value": "Note 30 Events subsequent to reporting date
\nOn 26 January 2023, two new directors were appointed to the
\nboard. The appointments were pursuant to recommendations
\nfrom the nomination committee. The two new directors, Mrs.
\nAzza Fawzi and Mr. Jarle Norman-Hansen, take the company\u2019s
\nboard to a total of six directors.
\nIn the O\ufb03cial Gazette of Guinea-Bissau (Boletim O\ufb01cial 45), it
\nwas announced that following the withdrawal of FAR Limited
\nfrom the Sinapa and Esperan\u00e7a licences o\ufb00shore Guinea-
\nBissau their equity interest had been awarded to PetroNor.
\nAt the start of February, 317,904 bbls of oil were lifted from
\nthe Djeno Terminal, this sale generated a cash in\ufb02ow of USD
\n24.1 million. On 1 April 2023, a further 260,362 bbls of oil were
\nlifted generating USD 21.2 million of cash in\ufb02ow.
\nIn a CPR update prepared by AGR Petroleum Services AS on
\nthe Company\u2019s PNGF Sud assets, the end of year 2P reserves
\nwere updated to 18.5 Mmbbl with 2C reserves to 23.5 Mmbbl.
\nExcept for the above, the company has not identi\ufb01ed any
\nevents with signi\ufb01cant accounting impacts that have occurred
\nbetween the end of the reporting period and the date of this
\nreport.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10172": {
"value": "Note 31 Summary of accounting policies
\nAccounting policies are selected and applied in a manner
\nwhich ensures that the resulting \ufb01nancial information satis\ufb01es
\nthe concepts of relevance and reliability, thereby ensuring that
\nthe substance of the underlying transactions or other events
\nis reported.
\nThe following is a summary of the material accounting policies
\nadopted by the group in the preparation of the consolidated
\n\ufb01nancial statements. The accounting policies have been
\nconsistently applied, unless otherwise stated.
\n31A.
ADOPTION OF NEW AND REVISED ACCOUNTING
\nSTANDARDS
\nIASB has issued several amendments to standards or
\ninterpretations to standards e\ufb00ective as of 1 January 2022.
\nPetroNor have adopted these standards in the \ufb01nancial year,
\nthe impacts were not material to PetroNor\u2019s consolidated
\n\ufb01nancial statements upon adoption.
\nImpacts of other standards and amendments to standards,
\nand interpretations of standards, issued but not yet e\ufb00ective
\nare under assessment by PetroNor.
\n31B.
CONSOLIDATION
\nThe consolidated \ufb01nancial statements comprise the \ufb01nancial
\nstatements of PetroNor E&P ASA (\u201cthe company\u201d, formerly
\nPetroNor E&P Ltd) and its subsidiaries for the year ended 31
\nDecember 2022 (together the group).
\nAn entity has been assessed as being controlled by the group
\nwhen the groups is exposed, or has the rights, to variable
\nreturns from its involvement with the entity and has the
\nability to a\ufb00ect those returns through its power over the
\nentity. Speci\ufb01cally, the group controls an entity if and only if
\nthe group has:
\n\u25a0
Power over the entity (i.e., existing rights that give it the
\ncurrent ability to direct the relevant activities of the entity)
\n\u25a0
Exposure, or rights, to variable returns from its involvement
\nwith the entity, and
\n\u25a0
The ability to use its power over the entity to a\ufb00ect its
\nreturns
\nWhen the group has less than a majority of the voting or
\nsimilar rights of an entity, the group considers all relevant facts
\nand circumstances in assessing whether it has power over an
\nentity, including:
\n\u25a0
The contractual arrangement with the other vote holders of
\nthe entity
\n\u25a0
Rights arising from other contractual arrangements
\n\u25a0
The group\u2019s voting rights and potential voting rights
\nThe group reassesses whether or not it controls an entity if
\nfacts and circumstances indicate that there are changes to
\none or more of the three elements of control. Consolidation
\nof a subsidiary begins when the group obtains control over
\nthe subsidiary and ceases when the group loses control of
\nthe subsidiary. Business combinations are accounted for by
\nusing the acquisition method. Assets, liabilities, income, and
\nexpenses of a subsidiary acquired or disposed of during the
\nyear are included in the statement of comprehensive income
\nfrom the date the group gains control until the date the group
\nceases to control the subsidiary.
\nPro\ufb01t or loss and each component of other comprehensive
\nincome (OCI) are attributed to the equity holders of the parent
\nof the group and to the non-controlling interests, even if this
\nresults in the non-controlling interests having a de\ufb01cit balance.
\nWhen necessary, adjustments are made to the \ufb01nancial
\nstatements of subsidiaries to bring their accounting policies
\n
into line with the group\u2019s accounting policies. All intra-group
\nassets and liabilities, equity, income, expenses, and cash \ufb02ows
\nrelating to transactions between members of the group are
\neliminated in full on consolidation.
\nA change in the ownership interest of a subsidiary, without a
\nloss of control, is accounted for as an equity transaction.
\nIf the group loses control over a subsidiary, it:
\n\u25a0
Derecognises the assets (including goodwill) and liabilities of
\nthe subsidiary.
\n\u25a0
Derecognises the carrying amount of any non-controlling
\ninterests
\n\u25a0
Derecognises the cumulative translation di\ufb00erences
\nrecorded in equity
\n\u25a0
Recognises the fair value of the consideration received
\n\u25a0
Recognises the fair value of any investment retained
\n\u25a0
Recognises any surplus or de\ufb01cit in pro\ufb01t or loss
\n\u25a0
Reclassi\ufb01es the parent\u2019s share of components previously
\nrecognised in OCI to pro\ufb01t or loss or retained earnings, as
\nappropriate, as would be required if the group had directly
\ndisposed of the related assets or liabilities.
\nJoint operations
\nA joint arrangement is a joint operation whereby the group and
\nthe other parties that have joint control over the arrangement,
\nhave contractual rights to the assets and obligation for the
\nliabilities relating to the arrangement. All decisions about the
\nrelevant activities require unanimous consent.
\nWhen assessing if a joint arrangement is joint operation,
\nthe group assesses the structure of the arrangement, the
\nlegal form, the contractual agreement and other facts and
\ncircumstances.
\nThe group recognises its assets, liabilities, revenue and
\nexpenses and its relative share of assets, liabilities, revenue,
\nand expenses of the joint operation.
\nWhen the group enters into transactions with a joint operation
\nin which it is a joint operator, the group recognises gains and
\nlosses resulting from such a transaction only to the extent of
\nthe other parties\u2019 interests in the joint operation.
\n31C.
SEGMENT REPORTING
\nAn operating segment is a component of an entity that
\nengages in business activities from which it may earn revenues
\nand incur expenses (including revenues and expenses relating
\nto transactions with other components of the same entity),
\nwhose operating results are regularly reviewed by the entity\u2019s
\nchief operating decision-makers to make decisions about
\nresources to be allocated to the segments and assess their
\nperformance and for which discrete \ufb01nancial information is
\navailable. This includes start-up operations which are yet to
\nearn revenues.
\nOperating segments have been identi\ufb01ed based on the
\ninformation available to chief operating decision-makers \u2013
\nbeing the board and the executive management team.
\nInformation about other business activities and operating
\nsegments that are below the quantitative criteria are
\ncombined and disclosed in a separate category called \u201call other
\nsegments\u201d.
\n31D.
FOREIGN CURRENCY TRANSLATION
\nFunctional and presentation currency
\nThe company has applied United States Dollars, being the
\nfunctional currency of all major subsidiaries in the group, as
\nits presentation currency. Where the functional currencies
\nof entities within the consolidated group di\ufb00er from United
\nStates Dollars, they have been translated into United States
\nDollars. The functional currency of PetroNor E&P ASA is
\nNorwegian Kroner.
\nTransactions and balances
\nTransactions in foreign currencies are initially recorded in the
\nfunctional currency by applying the exchange rates ruling at
\nthe date of the transaction. Monetary assets and liabilities
\ndenominated in foreign currencies are retranslated at the
\nrate of exchange ruling at the reporting date and any gains or
\nlosses are recognised in the income statement.
\nNon-monetary items that are measured in terms of historical
\ncost in the foreign currency are translated using the exchange
\nrate as at the date of the initial transaction. Non-monetary
\nitems measured at fair value in a foreign currency are
\ntranslated using the exchange rates at the date when the fair
\nvalue was determined.
\nTranslation of group companies' functional currency to
\npresentation currency
\nOn consolidation, the assets and liabilities of foreign
\noperations are translated into United States Dollars at the rate
\nof exchange prevailing at the reporting date and their income
\nand expenditure are translated at exchange rates prevailing
\nat the dates of the transactions. The exchange di\ufb00erences
\narising on translation for consolidation are recognised in other
\ncomprehensive income. On disposal of a foreign operation, the
\ncomponent of other comprehensive income relating to that
\nparticular foreign operation is recognised in pro\ufb01t or loss.
\n31E.
CASH AND CASH EQUIVALENTS
\nCash and cash equivalents include cash on hand, deposits held
\nat call with banks, other short-term highly liquid investments
\nwith original maturities of three months or less, and bank
\noverdrafts. Bank overdrafts are shown within short-term
\nborrowings in current liabilities on the Statement of Financial
\nPosition.
\n31F.
TRADE RECEIVABLES
\nTrade receivables are amounts due from customers for goods
\nsold or services performed in the ordinary course of business.
\nThey are generally due for settlement within 30 to 90 days
\nand therefore are all classi\ufb01ed as current. Trade receivables
\nare recognised initially at the amount of consideration that
\nis unconditional unless they contain signi\ufb01cant \ufb01nancing
\ncomponents, when they are recognised at fair value. The
\ngroup holds the trade receivables with the objective to collect
\nthe contractual cash \ufb02ows and therefore measures them
\nsubsequently at amortised cost using the e\ufb00ective interest
\nmethod.
\nTrade receivables are written o\ufb00 when there is no reasonable
\nexpectation of recovery. Indicators that there is no reasonable
\nexpectation of recovery include, amongst others, the failure
\nof a debtor to engage in a repayment plan with the group, and
\na failure to make contractual payments for a period of greater
\nthan 120 days past due.
\n
Impairment losses on trade receivables and contract assets
\nare presented as net impairment losses within operating
\npro\ufb01t. Subsequent recoveries of amounts previously written
\no\ufb00 are credited against the same line item.
\n31G.
INVENTORY
\nThe crude oil inventory and the material and supplies
\ninventory are valued at the lower of cost and net realisable
\nvalue. Cost is determined using the weighted average method.
\nNet realisable value is the estimated selling price, less
\napplicable selling expenses. The cost of inventory includes all
\ncosts related to bringing the inventory to its current condition,
\nincluding processing costs, labour costs, supplies, direct
\nand allocated indirect operating overhead and depreciation
\nexpense, where applicable, including allocation of \ufb01xed and
\nvariable costs to inventory.
\n31H.
TANGIBLE ASSETS
\nProperty, plant, and equipment
\nOil & gas production assets
\nOil and gas production assets are aggregated exploration and
\nevaluation tangible assets and development expenditures
\nassociated with the production of proved reserves.
\nThe cost of development and production assets also includes
\nthe cost of acquisitions and purchases of such assets, directly
\nattributable overheads and the cost of recognising provisions
\nfor future restoration and decommissioning.
\nWhere major and identi\ufb01able parts of the production assets
\nhave di\ufb00erent useful lives, they are accounted for as separate
\nitems of property, plant, and equipment. Costs of minor
\nrepairs and maintenance are expensed as incurred. Oil and
\ngas production assets have a \ufb01nite life.
\nDepreciation
\nOil and gas properties are depreciated using the unit-of-
\nproduction method. Unit of production rates are based on 1P
\nproved reserves, which are oil, gas and other mineral reserves
\nestimated to be recovered from existing facilities using current
\noperating methods. Oil and gas volumes are considered
\nproduced once they have been measured through meters at
\ncustody transfer or sales transaction points at the outlet valve
\non the \ufb01eld storage tank.
\nField infrastructure exceeding beyond the life of the \ufb01eld is
\ndepreciated over the useful life of the infrastructure using a
\nstraight-line method.
\nProperty, plant, and equipment not associated with
\nexploration and production activities are carried at cost less
\naccumulated depreciation. These assets are also evaluated for
\nimpairment. Depreciation of other assets is calculated on a
\nstraight-line basis as follows:
\nComputer equipment
20 \u2013 33.33%
\nFurniture, \ufb01xtures, & \ufb01ttings
10 \u2013 33.33%
\nMotor vehicles
20%
\n31I.
INTANGIBLE ASSETS
\nExploration and evaluation activity involves the search for
\nhydrocarbon resources, the determination of technical
\nfeasibility and the assessment of commercial viability of an
\nidenti\ufb01ed resource. For each area of interest, expenditure
\nincurred in the acquisition of rights to explore and all costs
\ndirectly associated with holding the licence such as rental,
\ntraining and corporate and social responsibility are capitalised
\nas exploration and evaluation intangible assets. Signature
\nbonuses required by licence agreements are capitalised as
\nexploration and evaluation intangible assets. Other costs
\ndirectly associated with the licence are expensed as incurred.
\nExploration, evaluation, and development expenditure is
\nrecorded at historical cost and allocated to cost pools on
\nan area of interest. Expenditure on an area of interest is
\ncapitalised and carried forward where rights to tenure of the
\narea of interest are current and:
\n\u25a0
it is expected to be recouped through successful
\ndevelopment and exploitation of the area of interest or
\nalternatively by its sale; or
\n\u25a0
exploration and evaluation activities are continuing in
\nan area of interest but at reporting date have not yet
\nreached a stage which permits a reasonable assessment
\nof the existence or otherwise of economically recoverable
\nreserves.
\nAccumulated costs in respect of areas of interest which are
\nabandoned are written o\ufb00 in full against pro\ufb01t in the period in
\nwhich the decision to abandon the area is made.
\nProjects are advanced to development status when it is
\nexpected that further expenditure can be recouped through
\nsale or successful development and exploitation of the area of
\ninterest.
\nAll capitalised costs are subject to commercial and
\nmanagement review, as well as review for indicators of
\nimpairment at least once a year. This is to con\ufb01rm the
\ncontinued intent to develop or otherwise extract value from
\nthe discovery. When this is no longer the case, the costs are
\nwritten o\ufb00 through the statement of pro\ufb01t or loss and other
\ncomprehensive income.
\nWhen proved reserves of oil and natural gas are identi\ufb01ed
\nand development is sanctioned by management, the relevant
\ncapitalised expenditure is \ufb01rst assessed for impairment and
\n(if required) any impairment loss is recognised, then the
\nremaining balance is transferred to oil and gas properties.
\nProceeds from disposal or farm-out transactions of intangible
\nexploration assets are used to reduce the carrying amount of
\nthe assets. When proceeds exceed the carrying amount, the
\ndi\ufb00erence is recognised as a gain. When the group disposes of
\nits full interests, gains or losses are recognised in accordance
\nwith the policy for recognising gains or losses on sale of plant,
\nproperty, and equipment.
\nGenerally Intangible assets can be viewed inde\ufb01nite as
\nthey will be retained on the balance sheet until impaired or
\ntransferred to oil and gas properties. Certain licence related
\ncosts capitalised as intangible assets are deemed to have a
\n\ufb01nite life and are accreted over the life of the licence area.
\nDepreciation
\nLicence related costs capitalised as Intangible assets are
\ndepreciated using the unit-of-production method. Unit-of
\nproduction rates are based on 1P proved reserves, which are
\noil, gas and other mineral reserves estimated to be recovered
\nfrom existing facilities using current operating methods. Oil
\n
and gas volumes are considered produced once they have
\nbeen measured through meters at custody transfer or sales
\ntransaction points at the outlet valve on the \ufb01eld storage tank.
\nTechnical goodwill
\nTechnical goodwill recognised in business combinations
\nis allocated to each CGU for the purposes of impairment
\ntesting. Impairment is tested on an annual basis or when
\nthere are impairment indicators. Indicators may be speci\ufb01c
\nto an individual CGU or groups of CGUs to which the technical
\ngoodwill is related. When conducting impairment testing,
\ndeferred tax recognised in relation to the acquired licences
\nreduces the net carrying value prior to the impairment
\ncharges.
\nImpairment is recognised if the recoverable amount of the
\nCGU (or groups of CGUs) to which the technical goodwill relates
\nto is less than the carrying amount.
\nImpairment of goodwill cannot be reversed in future periods.
\n31J.
BORROWING COSTS
\nBorrowing costs that are directly attributable to the
\nacquisition, construction or production of a qualifying non-
\ncurrent asset are added to the cost of the asset during the
\nperiod of time that is required to complete and prepare the
\nasset for its intended use. Borrowing costs are capitalised to
\nthe extent that funds are borrowed speci\ufb01cally for the purpose
\nof obtaining a qualifying asset. To the extent that funds are
\nborrowed generally and used for the purpose of obtaining a
\nqualifying asset, the amount of borrowing costs eligible for
\ncapitalisation is determined by applying a capitalisation rate to
\nthe expenditures on that asset. All other borrowing costs are
\nexpensed as incurred.
\n31K.
REVENUE
\n(i)
Revenue from petroleum products
\nRevenue from the sale of crude oil is recognised when a
\ncustomer obtains control (\u201csales\u201d or \u201clifting\u201d method), normally
\nthis is when title passes at point of delivery. Revenues from
\nproduction of oil properties are recognised based on actual
\nvolumes lifted and sold to customers during the period.
\n(ii)
Other revenue
\nUnder a production sharing contract, where the group is
\nrequired to pay pro\ufb01t oil tax and royalties on production
\nof crude oil, such payments are settled in kind (where the
\ngovernment lift the crude it is entitled to). The group presents
\na gross-up of the pro\ufb01t oil tax as an income tax expense with
\na corresponding increase in oil and gas revenues and any
\nassociated royalties are included in the cost of sales.
\nThe group assesses whether it acts as a principal or agent in
\neach of its revenue arrangements. The group has concluded
\nthat in all sales transactions it acts as a principal.
\n(iii)
Variable consideration
\nIf the consideration in a contract includes a variable amount,
\nthe group recognises this amount as revenue only to the
\nextent that it is highly probable that a signi\ufb01cant reversal will
\nnot occur in the future.
\n(iv)
Interest
\nInterest income is recognised on a time-proportional basis
\nusing the e\ufb00ective interest method. This is a method of
\ncalculating the amortised cost of a \ufb01nancial asset and
\nallocating the interest income over the relevant period using
\nthe e\ufb00ective interest rate, which is the rate that exactly
\ndiscounts the estimated future cash receipts through the
\nexpected useful life of the \ufb01nancial asset to the net carrying
\namount of the \ufb01nancial asset.
\n31L.
LEASES
\nThe group as lessee
\nThe group assesses whether contract is or contains a lease,
\nat inception of the contract. The group recognises a right-of-
\nuse asset and a corresponding lease liability with respect to all
\nlease arrangements in which it is the lessee, except for short-
\nterm leases (de\ufb01ned as leases with a lease term of 12 months
\nor less) and leases of low value assets. For these leases, the
\ngroup recognises the lease payments as an operating expense
\non a straight-line basis over the term of the lease unless
\nanother systematic basis is more representative of the time
\npattern in which economic bene\ufb01ts from the leased assets are
\nconsumed.
\nThe lease liability is initially measured at the present value of
\nthe lease payments that are not paid at the commencement
\ndate, discounted by using the rate implicit in the lease. If
\nthis rate cannot be readily determined, the group uses its
\nincremental borrowing rate.
\nLease payments included in the measurement of the lease
\nliability comprise:
\n\u25a0
\ufb01xed lease payments (including in-substance \ufb01xed
\npayments), less any lease incentives;
\n\u25a0
variable lease payments that depend on an index or
\nrate, initially measured using the index or rate at the
\ncommencement date;
\n\u25a0
the amount expected to be payable by the lessee under
\nresidual value guarantees;
\n\u25a0
the exercise price of purchase options, if the lessee is
\nreasonably certain to exercise the options; and
\n\u25a0
payments of penalties for terminating the lease, if the lease
\nterm re\ufb02ects the exercise of an option to terminate the
\nlease.
\nThe lease liability is presented as a separate line item in the
\nstatement of \ufb01nancial position.
\nThe lease liability is subsequently measured by increasing
\nthe carrying amount to re\ufb02ect interest on the lease liability
\n(using e\ufb00ective interest method) and by reducing the carrying
\namount to re\ufb02ect the lease payments made.
\nThe group remeasures the lease liability (and makes a
\ncorresponding adjustment to the related right-of-use asset)
\nwhenever:
\n\u25a0
the lease term has changed or there is a change in the
\nassessment of exercise of a purchase option, in which case
\nthe lease liability is remeasured by discounting the revised
\nlease payments using a revised discount rate.
\n\u25a0
the lease payments change due to changes in an index or
\nrate or a change in expected payment under a guaranteed
\nresidual value, in which cases the lease liability is
\nremeasured by discounting the revised lease payments
\nusing the initial discount rate (unless the lease payments
\n
change is due to a change in a \ufb02oating interest rate, in which
\ncase a revise discount rate is used).
\n\u25a0
a lease contract is modi\ufb01ed, and the lease modi\ufb01cation is
\nnot accounted for as a separate lease, in which case the
\nlease liability is remeasured by discounting the revised lease
\npayments using a revised discount rate.
\nThe group did not make any such adjustments during the
\nperiods presented.
\nRight of use assets
\nThe group measures the right-of use asset at cost, less any
\naccumulated depreciation and impairment losses, adjusted for
\nany remeasurement of lease liabilities. The cost of the right-of-
\nuse asset comprise:
\n\u25a0
The amount of the initial measurement of the lease liability
\nrecognised
\n\u25a0
Any lease payments made at or before the commencement
\ndate, less any incentives received
\n\u25a0
Any initial direct costs incurred by the group. An estimate
\nof the costs to be incurred by the group in dismantling and
\nremoving the underlying asset, restoring the site on which it
\nis located or restoring the underlying asset to the condition
\nrequired by the terms and conditions of the lease, unless
\nthose costs are incurred to produce inventories.
\nThe group applies the depreciation requirements in IAS 16
\nProperty, Plant and Equipment in depreciating the right-of-use
\nasset, except that the right-of-use asset is depreciated from
\nthe commencement date to the earlier of the lease term and
\nthe remaining useful life of the right-of-use asset.
\nThe group applies IAS 36 Impairment of Assets to determine
\nwhether the right-of-use asset is impaired and to account for
\nany impairment loss identi\ufb01ed.
\nVariable rents that do not depend on an index or rate are not
\nincluded in the measurement of the lease liability and the
\nright-of-use asset. The related payments are recognised as
\nan expense in the period in which the event or condition that
\ntriggers those payments occurs and are included in the line
\n\u2018Administrative expenses\u2019 in the statement of pro\ufb01t or loss.
\n31M.
TAXES
\nThe income tax expense or bene\ufb01t for the period consists of
\ntwo components: current and deferred tax.
\nThe current income tax payable or recoverable is calculated
\nusing the tax rates and legislation that have been enacted or
\nsubstantively enacted at year-end in each of the jurisdictions
\nand includes any adjustments for taxes payable or recovery in
\nrespect of prior periods.
\nDeferred tax assets and liabilities are determined using
\nthe balance sheet liability method based on temporary
\ndi\ufb00erences between the carrying value of assets and liabilities
\nfor \ufb01nancial reporting purposes and their tax bases. In
\ncalculating the deferred tax assets and liabilities, the tax
\nrates used are those that have been enacted or substantively
\nenacted by year-end in each of the jurisdictions and that
\nare expected to apply when the assets are recovered, or the
\nliabilities are settled.
\nRevenue-based taxes
\nIn addition to corporate income taxes, the group\u2019s
\nconsolidated \ufb01nancial statements also include and recognise
\nas income taxes, other types of taxes on net income such as
\ncertain revenue-based taxes.
\nProduction-sharing arrangements
\nAccording to the production-sharing arrangement (PSA)
\nin certain licences, the share of the pro\ufb01t oil to which the
\ngovernment is entitled in any calendar year in accordance
\nwith the PSA is deemed to include a portion representing the
\ncorporate income tax imposed upon and due by the group.
\nThis amount will be paid directly by the government on behalf
\nof the group to the appropriate tax authorities.
\nThe income tax expense
\nThe current income tax is calculated using the PSA, paid in
\nbarrels and booked as income tax and also shown as revenue.
\nSales tax
\nRevenues, expenses and assets are recognised net of the
\namount of sales tax except:
\nWhere the sales tax incurred on a purchase of assets or
\nservices is not recoverable from the taxation authority, in
\nwhich case, the sales tax is recognised as part of the cost
\nof acquisition of the asset or as part of the expense item as
\napplicable.
\nReceivables and payables that are stated with the amount of
\nsales tax included.
\nThe net amount of sales tax recoverable from, or payable to,
\nthe taxation authority is included as part of receivables or
\npayables in the statement of \ufb01nancial position.
\nCurrent and deferred tax balances attributable to amounts
\nrecognised directly in equity are also recognised directly in
\nequity.
\n31N.
EMPLOYEE BENEFITS
\nProvision is made for bene\ufb01ts accruing to employees in
\nrespect of wages and salaries, annual leave, and long service
\nleave when it is probable that settlement will be required, and
\nthey are capable of being measured reliably. Provisions made
\nin respect of employee bene\ufb01ts expected to be settled within
\n12 months are measured at their nominal values using the
\nremuneration rate expected to apply at the time of settlement.
\nProvisions made in respect of employee bene\ufb01ts, which are
\nnot due to be settled within 12 months are determined using
\nthe projected unit credit method.
\n31O.
DEFINED CONTRIBUTION PENSION PLAN
\nThe group pays contributions into de\ufb01ned contribution plans.
\nObligations for contributions to de\ufb01ned contribution pension
\nplans are recognised as an expense in the income statement in
\nthe periods during which services are rendered by employees.
\n31P.
TRADE AND OTHER PAYABLES
\nTrade and other payables are carried at amortised cost and
\ndue to their short-term nature, they are not discounted.
\n31Q.
PROVISIONS
\n(i)
General
\nProvisions are recognised when the group has a present
\nobligation (legal or constructive) as a result of a past event, it
\nis probable that an out\ufb02ow of resources embodying economic
\n
bene\ufb01ts will be required to settle the obligation and a reliable
\nestimate can be made of the amount of the obligation.
\nWhere the group expects some or all of the provision to be
\nreimbursed, for example under an insurance contract, the
\nreimbursement is recognised as a separate asset but only
\nwhen the reimbursement is virtually certain. The expense
\nrelating to any provision is recognised through pro\ufb01t and loss
\nnet of any reimbursement. If the e\ufb00ect of the time value of
\nmoney is material, provisions are discounted using a current
\npre-tax rate that re\ufb02ects, where appropriate, the risks speci\ufb01c
\nto the liability. Where discounting is used, the increase in the
\nprovision due to the passage of time is recognised as interest
\nexpense. The present obligation under onerous contracts is
\nrecognised as a provision.
\n(ii)
Decommissioning liability
\nA decommissioning liability is recognised when the group has
\na present legal or constructive obligation as a result of past
\nevents, and it is probable that an out\ufb02ow of resources will be
\nrequired to settle the obligation, and a reliable estimate of the
\namount of obligation can be made. A corresponding amount
\nequivalent to the obligation is also recognised as part of the
\ncost of the related production plant and equipment. The
\namount recognised in the estimated cost of decommissioning,
\ndiscounted to its present value. Changes in the estimated
\ntiming of decommissioning or decommissioning cost estimates
\nare dealt with prospectively by recording an adjustment to
\nthe provision, and a corresponding adjustment to production
\nplant and equipment. The unwinding of the discount on the
\ndecommissioning liability is included as a \ufb01nance cost.
\nAn escrow account is maintained by the operator of the PNGF
\nSud licence and is governed by a joint operating agreement
\nand the Congolese Government rules. The group\u2019s share, paid
\nagainst the decommissioning liability until the balance sheet
\ndate, is classi\ufb01ed as an advance against decommissioning
\nliability in current assets.
\n31R.
SHARE CAPITAL
\nContributed equity is recognised at the fair value of the
\nconsideration received by the group, less any capital raising
\ncosts in relation to the issue.
\nIncremental costs directly attributable to the issue of new
\nshares or options are shown in equity as a deduction, net of
\ntax, from the proceeds.
\n31S.
DIVIDEND DISTRIBUTION
\nDividend distribution to the company\u2019s shareholders is
\nrecognised as a liability in the group\u2019s \ufb01nancial statements
\nin the period in which the dividends are declared and
\nappropriately authorised or approved by the company\u2019s
\nshareholders\u2019 general meeting. Interim dividends proposed
\nby the board of directors are recognised as liabilities upon
\ndeclaration.
\n31T.
FINANCIAL INSTRUMENTS
\nA \ufb01nancial instrument is any contract that gives rise to a
\n\ufb01nancial asset of any one entity and a \ufb01nancial liability or
\nequity instrument of another entity.
\n(i)
Financial assets
\nFinancial assets are classi\ufb01ed, at initial recognition, as
\nsubsequently measured at amortised cost, fair value through
\nother comprehensive income (OCI), and fair value through
\npro\ufb01t or loss, as appropriate.
\nThe classi\ufb01cation of \ufb01nancial assets at initial recognition
\ndepends on the \ufb01nancial asset\u2019s contractual cash \ufb02ow
\ncharacteristics and the group\u2019s business model for managing
\nthem. With the exception of trade receivables that do not
\ncontain a signi\ufb01cant \ufb01nancing component or for which the
\ngroup has applied the practical expedient, the group initially
\nmeasures a \ufb01nancial asset at its fair value plus, in the case
\nof \ufb01nancial assets not subsequently measured at fair value
\nthrough pro\ufb01t or loss, transaction costs that are attributable
\nto the acquisition of the \ufb01nancial asset.
\nIn order for a \ufb01nancial asset to be classi\ufb01ed and measured at
\namortised cost or fair value through OCI, it needs to give rise
\nto cash \ufb02ows that are solely payments of principal and interest
\n(SPPI) on the principal amount outstanding. This assessment is
\nreferred to as the SPPI test and is performed at an instrument
\nlevel.
\nThe group\u2019s business model for managing \ufb01nancial assets
\nrefers to how it manages its \ufb01nancial assets in order to
\ngenerate cash \ufb02ows. The business model determines whether
\ncash \ufb02ows will result from collecting contractual cash \ufb02ows,
\nselling the \ufb01nancial assets, or both.
\nPurchases or sales of \ufb01nancial assets that require delivery
\nof assets within a time frame established by regulation
\nor convention in the marketplace (regular way trades) are
\nrecognised on the trade date, i.e., the date that the group
\ncommits to purchase or sell the asset.
\nFinancial assets are recognised initially at fair value,
\nnormally being the transaction price. In the case of \ufb01nancial
\nassets not at fair value through pro\ufb01t or loss, directly
\nattributable transaction costs are also included. The
\nsubsequent measurement of \ufb01nancial assets depends on
\ntheir classi\ufb01cation, as set out below. The group derecognizes
\n\ufb01nancial assets when the contractual rights to the cash \ufb02ows
\nexpire or the \ufb01nancial asset is transferred to a 3
\nrd
\nparty. This
\nincludes the derecognition of receivables for which discounting
\narrangements are entered into. The classi\ufb01cation depends on
\nthe business model for managing the \ufb01nancial assets and the
\ncontractual cash \ufb02ow characteristics of the \ufb01nancial asset.
\nSubsequent measurement
\n\u25a0
For purposes of subsequent measurement, \ufb01nancial assets
\nare classi\ufb01ed in 4 categories:
\n\u25a0
Financial assets at amortised cost (debt instruments)
\n\u25a0
Financial assets at fair value through OCI with recycling of
\ncumulative gains and losses (debt instruments)
\n\u25a0
Financial assets designated at fair value through OCI with no
\nrecycling of cumulative gains and losses upon derecognition
\n(equity instruments)
\n\u25a0
Financial assets at fair value through pro\ufb01t or loss
\n\u25a0
The group has not designated any \ufb01nancial assets at fair
\nvalue through pro\ufb01t or loss.
\n\u25a0
Financial assets at amortised cost (debt instruments)
\n\u25a0
The group measures \ufb01nancial assets at amortised cost if
\nboth of the following conditions are met:
\n\u25a0
The \ufb01nancial asset is held within a business model with
\nthe objective to hold \ufb01nancial assets in order to collect
\ncontractual cash \ufb02ows;
\nAnd
\n\u25a0
The contractual terms of the \ufb01nancial asset give rise on
\n
speci\ufb01ed dates to cash \ufb02ows that are solely payments of
\nprincipal and interest on the principal amount outstanding;
\nFinancial assets at amortised cost are subsequently measured
\nusing the e\ufb00ective interest (EIR) method and are subject to
\nimpairment. Gains and losses are recognised in pro\ufb01t or loss
\nwhen the asset is derecognised, modi\ufb01ed or impaired.
\nCash equivalents
\nCash equivalents are short-term, highly liquid investments that
\nare readily convertible to known amounts of cash, are subject
\nto insigni\ufb01cant risk of changes in value and generally have a
\nmaturity of three months or less from the date of acquisition.
\nCash equivalents are classi\ufb01ed as \ufb01nancial assets measured at
\namortised cost.
\nLoans granted
\nLoans granted that have \ufb01xed or determinable payments that
\nare not quoted in an active market are classi\ufb01ed as \ufb01nancial
\nassets at amortised cost and are measured at amortised cost
\nusing the e\ufb00ective interest method, less any impairment.
\nInterest income is recognised by applying the e\ufb00ective interest
\nrate.
\nLoans granted to related parties are normally interest-free
\nand do not have a \ufb01xed repayment structure. These loans
\nare classi\ufb01ed as \ufb01nancial assets at amortised cost and are
\nmeasured at amortised cost using the e\ufb00ective interest
\nmethod, less any impairment. E\ufb00ective interest rate being zero
\nin this case.
\nDerecognition
\nA \ufb01nancial asset (or, where applicable, a part of a \ufb01nancial
\nasset or part of a group of similar \ufb01nancial assets) is primarily
\nderecognised (i.e., removed from the group\u2019s consolidated
\nstatement of \ufb01nancial position) when:
\nThe rights to receive cash \ufb02ows from the asset have expired or
\nthe group has transferred its rights to receive cash \ufb02ows from
\nthe asset or has assumed an obligation to pay the received
\ncash \ufb02ows in full without material delay to a third party under
\na \u2018pass-through\u2019 arrangement; and either (a) the group has
\ntransferred substantially all the risks and rewards of the
\nasset, or (b) the group has neither transferred nor retained
\nsubstantially all the risks and rewards of the asset, but has
\ntransferred control of the asset.
\nWhen the group has transferred its rights to receive cash
\n\ufb02ows from an asset or has entered into a pass-through
\narrangement, it evaluates if, and to what extent, it has retained
\nthe risks and rewards of ownership. When it has neither
\ntransferred nor retained substantially all of the risks and
\nrewards of the asset, nor transferred control of the asset,
\nthe group continues to recognise the transferred asset to the
\nextent of its continuing involvement. In that case, the group
\nalso recognises an associated liability. The transferred asset
\nand the associated liability are measured on a basis that
\nre\ufb02ects the rights and obligations that the group has retained.
\nImpairment of \ufb01nancial assets
\nThe group recognises an allowance for expected credit losses
\n(ECLs) for all debt instruments not held at fair value through
\npro\ufb01t or loss. ECLs are based on the di\ufb00erence between the
\ncontractual cash \ufb02ows due in accordance with the contract and
\nall the cash \ufb02ows that the group expects to receive, discounted
\nat an approximation of the original e\ufb00ective interest rate. The
\nexpected cash \ufb02ows will include cash \ufb02ows from the sale of
\ncollateral held or other credit enhancements that are integral
\nto the contractual terms.
\nECLs are recognised in two stages. For credit exposures
\nfor which there has not been a signi\ufb01cant increase in credit
\nrisk since initial recognition, ECLs are provided for credit
\nlosses that result from default events that are possible
\nwithin the next 12 months (a 12-month ECL). For those credit
\nexposures for which there has been a signi\ufb01cant increase
\nin credit risk since initial recognition, a loss allowance is
\nrequired for credit losses expected over the remaining life
\nof the exposure, irrespective of the timing of the default (a
\nlifetime ECL).
\nFor trade receivables and contract assets, the group applies a
\nsimpli\ufb01ed approach in calculating ECLs. Therefore, the group
\ndoes not track changes in credit risk, but instead recognises a
\nloss allowance based on lifetime ECLs at each reporting date.
\nThe group has established a provision matrix that is based
\non its historical credit-loss experience, adjusted for forward-
\nlooking factors speci\ufb01c to the debtors and the economic
\nenvironment.
\nThe group considers a \ufb01nancial asset in default when
\ncontractual payments are 90 days past due. However, in
\ncertain cases, the group may also consider a \ufb01nancial asset
\nto be in default when internal or external information
\nindicates that the group is unlikely to receive the outstanding
\ncontractual amounts in full before taking into account any
\ncredit enhancements held by the group. A \ufb01nancial asset
\nis written o\ufb00 when there is no reasonable expectation of
\nrecovering the contractual cash \ufb02ows.
\n(ii)
Financial liabilities
\nInitial recognition and measurement
\nFinancial liabilities are classi\ufb01ed, at initial recognition, as
\n\ufb01nancial liabilities at fair value through pro\ufb01t or loss, \ufb01nancial
\nliabilities at amortised cost, payables, or as derivatives
\ndesignated as hedging instruments in an e\ufb00ective hedge, as
\nappropriate.
\nAll \ufb01nancial liabilities are recognised initially at fair value and,
\nin the case of loans and borrowings and payables, net of
\ndirectly attributable transaction costs.
\nThe group\u2019s \ufb01nancial liabilities include trade and other
\npayables, loans and borrowings including bank overdrafts, and
\nderivative \ufb01nancial instruments.
\nSubsequent measurement
\nAfter initial recognition, interest-bearing loans and borrowings
\nare subsequently measured at amortised cost using the EIR
\nmethod. Gains and losses are recognised in pro\ufb01t or loss
\nwhen the liabilities are derecognised as well as through the EIR
\namortisation process.
\nAmortised cost is calculated by taking into account any
\ndiscount or premium on acquisition and fees or costs that are
\nan integral part of the EIR. The EIR amortisation is included as
\n\ufb01nance costs in the statement of pro\ufb01t or loss.
\n
This category generally applies to interest-bearing loans and
\nborrowings. For more information, refer to note 20.
\nPayables are measure at their nominal amount when the e\ufb00ect
\nof discounting is not material.
\nForeign exchange gains and losses
\nFor \ufb01nancial liabilities that are denominated in a foreign
\ncurrency and are measured at amortised cost at the end of each
\nreporting period, the foreign exchange gains and losses are
\ndetermined based on the amortised cost of the instruments.
\nThese foreign exchange gains and losses are recognised in
\nthe \u2018foreign exchange gain/(loss)\u2019 line item in pro\ufb01t or loss for
\n\ufb01nancial liabilities that are not part of a designated hedging
\nrelationship. For those which are designated as a hedging
\ninstrument for a hedge of foreign currency risk foreign exchange
\ngains and losses are recognised in other comprehensive income
\nand accumulated in a separate component of equity.
\nThe fair value of \ufb01nancial liabilities denominated in a foreign
\ncurrency is determined in that foreign currency and translated
\nat the spot rate at the end of the reporting period. For \ufb01nancial
\nliabilities that are measured as at FVTPL, the foreign exchange
\ncomponent forms part of the fair value gains or losses and is
\nrecognised in pro\ufb01t or loss for \ufb01nancial liabilities that are not
\npart of a designated hedging relationship.
\nDerecognition of \ufb01nancial liabilities
\nThe group derecognises \ufb01nancial liabilities when, and only
\nwhen, the group\u2019s obligations are discharged, cancelled or
\nhave expired. The di\ufb00erence between the carrying amount of
\nthe \ufb01nancial liability derecognised and the consideration paid
\nand payable is recognised in pro\ufb01t or loss.
\nWhen the group exchanges with the existing lender one debt
\ninstrument into another one with substantially di\ufb00erent
\nterms, such exchange is accounted for as an extinguishment
\nof the original \ufb01nancial liability and the recognition of a new
\n\ufb01nancial liability. Similarly, the group accounts for substantial
\nmodi\ufb01cation of terms of an existing liability or part of it as
\nan extinguishment of the original \ufb01nancial liability and the
\nrecognition of a new liability. It is assumed that the terms are
\nsubstantially di\ufb00erent if the discounted present value of the
\ncash \ufb02ows under the new terms, including any fees paid net of
\nany fees received and discounted using the original e\ufb00ective
\nrate is at least 10 per cent di\ufb00erent from the discounted
\npresent value of the remaining cash \ufb02ows of the original
\n\ufb01nancial liability. If the modi\ufb01cation is not substantial, the
\ndi\ufb00erence between: (1) the carrying amount of the liability
\nbefore the modi\ufb01cation; and (2) the present value of the cash
\n\ufb02ows after modi\ufb01cation is recognised in pro\ufb01t or loss as the
\nmodi\ufb01cation gain or loss within other gains and losses.
\n(iii)
Fair value measurement
\nThe group measures derivatives at fair value at each balance
\nsheet date and, for the purposes of impairment testing,
\nuses fair value less costs to sell (FVLCD) to determine the
\nrecoverable amount of some of its non-\ufb01nancial assets.
\nFair value is the price that would be received to sell an asset
\nor paid to transfer a liability in an orderly transaction between
\nmarket participants at the measurement date. The fair value
\nmeasurement is based on the presumption that the transaction
\nto sell the asset or transfer the liability takes place either:
\n\u25a0
In the principal market for the asset or liability
\nOr
\n\u25a0
In the absence of a principal market, in the most
\nadvantageous market for the asset or liability
\nThe principal or the most advantageous market must be
\naccessible by the group.
\nThe fair value of an asset or a liability is measured using the
\nassumptions that market participants would use when pricing
\nthe asset or liability, assuming that market participants act in
\ntheir economic best interest.
\nA fair value measurement of a non-\ufb01nancial asset takes into
\naccount a market participant's ability to generate economic
\nbene\ufb01ts by using the asset in its highest and best use or by
\nselling it to another market participant that would use the
\nasset in its highest and best use.
\nThe group uses valuation techniques that are appropriate in
\nthe circumstances and for which su\ufb03cient data are available to
\nmeasure fair value, maximising the use of relevant observable
\ninputs and minimising the use of unobservable inputs.
\nAll assets and liabilities, for which fair value is measured
\nor disclosed in the \ufb01nancial statements, are categorised
\nwithin the fair value hierarchy, described as follows, based
\non the lowest-level input that is signi\ufb01cant to the fair value
\nmeasurement as a whole:
\nLevel 1
\u2013 Quoted (unadjusted) market prices in active
\nmarkets for identical assets or liabilities
\nLevel 2
\u2013 Valuation techniques for which the lowest-level
\ninput that is signi\ufb01cant to the fair value measurement is
\ndirectly or indirectly observable
\nLevel 3
\u2013 Valuation techniques for which the lowest-level
\ninput that is signi\ufb01cant to the fair value measurement is
\nunobservable
\n(iv)
O\ufb00setting of \ufb01nancial instruments
\nFinancial assets and \ufb01nancial liabilities are o\ufb00set, and the net
\namount is reported in the consolidated statement of \ufb01nancial
\nposition if there is a currently enforceable legal right to o\ufb00set
\nthe recognised amounts and there is an intention to settle
\non a net basis, to realise the assets and settle the liabilities
\nsimultaneously.
\n31U.
JOINT ARRANGEMENTS
\nJoint arrangements are arrangements of which two or more
\nparties have joint control. Joint control is the contractual agreed
\nsharing of control of the arrangement which exists only when
\ndecisions about the relevant activities require unanimous
\nconsent of the parties sharing control. Joint arrangements are
\nclassi\ufb01ed as either a joint operation or joint venture, based
\non the rights and obligations arising from the contractual
\nobligations between the parties to the arrangement.
\nTo the extent the joint arrangement provides the company
\nwith rights to the individual assets and obligations arising from
\nthe joint arrangement, the arrangement is classi\ufb01ed as a joint
\noperation and as such, the company recognises its:
\n
\u25a0
Assets, including its share of any assets held jointly;
\n\u25a0
Liabilities, including its share of any liabilities incurred
\njointly;
\n\u25a0
Revenue from the sale of its share of the output arising from
\nthe joint operation;
\n\u25a0
Share of revenue from the sale of the output by the joint
\noperation; and
\n\u25a0
Expenses, including its share of any expenses incurred
\njointly.
\nTo the extent the joint arrangement provides the company
\nwith rights to the net assets of the arrangement, the
\ninvestment is classi\ufb01ed as a joint venture and accounted for
\nusing the equity method. Under the equity method, the cost of
\nthe investment is adjusted by the post-acquisition changes in
\nthe company\u2019s share of the net assets of the venture.
\n31V.
CURRENT VERSUS NON-CURRENT CLASSIFICATION
\nThe group presents assets and liabilities in the statement of
\n\ufb01nancial position based on current/non-current classi\ufb01cation.
\nAn asset is current when it is either:
\n\u25a0
Expected to be realised or intended to be sold or consumed
\nin the normal operating cycle;
\n\u25a0
Held primarily for the purpose of trading;
\n\u25a0
Expected to be realised within 12 months after the reporting
\nperiod;
\n\u25a0
Cash or cash equivalent unless restricted from being
\nexchanged or used to settle a liability for at least 12 months
\nafter the reporting period.
\nAll other assets are classi\ufb01ed as non-current.
\nA liability is current when either:
\n\u25a0
It is expected to be settled in the normal operating cycle
\n\u25a0
It is held primarily for the purpose of trading
\n\u25a0
It is due to be settled within 12 months after the reporting
\nperiod
\n\u25a0
There is no unconditional right to defer the settlement of the
\nliability for at least 12 months after the reporting period
\nThe group classi\ufb01es all other liabilities as non-current.
\nDeferred tax assets and liabilities are classi\ufb01ed as non-current
\nassets and liabilities.
\n31W.
BUSINESS COMBINATIONS AND GOODWILL
\nIn order to consider an acquisition as a business combination,
\nthe acquired asset or groups of assets must constitute
\na business (an integrated set of operations and assets
\nconducted and managed for the purpose of providing
\na return to the investors). The combination consists of
\ninputs and processes applied to these inputs that have the
\nability to create output. Acquired businesses are included
\nin the \ufb01nancial statements from the transaction date. The
\ntransaction date is de\ufb01ned as the date on which the company
\nachieves control over the \ufb01nancial and operating assets. This
\ndate may di\ufb00er from the actual date on which the assets
\nare transferred. Comparative \ufb01gures are not adjusted for
\nacquired, sold or liquidated businesses. On acquisition of
\na licence that involves the right to explore for and produce
\npetroleum resources, it is considered in each case whether
\nthe acquisition should be treated as a business combination
\nor an asset purchase. Generally, purchases of licences in
\na development or production phase will be regarded as a
\nbusiness combination. Business combinations are accounted
\nfor using the acquisition method. The cost of an acquisition is
\nmeasured as the aggregate of the consideration transferred,
\nmeasured at acquisition date fair value and the amount of
\nany non-controlling interest (NCI) in the acquiree. For each
\nbusiness combination, the group elects whether to measure
\nNCI in the acquiree at fair value or at the proportionate share
\nof the acquiree\u2019s identi\ufb01able net assets. Acquisition related
\ncosts are expensed as incurred and included in administrative
\nexpenses.
\nThe initial accounting for a business combination can be
\nchanged if new information about the fair value at the
\nacquisition date is present. The allocation can be amended
\nwithin 12 months of the acquisition date [provided that the
\ninitial accounting at the acquisition date was determined
\nprovisionally]. The non-controlling interest is set to the non-
\ncontrolling interest\u2019s share of identi\ufb01able assets and liabilities
\n[alternative fair value]. The measurement principle is done
\nfor each business combination separately. When the group
\nacquires a business, it assesses the assets and liabilities
\nassumed for appropriate classi\ufb01cation and designation
\nin accordance with the contractual terms, economic
\ncircumstances and pertinent conditions as at the acquisition
\ndate. This includes the separation of embedded derivatives
\nin host contracts by the acquiree. Those acquired petroleum
\nreserves and resources that can be reliably measured are
\nrecognised separately in the assessment of fair values on
\nacquisition. Other potential reserves, resources and rights,
\nfor which fair values cannot be reliably measured, are not
\nrecognised separately, but instead are subsumed in goodwill.
\nGoodwill is recognised as the aggregate of the consideration
\ntransferred and the amount of any non-controlling interest
\nand deducted by the net of the acquisition-date amounts of
\nthe identi\ufb01able assets acquired and the liabilities assumed.
\nGoodwill is not depreciated but is tested at least annually for
\nimpairment. In connection with this, goodwill is allocated to
\ncash-generating units or groups of cash-generating units that
\nare expected to bene\ufb01t from synergies from the business
\ncombination.
\nTechnical goodwill is recognised due to the requirement
\nto recognise deferred tax for the di\ufb00erence between the
\nassigned fair values and the related tax base. In accordance
\nwith IAS 12, a provision is made for deferred tax corresponding
\nto the tax rate multiplied by the di\ufb00erence between the
\nfair values of the acquired assets and the transferred tax
\ndepreciation basis.
\nIf the fair value of the equity exceeds the acquisition cost in a
\nbusiness combination, the di\ufb00erence is recognised as income
\nimmediately on the acquisition date.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSummaryOfSignificantAccountingPoliciesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10185": {
"value": "31A. ADOPTION OF NEW AND REVISED ACCOUNTING
\nSTANDARDS
\nIASB has issued several amendments to standards or
\ninterpretations to standards e\ufb00ective as of 1 January 2022.
\nPetroNor have adopted these standards in the \ufb01nancial year,
\nthe impacts were not material to PetroNor\u2019s consolidated
\n\ufb01nancial statements upon adoption.
\nImpacts of other standards and amendments to standards,
\nand interpretations of standards, issued but not yet e\ufb00ective
\nare under assessment by PetroNor. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfInitialApplicationOfStandardsOrInterpretations",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10199": {
"value": "31B. CONSOLIDATION
\nThe consolidated \ufb01nancial statements comprise the \ufb01nancial
\nstatements of PetroNor E&P ASA (\u201cthe company\u201d, formerly
\nPetroNor E&P Ltd) and its subsidiaries for the year ended 31
\nDecember 2022 (together the group).
\nAn entity has been assessed as being controlled by the group
\nwhen the groups is exposed, or has the rights, to variable
\nreturns from its involvement with the entity and has the
\nability to a\ufb00ect those returns through its power over the
\nentity. Speci\ufb01cally, the group controls an entity if and only if
\nthe group has:
\n\u25a0
Power over the entity (i.e., existing rights that give it the
\ncurrent ability to direct the relevant activities of the entity)
\n\u25a0
Exposure, or rights, to variable returns from its involvement
\nwith the entity, and
\n\u25a0
The ability to use its power over the entity to a\ufb00ect its
\nreturns
\nWhen the group has less than a majority of the voting or
\nsimilar rights of an entity, the group considers all relevant facts
\nand circumstances in assessing whether it has power over an
\nentity, including:
\n\u25a0
The contractual arrangement with the other vote holders of
\nthe entity
\n\u25a0
Rights arising from other contractual arrangements
\n\u25a0
The group\u2019s voting rights and potential voting rights
\nThe group reassesses whether or not it controls an entity if
\nfacts and circumstances indicate that there are changes to
\none or more of the three elements of control. Consolidation
\nof a subsidiary begins when the group obtains control over
\nthe subsidiary and ceases when the group loses control of
\nthe subsidiary. Business combinations are accounted for by
\nusing the acquisition method. Assets, liabilities, income, and
\nexpenses of a subsidiary acquired or disposed of during the
\nyear are included in the statement of comprehensive income
\nfrom the date the group gains control until the date the group
\nceases to control the subsidiary.
\nPro\ufb01t or loss and each component of other comprehensive
\nincome (OCI) are attributed to the equity holders of the parent
\nof the group and to the non-controlling interests, even if this
\nresults in the non-controlling interests having a de\ufb01cit balance.
\nWhen necessary, adjustments are made to the \ufb01nancial
\nstatements of subsidiaries to bring their accounting policies
\n
into line with the group\u2019s accounting policies. All intra-group
\nassets and liabilities, equity, income, expenses, and cash \ufb02ows
\nrelating to transactions between members of the group are
\neliminated in full on consolidation.
\nA change in the ownership interest of a subsidiary, without a
\nloss of control, is accounted for as an equity transaction.
\nIf the group loses control over a subsidiary, it:
\n\u25a0
Derecognises the assets (including goodwill) and liabilities of
\nthe subsidiary.
\n\u25a0
Derecognises the carrying amount of any non-controlling
\ninterests
\n\u25a0
Derecognises the cumulative translation di\ufb00erences
\nrecorded in equity
\n\u25a0
Recognises the fair value of the consideration received
\n\u25a0
Recognises the fair value of any investment retained
\n\u25a0
Recognises any surplus or de\ufb01cit in pro\ufb01t or loss
\n\u25a0
Reclassi\ufb01es the parent\u2019s share of components previously
\nrecognised in OCI to pro\ufb01t or loss or retained earnings, as
\nappropriate, as would be required if the group had directly
\ndisposed of the related assets or liabilities.
\nJoint operations
\nA joint arrangement is a joint operation whereby the group and
\nthe other parties that have joint control over the arrangement,
\nhave contractual rights to the assets and obligation for the
\nliabilities relating to the arrangement. All decisions about the
\nrelevant activities require unanimous consent.
\nWhen assessing if a joint arrangement is joint operation,
\nthe group assesses the structure of the arrangement, the
\nlegal form, the contractual agreement and other facts and
\ncircumstances.
\nThe group recognises its assets, liabilities, revenue and
\nexpenses and its relative share of assets, liabilities, revenue,
\nand expenses of the joint operation.
\nWhen the group enters into transactions with a joint operation
\nin which it is a joint operator, the group recognises gains and
\nlosses resulting from such a transaction only to the extent of
\nthe other parties\u2019 interests in the joint operation.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10316": {
"value": "31C. SEGMENT REPORTING
\nAn operating segment is a component of an entity that
\nengages in business activities from which it may earn revenues
\nand incur expenses (including revenues and expenses relating
\nto transactions with other components of the same entity),
\nwhose operating results are regularly reviewed by the entity\u2019s
\nchief operating decision-makers to make decisions about
\nresources to be allocated to the segments and assess their
\nperformance and for which discrete \ufb01nancial information is
\navailable. This includes start-up operations which are yet to
\nearn revenues.
\nOperating segments have been identi\ufb01ed based on the
\ninformation available to chief operating decision-makers \u2013
\nbeing the board and the executive management team.
\nInformation about other business activities and operating
\nsegments that are below the quantitative criteria are
\ncombined and disclosed in a separate category called \u201call other
\nsegments\u201d. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForSegmentReportingExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10338": {
"value": "31D. FOREIGN CURRENCY TRANSLATION
\nFunctional and presentation currency
\nThe company has applied United States Dollars, being the
\nfunctional currency of all major subsidiaries in the group, as
\nits presentation currency. Where the functional currencies
\nof entities within the consolidated group di\ufb00er from United
\nStates Dollars, they have been translated into United States
\nDollars. The functional currency of PetroNor E&P ASA is
\nNorwegian Kroner.
\nTransactions and balances
\nTransactions in foreign currencies are initially recorded in the
\nfunctional currency by applying the exchange rates ruling at
\nthe date of the transaction. Monetary assets and liabilities
\ndenominated in foreign currencies are retranslated at the
\nrate of exchange ruling at the reporting date and any gains or
\nlosses are recognised in the income statement.
\nNon-monetary items that are measured in terms of historical
\ncost in the foreign currency are translated using the exchange
\nrate as at the date of the initial transaction. Non-monetary
\nitems measured at fair value in a foreign currency are
\ntranslated using the exchange rates at the date when the fair
\nvalue was determined.
\nTranslation of group companies' functional currency to
\npresentation currency
\nOn consolidation, the assets and liabilities of foreign
\noperations are translated into United States Dollars at the rate
\nof exchange prevailing at the reporting date and their income
\nand expenditure are translated at exchange rates prevailing
\nat the dates of the transactions. The exchange di\ufb00erences
\narising on translation for consolidation are recognised in other
\ncomprehensive income. On disposal of a foreign operation, the
\ncomponent of other comprehensive income relating to that
\nparticular foreign operation is recognised in pro\ufb01t or loss.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10342": {
"value": "Functional and presentation currency The company has applied United States Dollars, being the
\nfunctional currency of all major subsidiaries in the group, as
\nits presentation currency. Where the functional currencies
\nof entities within the consolidated group di\ufb00er from United
\nStates Dollars, they have been translated into United States
\nDollars. The functional currency of PetroNor E&P ASA is
\nNorwegian Kroner. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10378": {
"value": "31E. CASH AND CASH EQUIVALENTS
\nCash and cash equivalents include cash on hand, deposits held
\nat call with banks, other short-term highly liquid investments
\nwith original maturities of three months or less, and bank
\noverdrafts. Bank overdrafts are shown within short-term
\nborrowings in current liabilities on the Statement of Financial
\nPosition.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10389": {
"value": "31F. TRADE RECEIVABLES
\nTrade receivables are amounts due from customers for goods
\nsold or services performed in the ordinary course of business.
\nThey are generally due for settlement within 30 to 90 days
\nand therefore are all classi\ufb01ed as current. Trade receivables
\nare recognised initially at the amount of consideration that
\nis unconditional unless they contain signi\ufb01cant \ufb01nancing
\ncomponents, when they are recognised at fair value. The
\ngroup holds the trade receivables with the objective to collect
\nthe contractual cash \ufb02ows and therefore measures them
\nsubsequently at amortised cost using the e\ufb00ective interest
\nmethod.
\nTrade receivables are written o\ufb00 when there is no reasonable
\nexpectation of recovery. Indicators that there is no reasonable
\nexpectation of recovery include, amongst others, the failure
\nof a debtor to engage in a repayment plan with the group, and
\na failure to make contractual payments for a period of greater
\nthan 120 days past due.
\n
Impairment losses on trade receivables and contract assets
\nare presented as net impairment losses within operating
\npro\ufb01t. Subsequent recoveries of amounts previously written
\no\ufb00 are credited against the same line item.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherReceivablesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10436": {
"value": "31G. INVENTORY
\nThe crude oil inventory and the material and supplies
\ninventory are valued at the lower of cost and net realisable
\nvalue. Cost is determined using the weighted average method.
\nNet realisable value is the estimated selling price, less
\napplicable selling expenses. The cost of inventory includes all
\ncosts related to bringing the inventory to its current condition,
\nincluding processing costs, labour costs, supplies, direct
\nand allocated indirect operating overhead and depreciation
\nexpense, where applicable, including allocation of \ufb01xed and
\nvariable costs to inventory.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForMeasuringInventories",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10451": {
"value": "31H. TANGIBLE ASSETS
\nProperty, plant, and equipment
\nOil & gas production assets
\nOil and gas production assets are aggregated exploration and
\nevaluation tangible assets and development expenditures
\nassociated with the production of proved reserves.
\nThe cost of development and production assets also includes
\nthe cost of acquisitions and purchases of such assets, directly
\nattributable overheads and the cost of recognising provisions
\nfor future restoration and decommissioning.
\nWhere major and identi\ufb01able parts of the production assets
\nhave di\ufb00erent useful lives, they are accounted for as separate
\nitems of property, plant, and equipment. Costs of minor
\nrepairs and maintenance are expensed as incurred. Oil and
\ngas production assets have a \ufb01nite life.
\nDepreciation
\nOil and gas properties are depreciated using the unit-of-
\nproduction method. Unit of production rates are based on 1P
\nproved reserves, which are oil, gas and other mineral reserves
\nestimated to be recovered from existing facilities using current
\noperating methods. Oil and gas volumes are considered
\nproduced once they have been measured through meters at
\ncustody transfer or sales transaction points at the outlet valve
\non the \ufb01eld storage tank.
\nField infrastructure exceeding beyond the life of the \ufb01eld is
\ndepreciated over the useful life of the infrastructure using a
\nstraight-line method.
\nProperty, plant, and equipment not associated with
\nexploration and production activities are carried at cost less
\naccumulated depreciation. These assets are also evaluated for
\nimpairment. Depreciation of other assets is calculated on a
\nstraight-line basis as follows:
\nComputer equipment
20 \u2013 33.33%
\nFurniture, \ufb01xtures, & \ufb01ttings
10 \u2013 33.33%
\nMotor vehicles
20%",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10452": {
"value": "31H. TANGIBLE ASSETS
\nProperty, plant, and equipment
\nOil & gas production assets
\nOil and gas production assets are aggregated exploration and
\nevaluation tangible assets and development expenditures
\nassociated with the production of proved reserves.
\nThe cost of development and production assets also includes
\nthe cost of acquisitions and purchases of such assets, directly
\nattributable overheads and the cost of recognising provisions
\nfor future restoration and decommissioning.
\nWhere major and identi\ufb01able parts of the production assets
\nhave di\ufb00erent useful lives, they are accounted for as separate
\nitems of property, plant, and equipment. Costs of minor
\nrepairs and maintenance are expensed as incurred. Oil and
\ngas production assets have a \ufb01nite life.
\nDepreciation
\nOil and gas properties are depreciated using the unit-of-
\nproduction method. Unit of production rates are based on 1P
\nproved reserves, which are oil, gas and other mineral reserves
\nestimated to be recovered from existing facilities using current
\noperating methods. Oil and gas volumes are considered
\nproduced once they have been measured through meters at
\ncustody transfer or sales transaction points at the outlet valve
\non the \ufb01eld storage tank.
\nField infrastructure exceeding beyond the life of the \ufb01eld is
\ndepreciated over the useful life of the infrastructure using a
\nstraight-line method.
\nProperty, plant, and equipment not associated with
\nexploration and production activities are carried at cost less
\naccumulated depreciation. These assets are also evaluated for
\nimpairment. Depreciation of other assets is calculated on a
\nstraight-line basis as follows:
\nComputer equipment
20 \u2013 33.33%
\nFurniture, \ufb01xtures, & \ufb01ttings
10 \u2013 33.33%
\nMotor vehicles
20%",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10458": {
"value": "Oil & gas production assets Oil and gas production assets are aggregated exploration and
\nevaluation tangible assets and development expenditures
\nassociated with the production of proved reserves.
\nThe cost of development and production assets also includes
\nthe cost of acquisitions and purchases of such assets, directly
\nattributable overheads and the cost of recognising provisions
\nfor future restoration and decommissioning.
\nWhere major and identi\ufb01able parts of the production assets
\nhave di\ufb00erent useful lives, they are accounted for as separate
\nitems of property, plant, and equipment. Costs of minor
\nrepairs and maintenance are expensed as incurred. Oil and
\ngas production assets have a \ufb01nite life.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForOilAndGasAssetsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10473": {
"value": "Depreciation
\nOil and gas properties are depreciated using the unit-of-
\nproduction method. Unit of production rates are based on 1P
\nproved reserves, which are oil, gas and other mineral reserves
\nestimated to be recovered from existing facilities using current
\noperating methods. Oil and gas volumes are considered
\nproduced once they have been measured through meters at
\ncustody transfer or sales transaction points at the outlet valve
\non the \ufb01eld storage tank.
\nField infrastructure exceeding beyond the life of the \ufb01eld is
\ndepreciated over the useful life of the infrastructure using a
\nstraight-line method.
\nProperty, plant, and equipment not associated with
\nexploration and production activities are carried at cost less
\naccumulated depreciation. These assets are also evaluated for
\nimpairment. Depreciation of other assets is calculated on a
\nstraight-line basis as follows:
\nComputer equipment
20 \u2013 33.33%
\nFurniture, \ufb01xtures, & \ufb01ttings
10 \u2013 33.33%
\nMotor vehicles
20%
Depreciation
\nLicence related costs capitalised as Intangible assets are
\ndepreciated using the unit-of-production method. Unit-of
\nproduction rates are based on 1P proved reserves, which are
\noil, gas and other mineral reserves estimated to be recovered
\nfrom existing facilities using current operating methods. Oil
and gas volumes are considered produced once they have
\nbeen measured through meters at custody transfer or sales
\ntransaction points at the outlet valve on the \ufb01eld storage tank.
\nTechnical goodwill
\nTechnical goodwill recognised in business combinations
\nis allocated to each CGU for the purposes of impairment
\ntesting. Impairment is tested on an annual basis or when
\nthere are impairment indicators. Indicators may be speci\ufb01c
\nto an individual CGU or groups of CGUs to which the technical
\ngoodwill is related. When conducting impairment testing,
\ndeferred tax recognised in relation to the acquired licences
\nreduces the net carrying value prior to the impairment
\ncharges.
\nImpairment is recognised if the recoverable amount of the
\nCGU (or groups of CGUs) to which the technical goodwill relates
\nto is less than the carrying amount.
\nImpairment of goodwill cannot be reversed in future periods.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10502": {
"value": "31I. INTANGIBLE ASSETS
\nExploration and evaluation activity involves the search for
\nhydrocarbon resources, the determination of technical
\nfeasibility and the assessment of commercial viability of an
\nidenti\ufb01ed resource. For each area of interest, expenditure
\nincurred in the acquisition of rights to explore and all costs
\ndirectly associated with holding the licence such as rental,
\ntraining and corporate and social responsibility are capitalised
\nas exploration and evaluation intangible assets. Signature
\nbonuses required by licence agreements are capitalised as
\nexploration and evaluation intangible assets. Other costs
\ndirectly associated with the licence are expensed as incurred.
\nExploration, evaluation, and development expenditure is
\nrecorded at historical cost and allocated to cost pools on
\nan area of interest. Expenditure on an area of interest is
\ncapitalised and carried forward where rights to tenure of the
\narea of interest are current and:
\n\u25a0
it is expected to be recouped through successful
\ndevelopment and exploitation of the area of interest or
\nalternatively by its sale; or
\n\u25a0
exploration and evaluation activities are continuing in
\nan area of interest but at reporting date have not yet
\nreached a stage which permits a reasonable assessment
\nof the existence or otherwise of economically recoverable
\nreserves.
\nAccumulated costs in respect of areas of interest which are
\nabandoned are written o\ufb00 in full against pro\ufb01t in the period in
\nwhich the decision to abandon the area is made.
\nProjects are advanced to development status when it is
\nexpected that further expenditure can be recouped through
\nsale or successful development and exploitation of the area of
\ninterest.
\nAll capitalised costs are subject to commercial and
\nmanagement review, as well as review for indicators of
\nimpairment at least once a year. This is to con\ufb01rm the
\ncontinued intent to develop or otherwise extract value from
\nthe discovery. When this is no longer the case, the costs are
\nwritten o\ufb00 through the statement of pro\ufb01t or loss and other
\ncomprehensive income.
\nWhen proved reserves of oil and natural gas are identi\ufb01ed
\nand development is sanctioned by management, the relevant
\ncapitalised expenditure is \ufb01rst assessed for impairment and
\n(if required) any impairment loss is recognised, then the
\nremaining balance is transferred to oil and gas properties.
\nProceeds from disposal or farm-out transactions of intangible
\nexploration assets are used to reduce the carrying amount of
\nthe assets. When proceeds exceed the carrying amount, the
\ndi\ufb00erence is recognised as a gain. When the group disposes of
\nits full interests, gains or losses are recognised in accordance
\nwith the policy for recognising gains or losses on sale of plant,
\nproperty, and equipment.
\nGenerally Intangible assets can be viewed inde\ufb01nite as
\nthey will be retained on the balance sheet until impaired or
\ntransferred to oil and gas properties. Certain licence related
\ncosts capitalised as intangible assets are deemed to have a
\n\ufb01nite life and are accreted over the life of the licence area.
\nDepreciation
\nLicence related costs capitalised as Intangible assets are
\ndepreciated using the unit-of-production method. Unit-of
\nproduction rates are based on 1P proved reserves, which are
\noil, gas and other mineral reserves estimated to be recovered
\nfrom existing facilities using current operating methods. Oil
\n
and gas volumes are considered produced once they have
\nbeen measured through meters at custody transfer or sales
\ntransaction points at the outlet valve on the \ufb01eld storage tank.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsOtherThanGoodwillExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10503": {
"value": "31I. INTANGIBLE ASSETS
\nExploration and evaluation activity involves the search for
\nhydrocarbon resources, the determination of technical
\nfeasibility and the assessment of commercial viability of an
\nidenti\ufb01ed resource. For each area of interest, expenditure
\nincurred in the acquisition of rights to explore and all costs
\ndirectly associated with holding the licence such as rental,
\ntraining and corporate and social responsibility are capitalised
\nas exploration and evaluation intangible assets. Signature
\nbonuses required by licence agreements are capitalised as
\nexploration and evaluation intangible assets. Other costs
\ndirectly associated with the licence are expensed as incurred.
\nExploration, evaluation, and development expenditure is
\nrecorded at historical cost and allocated to cost pools on
\nan area of interest. Expenditure on an area of interest is
\ncapitalised and carried forward where rights to tenure of the
\narea of interest are current and:
\n\u25a0
it is expected to be recouped through successful
\ndevelopment and exploitation of the area of interest or
\nalternatively by its sale; or
\n\u25a0
exploration and evaluation activities are continuing in
\nan area of interest but at reporting date have not yet
\nreached a stage which permits a reasonable assessment
\nof the existence or otherwise of economically recoverable
\nreserves.
\nAccumulated costs in respect of areas of interest which are
\nabandoned are written o\ufb00 in full against pro\ufb01t in the period in
\nwhich the decision to abandon the area is made.
\nProjects are advanced to development status when it is
\nexpected that further expenditure can be recouped through
\nsale or successful development and exploitation of the area of
\ninterest.
\nAll capitalised costs are subject to commercial and
\nmanagement review, as well as review for indicators of
\nimpairment at least once a year. This is to con\ufb01rm the
\ncontinued intent to develop or otherwise extract value from
\nthe discovery. When this is no longer the case, the costs are
\nwritten o\ufb00 through the statement of pro\ufb01t or loss and other
\ncomprehensive income.
\nWhen proved reserves of oil and natural gas are identi\ufb01ed
\nand development is sanctioned by management, the relevant
\ncapitalised expenditure is \ufb01rst assessed for impairment and
\n(if required) any impairment loss is recognised, then the
\nremaining balance is transferred to oil and gas properties.
\nProceeds from disposal or farm-out transactions of intangible
\nexploration assets are used to reduce the carrying amount of
\nthe assets. When proceeds exceed the carrying amount, the
\ndi\ufb00erence is recognised as a gain. When the group disposes of
\nits full interests, gains or losses are recognised in accordance
\nwith the policy for recognising gains or losses on sale of plant,
\nproperty, and equipment.
\nGenerally Intangible assets can be viewed inde\ufb01nite as
\nthey will be retained on the balance sheet until impaired or
\ntransferred to oil and gas properties. Certain licence related
\ncosts capitalised as intangible assets are deemed to have a
\n\ufb01nite life and are accreted over the life of the licence area.
\nDepreciation
\nLicence related costs capitalised as Intangible assets are
\ndepreciated using the unit-of-production method. Unit-of
\nproduction rates are based on 1P proved reserves, which are
\noil, gas and other mineral reserves estimated to be recovered
\nfrom existing facilities using current operating methods. Oil
\n
and gas volumes are considered produced once they have
\nbeen measured through meters at custody transfer or sales
\ntransaction points at the outlet valve on the \ufb01eld storage tank.
\nTechnical goodwill
\nTechnical goodwill recognised in business combinations
\nis allocated to each CGU for the purposes of impairment
\ntesting. Impairment is tested on an annual basis or when
\nthere are impairment indicators. Indicators may be speci\ufb01c
\nto an individual CGU or groups of CGUs to which the technical
\ngoodwill is related. When conducting impairment testing,
\ndeferred tax recognised in relation to the acquired licences
\nreduces the net carrying value prior to the impairment
\ncharges.
\nImpairment is recognised if the recoverable amount of the
\nCGU (or groups of CGUs) to which the technical goodwill relates
\nto is less than the carrying amount.
\nImpairment of goodwill cannot be reversed in future periods.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsAndGoodwillExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10615": {
"value": "31J. BORROWING COSTS
\nBorrowing costs that are directly attributable to the
\nacquisition, construction or production of a qualifying non-
\ncurrent asset are added to the cost of the asset during the
\nperiod of time that is required to complete and prepare the
\nasset for its intended use. Borrowing costs are capitalised to
\nthe extent that funds are borrowed speci\ufb01cally for the purpose
\nof obtaining a qualifying asset. To the extent that funds are
\nborrowed generally and used for the purpose of obtaining a
\nqualifying asset, the amount of borrowing costs eligible for
\ncapitalisation is determined by applying a capitalisation rate to
\nthe expenditures on that asset. All other borrowing costs are
\nexpensed as incurred.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingCostsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10632": {
"value": "31K. REVENUE
\n(i)
Revenue from petroleum products
\nRevenue from the sale of crude oil is recognised when a
\ncustomer obtains control (\u201csales\u201d or \u201clifting\u201d method), normally
\nthis is when title passes at point of delivery. Revenues from
\nproduction of oil properties are recognised based on actual
\nvolumes lifted and sold to customers during the period.
\n(ii)
Other revenue
\nUnder a production sharing contract, where the group is
\nrequired to pay pro\ufb01t oil tax and royalties on production
\nof crude oil, such payments are settled in kind (where the
\ngovernment lift the crude it is entitled to). The group presents
\na gross-up of the pro\ufb01t oil tax as an income tax expense with
\na corresponding increase in oil and gas revenues and any
\nassociated royalties are included in the cost of sales.
\nThe group assesses whether it acts as a principal or agent in
\neach of its revenue arrangements. The group has concluded
\nthat in all sales transactions it acts as a principal.
\n(iii)
Variable consideration
\nIf the consideration in a contract includes a variable amount,
\nthe group recognises this amount as revenue only to the
\nextent that it is highly probable that a signi\ufb01cant reversal will
\nnot occur in the future.
\n(iv)
Interest
\nInterest income is recognised on a time-proportional basis
\nusing the e\ufb00ective interest method. This is a method of
\ncalculating the amortised cost of a \ufb01nancial asset and
\nallocating the interest income over the relevant period using
\nthe e\ufb00ective interest rate, which is the rate that exactly
\ndiscounts the estimated future cash receipts through the
\nexpected useful life of the \ufb01nancial asset to the net carrying
\namount of the \ufb01nancial asset.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10661": {
"value": "(iv) Interest
\nInterest income is recognised on a time-proportional basis
\nusing the e\ufb00ective interest method. This is a method of
\ncalculating the amortised cost of a \ufb01nancial asset and
\nallocating the interest income over the relevant period using
\nthe e\ufb00ective interest rate, which is the rate that exactly
\ndiscounts the estimated future cash receipts through the
\nexpected useful life of the \ufb01nancial asset to the net carrying
amount of the \ufb01nancial asset.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForInterestIncomeAndExpenseExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10675": {
"value": "31L. LEASES
\nThe group as lessee
\nThe group assesses whether contract is or contains a lease,
\nat inception of the contract. The group recognises a right-of-
\nuse asset and a corresponding lease liability with respect to all
\nlease arrangements in which it is the lessee, except for short-
\nterm leases (de\ufb01ned as leases with a lease term of 12 months
\nor less) and leases of low value assets. For these leases, the
\ngroup recognises the lease payments as an operating expense
\non a straight-line basis over the term of the lease unless
\nanother systematic basis is more representative of the time
\npattern in which economic bene\ufb01ts from the leased assets are
\nconsumed.
\nThe lease liability is initially measured at the present value of
\nthe lease payments that are not paid at the commencement
\ndate, discounted by using the rate implicit in the lease. If
\nthis rate cannot be readily determined, the group uses its
\nincremental borrowing rate.
\nLease payments included in the measurement of the lease
\nliability comprise:
\n\u25a0
\ufb01xed lease payments (including in-substance \ufb01xed
\npayments), less any lease incentives;
\n\u25a0
variable lease payments that depend on an index or
\nrate, initially measured using the index or rate at the
\ncommencement date;
\n\u25a0
the amount expected to be payable by the lessee under
\nresidual value guarantees;
\n\u25a0
the exercise price of purchase options, if the lessee is
\nreasonably certain to exercise the options; and
\n\u25a0
payments of penalties for terminating the lease, if the lease
\nterm re\ufb02ects the exercise of an option to terminate the
\nlease.
\nThe lease liability is presented as a separate line item in the
\nstatement of \ufb01nancial position.
\nThe lease liability is subsequently measured by increasing
\nthe carrying amount to re\ufb02ect interest on the lease liability
\n(using e\ufb00ective interest method) and by reducing the carrying
\namount to re\ufb02ect the lease payments made.
\nThe group remeasures the lease liability (and makes a
\ncorresponding adjustment to the related right-of-use asset)
\nwhenever:
\n\u25a0
the lease term has changed or there is a change in the
\nassessment of exercise of a purchase option, in which case
\nthe lease liability is remeasured by discounting the revised
\nlease payments using a revised discount rate.
\n\u25a0
the lease payments change due to changes in an index or
\nrate or a change in expected payment under a guaranteed
\nresidual value, in which cases the lease liability is
\nremeasured by discounting the revised lease payments
\nusing the initial discount rate (unless the lease payments
\n
change is due to a change in a \ufb02oating interest rate, in which
\ncase a revise discount rate is used).
\n\u25a0
a lease contract is modi\ufb01ed, and the lease modi\ufb01cation is
\nnot accounted for as a separate lease, in which case the
\nlease liability is remeasured by discounting the revised lease
\npayments using a revised discount rate.
\nThe group did not make any such adjustments during the
\nperiods presented.
\nRight of use assets
\nThe group measures the right-of use asset at cost, less any
\naccumulated depreciation and impairment losses, adjusted for
\nany remeasurement of lease liabilities. The cost of the right-of-
\nuse asset comprise:
\n\u25a0
The amount of the initial measurement of the lease liability
\nrecognised
\n\u25a0
Any lease payments made at or before the commencement
\ndate, less any incentives received
\n\u25a0
Any initial direct costs incurred by the group. An estimate
\nof the costs to be incurred by the group in dismantling and
\nremoving the underlying asset, restoring the site on which it
\nis located or restoring the underlying asset to the condition
\nrequired by the terms and conditions of the lease, unless
\nthose costs are incurred to produce inventories.
\nThe group applies the depreciation requirements in IAS 16
\nProperty, Plant and Equipment in depreciating the right-of-use
\nasset, except that the right-of-use asset is depreciated from
\nthe commencement date to the earlier of the lease term and
\nthe remaining useful life of the right-of-use asset.
\nThe group applies IAS 36 Impairment of Assets to determine
\nwhether the right-of-use asset is impaired and to account for
\nany impairment loss identi\ufb01ed.
\nVariable rents that do not depend on an index or rate are not
\nincluded in the measurement of the lease liability and the
\nright-of-use asset. The related payments are recognised as
\nan expense in the period in which the event or condition that
\ntriggers those payments occurs and are included in the line
\n\u2018Administrative expenses\u2019 in the statement of pro\ufb01t or loss.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10798": {
"value": "31M. TAXES
\nThe income tax expense or bene\ufb01t for the period consists of
\ntwo components: current and deferred tax.
\nThe current income tax payable or recoverable is calculated
\nusing the tax rates and legislation that have been enacted or
\nsubstantively enacted at year-end in each of the jurisdictions
\nand includes any adjustments for taxes payable or recovery in
\nrespect of prior periods.
\nDeferred tax assets and liabilities are determined using
\nthe balance sheet liability method based on temporary
\ndi\ufb00erences between the carrying value of assets and liabilities
\nfor \ufb01nancial reporting purposes and their tax bases. In
\ncalculating the deferred tax assets and liabilities, the tax
\nrates used are those that have been enacted or substantively
\nenacted by year-end in each of the jurisdictions and that
\nare expected to apply when the assets are recovered, or the
\nliabilities are settled.
\nRevenue-based taxes
\nIn addition to corporate income taxes, the group\u2019s
\nconsolidated \ufb01nancial statements also include and recognise
\nas income taxes, other types of taxes on net income such as
\ncertain revenue-based taxes.
\nProduction-sharing arrangements
\nAccording to the production-sharing arrangement (PSA)
\nin certain licences, the share of the pro\ufb01t oil to which the
\ngovernment is entitled in any calendar year in accordance
\nwith the PSA is deemed to include a portion representing the
\ncorporate income tax imposed upon and due by the group.
\nThis amount will be paid directly by the government on behalf
\nof the group to the appropriate tax authorities.
\nThe income tax expense
\nThe current income tax is calculated using the PSA, paid in
\nbarrels and booked as income tax and also shown as revenue.
\nSales tax
\nRevenues, expenses and assets are recognised net of the
\namount of sales tax except:
\nWhere the sales tax incurred on a purchase of assets or
\nservices is not recoverable from the taxation authority, in
\nwhich case, the sales tax is recognised as part of the cost
\nof acquisition of the asset or as part of the expense item as
\napplicable.
\nReceivables and payables that are stated with the amount of
\nsales tax included.
\nThe net amount of sales tax recoverable from, or payable to,
\nthe taxation authority is included as part of receivables or
\npayables in the statement of \ufb01nancial position.
\nCurrent and deferred tax balances attributable to amounts
\nrecognised directly in equity are also recognised directly in
\nequity.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10809": {
"value": "Deferred tax assets and liabilities are determined using the balance sheet liability method based on temporary
\ndi\ufb00erences between the carrying value of assets and liabilities
\nfor \ufb01nancial reporting purposes and their tax bases. In
\ncalculating the deferred tax assets and liabilities, the tax
\nrates used are those that have been enacted or substantively
\nenacted by year-end in each of the jurisdictions and that
\nare expected to apply when the assets are recovered, or the
\nliabilities are settled.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10854": {
"value": "31N. EMPLOYEE BENEFITS
\nProvision is made for bene\ufb01ts accruing to employees in
\nrespect of wages and salaries, annual leave, and long service
\nleave when it is probable that settlement will be required, and
\nthey are capable of being measured reliably. Provisions made
\nin respect of employee bene\ufb01ts expected to be settled within
\n12 months are measured at their nominal values using the
\nremuneration rate expected to apply at the time of settlement.
\nProvisions made in respect of employee bene\ufb01ts, which are
\nnot due to be settled within 12 months are determined using
\nthe projected unit credit method.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10869": {
"value": "31O. DEFINED CONTRIBUTION PENSION PLAN
\nThe group pays contributions into de\ufb01ned contribution plans.
\nObligations for contributions to de\ufb01ned contribution pension
\nplans are recognised as an expense in the income statement in
\nthe periods during which services are rendered by employees.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDefinedBenefitPlansExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10878": {
"value": "31P. TRADE AND OTHER PAYABLES
\nTrade and other payables are carried at amortised cost and
\ndue to their short-term nature, they are not discounted.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherPayablesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10885": {
"value": "31Q. PROVISIONS
\n(i)
General
\nProvisions are recognised when the group has a present
\nobligation (legal or constructive) as a result of a past event, it
\nis probable that an out\ufb02ow of resources embodying economic
\n
bene\ufb01ts will be required to settle the obligation and a reliable
\nestimate can be made of the amount of the obligation.
\nWhere the group expects some or all of the provision to be
\nreimbursed, for example under an insurance contract, the
\nreimbursement is recognised as a separate asset but only
\nwhen the reimbursement is virtually certain. The expense
\nrelating to any provision is recognised through pro\ufb01t and loss
\nnet of any reimbursement. If the e\ufb00ect of the time value of
\nmoney is material, provisions are discounted using a current
\npre-tax rate that re\ufb02ects, where appropriate, the risks speci\ufb01c
\nto the liability. Where discounting is used, the increase in the
\nprovision due to the passage of time is recognised as interest
\nexpense. The present obligation under onerous contracts is
\nrecognised as a provision.
\n(ii)
Decommissioning liability
\nA decommissioning liability is recognised when the group has
\na present legal or constructive obligation as a result of past
\nevents, and it is probable that an out\ufb02ow of resources will be
\nrequired to settle the obligation, and a reliable estimate of the
\namount of obligation can be made. A corresponding amount
\nequivalent to the obligation is also recognised as part of the
\ncost of the related production plant and equipment. The
\namount recognised in the estimated cost of decommissioning,
\ndiscounted to its present value. Changes in the estimated
\ntiming of decommissioning or decommissioning cost estimates
\nare dealt with prospectively by recording an adjustment to
\nthe provision, and a corresponding adjustment to production
\nplant and equipment. The unwinding of the discount on the
\ndecommissioning liability is included as a \ufb01nance cost.
\nAn escrow account is maintained by the operator of the PNGF
\nSud licence and is governed by a joint operating agreement
\nand the Congolese Government rules. The group\u2019s share, paid
\nagainst the decommissioning liability until the balance sheet
\ndate, is classi\ufb01ed as an advance against decommissioning
\nliability in current assets. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10952": {
"value": "31R. SHARE CAPITAL
\nContributed equity is recognised at the fair value of the
\nconsideration received by the group, less any capital raising
\ncosts in relation to the issue.
\nIncremental costs directly attributable to the issue of new
\nshares or options are shown in equity as a deduction, net of
\ntax, from the proceeds. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIssuedCapitalExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10963": {
"value": "31S. DIVIDEND DISTRIBUTION
\nDividend distribution to the company\u2019s shareholders is
\nrecognised as a liability in the group\u2019s \ufb01nancial statements
\nin the period in which the dividends are declared and
\nappropriately authorised or approved by the company\u2019s
\nshareholders\u2019 general meeting. Interim dividends proposed
\nby the board of directors are recognised as liabilities upon
\ndeclaration. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDividendsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10975": {
"value": "31T. FINANCIAL INSTRUMENTS
\nA \ufb01nancial instrument is any contract that gives rise to a
\n\ufb01nancial asset of any one entity and a \ufb01nancial liability or
\nequity instrument of another entity.
\n(i)
Financial assets
\nFinancial assets are classi\ufb01ed, at initial recognition, as
\nsubsequently measured at amortised cost, fair value through
\nother comprehensive income (OCI), and fair value through
\npro\ufb01t or loss, as appropriate.
\nThe classi\ufb01cation of \ufb01nancial assets at initial recognition
\ndepends on the \ufb01nancial asset\u2019s contractual cash \ufb02ow
\ncharacteristics and the group\u2019s business model for managing
\nthem. With the exception of trade receivables that do not
\ncontain a signi\ufb01cant \ufb01nancing component or for which the
\ngroup has applied the practical expedient, the group initially
\nmeasures a \ufb01nancial asset at its fair value plus, in the case
\nof \ufb01nancial assets not subsequently measured at fair value
\nthrough pro\ufb01t or loss, transaction costs that are attributable
\nto the acquisition of the \ufb01nancial asset.
\nIn order for a \ufb01nancial asset to be classi\ufb01ed and measured at
\namortised cost or fair value through OCI, it needs to give rise
\nto cash \ufb02ows that are solely payments of principal and interest
\n(SPPI) on the principal amount outstanding. This assessment is
\nreferred to as the SPPI test and is performed at an instrument
\nlevel.
\nThe group\u2019s business model for managing \ufb01nancial assets
\nrefers to how it manages its \ufb01nancial assets in order to
\ngenerate cash \ufb02ows. The business model determines whether
\ncash \ufb02ows will result from collecting contractual cash \ufb02ows,
\nselling the \ufb01nancial assets, or both.
\nPurchases or sales of \ufb01nancial assets that require delivery
\nof assets within a time frame established by regulation
\nor convention in the marketplace (regular way trades) are
\nrecognised on the trade date, i.e., the date that the group
\ncommits to purchase or sell the asset.
\nFinancial assets are recognised initially at fair value,
\nnormally being the transaction price. In the case of \ufb01nancial
\nassets not at fair value through pro\ufb01t or loss, directly
\nattributable transaction costs are also included. The
\nsubsequent measurement of \ufb01nancial assets depends on
\ntheir classi\ufb01cation, as set out below. The group derecognizes
\n\ufb01nancial assets when the contractual rights to the cash \ufb02ows
\nexpire or the \ufb01nancial asset is transferred to a 3
\nrd
\nparty. This
\nincludes the derecognition of receivables for which discounting
\narrangements are entered into. The classi\ufb01cation depends on
\nthe business model for managing the \ufb01nancial assets and the
\ncontractual cash \ufb02ow characteristics of the \ufb01nancial asset.
\nSubsequent measurement
\n\u25a0
For purposes of subsequent measurement, \ufb01nancial assets
\nare classi\ufb01ed in 4 categories:
\n\u25a0
Financial assets at amortised cost (debt instruments)
\n\u25a0
Financial assets at fair value through OCI with recycling of
\ncumulative gains and losses (debt instruments)
\n\u25a0
Financial assets designated at fair value through OCI with no
\nrecycling of cumulative gains and losses upon derecognition
\n(equity instruments)
\n\u25a0
Financial assets at fair value through pro\ufb01t or loss
\n\u25a0
The group has not designated any \ufb01nancial assets at fair
\nvalue through pro\ufb01t or loss.
\n\u25a0
Financial assets at amortised cost (debt instruments)
\n\u25a0
The group measures \ufb01nancial assets at amortised cost if
\nboth of the following conditions are met:
\n\u25a0
The \ufb01nancial asset is held within a business model with
\nthe objective to hold \ufb01nancial assets in order to collect
\ncontractual cash \ufb02ows;
\nAnd
\n\u25a0
The contractual terms of the \ufb01nancial asset give rise on
\n
speci\ufb01ed dates to cash \ufb02ows that are solely payments of
\nprincipal and interest on the principal amount outstanding;
\nFinancial assets at amortised cost are subsequently measured
\nusing the e\ufb00ective interest (EIR) method and are subject to
\nimpairment. Gains and losses are recognised in pro\ufb01t or loss
\nwhen the asset is derecognised, modi\ufb01ed or impaired.
\nCash equivalents
\nCash equivalents are short-term, highly liquid investments that
\nare readily convertible to known amounts of cash, are subject
\nto insigni\ufb01cant risk of changes in value and generally have a
\nmaturity of three months or less from the date of acquisition.
\nCash equivalents are classi\ufb01ed as \ufb01nancial assets measured at
\namortised cost.
\nLoans granted
\nLoans granted that have \ufb01xed or determinable payments that
\nare not quoted in an active market are classi\ufb01ed as \ufb01nancial
\nassets at amortised cost and are measured at amortised cost
\nusing the e\ufb00ective interest method, less any impairment.
\nInterest income is recognised by applying the e\ufb00ective interest
\nrate.
\nLoans granted to related parties are normally interest-free
\nand do not have a \ufb01xed repayment structure. These loans
\nare classi\ufb01ed as \ufb01nancial assets at amortised cost and are
\nmeasured at amortised cost using the e\ufb00ective interest
\nmethod, less any impairment. E\ufb00ective interest rate being zero
\nin this case.
\nDerecognition
\nA \ufb01nancial asset (or, where applicable, a part of a \ufb01nancial
\nasset or part of a group of similar \ufb01nancial assets) is primarily
\nderecognised (i.e., removed from the group\u2019s consolidated
\nstatement of \ufb01nancial position) when:
\nThe rights to receive cash \ufb02ows from the asset have expired or
\nthe group has transferred its rights to receive cash \ufb02ows from
\nthe asset or has assumed an obligation to pay the received
\ncash \ufb02ows in full without material delay to a third party under
\na \u2018pass-through\u2019 arrangement; and either (a) the group has
\ntransferred substantially all the risks and rewards of the
\nasset, or (b) the group has neither transferred nor retained
\nsubstantially all the risks and rewards of the asset, but has
\ntransferred control of the asset.
\nWhen the group has transferred its rights to receive cash
\n\ufb02ows from an asset or has entered into a pass-through
\narrangement, it evaluates if, and to what extent, it has retained
\nthe risks and rewards of ownership. When it has neither
\ntransferred nor retained substantially all of the risks and
\nrewards of the asset, nor transferred control of the asset,
\nthe group continues to recognise the transferred asset to the
\nextent of its continuing involvement. In that case, the group
\nalso recognises an associated liability. The transferred asset
\nand the associated liability are measured on a basis that
\nre\ufb02ects the rights and obligations that the group has retained.
\nImpairment of \ufb01nancial assets
\nThe group recognises an allowance for expected credit losses
\n(ECLs) for all debt instruments not held at fair value through
\npro\ufb01t or loss. ECLs are based on the di\ufb00erence between the
\ncontractual cash \ufb02ows due in accordance with the contract and
\nall the cash \ufb02ows that the group expects to receive, discounted
\nat an approximation of the original e\ufb00ective interest rate. The
\nexpected cash \ufb02ows will include cash \ufb02ows from the sale of
\ncollateral held or other credit enhancements that are integral
\nto the contractual terms.
\nECLs are recognised in two stages. For credit exposures
\nfor which there has not been a signi\ufb01cant increase in credit
\nrisk since initial recognition, ECLs are provided for credit
\nlosses that result from default events that are possible
\nwithin the next 12 months (a 12-month ECL). For those credit
\nexposures for which there has been a signi\ufb01cant increase
\nin credit risk since initial recognition, a loss allowance is
\nrequired for credit losses expected over the remaining life
\nof the exposure, irrespective of the timing of the default (a
\nlifetime ECL).
\nFor trade receivables and contract assets, the group applies a
\nsimpli\ufb01ed approach in calculating ECLs. Therefore, the group
\ndoes not track changes in credit risk, but instead recognises a
\nloss allowance based on lifetime ECLs at each reporting date.
\nThe group has established a provision matrix that is based
\non its historical credit-loss experience, adjusted for forward-
\nlooking factors speci\ufb01c to the debtors and the economic
\nenvironment.
\nThe group considers a \ufb01nancial asset in default when
\ncontractual payments are 90 days past due. However, in
\ncertain cases, the group may also consider a \ufb01nancial asset
\nto be in default when internal or external information
\nindicates that the group is unlikely to receive the outstanding
\ncontractual amounts in full before taking into account any
\ncredit enhancements held by the group. A \ufb01nancial asset
\nis written o\ufb00 when there is no reasonable expectation of
\nrecovering the contractual cash \ufb02ows.
\n(ii)
Financial liabilities
\nInitial recognition and measurement
\nFinancial liabilities are classi\ufb01ed, at initial recognition, as
\n\ufb01nancial liabilities at fair value through pro\ufb01t or loss, \ufb01nancial
\nliabilities at amortised cost, payables, or as derivatives
\ndesignated as hedging instruments in an e\ufb00ective hedge, as
\nappropriate.
\nAll \ufb01nancial liabilities are recognised initially at fair value and,
\nin the case of loans and borrowings and payables, net of
\ndirectly attributable transaction costs.
\nThe group\u2019s \ufb01nancial liabilities include trade and other
\npayables, loans and borrowings including bank overdrafts, and
\nderivative \ufb01nancial instruments.
\nSubsequent measurement
\nAfter initial recognition, interest-bearing loans and borrowings
\nare subsequently measured at amortised cost using the EIR
\nmethod. Gains and losses are recognised in pro\ufb01t or loss
\nwhen the liabilities are derecognised as well as through the EIR
\namortisation process.
\nAmortised cost is calculated by taking into account any
\ndiscount or premium on acquisition and fees or costs that are
\nan integral part of the EIR. The EIR amortisation is included as
\n\ufb01nance costs in the statement of pro\ufb01t or loss.
\n
This category generally applies to interest-bearing loans and
\nborrowings. For more information, refer to note 20.
\nPayables are measure at their nominal amount when the e\ufb00ect
\nof discounting is not material.
\nForeign exchange gains and losses
\nFor \ufb01nancial liabilities that are denominated in a foreign
\ncurrency and are measured at amortised cost at the end of each
\nreporting period, the foreign exchange gains and losses are
\ndetermined based on the amortised cost of the instruments.
\nThese foreign exchange gains and losses are recognised in
\nthe \u2018foreign exchange gain/(loss)\u2019 line item in pro\ufb01t or loss for
\n\ufb01nancial liabilities that are not part of a designated hedging
\nrelationship. For those which are designated as a hedging
\ninstrument for a hedge of foreign currency risk foreign exchange
\ngains and losses are recognised in other comprehensive income
\nand accumulated in a separate component of equity.
\nThe fair value of \ufb01nancial liabilities denominated in a foreign
\ncurrency is determined in that foreign currency and translated
\nat the spot rate at the end of the reporting period. For \ufb01nancial
\nliabilities that are measured as at FVTPL, the foreign exchange
\ncomponent forms part of the fair value gains or losses and is
\nrecognised in pro\ufb01t or loss for \ufb01nancial liabilities that are not
\npart of a designated hedging relationship.
\nDerecognition of \ufb01nancial liabilities
\nThe group derecognises \ufb01nancial liabilities when, and only
\nwhen, the group\u2019s obligations are discharged, cancelled or
\nhave expired. The di\ufb00erence between the carrying amount of
\nthe \ufb01nancial liability derecognised and the consideration paid
\nand payable is recognised in pro\ufb01t or loss.
\nWhen the group exchanges with the existing lender one debt
\ninstrument into another one with substantially di\ufb00erent
\nterms, such exchange is accounted for as an extinguishment
\nof the original \ufb01nancial liability and the recognition of a new
\n\ufb01nancial liability. Similarly, the group accounts for substantial
\nmodi\ufb01cation of terms of an existing liability or part of it as
\nan extinguishment of the original \ufb01nancial liability and the
\nrecognition of a new liability. It is assumed that the terms are
\nsubstantially di\ufb00erent if the discounted present value of the
\ncash \ufb02ows under the new terms, including any fees paid net of
\nany fees received and discounted using the original e\ufb00ective
\nrate is at least 10 per cent di\ufb00erent from the discounted
\npresent value of the remaining cash \ufb02ows of the original
\n\ufb01nancial liability. If the modi\ufb01cation is not substantial, the
\ndi\ufb00erence between: (1) the carrying amount of the liability
\nbefore the modi\ufb01cation; and (2) the present value of the cash
\n\ufb02ows after modi\ufb01cation is recognised in pro\ufb01t or loss as the
\nmodi\ufb01cation gain or loss within other gains and losses.
\n(iii)
Fair value measurement
\nThe group measures derivatives at fair value at each balance
\nsheet date and, for the purposes of impairment testing,
\nuses fair value less costs to sell (FVLCD) to determine the
\nrecoverable amount of some of its non-\ufb01nancial assets.
\nFair value is the price that would be received to sell an asset
\nor paid to transfer a liability in an orderly transaction between
\nmarket participants at the measurement date. The fair value
\nmeasurement is based on the presumption that the transaction
\nto sell the asset or transfer the liability takes place either:
\n\u25a0
In the principal market for the asset or liability
\nOr
\n\u25a0
In the absence of a principal market, in the most
\nadvantageous market for the asset or liability
\nThe principal or the most advantageous market must be
\naccessible by the group.
\nThe fair value of an asset or a liability is measured using the
\nassumptions that market participants would use when pricing
\nthe asset or liability, assuming that market participants act in
\ntheir economic best interest.
\nA fair value measurement of a non-\ufb01nancial asset takes into
\naccount a market participant's ability to generate economic
\nbene\ufb01ts by using the asset in its highest and best use or by
\nselling it to another market participant that would use the
\nasset in its highest and best use.
\nThe group uses valuation techniques that are appropriate in
\nthe circumstances and for which su\ufb03cient data are available to
\nmeasure fair value, maximising the use of relevant observable
\ninputs and minimising the use of unobservable inputs.
\nAll assets and liabilities, for which fair value is measured
\nor disclosed in the \ufb01nancial statements, are categorised
\nwithin the fair value hierarchy, described as follows, based
\non the lowest-level input that is signi\ufb01cant to the fair value
\nmeasurement as a whole:
\nLevel 1
\u2013 Quoted (unadjusted) market prices in active
\nmarkets for identical assets or liabilities
\nLevel 2
\u2013 Valuation techniques for which the lowest-level
\ninput that is signi\ufb01cant to the fair value measurement is
\ndirectly or indirectly observable
\nLevel 3
\u2013 Valuation techniques for which the lowest-level
\ninput that is signi\ufb01cant to the fair value measurement is
\nunobservable
\n(iv)
O\ufb00setting of \ufb01nancial instruments
\nFinancial assets and \ufb01nancial liabilities are o\ufb00set, and the net
\namount is reported in the consolidated statement of \ufb01nancial
\nposition if there is a currently enforceable legal right to o\ufb00set
\nthe recognised amounts and there is an intention to settle
\non a net basis, to realise the assets and settle the liabilities
\nsimultaneously. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f10982": {
"value": "(i) Financial assets
\nFinancial assets are classi\ufb01ed, at initial recognition, as
\nsubsequently measured at amortised cost, fair value through
\nother comprehensive income (OCI), and fair value through
\npro\ufb01t or loss, as appropriate.
\nThe classi\ufb01cation of \ufb01nancial assets at initial recognition
\ndepends on the \ufb01nancial asset\u2019s contractual cash \ufb02ow
\ncharacteristics and the group\u2019s business model for managing
\nthem. With the exception of trade receivables that do not
\ncontain a signi\ufb01cant \ufb01nancing component or for which the
\ngroup has applied the practical expedient, the group initially
\nmeasures a \ufb01nancial asset at its fair value plus, in the case
\nof \ufb01nancial assets not subsequently measured at fair value
\nthrough pro\ufb01t or loss, transaction costs that are attributable
\nto the acquisition of the \ufb01nancial asset.
\nIn order for a \ufb01nancial asset to be classi\ufb01ed and measured at
\namortised cost or fair value through OCI, it needs to give rise
\nto cash \ufb02ows that are solely payments of principal and interest
\n(SPPI) on the principal amount outstanding. This assessment is
\nreferred to as the SPPI test and is performed at an instrument
\nlevel.
\nThe group\u2019s business model for managing \ufb01nancial assets
\nrefers to how it manages its \ufb01nancial assets in order to
\ngenerate cash \ufb02ows. The business model determines whether
\ncash \ufb02ows will result from collecting contractual cash \ufb02ows,
\nselling the \ufb01nancial assets, or both.
\nPurchases or sales of \ufb01nancial assets that require delivery
\nof assets within a time frame established by regulation
\nor convention in the marketplace (regular way trades) are
\nrecognised on the trade date, i.e., the date that the group
\ncommits to purchase or sell the asset.
\nFinancial assets are recognised initially at fair value,
\nnormally being the transaction price. In the case of \ufb01nancial
\nassets not at fair value through pro\ufb01t or loss, directly
\nattributable transaction costs are also included. The
\nsubsequent measurement of \ufb01nancial assets depends on
\ntheir classi\ufb01cation, as set out below. The group derecognizes
\n\ufb01nancial assets when the contractual rights to the cash \ufb02ows
\nexpire or the \ufb01nancial asset is transferred to a 3
\nrd
\nparty. This
\nincludes the derecognition of receivables for which discounting
\narrangements are entered into. The classi\ufb01cation depends on
\nthe business model for managing the \ufb01nancial assets and the
\ncontractual cash \ufb02ow characteristics of the \ufb01nancial asset.
\nSubsequent measurement
\n\u25a0
For purposes of subsequent measurement, \ufb01nancial assets
\nare classi\ufb01ed in 4 categories:
\n\u25a0
Financial assets at amortised cost (debt instruments)
\n\u25a0
Financial assets at fair value through OCI with recycling of
\ncumulative gains and losses (debt instruments)
\n\u25a0
Financial assets designated at fair value through OCI with no
\nrecycling of cumulative gains and losses upon derecognition
\n(equity instruments)
\n\u25a0
Financial assets at fair value through pro\ufb01t or loss
\n\u25a0
The group has not designated any \ufb01nancial assets at fair
\nvalue through pro\ufb01t or loss.
\n\u25a0
Financial assets at amortised cost (debt instruments)
\n\u25a0
The group measures \ufb01nancial assets at amortised cost if
\nboth of the following conditions are met:
\n\u25a0
The \ufb01nancial asset is held within a business model with
\nthe objective to hold \ufb01nancial assets in order to collect
\ncontractual cash \ufb02ows;
\nAnd
\n\u25a0
The contractual terms of the \ufb01nancial asset give rise on
\n
speci\ufb01ed dates to cash \ufb02ows that are solely payments of
\nprincipal and interest on the principal amount outstanding;
\nFinancial assets at amortised cost are subsequently measured
\nusing the e\ufb00ective interest (EIR) method and are subject to
\nimpairment. Gains and losses are recognised in pro\ufb01t or loss
\nwhen the asset is derecognised, modi\ufb01ed or impaired.
\nCash equivalents
\nCash equivalents are short-term, highly liquid investments that
\nare readily convertible to known amounts of cash, are subject
\nto insigni\ufb01cant risk of changes in value and generally have a
\nmaturity of three months or less from the date of acquisition.
\nCash equivalents are classi\ufb01ed as \ufb01nancial assets measured at
\namortised cost.
\nLoans granted
\nLoans granted that have \ufb01xed or determinable payments that
\nare not quoted in an active market are classi\ufb01ed as \ufb01nancial
\nassets at amortised cost and are measured at amortised cost
\nusing the e\ufb00ective interest method, less any impairment.
\nInterest income is recognised by applying the e\ufb00ective interest
\nrate.
\nLoans granted to related parties are normally interest-free
\nand do not have a \ufb01xed repayment structure. These loans
\nare classi\ufb01ed as \ufb01nancial assets at amortised cost and are
\nmeasured at amortised cost using the e\ufb00ective interest
\nmethod, less any impairment. E\ufb00ective interest rate being zero
\nin this case.
\nDerecognition
\nA \ufb01nancial asset (or, where applicable, a part of a \ufb01nancial
\nasset or part of a group of similar \ufb01nancial assets) is primarily
\nderecognised (i.e., removed from the group\u2019s consolidated
\nstatement of \ufb01nancial position) when:
\nThe rights to receive cash \ufb02ows from the asset have expired or
\nthe group has transferred its rights to receive cash \ufb02ows from
\nthe asset or has assumed an obligation to pay the received
\ncash \ufb02ows in full without material delay to a third party under
\na \u2018pass-through\u2019 arrangement; and either (a) the group has
\ntransferred substantially all the risks and rewards of the
\nasset, or (b) the group has neither transferred nor retained
\nsubstantially all the risks and rewards of the asset, but has
\ntransferred control of the asset.
\nWhen the group has transferred its rights to receive cash
\n\ufb02ows from an asset or has entered into a pass-through
\narrangement, it evaluates if, and to what extent, it has retained
\nthe risks and rewards of ownership. When it has neither
\ntransferred nor retained substantially all of the risks and
\nrewards of the asset, nor transferred control of the asset,
\nthe group continues to recognise the transferred asset to the
\nextent of its continuing involvement. In that case, the group
\nalso recognises an associated liability. The transferred asset
\nand the associated liability are measured on a basis that
\nre\ufb02ects the rights and obligations that the group has retained.
\nImpairment of \ufb01nancial assets
\nThe group recognises an allowance for expected credit losses
\n(ECLs) for all debt instruments not held at fair value through
\npro\ufb01t or loss. ECLs are based on the di\ufb00erence between the
\ncontractual cash \ufb02ows due in accordance with the contract and
\nall the cash \ufb02ows that the group expects to receive, discounted
\nat an approximation of the original e\ufb00ective interest rate. The
\nexpected cash \ufb02ows will include cash \ufb02ows from the sale of
\ncollateral held or other credit enhancements that are integral
\nto the contractual terms.
\nECLs are recognised in two stages. For credit exposures
\nfor which there has not been a signi\ufb01cant increase in credit
\nrisk since initial recognition, ECLs are provided for credit
\nlosses that result from default events that are possible
\nwithin the next 12 months (a 12-month ECL). For those credit
\nexposures for which there has been a signi\ufb01cant increase
\nin credit risk since initial recognition, a loss allowance is
\nrequired for credit losses expected over the remaining life
\nof the exposure, irrespective of the timing of the default (a
\nlifetime ECL).
\nFor trade receivables and contract assets, the group applies a
\nsimpli\ufb01ed approach in calculating ECLs. Therefore, the group
\ndoes not track changes in credit risk, but instead recognises a
\nloss allowance based on lifetime ECLs at each reporting date.
\nThe group has established a provision matrix that is based
\non its historical credit-loss experience, adjusted for forward-
\nlooking factors speci\ufb01c to the debtors and the economic
\nenvironment.
\nThe group considers a \ufb01nancial asset in default when
\ncontractual payments are 90 days past due. However, in
\ncertain cases, the group may also consider a \ufb01nancial asset
\nto be in default when internal or external information
\nindicates that the group is unlikely to receive the outstanding
\ncontractual amounts in full before taking into account any
\ncredit enhancements held by the group. A \ufb01nancial asset
\nis written o\ufb00 when there is no reasonable expectation of
\nrecovering the contractual cash \ufb02ows. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialAssetsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f11108": {
"value": "Derecognition
\nA \ufb01nancial asset (or, where applicable, a part of a \ufb01nancial
\nasset or part of a group of similar \ufb01nancial assets) is primarily
\nderecognised (i.e., removed from the group\u2019s consolidated
\nstatement of \ufb01nancial position) when:
\nThe rights to receive cash \ufb02ows from the asset have expired or
\nthe group has transferred its rights to receive cash \ufb02ows from
\nthe asset or has assumed an obligation to pay the received
\ncash \ufb02ows in full without material delay to a third party under
\na \u2018pass-through\u2019 arrangement; and either (a) the group has
\ntransferred substantially all the risks and rewards of the
\nasset, or (b) the group has neither transferred nor retained
\nsubstantially all the risks and rewards of the asset, but has
\ntransferred control of the asset.
\nWhen the group has transferred its rights to receive cash
\n\ufb02ows from an asset or has entered into a pass-through
\narrangement, it evaluates if, and to what extent, it has retained
\nthe risks and rewards of ownership. When it has neither
\ntransferred nor retained substantially all of the risks and
\nrewards of the asset, nor transferred control of the asset,
\nthe group continues to recognise the transferred asset to the
\nextent of its continuing involvement. In that case, the group
\nalso recognises an associated liability. The transferred asset
\nand the associated liability are measured on a basis that
\nre\ufb02ects the rights and obligations that the group has retained.
Derecognition of \ufb01nancial liabilities
\nThe group derecognises \ufb01nancial liabilities when, and only
\nwhen, the group\u2019s obligations are discharged, cancelled or
\nhave expired. The di\ufb00erence between the carrying amount of
\nthe \ufb01nancial liability derecognised and the consideration paid
\nand payable is recognised in pro\ufb01t or loss.
\nWhen the group exchanges with the existing lender one debt
\ninstrument into another one with substantially di\ufb00erent
\nterms, such exchange is accounted for as an extinguishment
\nof the original \ufb01nancial liability and the recognition of a new
\n\ufb01nancial liability. Similarly, the group accounts for substantial
\nmodi\ufb01cation of terms of an existing liability or part of it as
\nan extinguishment of the original \ufb01nancial liability and the
\nrecognition of a new liability. It is assumed that the terms are
\nsubstantially di\ufb00erent if the discounted present value of the
\ncash \ufb02ows under the new terms, including any fees paid net of
\nany fees received and discounted using the original e\ufb00ective
\nrate is at least 10 per cent di\ufb00erent from the discounted
\npresent value of the remaining cash \ufb02ows of the original
\n\ufb01nancial liability. If the modi\ufb01cation is not substantial, the
\ndi\ufb00erence between: (1) the carrying amount of the liability
\nbefore the modi\ufb01cation; and (2) the present value of the cash
\n\ufb02ows after modi\ufb01cation is recognised in pro\ufb01t or loss as the
\nmodi\ufb01cation gain or loss within other gains and losses.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDerecognitionOfFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f11135": {
"value": "Impairment of \ufb01nancial assets The group recognises an allowance for expected credit losses
\n(ECLs) for all debt instruments not held at fair value through
\npro\ufb01t or loss. ECLs are based on the di\ufb00erence between the
\ncontractual cash \ufb02ows due in accordance with the contract and
\nall the cash \ufb02ows that the group expects to receive, discounted
\nat an approximation of the original e\ufb00ective interest rate. The
\nexpected cash \ufb02ows will include cash \ufb02ows from the sale of
\ncollateral held or other credit enhancements that are integral
\nto the contractual terms.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfFinancialAssetsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f11148": {
"value": "ECLs are recognised in two stages. For credit exposures for which there has not been a signi\ufb01cant increase in credit
\nrisk since initial recognition, ECLs are provided for credit
\nlosses that result from default events that are possible
\nwithin the next 12 months (a 12-month ECL). For those credit
\nexposures for which there has been a signi\ufb01cant increase
\nin credit risk since initial recognition, a loss allowance is
\nrequired for credit losses expected over the remaining life
\nof the exposure, irrespective of the timing of the default (a
\nlifetime ECL).
\nFor trade receivables and contract assets, the group applies a
\nsimpli\ufb01ed approach in calculating ECLs. Therefore, the group
\ndoes not track changes in credit risk, but instead recognises a
\nloss allowance based on lifetime ECLs at each reporting date.
\nThe group has established a provision matrix that is based
\non its historical credit-loss experience, adjusted for forward-
\nlooking factors speci\ufb01c to the debtors and the economic
\nenvironment.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAllowanceForCreditLossesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f11179": {
"value": "(ii) Financial liabilities
\nInitial recognition and measurement
\nFinancial liabilities are classi\ufb01ed, at initial recognition, as
\n\ufb01nancial liabilities at fair value through pro\ufb01t or loss, \ufb01nancial
\nliabilities at amortised cost, payables, or as derivatives
\ndesignated as hedging instruments in an e\ufb00ective hedge, as
\nappropriate.
\nAll \ufb01nancial liabilities are recognised initially at fair value and,
\nin the case of loans and borrowings and payables, net of
\ndirectly attributable transaction costs.
\nThe group\u2019s \ufb01nancial liabilities include trade and other
\npayables, loans and borrowings including bank overdrafts, and
\nderivative \ufb01nancial instruments.
\nSubsequent measurement
\nAfter initial recognition, interest-bearing loans and borrowings
\nare subsequently measured at amortised cost using the EIR
\nmethod. Gains and losses are recognised in pro\ufb01t or loss
\nwhen the liabilities are derecognised as well as through the EIR
\namortisation process.
\nAmortised cost is calculated by taking into account any
\ndiscount or premium on acquisition and fees or costs that are
\nan integral part of the EIR. The EIR amortisation is included as
\n\ufb01nance costs in the statement of pro\ufb01t or loss.
\n
This category generally applies to interest-bearing loans and
\nborrowings. For more information, refer to note 20.
\nPayables are measure at their nominal amount when the e\ufb00ect
\nof discounting is not material.
\nForeign exchange gains and losses
\nFor \ufb01nancial liabilities that are denominated in a foreign
\ncurrency and are measured at amortised cost at the end of each
\nreporting period, the foreign exchange gains and losses are
\ndetermined based on the amortised cost of the instruments.
\nThese foreign exchange gains and losses are recognised in
\nthe \u2018foreign exchange gain/(loss)\u2019 line item in pro\ufb01t or loss for
\n\ufb01nancial liabilities that are not part of a designated hedging
\nrelationship. For those which are designated as a hedging
\ninstrument for a hedge of foreign currency risk foreign exchange
\ngains and losses are recognised in other comprehensive income
\nand accumulated in a separate component of equity.
\nThe fair value of \ufb01nancial liabilities denominated in a foreign
\ncurrency is determined in that foreign currency and translated
\nat the spot rate at the end of the reporting period. For \ufb01nancial
\nliabilities that are measured as at FVTPL, the foreign exchange
\ncomponent forms part of the fair value gains or losses and is
\nrecognised in pro\ufb01t or loss for \ufb01nancial liabilities that are not
\npart of a designated hedging relationship.
\nDerecognition of \ufb01nancial liabilities
\nThe group derecognises \ufb01nancial liabilities when, and only
\nwhen, the group\u2019s obligations are discharged, cancelled or
\nhave expired. The di\ufb00erence between the carrying amount of
\nthe \ufb01nancial liability derecognised and the consideration paid
\nand payable is recognised in pro\ufb01t or loss.
\nWhen the group exchanges with the existing lender one debt
\ninstrument into another one with substantially di\ufb00erent
\nterms, such exchange is accounted for as an extinguishment
\nof the original \ufb01nancial liability and the recognition of a new
\n\ufb01nancial liability. Similarly, the group accounts for substantial
\nmodi\ufb01cation of terms of an existing liability or part of it as
\nan extinguishment of the original \ufb01nancial liability and the
\nrecognition of a new liability. It is assumed that the terms are
\nsubstantially di\ufb00erent if the discounted present value of the
\ncash \ufb02ows under the new terms, including any fees paid net of
\nany fees received and discounted using the original e\ufb00ective
\nrate is at least 10 per cent di\ufb00erent from the discounted
\npresent value of the remaining cash \ufb02ows of the original
\n\ufb01nancial liability. If the modi\ufb01cation is not substantial, the
\ndi\ufb00erence between: (1) the carrying amount of the liability
\nbefore the modi\ufb01cation; and (2) the present value of the cash
\n\ufb02ows after modi\ufb01cation is recognised in pro\ufb01t or loss as the
\nmodi\ufb01cation gain or loss within other gains and losses.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f11278": {
"value": "(iii) Fair value measurement
\nThe group measures derivatives at fair value at each balance
\nsheet date and, for the purposes of impairment testing,
\nuses fair value less costs to sell (FVLCD) to determine the
\nrecoverable amount of some of its non-\ufb01nancial assets.
\nFair value is the price that would be received to sell an asset
\nor paid to transfer a liability in an orderly transaction between
\nmarket participants at the measurement date. The fair value
\nmeasurement is based on the presumption that the transaction
\nto sell the asset or transfer the liability takes place either:
\n\u25a0
In the principal market for the asset or liability
\nOr
\n\u25a0
In the absence of a principal market, in the most
\nadvantageous market for the asset or liability
\nThe principal or the most advantageous market must be
\naccessible by the group.
\nThe fair value of an asset or a liability is measured using the
\nassumptions that market participants would use when pricing
\nthe asset or liability, assuming that market participants act in
\ntheir economic best interest.
\nA fair value measurement of a non-\ufb01nancial asset takes into
\naccount a market participant's ability to generate economic
\nbene\ufb01ts by using the asset in its highest and best use or by
\nselling it to another market participant that would use the
\nasset in its highest and best use.
\nThe group uses valuation techniques that are appropriate in
\nthe circumstances and for which su\ufb03cient data are available to
\nmeasure fair value, maximising the use of relevant observable
\ninputs and minimising the use of unobservable inputs.
\nAll assets and liabilities, for which fair value is measured
\nor disclosed in the \ufb01nancial statements, are categorised
\nwithin the fair value hierarchy, described as follows, based
\non the lowest-level input that is signi\ufb01cant to the fair value
\nmeasurement as a whole:
\nLevel 1
\u2013 Quoted (unadjusted) market prices in active
\nmarkets for identical assets or liabilities
\nLevel 2
\u2013 Valuation techniques for which the lowest-level
\ninput that is signi\ufb01cant to the fair value measurement is
\ndirectly or indirectly observable
\nLevel 3
\u2013 Valuation techniques for which the lowest-level
\ninput that is signi\ufb01cant to the fair value measurement is
\nunobservable",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFairValueMeasurementExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f11329": {
"value": "(iv) O\ufb00setting of \ufb01nancial instruments
\nFinancial assets and \ufb01nancial liabilities are o\ufb00set, and the net
\namount is reported in the consolidated statement of \ufb01nancial
\nposition if there is a currently enforceable legal right to o\ufb00set
\nthe recognised amounts and there is an intention to settle
\non a net basis, to realise the assets and settle the liabilities
simultaneously. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForOffsettingOfFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f11341": {
"value": "31U. JOINT ARRANGEMENTS
\nJoint arrangements are arrangements of which two or more
\nparties have joint control. Joint control is the contractual agreed
\nsharing of control of the arrangement which exists only when
\ndecisions about the relevant activities require unanimous
\nconsent of the parties sharing control. Joint arrangements are
\nclassi\ufb01ed as either a joint operation or joint venture, based
\non the rights and obligations arising from the contractual
\nobligations between the parties to the arrangement.
\nTo the extent the joint arrangement provides the company
\nwith rights to the individual assets and obligations arising from
\nthe joint arrangement, the arrangement is classi\ufb01ed as a joint
\noperation and as such, the company recognises its:
\n
\u25a0
Assets, including its share of any assets held jointly;
\n\u25a0
Liabilities, including its share of any liabilities incurred
\njointly;
\n\u25a0
Revenue from the sale of its share of the output arising from
\nthe joint operation;
\n\u25a0
Share of revenue from the sale of the output by the joint
\noperation; and
\n\u25a0
Expenses, including its share of any expenses incurred
\njointly.
\nTo the extent the joint arrangement provides the company
\nwith rights to the net assets of the arrangement, the
\ninvestment is classi\ufb01ed as a joint venture and accounted for
\nusing the equity method. Under the equity method, the cost of
\nthe investment is adjusted by the post-acquisition changes in
\nthe company\u2019s share of the net assets of the venture.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfJointVenturesExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f11342": {
"value": "31U. JOINT ARRANGEMENTS
\nJoint arrangements are arrangements of which two or more
\nparties have joint control. Joint control is the contractual agreed
\nsharing of control of the arrangement which exists only when
\ndecisions about the relevant activities require unanimous
\nconsent of the parties sharing control. Joint arrangements are
\nclassi\ufb01ed as either a joint operation or joint venture, based
\non the rights and obligations arising from the contractual
\nobligations between the parties to the arrangement.
\nTo the extent the joint arrangement provides the company
\nwith rights to the individual assets and obligations arising from
\nthe joint arrangement, the arrangement is classi\ufb01ed as a joint
\noperation and as such, the company recognises its:
\n
\u25a0
Assets, including its share of any assets held jointly;
\n\u25a0
Liabilities, including its share of any liabilities incurred
\njointly;
\n\u25a0
Revenue from the sale of its share of the output arising from
\nthe joint operation;
\n\u25a0
Share of revenue from the sale of the output by the joint
\noperation; and
\n\u25a0
Expenses, including its share of any expenses incurred
\njointly.
\nTo the extent the joint arrangement provides the company
\nwith rights to the net assets of the arrangement, the
\ninvestment is classi\ufb01ed as a joint venture and accounted for
\nusing the equity method. Under the equity method, the cost of
\nthe investment is adjusted by the post-acquisition changes in
\nthe company\u2019s share of the net assets of the venture.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f11436": {
"value": "31W. BUSINESS COMBINATIONS AND GOODWILL
\nIn order to consider an acquisition as a business combination,
\nthe acquired asset or groups of assets must constitute
\na business (an integrated set of operations and assets
\nconducted and managed for the purpose of providing
\na return to the investors). The combination consists of
\ninputs and processes applied to these inputs that have the
\nability to create output. Acquired businesses are included
\nin the \ufb01nancial statements from the transaction date. The
\ntransaction date is de\ufb01ned as the date on which the company
\nachieves control over the \ufb01nancial and operating assets. This
\ndate may di\ufb00er from the actual date on which the assets
\nare transferred. Comparative \ufb01gures are not adjusted for
\nacquired, sold or liquidated businesses. On acquisition of
\na licence that involves the right to explore for and produce
\npetroleum resources, it is considered in each case whether
\nthe acquisition should be treated as a business combination
\nor an asset purchase. Generally, purchases of licences in
\na development or production phase will be regarded as a
\nbusiness combination. Business combinations are accounted
\nfor using the acquisition method. The cost of an acquisition is
\nmeasured as the aggregate of the consideration transferred,
\nmeasured at acquisition date fair value and the amount of
\nany non-controlling interest (NCI) in the acquiree. For each
\nbusiness combination, the group elects whether to measure
\nNCI in the acquiree at fair value or at the proportionate share
\nof the acquiree\u2019s identi\ufb01able net assets. Acquisition related
\ncosts are expensed as incurred and included in administrative
\nexpenses.
\nThe initial accounting for a business combination can be
\nchanged if new information about the fair value at the
\nacquisition date is present. The allocation can be amended
\nwithin 12 months of the acquisition date [provided that the
\ninitial accounting at the acquisition date was determined
\nprovisionally]. The non-controlling interest is set to the non-
\ncontrolling interest\u2019s share of identi\ufb01able assets and liabilities
\n[alternative fair value]. The measurement principle is done
\nfor each business combination separately. When the group
\nacquires a business, it assesses the assets and liabilities
\nassumed for appropriate classi\ufb01cation and designation
\nin accordance with the contractual terms, economic
\ncircumstances and pertinent conditions as at the acquisition
\ndate. This includes the separation of embedded derivatives
\nin host contracts by the acquiree. Those acquired petroleum
\nreserves and resources that can be reliably measured are
\nrecognised separately in the assessment of fair values on
\nacquisition. Other potential reserves, resources and rights,
\nfor which fair values cannot be reliably measured, are not
\nrecognised separately, but instead are subsumed in goodwill.
\nGoodwill is recognised as the aggregate of the consideration
\ntransferred and the amount of any non-controlling interest
\nand deducted by the net of the acquisition-date amounts of
\nthe identi\ufb01able assets acquired and the liabilities assumed.
\nGoodwill is not depreciated but is tested at least annually for
\nimpairment. In connection with this, goodwill is allocated to
\ncash-generating units or groups of cash-generating units that
\nare expected to bene\ufb01t from synergies from the business
\ncombination.
\nTechnical goodwill is recognised due to the requirement
\nto recognise deferred tax for the di\ufb00erence between the
\nassigned fair values and the related tax base. In accordance
\nwith IAS 12, a provision is made for deferred tax corresponding
\nto the tax rate multiplied by the di\ufb00erence between the
\nfair values of the acquired assets and the transferred tax
\ndepreciation basis.
\nIf the fair value of the equity exceeds the acquisition cost in a
\nbusiness combination, the di\ufb00erence is recognised as income
immediately on the acquisition date.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsAndGoodwillExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f11437": {
"value": "31W. BUSINESS COMBINATIONS AND GOODWILL
\nIn order to consider an acquisition as a business combination,
\nthe acquired asset or groups of assets must constitute
\na business (an integrated set of operations and assets
\nconducted and managed for the purpose of providing
\na return to the investors). The combination consists of
\ninputs and processes applied to these inputs that have the
\nability to create output. Acquired businesses are included
\nin the \ufb01nancial statements from the transaction date. The
\ntransaction date is de\ufb01ned as the date on which the company
\nachieves control over the \ufb01nancial and operating assets. This
\ndate may di\ufb00er from the actual date on which the assets
\nare transferred. Comparative \ufb01gures are not adjusted for
\nacquired, sold or liquidated businesses. On acquisition of
\na licence that involves the right to explore for and produce
\npetroleum resources, it is considered in each case whether
\nthe acquisition should be treated as a business combination
\nor an asset purchase. Generally, purchases of licences in
\na development or production phase will be regarded as a
\nbusiness combination. Business combinations are accounted
\nfor using the acquisition method. The cost of an acquisition is
\nmeasured as the aggregate of the consideration transferred,
\nmeasured at acquisition date fair value and the amount of
\nany non-controlling interest (NCI) in the acquiree. For each
\nbusiness combination, the group elects whether to measure
\nNCI in the acquiree at fair value or at the proportionate share
\nof the acquiree\u2019s identi\ufb01able net assets. Acquisition related
\ncosts are expensed as incurred and included in administrative
\nexpenses.
\nThe initial accounting for a business combination can be
\nchanged if new information about the fair value at the
\nacquisition date is present. The allocation can be amended
\nwithin 12 months of the acquisition date [provided that the
\ninitial accounting at the acquisition date was determined
\nprovisionally]. The non-controlling interest is set to the non-
\ncontrolling interest\u2019s share of identi\ufb01able assets and liabilities
\n[alternative fair value]. The measurement principle is done
\nfor each business combination separately. When the group
\nacquires a business, it assesses the assets and liabilities
\nassumed for appropriate classi\ufb01cation and designation
\nin accordance with the contractual terms, economic
\ncircumstances and pertinent conditions as at the acquisition
\ndate. This includes the separation of embedded derivatives
\nin host contracts by the acquiree. Those acquired petroleum
\nreserves and resources that can be reliably measured are
\nrecognised separately in the assessment of fair values on
\nacquisition. Other potential reserves, resources and rights,
\nfor which fair values cannot be reliably measured, are not
\nrecognised separately, but instead are subsumed in goodwill.
\nGoodwill is recognised as the aggregate of the consideration
\ntransferred and the amount of any non-controlling interest
\nand deducted by the net of the acquisition-date amounts of
\nthe identi\ufb01able assets acquired and the liabilities assumed.
\nGoodwill is not depreciated but is tested at least annually for
\nimpairment. In connection with this, goodwill is allocated to
\ncash-generating units or groups of cash-generating units that
\nare expected to bene\ufb01t from synergies from the business
\ncombination.
\nTechnical goodwill is recognised due to the requirement
\nto recognise deferred tax for the di\ufb00erence between the
\nassigned fair values and the related tax base. In accordance
\nwith IAS 12, a provision is made for deferred tax corresponding
\nto the tax rate multiplied by the di\ufb00erence between the
\nfair values of the acquired assets and the transferred tax
\ndepreciation basis.
\nIf the fair value of the equity exceeds the acquisition cost in a
\nbusiness combination, the di\ufb00erence is recognised as income
immediately on the acquisition date.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f11438": {
"value": "31W. BUSINESS COMBINATIONS AND GOODWILL
\nIn order to consider an acquisition as a business combination,
\nthe acquired asset or groups of assets must constitute
\na business (an integrated set of operations and assets
\nconducted and managed for the purpose of providing
\na return to the investors). The combination consists of
\ninputs and processes applied to these inputs that have the
\nability to create output. Acquired businesses are included
\nin the \ufb01nancial statements from the transaction date. The
\ntransaction date is de\ufb01ned as the date on which the company
\nachieves control over the \ufb01nancial and operating assets. This
\ndate may di\ufb00er from the actual date on which the assets
\nare transferred. Comparative \ufb01gures are not adjusted for
\nacquired, sold or liquidated businesses. On acquisition of
\na licence that involves the right to explore for and produce
\npetroleum resources, it is considered in each case whether
\nthe acquisition should be treated as a business combination
\nor an asset purchase. Generally, purchases of licences in
\na development or production phase will be regarded as a
\nbusiness combination. Business combinations are accounted
\nfor using the acquisition method. The cost of an acquisition is
\nmeasured as the aggregate of the consideration transferred,
\nmeasured at acquisition date fair value and the amount of
\nany non-controlling interest (NCI) in the acquiree. For each
\nbusiness combination, the group elects whether to measure
\nNCI in the acquiree at fair value or at the proportionate share
\nof the acquiree\u2019s identi\ufb01able net assets. Acquisition related
\ncosts are expensed as incurred and included in administrative
\nexpenses.
\nThe initial accounting for a business combination can be
\nchanged if new information about the fair value at the
\nacquisition date is present. The allocation can be amended
\nwithin 12 months of the acquisition date [provided that the
\ninitial accounting at the acquisition date was determined
\nprovisionally]. The non-controlling interest is set to the non-
\ncontrolling interest\u2019s share of identi\ufb01able assets and liabilities
\n[alternative fair value]. The measurement principle is done
\nfor each business combination separately. When the group
\nacquires a business, it assesses the assets and liabilities
\nassumed for appropriate classi\ufb01cation and designation
\nin accordance with the contractual terms, economic
\ncircumstances and pertinent conditions as at the acquisition
\ndate. This includes the separation of embedded derivatives
\nin host contracts by the acquiree. Those acquired petroleum
\nreserves and resources that can be reliably measured are
\nrecognised separately in the assessment of fair values on
\nacquisition. Other potential reserves, resources and rights,
\nfor which fair values cannot be reliably measured, are not
\nrecognised separately, but instead are subsumed in goodwill.
\nGoodwill is recognised as the aggregate of the consideration
\ntransferred and the amount of any non-controlling interest
\nand deducted by the net of the acquisition-date amounts of
\nthe identi\ufb01able assets acquired and the liabilities assumed.
\nGoodwill is not depreciated but is tested at least annually for
\nimpairment. In connection with this, goodwill is allocated to
\ncash-generating units or groups of cash-generating units that
\nare expected to bene\ufb01t from synergies from the business
\ncombination.
\nTechnical goodwill is recognised due to the requirement
\nto recognise deferred tax for the di\ufb00erence between the
\nassigned fair values and the related tax base. In accordance
\nwith IAS 12, a provision is made for deferred tax corresponding
\nto the tax rate multiplied by the di\ufb00erence between the
\nfair values of the acquired assets and the transferred tax
\ndepreciation basis.
\nIf the fair value of the equity exceeds the acquisition cost in a
\nbusiness combination, the di\ufb00erence is recognised as income
immediately on the acquisition date.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f13189": {
"value": "Fr\u00f8yas gate 13 NO-0273 Oslo
\nNorway",
"dimensions": {
"concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity",
"language": "en",
"entity": "scheme:984500AEEH2D2AK42C11",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
}
}
}