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"unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00329": { "value": "108007000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashFlowsFromUsedInOperationsBeforeChangesInWorkingCapital", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00328": { "value": "122331000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashFlowsFromUsedInOperationsBeforeChangesInWorkingCapital", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00156": { "value": "-34806000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:AdjustmentsForDecreaseIncreaseInTradeAndOtherReceivables", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, 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"decimals": -3, "dimensions": { "concept": "ifrs-full:AdjustmentsForProvisions", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00160": { "value": "-328000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:AdjustmentsForProvisions", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00162": { "value": "4574000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:AdjustmentsForDecreaseIncreaseInInventories", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00161": { "value": "247000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:AdjustmentsForDecreaseIncreaseInInventories", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00182": { "value": "-10848000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:AdjustmentsForIncreaseDecreaseInTradeAndOtherPayables", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00181": { "value": "-2069000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:AdjustmentsForIncreaseDecreaseInTradeAndOtherPayables", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00274": { "value": "35782000.0", "decimals": -3, "dimensions": { "concept": "pepa:IncreaseDecreaseInOverlift", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00275": { "value": "0.0", "decimals": -3, "dimensions": { "concept": "pepa:IncreaseDecreaseInOverlift", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00288": { "value": "100735000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashFlowsFromUsedInOperations", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00287": { "value": "89278000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashFlowsFromUsedInOperations", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00309": { "value": "39976000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:IncomeTaxesPaidClassifiedAsOperatingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00308": { "value": "39852000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:IncomeTaxesPaidClassifiedAsOperatingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00331": { "value": "60759000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashFlowsFromUsedInOperatingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00330": { "value": "49426000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashFlowsFromUsedInOperatingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00163": { "value": "-1534000.0", "decimals": -3, "dimensions": { "concept": "pepa:ProceedsOutflowsOfDiscontinuedOperationsClassifiedAsInvestingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00164": { "value": "21273000.0", "decimals": -3, "dimensions": { "concept": "pepa:ProceedsOutflowsOfDiscontinuedOperationsClassifiedAsInvestingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00166": { "value": "13061000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:PurchaseOfPropertyPlantAndEquipmentClassifiedAsInvestingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00165": { "value": "38253000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:PurchaseOfPropertyPlantAndEquipmentClassifiedAsInvestingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00180": { "value": "778000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:PurchaseOfIntangibleAssetsClassifiedAsInvestingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00179": { "value": "1513000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:PurchaseOfIntangibleAssetsClassifiedAsInvestingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00290": { "value": "-15373000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashFlowsFromUsedInInvestingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00289": { "value": "-18493000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashFlowsFromUsedInInvestingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00168": { "value": "5500000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:RepaymentsOfBorrowingsClassifiedAsFinancingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00167": { "value": "5500000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:RepaymentsOfBorrowingsClassifiedAsFinancingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00170": { "value": "383000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:InterestPaidClassifiedAsFinancingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00169": { "value": "830000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:InterestPaidClassifiedAsFinancingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00171": { "value": "1865000.0", "decimals": -3, "dimensions": { "concept": "pepa:InterestIncomeClassifiedAsFinancingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_Label_00172": { "value": "0.0", "decimals": -3, "dimensions": { "concept": "pepa:InterestIncomeClassifiedAsFinancingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00276": { "value": "7925000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:DividendsPaidToNoncontrollingInterestsClassifiedAsFinancingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_NegatedLabel_00277": { "value": "3170000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:DividendsPaidToNoncontrollingInterestsClassifiedAsFinancingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00332": { "value": "-11943000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashFlowsFromUsedInFinancingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00333": { "value": "-9500000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashFlowsFromUsedInFinancingActivities", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00173": { "value": "33443000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:IncreaseDecreaseInCashAndCashEquivalents", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_TotalLabel_00174": { "value": "21433000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:IncreaseDecreaseInCashAndCashEquivalents", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_PeriodStartLabel_00176": { "value": "46249000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashAndCashEquivalents", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_PeriodStartLabel_00175": { "value": "24816000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashAndCashEquivalents", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2023-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_PeriodEndLabel_00178": { "value": "79692000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashAndCashEquivalents", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ConsolidatedStatementOfCashFlows_PeriodEndLabel_00177": { "value": "46249000.0", "decimals": -3, "dimensions": { "concept": "ifrs-full:CashAndCashEquivalents", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00195": { "value": "Note 01
Corporate information
The
\ufb01
nancial report of the Company and its subsidiaries
(together the \u201cGroup\u201d) for the year ended 31 December 2024
was authorised for issue in accordance with a resolution of the
Directors on 28 April 2025.
PetroNor E&P ASA is a \u2018for pro
\ufb01
t entity\u2019 and is a company
limited by shares incorporated in Norway. Its shares are publicly
traded on the Oslo B\u00f8rs (ticker code: PNOR), the main regulated
marketplace of the Oslo Stock Exchange, Norway. The principal
activities of the Group are the exploration and production of
crude oil.", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00196": { "value": "The
\ufb01
nancial report of the Company and its subsidiaries
(together the \u201cGroup\u201d) for the year ended 31 December 2024
was authorised for issue in accordance with a resolution of the
Directors on 28 April 2025.", "dimensions": { "concept": "ifrs-full:DisclosureOfAuthorisationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00192": { "value": "2024-12-31", "dimensions": { "concept": "ifrs-full:DateOfEndOfReportingPeriod2013", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00185": { "value": "PetroNor E&P ASA", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00191": { "value": "PetroNor E&P ASA", "dimensions": { "concept": "ifrs-full:NameOfUltimateParentOfGroup", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00194": { "value": "company limited by shares", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00186": { "value": "Norway", "dimensions": { "concept": "ifrs-full:PrincipalPlaceOfBusiness", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00189": { "value": "Norway", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00193": { "value": "Norway", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00190": { "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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00197": { "value": "Note 02
Basis of preparation
PetroNor E&P ASA\u2019s consolidated
\ufb01
nancial statements have
been prepared in accordance with IFRS\u00ae Accounting Standards
as adopted by the EU and are mandatory for
\ufb01
nancial years
beginning on or after 1 January 2024, and Norwegian disclosure
requirements listed in the Norwegian Accounting Act as of
31 December 2024. The consolidated
\ufb01
nancial statements have
been prepared on the basis of uniform accounting principles
for similar transactions and events under otherwise similar
circumstances.
The
\ufb01
nancial report is presented in United States Dollars, which
is the functional currency for all the material subsidiaries, and
all values are rounded to the thousand dollars unless otherwise
stated.
GOING CONCERN
The Board of Directors con
\ufb01
rms that the annual
\ufb01
nancial
statements have been prepared pursuant to the going concern
assumption, and that this assumption was realistic as at the
balance sheet date. The going concern assumption is based
upon the
\ufb01
nancial position of the Group and the development
plans currently in place. In the Board of Directors\u2019 view, the
annual accounts give a true and fair view of the group\u2019s assets
and liabilities,
\ufb01
nancial position and results. PetroNor E&P ASA
is the parent company of the PetroNor Group. The
\ufb01
nancial
statements have been prepared on the assumption that the
PetroNor Group will continue as a going concern. The Group
recognises that in order to fund on-going operations and pursue
organic and inorganic growth opportunities it will require
additional funding. This funding may be sourced through joint
venture equity or share issues or through debt
\ufb01
nance.
As discussed in the Board of Directors\u2019 Report, the Group has
continued to operate e
\ufb00
ectively with a strong balance sheet and
cash
\ufb02
ow position, this has enabled the directors of PetroNor
(the \u201cDirectors\u201d) to form the opinion that the Group will be in a
position to continue to meet its liabilities and obligations for a
period of at least twelve months from the date of signing this
report.
This
\ufb01
nancial report does not include any adjustments relating to
the recoverability and classi
\ufb01
cation of recorded asset amounts
or to the amounts and classi
\ufb01
cation of liabilities that might be
necessary should the Group not continue as a going concern.
The following
\ufb01
nancial review is based on the
\ufb01
nancial
statements of PetroNor E&P ASA and its subsidiaries. The
statements have been prepared in accordance with IFRS
Accounting Standards as adopted by the EU as well as
Norwegian accounting legislation.
In the view of the Board, the consolidated statement of
comprehensive income, consolidated statement of changes
in equity, consolidated statement of
\ufb01
nancial position and
consolidated statement of cash
\ufb02
ows provide satisfactory
information about the operations,
\ufb01
nancial results and position
of the Group and the Parent company at 31 December 2024.", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00198": { "value": "PetroNor E&P ASA\u2019s consolidated
\ufb01
nancial statements have
been prepared in accordance with IFRS\u00ae Accounting Standards
as adopted by the EU and are mandatory for
\ufb01
nancial years
beginning on or after 1 January 2024, and Norwegian disclosure
requirements listed in the Norwegian Accounting Act as of
31 December 2024. The consolidated
\ufb01
nancial statements have
been prepared on the basis of uniform accounting principles
for similar transactions and events under otherwise similar
circumstances.", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00199": { "value": "GOING CONCERN
The Board of Directors con
\ufb01
rms that the annual
\ufb01
nancial
statements have been prepared pursuant to the going concern
assumption, and that this assumption was realistic as at the
balance sheet date. The going concern assumption is based
upon the
\ufb01
nancial position of the Group and the development
plans currently in place. In the Board of Directors\u2019 view, the
annual accounts give a true and fair view of the group\u2019s assets
and liabilities,
\ufb01
nancial position and results. PetroNor E&P ASA
is the parent company of the PetroNor Group. The
\ufb01
nancial
statements have been prepared on the assumption that the
PetroNor Group will continue as a going concern. The Group
recognises that in order to fund on-going operations and pursue
organic and inorganic growth opportunities it will require
additional funding. This funding may be sourced through joint
venture equity or share issues or through debt
\ufb01
nance.
As discussed in the Board of Directors\u2019 Report, the Group has
continued to operate e
\ufb00
ectively with a strong balance sheet and
cash
\ufb02
ow position, this has enabled the directors of PetroNor
(the \u201cDirectors\u201d) to form the opinion that the Group will be in a
position to continue to meet its liabilities and obligations for a
period of at least twelve months from the date of signing this
report.
This
\ufb01
nancial report does not include any adjustments relating to
the recoverability and classi
\ufb01
cation of recorded asset amounts
or to the amounts and classi
\ufb01
cation of liabilities that might be
necessary should the Group not continue as a going concern.
The following
\ufb01
nancial review is based on the
\ufb01
nancial
statements of PetroNor E&P ASA and its subsidiaries. The
statements have been prepared in accordance with IFRS
Accounting Standards as adopted by the EU as well as
Norwegian accounting legislation.
In the view of the Board, the consolidated statement of
comprehensive income, consolidated statement of changes
in equity, consolidated statement of
\ufb01
nancial position and
consolidated statement of cash
\ufb02
ows provide satisfactory
information about the operations,
\ufb01
nancial results and position
of the Group and the Parent company at 31 December 2024.", "dimensions": { "concept": "ifrs-full:DisclosureOfGoingConcernExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00201": { "value": "Note 03
Significant accounting judgements,
estimates and assumptions
As part of recognising assets and liabilities certain estimates
have been prepared based on historical knowledge and best-
available current information. The management apply their
professional judgment when assessing the assumptions to
be used in the calculation of the estimates. Estimates assume
a reasonable expectation of future events and are based on
current trends and economic data, obtained both externally and
within the Group.
Management has identi
\ufb01
ed the following critical accounting
policies for which signi
\ufb01
cant judgements, estimates and
assumptions are made. Actual results may di
\ufb00
er from these
estimates under di
\ufb00
erent assumptions and conditions and
may materially a
\ufb00
ect
\ufb01
nancial results or the
\ufb01
nancial position
reported in future period.
Further details of the nature of these assumptions and
conditions may be found in the relevant notes to the
\ufb01
nancial
statements.
HYDROCARBON RESERVE AND RESOURCE ESTIMATES
Hydrocarbon reserves are estimates of the amount of
hydrocarbons that can be economically and legally extracted
from the Group\u2019s oil and gas properties. The Group estimates
its commercial reserves and resources based on information
compiled by appropriately quali
\ufb01
ed persons relating to the
geological and technical data on the size, depth, shape and
grade of the hydrocarbon body and suitable production
techniques and recovery rates. Commercial reserves are
determined using estimates of oil and gas in place, recovery
factors and future commodity prices, the latter having an
impact on the total amount of recoverable reserves and the
proportion of the gross reserves which are attributable to the
host government under the terms of the Production-Sharing
Agreements. Future development costs are estimated using
assumptions as to the number of wells required to produce
the commercial reserves, the cost of such wells and associated
production facilities, and other capital costs. The current long-
term Brent oil price assumption used in the estimation of
commercial reserves is USD 70/bbl. The carrying amount of oil
and gas properties and licences at 31 December 2024 are shown
in Note 14 and 15.
The Group estimates and reports hydrocarbon reserves in
line with the principles contained in the Society of Petroleum
Engineers (SPE) Petroleum Resources Management Reporting
System (PRMS) framework. As the economic assumptions used
may change and as additional geological information is obtained
during the operation of a
\ufb01
eld, estimates of recoverable
reserves may change. Such changes may impact the Group\u2019s
reported
\ufb01
nancial position and results, which include:
\ue001
The carrying value of oil and gas properties may be a
\ufb00
ected
due to changes in estimated future cash
\ufb02
ows, Note 15;
\ue001
Depreciation and amortisation charges in the statement
of pro
\ufb01
t or loss and other comprehensive income may
change where such charges are determined using the Unit
Of Production (UOP) method, or where the useful life of the
related assets change, Note 15;
\ue001
Provisions for decommissioning are subject to re-estimation
\u2014 where changes to reserves estimates a
\ufb00
ect expectations
about when such activities will occur and the associated cost
of these activities, Note 18.
DECOMMISSIONING PROVISION
Decommissioning costs will be incurred by the Group at the
end of the operating life of some of the Group\u2019s facilities and
properties. The Group assesses its retirement obligation at
each reporting date. The ultimate decommissioning costs are
uncertain and cost estimates can vary in response to many
factors, including changes to relevant legal requirements, the
emergence of new restoration techniques or experience at
other production sites. The expected timing, extent and amount
of expenditure can also change, for example in response to
changes in reserves or changes in laws and regulations or their
interpretation. Therefore, signi
\ufb01
cant estimates and assumptions
are made in determining the provision for decommissioning
costs. As a result, there could be signi
\ufb01
cant adjustments to
the provisions established which would a
\ufb00
ect future
\ufb01
nancial
results. Climate considerations and the energy transition may
impact production pro
\ufb01
les and the economic lifespan of a
\ufb01
eld. Legislation may make decommissioning obligations more
onerous and or cost/commodity pricing may lead to an earlier
than anticipated asset abandonment. The provision at reporting
date represents management\u2019s best estimate of the present
value of the future decommissioning costs required. Additional
information is provided in Note 18.
IMPAIRMENT OF OIL AND GAS ASSETS
Management must determine whether there are circumstances
indicating a possible impairment of the Group\u2019s oil and gas
assets. Changes in the circumstances or expectations of future
performance of an individual asset or a group of assets may be
an indicator that the asset is impaired, requiring the carrying
amount to be written down to its recoverable amount. The
carrying value of an entity\u2019s assets or CGU\u2019s may be overstated
if the impairment calculation does not take into account
the impact of climate related matters. The evaluation for
impairment indicators involves assessing future cash
\ufb02
ows,
projected oil and gas prices, cost structures, and potential
factors that may render the asset uneconomic to develop.
This includes geological assessments and the remaining term
of the relevant licenses. Climate factors are incorporated
into the impairment review indirectly in the assessment of
the underlying macroeconomic assumptions including the
anticipated impacts of climate change in
\ufb02
uencing estimated
commodity prices.", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingEstimatesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00200": { "value": "Note 03
Significant accounting judgements,
estimates and assumptions
As part of recognising assets and liabilities certain estimates
have been prepared based on historical knowledge and best-
available current information. The management apply their
professional judgment when assessing the assumptions to
be used in the calculation of the estimates. Estimates assume
a reasonable expectation of future events and are based on
current trends and economic data, obtained both externally and
within the Group.
Management has identi
\ufb01
ed the following critical accounting
policies for which signi
\ufb01
cant judgements, estimates and
assumptions are made. Actual results may di
\ufb00
er from these
estimates under di
\ufb00
erent assumptions and conditions and
may materially a
\ufb00
ect
\ufb01
nancial results or the
\ufb01
nancial position
reported in future period.
Further details of the nature of these assumptions and
conditions may be found in the relevant notes to the
\ufb01
nancial
statements.
HYDROCARBON RESERVE AND RESOURCE ESTIMATES
Hydrocarbon reserves are estimates of the amount of
hydrocarbons that can be economically and legally extracted
from the Group\u2019s oil and gas properties. The Group estimates
its commercial reserves and resources based on information
compiled by appropriately quali
\ufb01
ed persons relating to the
geological and technical data on the size, depth, shape and
grade of the hydrocarbon body and suitable production
techniques and recovery rates. Commercial reserves are
determined using estimates of oil and gas in place, recovery
factors and future commodity prices, the latter having an
impact on the total amount of recoverable reserves and the
proportion of the gross reserves which are attributable to the
host government under the terms of the Production-Sharing
Agreements. Future development costs are estimated using
assumptions as to the number of wells required to produce
the commercial reserves, the cost of such wells and associated
production facilities, and other capital costs. The current long-
term Brent oil price assumption used in the estimation of
commercial reserves is USD 70/bbl. The carrying amount of oil
and gas properties and licences at 31 December 2024 are shown
in Note 14 and 15.
The Group estimates and reports hydrocarbon reserves in
line with the principles contained in the Society of Petroleum
Engineers (SPE) Petroleum Resources Management Reporting
System (PRMS) framework. As the economic assumptions used
may change and as additional geological information is obtained
during the operation of a
\ufb01
eld, estimates of recoverable
reserves may change. Such changes may impact the Group\u2019s
reported
\ufb01
nancial position and results, which include:
\ue001
The carrying value of oil and gas properties may be a
\ufb00
ected
due to changes in estimated future cash
\ufb02
ows, Note 15;
\ue001
Depreciation and amortisation charges in the statement
of pro
\ufb01
t or loss and other comprehensive income may
change where such charges are determined using the Unit
Of Production (UOP) method, or where the useful life of the
related assets change, Note 15;
\ue001
Provisions for decommissioning are subject to re-estimation
\u2014 where changes to reserves estimates a
\ufb00
ect expectations
about when such activities will occur and the associated cost
of these activities, Note 18.
DECOMMISSIONING PROVISION
Decommissioning costs will be incurred by the Group at the
end of the operating life of some of the Group\u2019s facilities and
properties. The Group assesses its retirement obligation at
each reporting date. The ultimate decommissioning costs are
uncertain and cost estimates can vary in response to many
factors, including changes to relevant legal requirements, the
emergence of new restoration techniques or experience at
other production sites. The expected timing, extent and amount
of expenditure can also change, for example in response to
changes in reserves or changes in laws and regulations or their
interpretation. Therefore, signi
\ufb01
cant estimates and assumptions
are made in determining the provision for decommissioning
costs. As a result, there could be signi
\ufb01
cant adjustments to
the provisions established which would a
\ufb00
ect future
\ufb01
nancial
results. Climate considerations and the energy transition may
impact production pro
\ufb01
les and the economic lifespan of a
\ufb01
eld. Legislation may make decommissioning obligations more
onerous and or cost/commodity pricing may lead to an earlier
than anticipated asset abandonment. The provision at reporting
date represents management\u2019s best estimate of the present
value of the future decommissioning costs required. Additional
information is provided in Note 18.
IMPAIRMENT OF OIL AND GAS ASSETS
Management must determine whether there are circumstances
indicating a possible impairment of the Group\u2019s oil and gas
assets. Changes in the circumstances or expectations of future
performance of an individual asset or a group of assets may be
an indicator that the asset is impaired, requiring the carrying
amount to be written down to its recoverable amount. The
carrying value of an entity\u2019s assets or CGU\u2019s may be overstated
if the impairment calculation does not take into account
the impact of climate related matters. The evaluation for
impairment indicators involves assessing future cash
\ufb02
ows,
projected oil and gas prices, cost structures, and potential
factors that may render the asset uneconomic to develop.
This includes geological assessments and the remaining term
of the relevant licenses. Climate factors are incorporated
into the impairment review indirectly in the assessment of
the underlying macroeconomic assumptions including the
anticipated impacts of climate change in
\ufb02
uencing estimated
commodity prices.", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00202": { "value": "DECOMMISSIONING PROVISION
Decommissioning costs will be incurred by the Group at the
end of the operating life of some of the Group\u2019s facilities and
properties. The Group assesses its retirement obligation at
each reporting date. The ultimate decommissioning costs are
uncertain and cost estimates can vary in response to many
factors, including changes to relevant legal requirements, the
emergence of new restoration techniques or experience at
other production sites. The expected timing, extent and amount
of expenditure can also change, for example in response to
changes in reserves or changes in laws and regulations or their
interpretation. Therefore, signi
\ufb01
cant estimates and assumptions
are made in determining the provision for decommissioning
costs. As a result, there could be signi
\ufb01
cant adjustments to
the provisions established which would a
\ufb00
ect future
\ufb01
nancial
results. Climate considerations and the energy transition may
impact production pro
\ufb01
les and the economic lifespan of a
\ufb01
eld. Legislation may make decommissioning obligations more
onerous and or cost/commodity pricing may lead to an earlier
than anticipated asset abandonment. The provision at reporting
date represents management\u2019s best estimate of the present
value of the future decommissioning costs required. Additional
information is provided in Note 18.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00204": { "value": "Note 04
Revenue
\n\n\n\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\n\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\n
\u00a0 \u00a0
Amounts in USD thousand
2024
2023
Revenue from contracts from customers
\u00a0 \u00a0
Revenue from sales of petroleum products
1
139,945
120,893
Other Revenue
\u00a0 \u00a0
Assignment of tax oil
39,976
39,852
Assignment of royalties
24,442
26,584
Marketing fees
170
-
Total Revenue
204,533
187,329
Quantity of oil lifted (barrels)
1,795,459
1,543,910
Average selling price (USD per barrel)
77.94
78.30
Quantity of net oil produced after royalty, cost oil and tax oil (barrels)
1,202,459
1,396,118
\n", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00203": { "value": "Note 04
Revenue
\n\n\n\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\n\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\t\n\t\t\t\n\t\t\t\n\t\t\t\n\t\t\n\t\n
\u00a0 \u00a0
Amounts in USD thousand
2024
2023
Revenue from contracts from customers
\u00a0 \u00a0
Revenue from sales of petroleum products
1
139,945
120,893
Other Revenue
\u00a0 \u00a0
Assignment of tax oil
39,976
39,852
Assignment of royalties
24,442
26,584
Marketing fees
170
-
Total Revenue
204,533
187,329
Quantity of oil lifted (barrels)
1,795,459
1,543,910
Average selling price (USD per barrel)
77.94
78.30
Quantity of net oil produced after royalty, cost oil and tax oil (barrels)
1,202,459
1,396,118
\n
1
All revenue from the sales of petroleum products in 2024 is generated, recognised and transferred at a point in time. Invoices are due for settlement thirty
days from the Bill of Lading, the point at which crude oil had been loaded onto vessel for shipment. All Group revenue is derived from production in the
Republic of the Congo from the PNGF Sud o
\ufb00
shore asset. The Group presents pro
\ufb01
t oil tax and royalties on a grossed-up basis as an income tax expense
with corresponding increase in oil and gas revenues and any associated royalties are included in cost of sales. Refer to note 28(h) for additional information. ", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00205": { "value": "Note 05
Cost of sales
Amounts in USD thousand
2024
2023
Operating expenses
19,957
20,795
Movement in oil overlift position
35,467
-
Royalty
24,442
26,584
Depreciation and amortisation of oil and gas properties
20,615
17,119
Provision for Diversi
\ufb01
ed Investment
1,627
1,772
Movement in oil inventory
3,081
4,399
Total
105,189
70,669
", "dimensions": { "concept": "ifrs-full:DisclosureOfCostOfSalesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00206": { "value": "Note 06
Administrative expenses
Amounts in USD thousand
Note
2024
2023
Employee bene
\ufb01
t expenses
6a
5,271
5,415
Travelling expenses
475
594
Legal and professional expenses
5,757
4,067
Corporate social responsibility
103
294
Restructuring expenses
726
-
Other expenses
1,649
1,034
Total
13,981
11,404
\n
6A.
EMPLOYEE BENEFIT EXPENSES
\n \n
Amounts in USD thousand
2024
2023
Salaries
3,891
4,334
Short-term non-monetary bene
\ufb01
ts
286
641
Employee bonuses
744
104
De
\ufb01
ned contribution pension cost
119
65
Social-security contributions and similar taxes
231
271
Total
5,271
5,415
\n
In accordance with Norwegian law PetroNor is required to
\n
have an occupational pension scheme (\u201cLov om obligatorisk
\n
tjenestepensjon\u201d). The Norwegian subsidiary that employs sta
\ufb00
\n
PetroNor E&P Services AS contributes to an external de
\ufb01
ned
\n
contribution scheme and therefore no pension liability is
\n
recognised in the statement of
\ufb01
nancial position.
\n
Under the Pensions Act 2008 every employer in the UK must put
\n
certain sta
\ufb00
into a workplace pension scheme and contribute
\n
towards it,
\n
PetroNor E&P Services Limited the subsidiary that employs sta
\ufb00
\n
in the UK, contributes into an external de
\ufb01
ned contribution
\n
scheme. As such, no pension liability is recognised in the
\n
statement of
\ufb01
nancial position in relation to the company\u2019s UK
\n
based employees.
\n
There are currently no share-based payment incentive schemes
\n
in place for employees. The cost of non-cash bene
\ufb01
ts to
\n
employees is disclosed as short-term non-monetary bene
\ufb01
ts
\n
above. Detailed disclosures on employee pro
\ufb01
les is included
\n
within the social information section of the Sustainability
\n
Report.
\n
The average full-time equivalent (FTE) employees for 2024 was
\n
15 (2023: 22).
6B.
AUDITORS\u2019 REMUNERATION
Amounts in USD thousand
2024
2023
Paid or payable to BDO
Audit review of
\ufb01
nancial reports
BDO AS
256
358
BDO Network
\ufb01
rms
46
59
Total
302
417
Other non-assurance services
BDO related practices
77
12
Total
77
12
Paid or payable to other audit
\ufb01
rms
Audit or review of
\ufb01
nancial reports
62
67
Other non-assurance services
35
121
Total
97
188
\nFees, excluding VAT, to the auditors are included in administration expenses.", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralAndAdministrativeExpenseExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00207": { "value": "6A.
EMPLOYEE BENEFIT EXPENSES
\n \n
Amounts in USD thousand
2024
2023
Salaries
3,891
4,334
Short-term non-monetary bene
\ufb01
ts
286
641
Employee bonuses
744
104
De
\ufb01
ned contribution pension cost
119
65
Social-security contributions and similar taxes
231
271
Total
5,271
5,415
\n
In accordance with Norwegian law PetroNor is required to
\n
have an occupational pension scheme (\u201cLov om obligatorisk
\n
tjenestepensjon\u201d). The Norwegian subsidiary that employs sta
\ufb00
\n
PetroNor E&P Services AS contributes to an external de
\ufb01
ned
\n
contribution scheme and therefore no pension liability is
\n
recognised in the statement of
\ufb01
nancial position.
\n
Under the Pensions Act 2008 every employer in the UK must put
\n
certain sta
\ufb00
into a workplace pension scheme and contribute
\n
towards it,
\n
PetroNor E&P Services Limited the subsidiary that employs sta
\ufb00
\n
in the UK, contributes into an external de
\ufb01
ned contribution
\n
scheme. As such, no pension liability is recognised in the
\n
statement of
\ufb01
nancial position in relation to the company\u2019s UK
\n
based employees.
\n
There are currently no share-based payment incentive schemes
\n
in place for employees. The cost of non-cash bene
\ufb01
ts to
\n
employees is disclosed as short-term non-monetary bene
\ufb01
ts
\n
above. Detailed disclosures on employee pro
\ufb01
les is included
\n
within the social information section of the Sustainability
\n
Report.
\n
The average full-time equivalent (FTE) employees for 2024 was
\n15 (2023: 22).", "dimensions": { "concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00208": { "value": "6B.
AUDITORS\u2019 REMUNERATION
Amounts in USD thousand
2024
2023
Paid or payable to BDO
Audit review of
\ufb01
nancial reports
BDO AS
256
358
BDO Network
\ufb01
rms
46
59
Total
302
417
Other non-assurance services
BDO related practices
77
12
Total
77
12
Paid or payable to other audit
\ufb01
rms
Audit or review of
\ufb01
nancial reports
62
67
Other non-assurance services
35
121
Total
97
188
Fees, excluding VAT, to the auditors are included in administration expenses.", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00213": { "value": "Note 07
Finance
expense
\n \n
Amounts in USD thousand
2024
2023
Interest income
1,865
-
Total
1,865
-
Finance Expense
\n \n
Amounts in USD thousand
Note
2024
2023
Unwinding of discount on decommissioning liability
18
3,306
2,440
Other
\ufb01
nance costs
30
38
Interest on loans
17
353
813
Total
3,689
3,291
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00212": { "value": "Note 07
Finance
expense
\n \n
Amounts in USD thousand
2024
2023
Interest income
1,865
-
Total
1,865
-
Finance Expense
\n \n
Amounts in USD thousand
Note
2024
2023
Unwinding of discount on decommissioning liability
18
3,306
2,440
Other
\ufb01
nance costs
30
38
Interest on loans
17
353
813
Total
3,689
3,291
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00211": { "value": "Note 07
Finance
expense
\n \n
Amounts in USD thousand
2024
2023
Interest income
1,865
-
Total
1,865
-
Finance Expense
\n \n
Amounts in USD thousand
Note
2024
2023
Unwinding of discount on decommissioning liability
18
3,306
2,440
Other
\ufb01
nance costs
30
38
Interest on loans
17
353
813
Total
3,689
3,291
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00210": { "value": "Note 07
Finance
expense
\n \n
Amounts in USD thousand
2024
2023
Interest income
1,865
-
Total
1,865
-
Finance Expense
\n \n
Amounts in USD thousand
Note
2024
2023
Unwinding of discount on decommissioning liability
18
3,306
2,440
Other
\ufb01
nance costs
30
38
Interest on loans
17
353
813
Total
3,689
3,291
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00209": { "value": "Note 07
Finance
expense
\n \n
Amounts in USD thousand
2024
2023
Interest income
1,865
-
Total
1,865
-
Finance Expense
\n \n
Amounts in USD thousand
Note
2024
2023
Unwinding of discount on decommissioning liability
18
3,306
2,440
Other
\ufb01
nance costs
30
38
Interest on loans
17
353
813
Total
3,689
3,291
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00215": { "value": "Note 08
Tax expense
\n
Tax expense excluding tax on sale of discontinued operation
Amounts in USD thousand
2024
2023
Petroleum revenue tax expense
Current income tax charge
39,976
39,852
Total tax expense reported in the consolidated statement of comprehensive income
39,976
39,852
\n
The petroleum revenue tax expense relates solely to the
\n
subsidiary in Congo and represents the assignment of tax oil on
\n
the revenue from sales of petroleum products, Note 4.
\n
During 2023, a taxable gain arose on the farm-out of the
\n
Guinea-Bissau assets. A further tax expense of USD 1.5 million
\n
was recognised in association with this transaction during
\n
2024 which is included within pro
\ufb01
t/(loss) from discontinued
\n
operations in the statement of comprehensive income.
\n
There was no income tax expense in the other subsidiaries\u2019
\n
jurisdictions nor in the parent\u2019s jurisdiction as these companies
\n
are in taxable loss positions in both 2024 and 2023. Average
\n
e
\ufb00
ective tax rate for the year was 20% (2023: 21%) based on
\ngross revenue of the Group.", "dimensions": { "concept": "ifrs-full:DisclosureOfDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00214": { "value": "Note 08
Tax expense
\n
Tax expense excluding tax on sale of discontinued operation
Amounts in USD thousand
2024
2023
Petroleum revenue tax expense
Current income tax charge
39,976
39,852
Total tax expense reported in the consolidated statement of comprehensive income
39,976
39,852
\n
The petroleum revenue tax expense relates solely to the
\n
subsidiary in Congo and represents the assignment of tax oil on
\n
the revenue from sales of petroleum products, Note 4.
\n
During 2023, a taxable gain arose on the farm-out of the
\n
Guinea-Bissau assets. A further tax expense of USD 1.5 million
\n
was recognised in association with this transaction during
\n
2024 which is included within pro
\ufb01
t/(loss) from discontinued
\n
operations in the statement of comprehensive income.
\n
There was no income tax expense in the other subsidiaries\u2019
\n
jurisdictions nor in the parent\u2019s jurisdiction as these companies
\n
are in taxable loss positions in both 2024 and 2023. Average
\n
e
\ufb00
ective tax rate for the year was 20% (2023: 21%) based on
\ngross revenue of the Group.", "dimensions": { "concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00216": { "value": "Note 09
Earnings per share
There are nil options as at 31 December 2024 (31 December 2023: nil).
\n \n
Amounts in USD thousand
2024
2023
Pro
\ufb01
t attributable to ordinary shareholders from continuing operations
Pro
\ufb01
t attributable to the ordinary equity holders used in calculating
basic / diluted pro
\ufb01
t per share
35,172
52,479
Pro
\ufb01
t attributable to the ordinary equity holders used in calculating
basic / diluted pro
\ufb01
t per share
35,172
52,479
\n \n
Weighted average number of ordinary shares outstanding during the period used in the
calculation of pro
\ufb01
t / (loss) per share
2024
2023
Basic
142,356,855
142,356,855
Diluted
142,356,855
142,356,855
\n \n
Earnings per share
2024
2023
USD Cents
USD Cents
Basic
24.7
35.0
Diluted
24.7
35.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00217": { "value": "Note 10
Inventories
\n \n
Amounts in USD thousand
2024
2023
Crude oil inventory
-
3,078
Materials and supplies
13,265
14,761
Total
13,265
17,839
Crude oil inventory is valued at cost, PetroNor were in an overlift
position at 31 December 2024 and thus crude oil inventory is nil.
The crude oil inventory and the material and supplies inventory
are valued at the lower of cost and net realisable value. Cost is
determined using the weighted average method. Net realisable
value is the estimated selling price, less applicable selling
expenses. The cost of inventory includes all costs related
to bringing the inventory to its current condition, including
processing costs, labour costs, supplies, direct and allocated
indirect operating overhead and depreciation expense, where
applicable, including allocation of
\ufb01
xed and variable costs to
inventory. ", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00218": { "value": "Note 11
Trade and other receivables
\n \n
Amounts in USD thousand
2024
2023
Recoverability less than one year
Trade receivables
64,010
27,317
Other receivables
5,405
3,759
Total
69,415
31,076
Recoverability more than one year
Other receivables:
Due from related parties
1
11,681
11,057
Advance against decommissioning cost
2
30,515
30,050
Fair value of contingent consideration
3
2,600
2,600
Total
44,796
43,707
1
The Group disposed of its interests in fully owned subsidiaries Aje Nigeria Holding B.V., Aje Services Holding B.V. and Aje Production Ltd. The transaction
completed on 29 December 2023 with the consideration of USD 10 million expected to be paid via the allotment and issue of new shares in Aje Production
AS. The disposal forms part of the YFP DW joint venture transaction where the consideration receivable will be reclassi
\ufb01
ed to an investment in associate once
consideration is paid. USD 1 million relates to an assignment fee to be recovered from the joint venture in due course.
2
In addition to the booking of the decommissioning cost asset and liability, the contractors group and the Congolese Government have agreed to set up funds
for the decommissioning cost in an escrow account which is managed by the operator. The advances of the funds for the year are made on the basis of an
average rate of USD 0.50 per barrel produced (2023: USD 0.28 per barrel). Refer to Note 18 for further details on the decommissioning liability.
3
On June 27, 2023, PetroNor E&P ASA announced the farm-out of the exploration licences in Guinea-Bissau. On this occasion, PetroNor E&P AB entered into
a binding agreement to transfer 100 percent of its participation interest in the two exploration licences to Apus Energia Guin\u00e9-Bissau SA. Under the terms
of the agreement, e
\ufb00
ective January 1, 2023, PetroNor received a payment of USD 21.3 million upon completion of the transaction, plus costs for 2023
incurred after January 1, 2023 and up to the point of completion of USD 1.6 million. The company will then be eligible for two additional contingent earnout
payments of USD 30 million each. The
\ufb01
rst payment would be made after government approval of a Field Development Plan, and the second payment would
be made after the achievement of continuous oil production. PetroNor have assessed the fair value of the contingent consideration as at 31 December 2024
to be USD 2.6 million.
Trade receivables of USD 64.0 million re
\ufb02
ect the occurrence of
a sale on 29 December 2024, this amount was fully recovered in
January 2025.
The Group has adopted the simpli
\ufb01
ed approach allowable
under IFRS 9 Financial Instruments where the Group measures
the provision for impairment for trade receivables and amounts
due from related parties at an amount equal to lifetime ECL.
The ECL on trade receivables are estimated using a provision
matrix by reference to past default experience of the debtor and
an analysis of the debtors\u2019 current
\ufb01
nancial position, adjusted
for factors that are speci
\ufb01
c to the debtors\u2019 general economic
conditions and forward looking elements of the industry in
which the debtors operate and an assessment of both the
current as well as the forecast direction of conditions at the
reporting date. The group has established a provision matrix
that is based on its historical credit-loss experience, adjusted
for forward looking factors speci
\ufb01
c to the debtors and the
economic environment. At 31 December 2024, the provision for
the Group is nil. ", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00220": { "value": "Note 12
Cash and cash equivalents
\n \n
Amounts in USD thousand
2024
2023
Cash in bank
79,668
46,217
Restricted cash
24
32
Total
79,692
46,249
Restricted cash at 31 December 2024 represents ringfenced cash payable to Norwegian authorities in relation to employment
obligations. ", "dimensions": { "concept": "ifrs-full:DisclosureOfRestrictedCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00219": { "value": "Note 12
Cash and cash equivalents
\n \n
Amounts in USD thousand
2024
2023
Cash in bank
79,668
46,217
Restricted cash
24
32
Total
79,692
46,249
Restricted cash at 31 December 2024 represents ringfenced cash payable to Norwegian authorities in relation to employment
obligations.
The following table represents the changes in liabilities arising from
\ufb01
nancing activities through cash
\ufb02
ows and non-cash changes:
\n \n
Non-current
Current
Amounts in USD thousand
borrowings
borrowings
Total
As at 1 January 2024
-
5,500
5,500
Cash
\ufb02
ows
-
(5,500)
(5,500)
Non-cash
\ufb02
ows
-
-
-
As at 31 December 2024
-
-
-
As at 1 January 2023
5,500
5,500
11,000
Cash
\ufb02
ows
-
(5,500)
(5,500)
Non-cash
\ufb02
ows
(5,500)
5,500
-
As at 31 December 2023
-
5,500
5,500
", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00221": { "value": "Note 13
Segment information
For management purposes, the Group is organised into one
main operating segment, which involves exploration and
production of hydrocarbons. All of the Group's activities are
interrelated, and discrete
\ufb01
nancial information is reported
to Chief Operating Decision Maker as a single segment.
Accordingly, all signi
\ufb01
cant operating decisions are based upon
analysis of the Group as one segment. The
\ufb01
nancial results from
this segment are equivalent to the
\ufb01
nancial statements of the
Group as a whole.
The Group only has one operating segment, being exploration
and production of hydrocarbons.
The analysis of the location of non-current assets is as follows:
\n \n
Amounts in USD thousand
2024
2023
Congo
118,059
124,798
Gambia
6,414
5,461
Guinea-Bissau
2,600
2,600
Norway
11,791
11,324
Other
-
175
Total
138,864
144,358
Note 14
Property, plant, and equipment
PRODUCTION ASSETS AND EQUIPMENT
\n \n
Amounts in USD thousand
2024
2023
Cost
At 1 January
132,034
90,493
Additions
13,061
42,467
Disposals in relation to loss of control of entities
-
(926)
At 31 December
145,095
132,034
Depreciation
At 1 January
39,243
22,552
Charge for the year
19,962
16,691
Depreciation on disposals
-
-
At 31 December
59,205
39,243
Net carrying amount
At 31 December
85,890
92,791
Production assets and equipment are carried at the following values:
\n \n
Amounts in USD thousand
2024
2023
Oil & gas CAPEX
74,842
84,589
Decommissioning costs
10,910
7,864
Other
138
30
Total
85,890
92,473
PPE assets are distributed geographically as follow:
Amounts in USD thousand
2024
2023
Congo
85,780
92,473
Other
110
10
Total
85,890
92,483
\n \n
Amounts in USD thousand
2024
2023
Right-of-use assets
120
308
The carrying value of production assets are assessed against
their risked economic value for indicators of impairment. Two
of the key factors in the economic evaluation of hydrocarbon
assets are the future oil prices and the recoverable reserves of
the assets, the bench mark oil price used economic valuations
was USD 70/bbl. Please reference the Reserves report and the
reserves table included in note 15. There were no indicators of
impairment.", "dimensions": { "concept": "ifrs-full:DisclosureOfGeographicalAreasExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00222": { "value": "Note 13
Segment information
For management purposes, the Group is organised into one
main operating segment, which involves exploration and
production of hydrocarbons. All of the Group's activities are
interrelated, and discrete
\ufb01
nancial information is reported
to Chief Operating Decision Maker as a single segment.
Accordingly, all signi
\ufb01
cant operating decisions are based upon
analysis of the Group as one segment. The
\ufb01
nancial results from
this segment are equivalent to the
\ufb01
nancial statements of the
Group as a whole.
The Group only has one operating segment, being exploration
and production of hydrocarbons.
The analysis of the location of non-current assets is as follows:
\n \n
Amounts in USD thousand
2024
2023
Congo
118,059
124,798
Gambia
6,414
5,461
Guinea-Bissau
2,600
2,600
Norway
11,791
11,324
Other
-
175
Total
138,864
144,358
", "dimensions": { "concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00223": { "value": "Note 14
Property, plant, and equipment
PRODUCTION ASSETS AND EQUIPMENT
\n \n
Amounts in USD thousand
2024
2023
Cost
At 1 January
132,034
90,493
Additions
13,061
42,467
Disposals in relation to loss of control of entities
-
(926)
At 31 December
145,095
132,034
Depreciation
At 1 January
39,243
22,552
Charge for the year
19,962
16,691
Depreciation on disposals
-
-
At 31 December
59,205
39,243
Net carrying amount
At 31 December
85,890
92,791
Production assets and equipment are carried at the following values:
\n \n
Amounts in USD thousand
2024
2023
Oil & gas CAPEX
74,842
84,589
Decommissioning costs
10,910
7,864
Other
138
30
Total
85,890
92,473
PPE assets are distributed geographically as follow:
Amounts in USD thousand
2024
2023
Congo
85,780
92,473
Other
110
10
Total
85,890
92,483
\n \n
Amounts in USD thousand
2024
2023
Right-of-use assets
120
308
The carrying value of production assets are assessed against
their risked economic value for indicators of impairment. Two
of the key factors in the economic evaluation of hydrocarbon
assets are the future oil prices and the recoverable reserves of
the assets, the bench mark oil price used economic valuations
was USD 70/bbl. Please reference the Reserves report and the
reserves table included in note 15. There were no indicators of
impairment.", "dimensions": { "concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00224": { "value": "\n \n
Amounts in USD thousand
2024
2023
Cost
At 1 January
132,034
90,493
Additions
13,061
42,467
Disposals in relation to loss of control of entities
-
(926)
At 31 December
145,095
132,034
Depreciation
At 1 January
39,243
22,552
Charge for the year
19,962
16,691
Depreciation on disposals
-
-
At 31 December
59,205
39,243
Net carrying amount
At 31 December
85,890
92,791
\n \n
Amounts in USD thousand
2024
2023
Cost
At 1 January
13,025
37,831
Additions
952
1,129
Disposals
(174)
(667)
Disposals in relation to loss of control of entities
-
(25,268)
At 31 December
13,803
13,025
Accumulated amortisation and impairment
At 1 January
5,165
4,579
Amortisation
460
586
At 31 December
5,625
5,165
Net carrying value
At 1 January
7,860
33,252
At 31 December
8,178
7,860
", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00226": { "value": "Note 15
Intangible assets
LICENCES AND APPROVALS
\n \n
Amounts in USD thousand
2024
2023
Cost
At 1 January
13,025
37,831
Additions
952
1,129
Disposals
(174)
(667)
Disposals in relation to loss of control of entities
-
(25,268)
At 31 December
13,803
13,025
Accumulated amortisation and impairment
At 1 January
5,165
4,579
Amortisation
460
586
At 31 December
5,625
5,165
Net carrying value
At 1 January
7,860
33,252
At 31 December
8,178
7,860
GOODWILL
\n \n
Amounts in USD thousand
2024
2023
Cost
At 1 January
-
9,031
Additions in relation to business combinations
-
-
Disposals in relation to loss of control of entities
-
(9,031)
At 31 December
-
-
GOODWILL
During 2023, the technical goodwill was derecognised as part of
the disposal of the entities and assets in which they originated
from.
LICENCE OVERVIEW
Congo
In 2017, subsidiary company Hemla E&P Congo SA acquired
interests in three development and production permits
(Tchendo II: 20%; Tchibouela II: 20% and Tchibeli-Litanzi II: 20%)
which will respectively end in December 2037, for each of them,
with possible extensions for 5 years. All these three licences
are called or named collectively \u201cPNGF Sud\u201d and together
comprise an area of 482.28km
2
. The operator of the licences
is Perenco, and the carrying value as at 31 December 2024 is
USD 1.8 million. This number is net of depletion, the Congo
intangible assets are the only intangibles in active use and being
amortised.
The Gambia
The A4 licence area is 1,376km
2
and is operated by company
subsidiary PetroNor E&P Gambia Ltd. PetroNor secured a new
exploration licence (PEPLA) on 18 November 2022 and entered
into the
\ufb01
rst exploration period which has a duration of three
years. PetroNor hold 90% equity with the Gambia National
Petroleum Company as partner (10% equity). As at 31 December
2024 the carrying value of the A4 licence is USD 6.4 million.
IMPAIRMENT ASSESSMENT
Group assets are assessed for indicators of impairment on a
periodic basis. Indicators of impairment would be for example
a licence that is approaching the end of its term or a licence
where management have indicated that there are no plans
to continue with exploration and evaluation, or evaluation
work which indicated that an asset would be uneconomic. The
carrying value of intangible assets relating to Congo and The
Gambia were assessed against their risked economic value
and no assets were impaired in the period ended 31 December
2024.
RESERVES AND RESOURCES
The Group has adopted a policy of regional reserve reporting
using external third-party companies to audit its work and
certify reserves and resources. Reserve and contingent resource
estimates comply with the de
\ufb01
nitions set by the Petroleum
Resources Management System (\u201cPRMS\u201d) issued by the Society
of Petroleum Engineers (\u201cSPE\u201d), the American Association of
Petroleum Geologists (\u201cAAPG\u201d), the World Petroleum Council
(\u201cWPC\u201d) and the Society of Petroleum Evaluation Engineers
(\u201cSPEE\u201d) in March 2007. Three60 Energy Norway AS provided the
3
rd
party veri
\ufb01
cations of the PNGF Sud reserves.
The following is a summary of key results from the Annual
Reserve Report (ASR) (net of the Group\u2019s share):
\n \n
1P/1C
2P/2C
3P/3C
reserves/
reserves/
reserves/
resources
resources
resources
Asset
MMbbls
MMbbls
MMbbls
PNGF Sud reserves
11.3
16.0
20.3
PNGF Sud contingent
resources
2.5
5.8
14.5
De
\ufb01
nitions:
1P) Proved
reserves
Proved Reserves are those quantities of petroleum, which by
analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be commercially recoverable, from
a given date forward, from known reservoirs and under de
\ufb01
ned
economic conditions, operating methods, and government
regulations.
2P) Proved plus Probable Reserves
Probable Reserves are those additional reserves which analysis
of geoscience and engineering data indicate are less likely to
be recovered than Proved Reserves but more certain to be
recovered than Possible Reserves.
3P) Proved plus Probable plus Possible Reserves
Possible Reserves are those additional reserves which analysis
of geoscience and engineering data indicate are less likely to be
recovered than Probable Reserves.", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00225": { "value": "Note 15
Intangible assets
LICENCES AND APPROVALS
\n \n
Amounts in USD thousand
2024
2023
Cost
At 1 January
13,025
37,831
Additions
952
1,129
Disposals
(174)
(667)
Disposals in relation to loss of control of entities
-
(25,268)
At 31 December
13,803
13,025
Accumulated amortisation and impairment
At 1 January
5,165
4,579
Amortisation
460
586
At 31 December
5,625
5,165
Net carrying value
At 1 January
7,860
33,252
At 31 December
8,178
7,860
GOODWILL
\n \n
Amounts in USD thousand
2024
2023
Cost
At 1 January
-
9,031
Additions in relation to business combinations
-
-
Disposals in relation to loss of control of entities
-
(9,031)
At 31 December
-
-
GOODWILL
During 2023, the technical goodwill was derecognised as part of
the disposal of the entities and assets in which they originated
from.
LICENCE OVERVIEW
Congo
In 2017, subsidiary company Hemla E&P Congo SA acquired
interests in three development and production permits
(Tchendo II: 20%; Tchibouela II: 20% and Tchibeli-Litanzi II: 20%)
which will respectively end in December 2037, for each of them,
with possible extensions for 5 years. All these three licences
are called or named collectively \u201cPNGF Sud\u201d and together
comprise an area of 482.28km
2
. The operator of the licences
is Perenco, and the carrying value as at 31 December 2024 is
USD 1.8 million. This number is net of depletion, the Congo
intangible assets are the only intangibles in active use and being
amortised.
The Gambia
The A4 licence area is 1,376km
2
and is operated by company
subsidiary PetroNor E&P Gambia Ltd. PetroNor secured a new
exploration licence (PEPLA) on 18 November 2022 and entered
into the
\ufb01
rst exploration period which has a duration of three
years. PetroNor hold 90% equity with the Gambia National
Petroleum Company as partner (10% equity). As at 31 December
2024 the carrying value of the A4 licence is USD 6.4 million.
IMPAIRMENT ASSESSMENT
Group assets are assessed for indicators of impairment on a
periodic basis. Indicators of impairment would be for example
a licence that is approaching the end of its term or a licence
where management have indicated that there are no plans
to continue with exploration and evaluation, or evaluation
work which indicated that an asset would be uneconomic. The
carrying value of intangible assets relating to Congo and The
Gambia were assessed against their risked economic value
and no assets were impaired in the period ended 31 December
2024.
RESERVES AND RESOURCES
The Group has adopted a policy of regional reserve reporting
using external third-party companies to audit its work and
certify reserves and resources. Reserve and contingent resource
estimates comply with the de
\ufb01
nitions set by the Petroleum
Resources Management System (\u201cPRMS\u201d) issued by the Society
of Petroleum Engineers (\u201cSPE\u201d), the American Association of
Petroleum Geologists (\u201cAAPG\u201d), the World Petroleum Council
(\u201cWPC\u201d) and the Society of Petroleum Evaluation Engineers
(\u201cSPEE\u201d) in March 2007. Three60 Energy Norway AS provided the
3
rd
party veri
\ufb01
cations of the PNGF Sud reserves.
The following is a summary of key results from the Annual
Reserve Report (ASR) (net of the Group\u2019s share):
\n \n
1P/1C
2P/2C
3P/3C
reserves/
reserves/
reserves/
resources
resources
resources
Asset
MMbbls
MMbbls
MMbbls
PNGF Sud reserves
11.3
16.0
20.3
PNGF Sud contingent
resources
2.5
5.8
14.5
De
\ufb01
nitions:
1P) Proved
reserves
Proved Reserves are those quantities of petroleum, which by
analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be commercially recoverable, from
a given date forward, from known reservoirs and under de
\ufb01
ned
economic conditions, operating methods, and government
regulations.
2P) Proved plus Probable Reserves
Probable Reserves are those additional reserves which analysis
of geoscience and engineering data indicate are less likely to
be recovered than Proved Reserves but more certain to be
recovered than Possible Reserves.
3P) Proved plus Probable plus Possible Reserves
Possible Reserves are those additional reserves which analysis
of geoscience and engineering data indicate are less likely to be
recovered than Probable Reserves.", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00228": { "value": "\n \n
Amounts in USD thousand
2024
2023
Cost
At 1 January
13,025
37,831
Additions
952
1,129
Disposals
(174)
(667)
Disposals in relation to loss of control of entities
-
(25,268)
At 31 December
13,803
13,025
Accumulated amortisation and impairment
At 1 January
5,165
4,579
Amortisation
460
586
At 31 December
5,625
5,165
Net carrying value
At 1 January
7,860
33,252
At 31 December
8,178
7,860
GOODWILL
\n \n
Amounts in USD thousand
2024
2023
Cost
At 1 January
-
9,031
Additions in relation to business combinations
-
-
Disposals in relation to loss of control of entities
-
(9,031)
At 31 December
-
-
", "dimensions": { "concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00227": { "value": "GOODWILL \n \n
Amounts in USD thousand
2024
2023
Cost
At 1 January
-
9,031
Additions in relation to business combinations
-
-
Disposals in relation to loss of control of entities
-
(9,031)
At 31 December
-
-
GOODWILL
During 2023, the technical goodwill was derecognised as part of
the disposal of the entities and assets in which they originated
from. ", "dimensions": { "concept": "ifrs-full:DisclosureOfGoodwillExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00229": { "value": "Note 16
Overlift, trade and other payables
Trade and other payables
\n \n
Amounts in USD thousand
Note
2024
2023
Amounts due less than one year:
Trade payables
5,525
12,233
Other payables and accrued liabilities
3,283
3,630
Due to related parties
22d
8
26
Taxes and state payables
529
4,162
Total
9,345
20,051
Amounts due more than one year
Other payables
3
145
Total
3
145
Overlift
A new trading agreement entered during the second quarter of 2024, allowed PetroNor to lift and sell more oil than the entitlement
interest it had in stock at the Djeno terminal at the time of lifting. This is known as an overlift position and will be replenished from
continuing production during the
\ufb01
rst half of 2025.
\n \n
Amounts in USD thousand
Note
2024
2023
Amounts due less than one year:
Overlift
35,782
-
Total
35,782
-
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00230": { "value": "\n \n
Amounts in USD thousand
Note
2024
2023
Amounts due less than one year:
Trade payables
5,525
12,233
Other payables and accrued liabilities
3,283
3,630
Due to related parties
22d
8
26
Taxes and state payables
529
4,162
Total
9,345
20,051
Amounts due more than one year
Other payables
3
145
Total
3
145
", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00231": { "value": "Note 17
Loans and borrowings
\n \n
Amounts in USD thousand
2024
2023
At 1 January
5,500
11,000
Principal repayment
(5,500)
(5,500)
Interest on loan accrued
353
813
Interest on loan paid
(353)
(813)
At 31 December
-
5,500
Ageing of loans payable
Current
-
5,500
Non-current
-
-
Total
-
5,500
During 2024, subsidiary Hemla Africa Holding AS fully repaid its facility held with Acqua Diversi
\ufb01
ed Holdings SPC early.", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00232": { "value": "Note 18
Provisions
DECOMMISSIONING PROVISION
In accordance with joint venture agreements and legislation, the
wellheads, production assets, pipelines and other installations
may have to be dismantled and removed from oil and natural
gas
\ufb01
elds when the production ceases. The exact timing of the
obligations is uncertain and depends on the rate the reserves of
the
\ufb01
eld are depleted.
Based on the existing production pro
\ufb01
le of the PNGF Sud
\ufb01
eld
and the size of the reserves, it is expected that expenditure
on retirement is likely to be after more than ten years. The
current bases for the provision are a discount rate of 6.25%
(2023: 6.5%) and an in
\ufb02
ation rate of 4.3% (2023: 3.0%). The initial
decommissioning liability study was prepared internally by
the operator Perenco. The company reassessed the applicable
discount and in
\ufb02
ation rate during 2024, the impact of the
reassessment was a net liability increase of USD 6.4 million
where USD 2.0 million was expensed.
The following table presents a reconciliation of the beginning
and ending aggregate amounts of the obligations associated
with the retirement of oil and natural gas properties:
\n \n
Amounts in USD thousand
Note
2024
2023
At 1 January
23,749
20,912
Arising during the year
4,804
4,284
Derecognised due to loss of control of entities
-
(3,887)
Unwinding of discount on decommissioning
7
3,306
2,440
At 31 December
31,859
23,749
Other provisions
3,364
3,323
Total provisions
35,223
27,072
", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00233": { "value": "Note 19
Deferred tax liabilities
Changes in net deferred tax liabilities during the year were as follows:
\n \n
Amounts in USD thousand
2024
2023
Net deferred tax liability at 1 January
-
(9,031)
Acquisitions and disposals
-
9,031
Net deferred tax liability at 31 December
-
-
Deferred tax assets have not been brought to account in respect
of tax losses and unrecognised capital allowances because as at
31 December 2024 it is uncertain when future taxable amounts
will be available to utilise those temporary di
\ufb00
erences and
losses. The primary income generating unit of the Group is in
a jurisdiction where taxes are an in-kind production levy. The
status of asset development in other jurisdictions is such that
pro
\ufb01
ts are not yet being recorded management are therefore
not yet able to perform an assessment that deferred tax assets
can be realised. As at 31 December 2024, the carried forward
gross tax loss is USD 130 million (2023: USD 127 million). Carried
forward losses from previous periods do not have an expiry
date.", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00234": { "value": "Note 20
Share capital
Ordinary shares participate in dividends and the proceeds on
winding up of the company in proportion to the number of
shares held and in proportion to the amount paid up on the
shares held.
At shareholders\u2019 meetings, each ordinary share entitles the
holder to one vote in proportion to the paid-up amount of the
share when a poll is called, otherwise each shareholder has one
vote on a show of hands.
Reconciliation of movement in shares on issue
\n \n
Number of fully
Number of fully
paid ordinary
paid ordinary
shares
shares
2024
2023
Balance at the beginning of the year
142,356,855
1,423,568,543
Issue of shares
-
7
Reverse share split
1
-
(1,281,211,695)
Balance at end of the year
142,356,855
142,356,855
Reconciliation of movements in issued capital
\n \n
2024
2023
Opening balance
159
159
Balance at end of the period
159
159
1
On 16 June 2023, PetroNor announced that the reverse share split in the ratio 10:1 had been registered with the Norwegian Register of Business Enterprises.
Following such registration, the share capital of the company is NOK 1,423,568.55 divided into 142,356,855 shares, each with a nominal value of NOK 0.01.
Share premium
Share premium reserve represents excess of subscription
value of the shares over the nominal amount.
\n \n
2024
2023
Opening balance
71,956
71,956
Balance at end of the period
71,956
71,956
", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00235": { "value": "Note 21
Reserves
The movement in reserves are re
\ufb02
ected in the statement of
changes in equity.
Foreign currency translation reserve
The foreign currency translation reserve is used to recognise
foreign currency exchange di
\ufb00
erences arising on translation of
functional currency to presentation currency.
Retained earnings
All other net gains and losses and transactions with owners not
recognised elsewhere.
Dividends
No dividends were declared during the year by the parent
company.
A repayment of capital equivalent to 2 NOK per share was
proposed based on an audited interim balance sheet from
9 December 2024. The repayment of capital was approved
post year end at a shareholder EGM on 23 January 2025, and
USD 25.6 million was paid out to shareholders on 31 January
2025.", "dimensions": { "concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00236": { "value": "Foreign currency translation reserve
The foreign currency translation reserve is used to recognise
foreign currency exchange di
\ufb00
erences arising on translation of
functional currency to presentation currency.", "dimensions": { "concept": "ifrs-full:DisclosureOfEffectOfChangesInForeignExchangeRatesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00237": { "value": "Dividends
No dividends were declared during the year by the parent
company. ", "dimensions": { "concept": "ifrs-full:DisclosureOfDividendsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00238": { "value": "Note 22
Related party transactions
22A.
BOARD AND KEY MANAGEMENT PERSONNEL REMUNERATION
Key management personnel are those persons having authority and responsibility for planning, directing and controlling the
activities of the Group, including the Directors listed on page 34, and the following other key personnel:
\n \n
Jens Pace
Chief executive o
\ufb03
cer
Claus Frimann-Dahl
Chief technical o
\ufb03
cer
Chris Butler
Group
\ufb01
nancial controller
As at the approval date of this report the base salary and fees for the following members of key management is as follows:
\n \n
Base salary and fees
Total base salary and
Individual
Title
Group Entity
/per annum
fees USD equivalent
J Iskander
Chair
PetroNor E&P Services AS
NOK 800,000
71,600
J Norman-Hansen
Board member
PetroNor E&P Services AS
NOK 550,000
49,225
A Georghiou
Board member
PetroNor E&P Services AS
NOK 550,000
64,825
PetroNor E&P Limited
EUR 15,000
J Pace
Chief Executive O
\ufb03
cer
PetroNor E&P Services AS
GBP 410,000
517,625
C Frimann-Dahl
Chief Technical O
\ufb03
cer
PetroNor E&P Services AS
NOK 2,625,000
234,938
C Butler
Group Financial Controller
PetroNor E&P Services Ltd
GBP
147,000
251,588
Hemla E&P Congo SA
USD 66,000
FX rates used:
NOK 1.00 : USD 0.0895
|
GBP 1.00 : USD 1.2625
\n \n
Post-
2024
Salary
Other cash
Severance
employment
Amounts in USD
Designation
and fees
Bonus
bene
\ufb01
ts
Package
bene
\ufb01
ts
Total
J Iskander
Chair
42,987
83,064
-
-
-
126,051
E Alhomouz
1
Former Chair
172,500
140,877
-
-
-
313,377
I Smines Tybring-Gjedde
2
Board member
38,973
84,526
-
-
-
123,499
G Kielland
2
Board member
38,973
84,526
-
-
-
123,499
A Samir Fawzi
Board member
47,208
84,526
-
-
-
131,734
J Norman-Hansen
Board member
47,208
84,526
-
-
-
131,734
J Pace
Chief Executive O
\ufb03
cer
523,580
135,623
-
-
-
659,203
C Frimann-Dahl
Chief Technical O
\ufb03
cer
247,621
39,324
2,666
-
15,569
305,180
M Barrett
3
Exploration Manager
209,289
-
1,886
223,964
-
435,139
C Butler
Group Financial Controller
252,317
41,599
6,936
-
18,824
319,676
E Sultan
3
Strategy and Contracts
Manager
105,000
-
-
21,000
-
126,000
Total
1,725,656
778,591
11,488
244,964
34,393
2,795,092
1
Eyas Alhomouz did not stand for re-election as Chair at the AGM on 29 May 2024.
2
Ingvil Smines Tybring-Gjedde and Gro Kielland resigned as board members on 1 November 2024.
3
As part of the restructuring process Michael Barrett and Emad Sultan left the company on 31 August 2024 and 30 June 2024 respectively.
Remuneration of board and key management personnel
\n \n
Post-
2023
Salary
Other cash
employment
Amounts in USD
Designation
and fees
Bonus
bene
\ufb01
ts
bene
\ufb01
ts
Total
E Alhomouz
1
Chairman
294,000
-
-
-
294,000
I Smines Tybring-Gjedde
Board member
38,685
-
-
-
38,685
G Kielland
Board member
38,685
-
-
-
38,685
A Samir Fawzi
Board member
32,763
-
-
-
32,763
J Norman-Hansen
Board member
32,763
-
-
-
32,763
J Pace
Interim CEO
530,111
-
-
-
530,111
C Frimann-Dahl
2
Chief Technical O
\ufb03
cer
240,053
42,123
719
13,493
296,388
M Barrett
2
Exploration Manager
280,755
47,678
1,731
-
330,164
C Butler
2
Group Financial Controller
243,400
31,202
2,427
17,740
294,769
E Sultan
Strategy and Contracts Manager
244,000
-
-
-
244,000
Total
1,975,215
121,003
4,877
31,233
2,132,328
1
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
related party Petromal LLC, above
\ufb01
gures represent the company\u2019s fair value estimate of associated costs for the individual\u2019s services.
2
Bonus received was determined at the discretion of management, contingent upon both company performance and individual contributions.
Share holdings by Directors and other Key Management Personnel
\n \n
Balance
Shares
Granted as
Net change
Balance
1 January 2024
purchased
remuneration
other
31 December 2024
J Norman-Hansen
1
215,060
-
-
-
215,060
J Pace
146,553
-
-
-
146,553
M Barrett
115,167
-
-
(115,167)
-
C Frimann-Dahl
60,456
-
-
-
60,456
C Butler
23,430
-
-
-
23,430
Total
560,666
-
-
(115,167)
445,499
1
In addition to the share holding above, Jarle Norman-Hansen holds shares indirectly through Ambolt Invest AS totalling 8,758,329
Other board members and key management not included in the above table held no shares during the current year.
No warrants or options were held by board members or key management personnel during the current year.
22B.
SIGNIFICANT SHAREHOLDERS
\n \n
31 December 2024
31 December 2023
Shareholder
Place of incorporation
Ownership
Ownership
Petromal LLC \u2013 Sole Proprietorship LLC
UAE
33.82%
33.82%
Symero Ltd
Cyprus
9.75%
9.75%
Ambolt Invest AS
Norway
6.15%
6.15%
Sj\u00f8vollen AS
Norway
4.20%
8.62%
Gulshagen III AS
Norway
3.16%
3.16%
Gulshagen IV AS
Norway
3.16%
3.16%
All of the shares held by Petromal LLC are recorded in the name of nominee company, Clearstream Banking S.A. on behalf of
Petromal LLC. Ambolt Invest AS is a company controlled by Jarle Norman-Hansen who was appointed as a board member on 26
January 2023
22C.
TRANSACTIONS AND PERIOD-END BALANCES WITH RELATED PARTIES
Transactions with related parties included in the consolidated statement of comprehensive income:
Petromal LLC has had an agreement to provide technical and project management services to the PetroNor Group since 2017.
\n \n
Amounts in USD thousand
2024
2023
Petromal \u2013 Sole Proprietorship LLC
214
305
Administrative expenses
214
305
Balances due from and due to related parties disclosed in the consolidated statement of
\ufb01
nancial position:
\n \n
Amounts in USD thousand
2024
2023
Balances due from related parties
Receivable from Aje Production AS and its subsidiaries
11,681
11,067
Balances due to related parties
Other payable to Petromal \u2013 Sole Proprietorship LLC
(8)
(26)
Total payables to related parties (Note 16)
(8)
(26)
Amounts due from / to related parties included in the consolidated statement of
\ufb01
nancial position are interest-free and have no
\ufb01
xed repayment terms.", "dimensions": { "concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00240": { "value": "22A.
BOARD AND KEY MANAGEMENT PERSONNEL REMUNERATION
Key management personnel are those persons having authority and responsibility for planning, directing and controlling the
activities of the Group, including the Directors listed on page 34, and the following other key personnel:
\n \n
Jens Pace
Chief executive o
\ufb03
cer
Claus Frimann-Dahl
Chief technical o
\ufb03
cer
Chris Butler
Group
\ufb01
nancial controller
As at the approval date of this report the base salary and fees for the following members of key management is as follows:
\n \n
Base salary and fees
Total base salary and
Individual
Title
Group Entity
/per annum
fees USD equivalent
J Iskander
Chair
PetroNor E&P Services AS
NOK 800,000
71,600
J Norman-Hansen
Board member
PetroNor E&P Services AS
NOK 550,000
49,225
A Georghiou
Board member
PetroNor E&P Services AS
NOK 550,000
64,825
PetroNor E&P Limited
EUR 15,000
J Pace
Chief Executive O
\ufb03
cer
PetroNor E&P Services AS
GBP 410,000
517,625
C Frimann-Dahl
Chief Technical O
\ufb03
cer
PetroNor E&P Services AS
NOK 2,625,000
234,938
C Butler
Group Financial Controller
PetroNor E&P Services Ltd
GBP
147,000
251,588
Hemla E&P Congo SA
USD 66,000
FX rates used:
NOK 1.00 : USD 0.0895
|
GBP 1.00 : USD 1.2625
\n \n
Post-
2024
Salary
Other cash
Severance
employment
Amounts in USD
Designation
and fees
Bonus
bene
\ufb01
ts
Package
bene
\ufb01
ts
Total
J Iskander
Chair
42,987
83,064
-
-
-
126,051
E Alhomouz
1
Former Chair
172,500
140,877
-
-
-
313,377
I Smines Tybring-Gjedde
2
Board member
38,973
84,526
-
-
-
123,499
G Kielland
2
Board member
38,973
84,526
-
-
-
123,499
A Samir Fawzi
Board member
47,208
84,526
-
-
-
131,734
J Norman-Hansen
Board member
47,208
84,526
-
-
-
131,734
J Pace
Chief Executive O
\ufb03
cer
523,580
135,623
-
-
-
659,203
C Frimann-Dahl
Chief Technical O
\ufb03
cer
247,621
39,324
2,666
-
15,569
305,180
M Barrett
3
Exploration Manager
209,289
-
1,886
223,964
-
435,139
C Butler
Group Financial Controller
252,317
41,599
6,936
-
18,824
319,676
E Sultan
3
Strategy and Contracts
Manager
105,000
-
-
21,000
-
126,000
Total
1,725,656
778,591
11,488
244,964
34,393
2,795,092
1
Eyas Alhomouz did not stand for re-election as Chair at the AGM on 29 May 2024.
2
Ingvil Smines Tybring-Gjedde and Gro Kielland resigned as board members on 1 November 2024.
3
As part of the restructuring process Michael Barrett and Emad Sultan left the company on 31 August 2024 and 30 June 2024 respectively.
Remuneration of board and key management personnel
\n \n
Post-
2023
Salary
Other cash
employment
Amounts in USD
Designation
and fees
Bonus
bene
\ufb01
ts
bene
\ufb01
ts
Total
E Alhomouz
1
Chairman
294,000
-
-
-
294,000
I Smines Tybring-Gjedde
Board member
38,685
-
-
-
38,685
G Kielland
Board member
38,685
-
-
-
38,685
A Samir Fawzi
Board member
32,763
-
-
-
32,763
J Norman-Hansen
Board member
32,763
-
-
-
32,763
J Pace
Interim CEO
530,111
-
-
-
530,111
C Frimann-Dahl
2
Chief Technical O
\ufb03
cer
240,053
42,123
719
13,493
296,388
M Barrett
2
Exploration Manager
280,755
47,678
1,731
-
330,164
C Butler
2
Group Financial Controller
243,400
31,202
2,427
17,740
294,769
E Sultan
Strategy and Contracts Manager
244,000
-
-
-
244,000
Total
1,975,215
121,003
4,877
31,233
2,132,328
1
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
related party Petromal LLC, above
\ufb01
gures represent the company\u2019s fair value estimate of associated costs for the individual\u2019s services.
2
Bonus received was determined at the discretion of management, contingent upon both company performance and individual contributions.
Share holdings by Directors and other Key Management Personnel
\n \n
Balance
Shares
Granted as
Net change
Balance
1 January 2024
purchased
remuneration
other
31 December 2024
J Norman-Hansen
1
215,060
-
-
-
215,060
J Pace
146,553
-
-
-
146,553
M Barrett
115,167
-
-
(115,167)
-
C Frimann-Dahl
60,456
-
-
-
60,456
C Butler
23,430
-
-
-
23,430
Total
560,666
-
-
(115,167)
445,499
1
In addition to the share holding above, Jarle Norman-Hansen holds shares indirectly through Ambolt Invest AS totalling 8,758,329
Other board members and key management not included in the above table held no shares during the current year.
No warrants or options were held by board members or key management personnel during the current year. ", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00241": { "value": "22C.
TRANSACTIONS AND PERIOD-END BALANCES WITH RELATED PARTIES
Transactions with related parties included in the consolidated statement of comprehensive income:
Petromal LLC has had an agreement to provide technical and project management services to the PetroNor Group since 2017.
\n \n
Amounts in USD thousand
2024
2023
Petromal \u2013 Sole Proprietorship LLC
214
305
Administrative expenses
214
305
Balances due from and due to related parties disclosed in the consolidated statement of
\ufb01
nancial position:
\n \n
Amounts in USD thousand
2024
2023
Balances due from related parties
Receivable from Aje Production AS and its subsidiaries
11,681
11,067
Balances due to related parties
Other payable to Petromal \u2013 Sole Proprietorship LLC
(8)
(26)
Total payables to related parties (Note 16)
(8)
(26)
Amounts due from / to related parties included in the consolidated statement of
\ufb01
nancial position are interest-free and have no
\ufb01
xed repayment terms.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTransactionsWithRelatedPartiesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00248": { "value": "Note 23
Risk Management
The Group\u2019s principal
\ufb01
nancial liabilities comprise accounts
payable and amounts due to related parties. The main purpose
of these
\ufb01
nancial instruments is to manage short-term cash
\ufb02
ow. The Group has various
\ufb01
nancial assets such as accounts
receivable and cash.
The main risks that could adversely a
\ufb00
ect the Group\u2019s
\ufb01
nancial assets, liabilities or future cash
\ufb02
ows are credit risk,
liquidity risk, interest rate risk and foreign currency risk. The
management reviews and agrees policies for managing each of
these risks which are summarised below.
The following discussion also includes a sensitivity analysis that
is intended to illustrate the sensitivity to changes in the market
variables on the Group\u2019s
\ufb01
nancial instruments and shows
the impact on pro
\ufb01
t or loss and shareholders\u2019 equity, where
applicable. Financial instruments a
\ufb00
ected by market risk include
accounts receivable, accounts payable and accrued liabilities.
The sensitivity has been prepared for periods ending
31 December 2024 using the amounts of debt and other
\ufb01
nancial assets and liabilities held as at those reporting dates.
The tables below detail the credit quality of the company\u2019s
\ufb01
nancial assets as well as the company\u2019s maximum exposure
to credit risk by credit risk rating grades.
\n \n
External
Gross
Net
credit
12-month or
carrying
Loss
carrying
Amounts in USD thousand
Notes
rating
lifetime ECL
amount
allowance
amount
31 December 2024
Trade receivables
(i)
11
N/a
Lifetime ECL
64,010
-
64,010
Due from related parties
11, 22d
N/a
Lifetime ECL
11,681
-
11,681
Advance against decommissioning cost
11
N/a
Lifetime ECL
30,515
-
30,515
Cash and cash equivalents
12
Aa3/B
12-month ECL
79,692
-
79,692
Other receivables
11
N/a
Lifetime ECL
8,005
-
8,005
31 December 2023
Trade receivables
(i)
11
N/a
Lifetime ECL
27,317
-
27,317
Due from related parties
11, 22d
N/a
Lifetime ECL
11,057
-
11,057
Advance against decommissioning cost
11
N/a
Lifetime ECL
30,050
-
30,050
Cash and cash equivalents
12
Aa3/B
12-month ECL
46,249
-
46,249
Other receivables
11
N/a
Lifetime ECL
6,359
-
6,359
(i)
For trade receivables and amounts due from related parties, the Group has applied the simpli
\ufb01
ed approach in IFRS 9 to measure the loss allowance at
lifetime 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
debtor\u2019s current
\ufb01
nancial position, adjusted for factors that are speci
\ufb01
c to the debtors, general economic conditions of the industry in which the debtors
operate and an assessment of both the current as well as the forecast direction of conditions at the reporting date.
LIQUIDITY RISK
The Group seeks to limit its liquidity risk by ensuring
\ufb01
nancial
support is available from the shareholders. The Group\u2019s terms
of sales requires amounts to be paid within 30 days from the
bill of lading, the point at which crude oil had been loaded onto
vessel for shipment . Trade payables are normally settled within
90 to 120 days of the date of receipt of invoice.
The table below summarises the maturity pro
\ufb01
le of the Group\u2019s
\ufb01
nancial liabilities at 31 December 2024 based on contractual
undiscounted payments.
\n \n
Between
Between
Less than
1 and 3
3 months
More than
Amounts in USD thousand
Note
On demand
1 month
months
and 1 year
1 year
Total
31 December 2024
Trade accounts payable
16
-
5,525
-
-
-
5,525
Amounts due to related parties
22d
8
-
-
-
-
8
Loan payable
17
-
-
-
-
-
-
Other payable
16
3,283
-
-
-
3
3,286
Total
3,291
5,525
-
-
3
8,819
\n \n
Between
Between
Less than
1 and 3
3 months
More than
Amounts in USD thousand
Note
On demand
1 month
months
and 1 year
1 year
Total
31 December 2023
Trade accounts payable
16
-
11,954
-
-
-
11,954
Amounts due to related parties
22d
26
-
-
-
-
26
Loan payable
17
-
-
1,375
4,125
-
5,500
Other payable
16
-
-
-
-
-
-
Total
26
11,954
1,375
4,125
-
17,480
The company had USD 79.7 million (2023: 46.2 million) in
unrestricted cash as of 31 December 2024. Should additional
funding be required in the future for additional capital
expenditure for new development phases or working capital
requirements, the company has various alternatives available
which it can explore to ful
\ufb01
l such additional requirements.
The options include, amongst others, debt
\ufb01
nancing, o
\ufb00
take
prepayment structures. As a result, the
\ufb01
nancial statements
have been prepared under the assumption of going concern
and realisation of assets and settlement of debt in normal
operations.
INTEREST RATE RISK
The Group is exposed to interest rate risk on its interest-bearing
assets and liabilities and seeks to limit this risk by obtaining
favourable interest rates.
\n \n
31 December 2024
31 December 2023
Amounts in USD thousand
+150bp
-150bp
+150bp
-150bp
Loans payable
-
-
(83)
83
CURRENCY RISK
The Group operates internationally and is exposed to risk
arising from various currency exposures, primarily with respect
to the Norwegian Kroner (NOK), and the Great British Pound
(GBP). The Group has transactional currency exposures. Such
exposure arises from sales or purchases in currencies other
than the respective functional currency.
The Group reports its consolidated results in USD; any
change in exchange rates between its operating subsidiaries\u2019
functional currencies and the USD a
\ufb00
ects its consolidated
statement of comprehensive income and statement of
\ufb01
nancial position when the results of those operating
subsidiaries are translated into USD for reporting purposes.
Group companies are required to manage their foreign
exchange risk against their functional currency.
A 20% strengthening or weakening of the USD against the
following currencies at 31 December 2024 would have increased
/ (decreased) equity and pro
\ufb01
t or loss before tax by the amounts
shown below.
The Group\u2019s assessment of what a reasonable potential
change in foreign currencies that it is currently exposed to
have been changed as a result of the changes observed in the
world
\ufb01
nancial markets. This hypothetical analysis assumes
that all other variables, including interest rates and commodity
prices, remain constant.
\n \n
31 December 2024
31 December 2023
Amounts in USD thousand
+20%
-20%
+20%
-20%
USD vs NOK
Cash
(6)
6
(13)
13
Receivables
(49)
49
(2,918)
2,910
Payables
103
(103)
185
(184)
Total
48
(48)
(2,746)
2,739
USD vs GBP
Cash
(13)
13
(14)
14
Receivables
(2)
2
(7)
7
Payables
26
(26)
2
(2)
Total
11
(11)
(19)
19
CAPITAL RISK
The primary objective of the Group\u2019s capital management is to
continuously evaluate measures to strengthen its
\ufb01
nancial basis
and to ensure that the Group is fully funded for its committed
2025 activities. The Group manages its capital structure
and makes adjustments to it in light of changes in economic
conditions. In order to maintain or change the capital structure,
the Group may adjust the amount of dividend payments to
shareholders, return capital to shareholders or issue new
shares.
The Group is continuously evaluating the capital structure, with
the aim of having an optimal mix of equity and debt capital to
reduce the Group\u2019s cost of capital and looking at avenues to
procure capital in the forthcoming years.", "dimensions": { "concept": "ifrs-full:DisclosureOfNatureAndExtentOfRisksArisingFromFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00242": { "value": "Note 23
Risk Management
The Group\u2019s principal
\ufb01
nancial liabilities comprise accounts
payable and amounts due to related parties. The main purpose
of these
\ufb01
nancial instruments is to manage short-term cash
\ufb02
ow. The Group has various
\ufb01
nancial assets such as accounts
receivable and cash.
The main risks that could adversely a
\ufb00
ect the Group\u2019s
\ufb01
nancial assets, liabilities or future cash
\ufb02
ows are credit risk,
liquidity risk, interest rate risk and foreign currency risk. The
management reviews and agrees policies for managing each of
these risks which are summarised below.
The following discussion also includes a sensitivity analysis that
is intended to illustrate the sensitivity to changes in the market
variables on the Group\u2019s
\ufb01
nancial instruments and shows
the impact on pro
\ufb01
t or loss and shareholders\u2019 equity, where
applicable. Financial instruments a
\ufb00
ected by market risk include
accounts receivable, accounts payable and accrued liabilities.
The sensitivity has been prepared for periods ending
31 December 2024 using the amounts of debt and other
\ufb01
nancial assets and liabilities held as at those reporting dates.
The tables below detail the credit quality of the company\u2019s
\ufb01
nancial assets as well as the company\u2019s maximum exposure
to credit risk by credit risk rating grades.
\n \n
External
Gross
Net
credit
12-month or
carrying
Loss
carrying
Amounts in USD thousand
Notes
rating
lifetime ECL
amount
allowance
amount
31 December 2024
Trade receivables
(i)
11
N/a
Lifetime ECL
64,010
-
64,010
Due from related parties
11, 22d
N/a
Lifetime ECL
11,681
-
11,681
Advance against decommissioning cost
11
N/a
Lifetime ECL
30,515
-
30,515
Cash and cash equivalents
12
Aa3/B
12-month ECL
79,692
-
79,692
Other receivables
11
N/a
Lifetime ECL
8,005
-
8,005
31 December 2023
Trade receivables
(i)
11
N/a
Lifetime ECL
27,317
-
27,317
Due from related parties
11, 22d
N/a
Lifetime ECL
11,057
-
11,057
Advance against decommissioning cost
11
N/a
Lifetime ECL
30,050
-
30,050
Cash and cash equivalents
12
Aa3/B
12-month ECL
46,249
-
46,249
Other receivables
11
N/a
Lifetime ECL
6,359
-
6,359
(i)
For trade receivables and amounts due from related parties, the Group has applied the simpli
\ufb01
ed approach in IFRS 9 to measure the loss allowance at
lifetime 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
debtor\u2019s current
\ufb01
nancial position, adjusted for factors that are speci
\ufb01
c to the debtors, general economic conditions of the industry in which the debtors
operate and an assessment of both the current as well as the forecast direction of conditions at the reporting date.
LIQUIDITY RISK
The Group seeks to limit its liquidity risk by ensuring
\ufb01
nancial
support is available from the shareholders. The Group\u2019s terms
of sales requires amounts to be paid within 30 days from the
bill of lading, the point at which crude oil had been loaded onto
vessel for shipment . Trade payables are normally settled within
90 to 120 days of the date of receipt of invoice.
The table below summarises the maturity pro
\ufb01
le of the Group\u2019s
\ufb01
nancial liabilities at 31 December 2024 based on contractual
undiscounted payments.
\n \n
Between
Between
Less than
1 and 3
3 months
More than
Amounts in USD thousand
Note
On demand
1 month
months
and 1 year
1 year
Total
31 December 2024
Trade accounts payable
16
-
5,525
-
-
-
5,525
Amounts due to related parties
22d
8
-
-
-
-
8
Loan payable
17
-
-
-
-
-
-
Other payable
16
3,283
-
-
-
3
3,286
Total
3,291
5,525
-
-
3
8,819
\n \n
Between
Between
Less than
1 and 3
3 months
More than
Amounts in USD thousand
Note
On demand
1 month
months
and 1 year
1 year
Total
31 December 2023
Trade accounts payable
16
-
11,954
-
-
-
11,954
Amounts due to related parties
22d
26
-
-
-
-
26
Loan payable
17
-
-
1,375
4,125
-
5,500
Other payable
16
-
-
-
-
-
-
Total
26
11,954
1,375
4,125
-
17,480
The company had USD 79.7 million (2023: 46.2 million) in
unrestricted cash as of 31 December 2024. Should additional
funding be required in the future for additional capital
expenditure for new development phases or working capital
requirements, the company has various alternatives available
which it can explore to ful
\ufb01
l such additional requirements.
The options include, amongst others, debt
\ufb01
nancing, o
\ufb00
take
prepayment structures. As a result, the
\ufb01
nancial statements
have been prepared under the assumption of going concern
and realisation of assets and settlement of debt in normal
operations.
INTEREST RATE RISK
The Group is exposed to interest rate risk on its interest-bearing
assets and liabilities and seeks to limit this risk by obtaining
favourable interest rates.
\n \n
31 December 2024
31 December 2023
Amounts in USD thousand
+150bp
-150bp
+150bp
-150bp
Loans payable
-
-
(83)
83
CURRENCY RISK
The Group operates internationally and is exposed to risk
arising from various currency exposures, primarily with respect
to the Norwegian Kroner (NOK), and the Great British Pound
(GBP). The Group has transactional currency exposures. Such
exposure arises from sales or purchases in currencies other
than the respective functional currency.
The Group reports its consolidated results in USD; any
change in exchange rates between its operating subsidiaries\u2019
functional currencies and the USD a
\ufb00
ects its consolidated
statement of comprehensive income and statement of
\ufb01
nancial position when the results of those operating
subsidiaries are translated into USD for reporting purposes.
Group companies are required to manage their foreign
exchange risk against their functional currency.
A 20% strengthening or weakening of the USD against the
following currencies at 31 December 2024 would have increased
/ (decreased) equity and pro
\ufb01
t or loss before tax by the amounts
shown below.
The Group\u2019s assessment of what a reasonable potential
change in foreign currencies that it is currently exposed to
have been changed as a result of the changes observed in the
world
\ufb01
nancial markets. This hypothetical analysis assumes
that all other variables, including interest rates and commodity
prices, remain constant.
\n \n
31 December 2024
31 December 2023
Amounts in USD thousand
+20%
-20%
+20%
-20%
USD vs NOK
Cash
(6)
6
(13)
13
Receivables
(49)
49
(2,918)
2,910
Payables
103
(103)
185
(184)
Total
48
(48)
(2,746)
2,739
USD vs GBP
Cash
(13)
13
(14)
14
Receivables
(2)
2
(7)
7
Payables
26
(26)
2
(2)
Total
11
(11)
(19)
19
CAPITAL RISK
The primary objective of the Group\u2019s capital management is to
continuously evaluate measures to strengthen its
\ufb01
nancial basis
and to ensure that the Group is fully funded for its committed
2025 activities. The Group manages its capital structure
and makes adjustments to it in light of changes in economic
conditions. In order to maintain or change the capital structure,
the Group may adjust the amount of dividend payments to
shareholders, return capital to shareholders or issue new
shares.
The Group is continuously evaluating the capital structure, with
the aim of having an optimal mix of equity and debt capital to
reduce the Group\u2019s cost of capital and looking at avenues to
procure capital in the forthcoming years.", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00243": { "value": "The tables below detail the credit quality of the company\u2019s
\ufb01
nancial assets as well as the company\u2019s maximum exposure
to credit risk by credit risk rating grades.
\n \n
External
Gross
Net
credit
12-month or
carrying
Loss
carrying
Amounts in USD thousand
Notes
rating
lifetime ECL
amount
allowance
amount
31 December 2024
Trade receivables
(i)
11
N/a
Lifetime ECL
64,010
-
64,010
Due from related parties
11, 22d
N/a
Lifetime ECL
11,681
-
11,681
Advance against decommissioning cost
11
N/a
Lifetime ECL
30,515
-
30,515
Cash and cash equivalents
12
Aa3/B
12-month ECL
79,692
-
79,692
Other receivables
11
N/a
Lifetime ECL
8,005
-
8,005
31 December 2023
Trade receivables
(i)
11
N/a
Lifetime ECL
27,317
-
27,317
Due from related parties
11, 22d
N/a
Lifetime ECL
11,057
-
11,057
Advance against decommissioning cost
11
N/a
Lifetime ECL
30,050
-
30,050
Cash and cash equivalents
12
Aa3/B
12-month ECL
46,249
-
46,249
Other receivables
11
N/a
Lifetime ECL
6,359
-
6,359
(i)
For trade receivables and amounts due from related parties, the Group has applied the simpli
\ufb01
ed approach in IFRS 9 to measure the loss allowance at
lifetime 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
debtor\u2019s current
\ufb01
nancial position, adjusted for factors that are speci
\ufb01
c to the debtors, general economic conditions of the industry in which the debtors
operate 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00244": { "value": "LIQUIDITY RISK
The Group seeks to limit its liquidity risk by ensuring
\ufb01
nancial
support is available from the shareholders. The Group\u2019s terms
of sales requires amounts to be paid within 30 days from the
bill of lading, the point at which crude oil had been loaded onto
vessel for shipment . Trade payables are normally settled within
90 to 120 days of the date of receipt of invoice.
The table below summarises the maturity pro
\ufb01
le of the Group\u2019s
\ufb01
nancial liabilities at 31 December 2024 based on contractual
undiscounted payments.
\n \n
Between
Between
Less than
1 and 3
3 months
More than
Amounts in USD thousand
Note
On demand
1 month
months
and 1 year
1 year
Total
31 December 2024
Trade accounts payable
16
-
5,525
-
-
-
5,525
Amounts due to related parties
22d
8
-
-
-
-
8
Loan payable
17
-
-
-
-
-
-
Other payable
16
3,283
-
-
-
3
3,286
Total
3,291
5,525
-
-
3
8,819
\n \n
Between
Between
Less than
1 and 3
3 months
More than
Amounts in USD thousand
Note
On demand
1 month
months
and 1 year
1 year
Total
31 December 2023
Trade accounts payable
16
-
11,954
-
-
-
11,954
Amounts due to related parties
22d
26
-
-
-
-
26
Loan payable
17
-
-
1,375
4,125
-
5,500
Other payable
16
-
-
-
-
-
-
Total
26
11,954
1,375
4,125
-
17,480
The company had USD 79.7 million (2023: 46.2 million) in
unrestricted cash as of 31 December 2024. Should additional
funding be required in the future for additional capital
expenditure for new development phases or working capital
requirements, the company has various alternatives available
which it can explore to ful
\ufb01
l such additional requirements.
The options include, amongst others, debt
\ufb01
nancing, o
\ufb00
take
prepayment structures. As a result, the
\ufb01
nancial statements
have been prepared under the assumption of going concern
and realisation of assets and settlement of debt in normal
operations.", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00245": { "value": "INTEREST RATE RISK
The Group is exposed to interest rate risk on its interest-bearing
assets and liabilities and seeks to limit this risk by obtaining
favourable interest rates.
\n \n
31 December 2024
31 December 2023
Amounts in USD thousand
+150bp
-150bp
+150bp
-150bp
Loans payable
-
-
(83)
83
CURRENCY RISK
The Group operates internationally and is exposed to risk
arising from various currency exposures, primarily with respect
to the Norwegian Kroner (NOK), and the Great British Pound
(GBP). The Group has transactional currency exposures. Such
exposure arises from sales or purchases in currencies other
than the respective functional currency.
The Group reports its consolidated results in USD; any
change in exchange rates between its operating subsidiaries\u2019
functional currencies and the USD a
\ufb00
ects its consolidated
statement of comprehensive income and statement of
\ufb01
nancial position when the results of those operating
subsidiaries are translated into USD for reporting purposes.
Group companies are required to manage their foreign
exchange risk against their functional currency.
A 20% strengthening or weakening of the USD against the
following currencies at 31 December 2024 would have increased
/ (decreased) equity and pro
\ufb01
t or loss before tax by the amounts
shown below.
The Group\u2019s assessment of what a reasonable potential
change in foreign currencies that it is currently exposed to
have been changed as a result of the changes observed in the
world
\ufb01
nancial markets. This hypothetical analysis assumes
that all other variables, including interest rates and commodity
prices, remain constant.
\n \n
31 December 2024
31 December 2023
Amounts in USD thousand
+20%
-20%
+20%
-20%
USD vs NOK
Cash
(6)
6
(13)
13
Receivables
(49)
49
(2,918)
2,910
Payables
103
(103)
185
(184)
Total
48
(48)
(2,746)
2,739
USD vs GBP
Cash
(13)
13
(14)
14
Receivables
(2)
2
(7)
7
Payables
26
(26)
2
(2)
Total
11
(11)
(19)
19
", "dimensions": { "concept": "ifrs-full:DisclosureOfMarketRiskExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00246": { "value": "\n \n
31 December 2024
31 December 2023
Amounts in USD thousand
+150bp
-150bp
+150bp
-150bp
Loans payable
-
-
(83)
83
\n \n
31 December 2024
31 December 2023
Amounts in USD thousand
+20%
-20%
+20%
-20%
USD vs NOK
Cash
(6)
6
(13)
13
Receivables
(49)
49
(2,918)
2,910
Payables
103
(103)
185
(184)
Total
48
(48)
(2,746)
2,739
USD vs GBP
Cash
(13)
13
(14)
14
Receivables
(2)
2
(7)
7
Payables
26
(26)
2
(2)
Total
11
(11)
(19)
19
", "dimensions": { "concept": "ifrs-full:SensitivityAnalysisForEachTypeOfMarketRisk", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00247": { "value": "CAPITAL RISK
The primary objective of the Group\u2019s capital management is to
continuously evaluate measures to strengthen its
\ufb01
nancial basis
and to ensure that the Group is fully funded for its committed
2025 activities. The Group manages its capital structure
and makes adjustments to it in light of changes in economic
conditions. In order to maintain or change the capital structure,
the Group may adjust the amount of dividend payments to
shareholders, return capital to shareholders or issue new
shares.
The Group is continuously evaluating the capital structure, with
the aim of having an optimal mix of equity and debt capital to
reduce the Group\u2019s cost of capital and looking at avenues to
procure capital in the forthcoming years.", "dimensions": { "concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00251": { "value": "Note 24
Financial instruments
Financial instruments comprise
\ufb01
nancial assets and
\ufb01
nancial
liabilities.
Financial assets consist of bank balances and cash, amounts
due from related parties and trade and some other receivables.
Financial liabilities consist of amounts due to related parties,
loans payable, trade account payables and some other liabilities.
Financial Assets
\n \n
Fair value through
pro
\ufb01
t or loss
Amortised cost
Amounts in USD thousand
2024
2023
2024
2023
Cash and cash equivalents
-
-
79,692
46,249
Trade and other receivables
2
2,600
2,600
81,096
42,133
Advance against decommissioning cost
1
-
-
30,515
30,050
Total
2,600
2,600
191,303
118,432
1
The Group has advanced USD 30 million in cash to the operator as a contribution towards the future obligation to decommission the PNGF asset.
2
The valuation of contingent consideration was reviewed and the risk pro
\ufb01
le was deemed largely unchanged therefore there was no change in the valuation
booked.
Financial Liabilities
\n \n
Amortised cost
Amounts in USD thousand
2024
2023
Trade and other payables
45,129
20,054
Loans and borrowings
-
5,500
Total
45,129
25,554
The fair values of the Group's
\ufb01
nancial instruments are
not materially di
\ufb00
erent from their carrying amounts at the
reporting date largely due to the short term maturities of
these instruments.", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00249": { "value": "Note 24
Financial instruments
Financial instruments comprise
\ufb01
nancial assets and
\ufb01
nancial
liabilities.
Financial assets consist of bank balances and cash, amounts
due from related parties and trade and some other receivables.
Financial liabilities consist of amounts due to related parties,
loans payable, trade account payables and some other liabilities.
Financial Assets
\n \n
Fair value through
pro
\ufb01
t or loss
Amortised cost
Amounts in USD thousand
2024
2023
2024
2023
Cash and cash equivalents
-
-
79,692
46,249
Trade and other receivables
2
2,600
2,600
81,096
42,133
Advance against decommissioning cost
1
-
-
30,515
30,050
Total
2,600
2,600
191,303
118,432
1
The Group has advanced USD 30 million in cash to the operator as a contribution towards the future obligation to decommission the PNGF asset.
2
The valuation of contingent consideration was reviewed and the risk pro
\ufb01
le was deemed largely unchanged therefore there was no change in the valuation
booked.
Financial Liabilities
\n \n
Amortised cost
Amounts in USD thousand
2024
2023
Trade and other payables
45,129
20,054
Loans and borrowings
-
5,500
Total
45,129
25,554
The fair values of the Group's
\ufb01
nancial instruments are
not materially di
\ufb00
erent from their carrying amounts at the
reporting date largely due to the short term maturities of
these instruments.", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00250": { "value": "Note 24
Financial instruments
Financial instruments comprise
\ufb01
nancial assets and
\ufb01
nancial
liabilities.
Financial assets consist of bank balances and cash, amounts
due from related parties and trade and some other receivables.
Financial liabilities consist of amounts due to related parties,
loans payable, trade account payables and some other liabilities.
Financial Assets
\n \n
Fair value through
pro
\ufb01
t or loss
Amortised cost
Amounts in USD thousand
2024
2023
2024
2023
Cash and cash equivalents
-
-
79,692
46,249
Trade and other receivables
2
2,600
2,600
81,096
42,133
Advance against decommissioning cost
1
-
-
30,515
30,050
Total
2,600
2,600
191,303
118,432
1
The Group has advanced USD 30 million in cash to the operator as a contribution towards the future obligation to decommission the PNGF asset.
2
The valuation of contingent consideration was reviewed and the risk pro
\ufb01
le was deemed largely unchanged therefore there was no change in the valuation
booked.
Financial Liabilities
\n \n
Amortised cost
Amounts in USD thousand
2024
2023
Trade and other payables
45,129
20,054
Loans and borrowings
-
5,500
Total
45,129
25,554
The fair values of the Group's
\ufb01
nancial instruments are
not materially di
\ufb00
erent from their carrying amounts at the
reporting date largely due to the short term maturities of
these instruments.", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00252": { "value": "Note 25
Subsidiaries and joint ventures
The principal subsidiaries of the PetroNor E&P ASA, all of which have been included in these consolidated
\ufb01
nancial statements, are
as follows:
\n \n
Proportion of e
\ufb00
ective ownership
interest at 31 December
Country of
Principal place
Name
incorporation
of business
2024
2023
PetroNor E&P Pty Limited
Australia
Australia
100%
100%
PetroNor E&P Ltd
Cyprus
Cyprus
100%
100%
PetroNor E&P Services AS
Norway
Norway
100%
100%
PetroNor E&P Services Ltd
United Kingdom
United Kingdom
100%
100%
PetroNor E&P AB
Sweden
Guinea-Bissau
100%
100%
PetroNor E&P Gambia Ltd
Cayman Islands
The Gambia
100%
100%
Hemla Africa Holding AS
Norway
Norway
100%
100%
Hemla E&P Congo SA
Congo
Congo
84.15%
84.15%
African Petroleum Corporation Ltd
Cayman Islands
United Kingdom
100%
100%
African Petroleum Senegal Ltd
Cayman Islands
Senegal
90%
90%
", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00253": { "value": "Note 25
Subsidiaries and joint ventures
The principal subsidiaries of the PetroNor E&P ASA, all of which have been included in these consolidated
\ufb01
nancial statements, are
as follows:
\n \n
Proportion of e
\ufb00
ective ownership
interest at 31 December
Country of
Principal place
Name
incorporation
of business
2024
2023
PetroNor E&P Pty Limited
Australia
Australia
100%
100%
PetroNor E&P Ltd
Cyprus
Cyprus
100%
100%
PetroNor E&P Services AS
Norway
Norway
100%
100%
PetroNor E&P Services Ltd
United Kingdom
United Kingdom
100%
100%
PetroNor E&P AB
Sweden
Guinea-Bissau
100%
100%
PetroNor E&P Gambia Ltd
Cayman Islands
The Gambia
100%
100%
Hemla Africa Holding AS
Norway
Norway
100%
100%
Hemla E&P Congo SA
Congo
Congo
84.15%
84.15%
African Petroleum Corporation Ltd
Cayman Islands
United Kingdom
100%
100%
African Petroleum Senegal Ltd
Cayman Islands
Senegal
90%
90%
HEMLA E&P CONGO SA
Material non-controlling interests
The Group holds 84.15% of the share capital of Hemla E&P Congo SA. Set out below is summarised
\ufb01
nancial information for the
subsidiary that has non-controlling interests that are material to the group. The amounts disclosed for the subsidiary are before
inter-company eliminations.
Summarised statement of
\ufb01
nancial position
\n \n
Hemla E&P Congo SA
Amounts in USD thousand
2024
2023
Current asset
109,754
61,523
Current liabilities
42,445
12,836
Current net assets
67,309
48,687
Non-current assets
118,059
124,798
Non-current liabilities
35,223
27,084
Non-current net assets
82,836
97,614
Net assets
150,145
146,301
Accumulated NCI
24,693
24,100
Summarised statement of comprehensive income
\n \n
Hemla E&P Congo SA
Amounts in USD thousand
2024
2023
Revenue
204,532
187,330
Pro
\ufb01
t for the period
53,740
71,175
Other comprehensive income
-
-
Total comprehensive income for the year
53,740
71,175
Pro
\ufb01
t allocated to NCI
8,518
11,217
Dividends paid to NCI
7,925
3,170
Summarised cash
\ufb02
ows
\n \n
Hemla E&P Congo SA
Amounts in USD thousand
2024
2023
Cash
\ufb02
ows from operating activities
29,186
36,313
Cash
\ufb02
ows from investing activities
(8,649)
(8,724)
Cash
\ufb02
ows from
\ufb01
nancing activities
(7,925)
(124)
Net (decrease)/increase in cash and cash equivalents
12,612
27,465
Investments in joint ventures:
\n \n
Proportion of e
\ufb00
ective control
at 31 December
Country of
Principal place
Name
incorporation
of business
2024
2023
Aje Production AS
Norway
Norway
50%
50%
Aje Production AS is a small group that holds non-operating interests in the Nigerian OML 113 licence through Nigerian subsidiaries
Aje Production Ltd and YFP Deepwater Company Ltd.28O.
JOINT ARRANGEMENTS
Joint arrangements are arrangements of which two or more
parties have joint control. Joint control is the contractual agreed
sharing of control of the arrangement which exists only when
decisions about the relevant activities require unanimous
consent of the parties sharing control. Control is assessed by
applying the principles under IFRS 10 to determine whether the
Group has joint control . Joint arrangements are classi
\ufb01
ed as
either a joint operation or joint venture, based on the rights and
obligations arising from the contractual obligations between
the parties to the arrangement. Considerations in assessing the
classi
\ufb01
cations would include assessments of control that are
based not just on voting rights but on the extent that the joint
arrangement provides the Company with rights to the individual
assets and obligations arising from the joint arrangement
If the arrangement is classi
\ufb01
ed as a joint operation the Company
recognises its:
\ue001
Assets, including its share of any assets held jointly;
\ue001
Liabilities, including its share of any liabilities incurred
jointly;
\ue001
Revenue from the sale of its share of the output arising from
the joint operation;
\ue001
Share of revenue from the sale of the output by the joint
operation; and
\ue001
Expenses, including its share of any expenses incurred
jointly.
A joint arrangement which provides the Company with rights
to the net assets of the arrangement, is classi
\ufb01
ed as a joint
venture and accounted for using the equity method and treated
as an investment . Under the equity method, the cost of the
investment is adjusted by the post-acquisition changes in the
Company\u2019s share of the net assets of the venture.
Where assets are transferred into separate legal entities
concurrent with the entities shares being sold to a third party
thereby resulting in a loss of control of those asset owning
subsidiaries these assets will be treated as a joint venture.", "dimensions": { "concept": "ifrs-full:DisclosureOfJointVenturesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00239": { "value": "HEMLA E&P CONGO SA
Material non-controlling interests
The Group holds 84.15% of the share capital of Hemla E&P Congo SA. Set out below is summarised
\ufb01
nancial information for the
subsidiary that has non-controlling interests that are material to the group. The amounts disclosed for the subsidiary are before
inter-company eliminations.", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncontrollingInterestsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00254": { "value": "Note 26
Commitments and contingencies
COMMITMENTS
Production asset commitments
As at 31 December 2024, the Group had approved the budget
for PNGF Sud operations in Congo that included planned
capex expenditure for coming year of USD 18.3 million (2023
USD 18.1 million) representing HEPCO's equity interest funding
commitment in the licence.
CONTINGENCIES
\u00d8kokrim Matter
In December 2021 the National Authority for Investigation
and Prosecution of Economic and Environmental Crime in
Norway (\u00d8kokrim) initiated an investigation into allegations of
corruption and, from 2024, allegations of market manipulation,
and brought criminal charges against individuals associated with
the company. \u00d8kokrim has con
\ufb01
rmed that neither PetroNor nor
any of its subsidiaries has been charged. However, from 2024,
PetroNor has been given status as suspect in relation to the
market manipulation investigation, and its subsidiary, Hemla
Africa Holding AS, has been given status as a suspect in relation
to the corruption investigation.
To mitigate potential corporate liability risks, the board has
taken various remediation steps, as outlined in the director\u2019s
report, including obtaining independent legal advice and
implementing a compliance action plan. Despite the ongoing
investigations, the company has continued to operate e
\ufb00
ectively
but has incurred costs in addressing this issue and fully
cooperating with the investigating authorities. The company is
not aware of the status or duration of the investigations into
the individuals involved, and the uncertainty surrounding the
outcome could potentially impact the Group\u2019s ability to conduct
transactions with both new and existing partners.
OML 113 Conditional Consideration
As part of the transaction to acquire the interest in OML 113
conditional consideration has been assessed as a potential
contingency to the Group. An additional consideration of USD
0.10 per 1,000 cubic feet of the AJE Natural Gas Sales Volume is
to be paid to Panoro Energy ASA once the conditions stipulated
within the SPA are met. This conditional consideration is capped
at USD 16.67 million.", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00255": { "value": "COMMITMENTS
Production asset commitments
As at 31 December 2024, the Group had approved the budget
for PNGF Sud operations in Congo that included planned
capex expenditure for coming year of USD 18.3 million (2023
USD 18.1 million) representing HEPCO's equity interest funding
commitment in the licence.", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00262": { "value": "CONTINGENCIES
\u00d8kokrim Matter
In December 2021 the National Authority for Investigation
and Prosecution of Economic and Environmental Crime in
Norway (\u00d8kokrim) initiated an investigation into allegations of
corruption and, from 2024, allegations of market manipulation,
and brought criminal charges against individuals associated with
the company. \u00d8kokrim has con
\ufb01
rmed that neither PetroNor nor
any of its subsidiaries has been charged. However, from 2024,
PetroNor has been given status as suspect in relation to the
market manipulation investigation, and its subsidiary, Hemla
Africa Holding AS, has been given status as a suspect in relation
to the corruption investigation.
To mitigate potential corporate liability risks, the board has
taken various remediation steps, as outlined in the director\u2019s
report, including obtaining independent legal advice and
implementing a compliance action plan. Despite the ongoing
investigations, the company has continued to operate e
\ufb00
ectively
but has incurred costs in addressing this issue and fully
cooperating with the investigating authorities. The company is
not aware of the status or duration of the investigations into
the individuals involved, and the uncertainty surrounding the
outcome could potentially impact the Group\u2019s ability to conduct
transactions with both new and existing partners.
OML 113 Conditional Consideration
As part of the transaction to acquire the interest in OML 113
conditional consideration has been assessed as a potential
contingency to the Group. An additional consideration of USD
0.10 per 1,000 cubic feet of the AJE Natural Gas Sales Volume is
to be paid to Panoro Energy ASA once the conditions stipulated
within the SPA are met. This conditional consideration is capped
at USD 16.67 million.", "dimensions": { "concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00263": { "value": "Note 27
Events subsequent to reporting date
An interim balance sheet as of 9 December 2024 was approved
at an EGM held on 23 January 2025. This enabled the approval
of a shareholder distribution equivalent to 2 NOK per share that
was
paid out on 31 January 2025. USD 25.6 million of cash was
used to payout this distribution.
At an EGM held on 20 March 2025, Azza Fawzi stepped down
from the board and was replaced by Andri Georghiou.
On 2 April 2025, PetroNor advised that it had been noti
\ufb01
ed by
the US Department of Justice (DoJ) that they have closed their
investigation into the Company. ", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00264": { "value": "Note 28
Summary of accounting policies
Accounting policies are selected and applied in a manner which
ensures that the resulting
\ufb01
nancial information satis
\ufb01
es the
concepts of relevance and reliability, thereby ensuring that the
substance of the underlying transactions or other events is
reported.
The following is a summary of the material accounting policies
adopted by the Group in the preparation of the
\ufb01
nancial report.
The accounting policies have been consistently applied, unless
otherwise stated
28A.
ADOPTION OF NEW AND REVISED ACCOUNTING
STANDARDS
IASB has issued several amendments to standards or
interpretations to standards e
\ufb00
ective as of 1 January 2024.
PetroNor have adopted these standards in the
\ufb01
nancial year, the
impacts were not material to PetroNor\u2019s consolidated
\ufb01
nancial
statements upon adoption.
The IASB issued IFRS 18 Presentation and Disclosure in Financial
Statements in April 2024, which becomes e
\ufb00
ective for annual
periods beginning on or after 1 January 2027. IFRS 18 introduces
signi
\ufb01
cant changes to the structure and content of the primary
\ufb01
nancial statements, including:
\ue001
A revised format for the statement of pro
\ufb01
t or loss,
including the classi
\ufb01
cation of income and expenses into
\ufb01
ve
categories in the Consolidated statement of comprehensive
income: operating, investing,
\ufb01
nancing, income taxes, and
discontinued operations
\ue001
Introduction of de
\ufb01
ned subtotals such as operating pro
\ufb01
t.
\ue001
Enhanced aggregation and disaggregation requirements to
improve comparability and clarity.
\ue001
Disclosure of management-de
\ufb01
ned performance measures
(MDPMs), promoting transparency around non-GAAP
metrics.
The Group has not early adopted IFRS 18. The standard is
expected to a
\ufb00
ect the presentation and disclosure of the
Group\u2019s
\ufb01
nancial statements but will not impact recognition or
measurement of assets, liabilities, income, or expenses. The
Group is currently assessing the impact of these changes and
will implement necessary updates to its
\ufb01
nancial reporting
systems and processes ahead of the e
\ufb00
ective date.
Impacts of other standards and amendments to standards, and
interpretations of standards, issued but not yet e
\ufb00
ective are not
expected to have a material impact on the Group.
28B.
CONSOLIDATION
The consolidated
\ufb01
nancial statements comprise the
\ufb01
nancial
statements of PetroNor E&P ASA (\u201cthe company\u201d, formerly
PetroNor E&P Ltd) and its subsidiaries for the year ended
31 December 2024 (together the Group).
An entity has been assessed as being controlled by the Group
when the Groups is exposed, or has the rights, to variable
returns from its involvement with the entity and has the ability
to a
\ufb00
ect those returns through its power over the entity.
Speci
\ufb01
cally, the Group controls an entity if and only if the Group
has:
\ue001
Power over the entity (i.e., existing rights that give it the
current ability to direct the relevant activities of the entity)
\ue001
Exposure, or rights, to variable returns from its involvement
with the entity, and
\ue001
The ability to use its power over the entity to a
\ufb00
ect its
returns
When the Group has less than a majority of the voting or similar
rights of an entity, the Group considers all relevant facts and
circumstances in assessing whether it has power over an entity,
including:
\ue001
The contractual arrangement with the other vote holders of
the entity
\ue001
Rights arising from other contractual arrangements
\ue001
The Group\u2019s voting rights and potential voting rights
The Group reassesses whether or not it controls an entity if
facts and circumstances indicate that there are changes to
one or more of the three elements of control. Consolidation
of a subsidiary begins when the Group obtains control over
the subsidiary and ceases when the Group loses control of the
subsidiary. Business combinations are accounted for by using
the acquisition method. Assets, liabilities, income and expenses
of a subsidiary acquired or disposed of during the year are
included in the statement of comprehensive income from the
date the Group gains control until the date the Group ceases to
control the subsidiary.
Pro
\ufb01
t or loss and each component of other comprehensive
income (OCI) are attributed to the equity holders of the parent
of the Group and to the non-controlling interests, even if this
results in the non-controlling interests having a de
\ufb01
cit balance.
When necessary, adjustments are made to the
\ufb01
nancial
statements of subsidiaries to bring their accounting policies into
line with the Group\u2019s accounting policies. All intra-group assets
and liabilities, equity, income, expenses and cash
\ufb02
ows relating
to transactions between members of the Group are eliminated
in full on consolidation.
A change in the ownership interest of a subsidiary, without a
loss of control, is accounted for as an equity transaction.
If the Group loses control over a subsidiary, it:
\ue001
Derecognises the assets (including goodwill) and liabilities of
the subsidiary
\ue001
Derecognises the carrying amount of any non-controlling
interests
\ue001
Derecognises the cumulative translation di
\ufb00
erences
recorded in equity
\ue001
Recognises the fair value of the consideration received
\ue001
Recognises the fair value of any investment retained
\ue001
Recognises any surplus or de
\ufb01
cit in pro
\ufb01
t or loss
\ue001
Reclassi
\ufb01
es the parent\u2019s share of components previously
recognised in OCI to pro
\ufb01
t or loss or retained earnings, as
appropriate, as would be required if the Group had directly
disposed of the related assets or liabilities.
28C.
FOREIGN CURRENCY TRANSLATION
Functional and presentation currency
The company has applied United States Dollars, being the
functional currency of all major subsidiaries in the Group, as
its presentation currency. Where the functional currencies of
entities within the consolidated group di
\ufb00
er from United States
Dollars, they have been translated into United States Dollars.
The functional currency of PetroNor E&P ASA Group is United
States Dollars.
Transactions and balances
Transactions in foreign currencies are initially recorded in the
functional currency by applying the exchange rates ruling at
the date of the transaction. Monetary assets and liabilities
denominated in foreign currencies are retranslated at the rate
of exchange ruling at the reporting date and any gains or losses
are recognised in the income statement.
Non-monetary items that are measured in terms of historical
cost in the foreign currency are translated using the exchange
rate as at the date of the initial transaction. Non-monetary
items measured at fair value in a foreign currency are translated
using the exchange rates at the date when the fair value was
determined.
Translation of Group Companies\u2019 functional currency to
presentation currency
On consolidation, the assets and liabilities of foreign operations
are translated into United States Dollars at the rate of
exchange prevailing at the reporting date and their income
and expenditure are translated at exchange rates prevailing
at the dates of the transactions. The exchange di
\ufb00
erences
arising on translation for consolidation are recognised in other
comprehensive income. On disposal of a foreign operation, the
component of other comprehensive income relating to that
particular foreign operation is recognised in pro
\ufb01
t or loss.
28D.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include cash on hand, deposits held
at call with banks, other short-term highly liquid investments
with original maturities of three months or less, and bank
overdrafts. Bank overdrafts are shown within short-term
borrowings in current liabilities on the Statement of Financial
Position.
28E.
TRADE RECEIVABLES
Trade receivables are amounts due from customers for
goods sold or services performed in the ordinary course of
business. They are generally due for settlement within 30 days
and therefore are all classi
\ufb01
ed as current. Trade receivables
are recognised initially at the amount of consideration that
is unconditional unless they contain signi
\ufb01
cant
\ufb01
nancing
components, when they are recognised at fair value. The
group holds the trade receivables with the objective to collect
the contractual cash
\ufb02
ows and therefore measures them
subsequently at amortised cost using the e
\ufb00
ective interest
method.
28F.
TANGIBLE ASSETS
Property, plant and equipment
Oil & gas production assets
Oil and gas production assets are aggregated exploration and
evaluation tangible assets and development expenditures
associated with the production of proved reserves.
The cost of development and production assets also includes
the cost of acquisitions and purchases of such assets, directly
attributable overheads and the cost of recognising provisions
for future restoration and decommissioning.
Where major and identi
\ufb01
able parts of the production assets
have di
\ufb00
erent useful lives, they are accounted for as separate
items of property, plant and equipment. Costs of minor repairs
and maintenance are expensed as incurred. Oil and gas
production assets have a
\ufb01
nite life.
Depreciation
Oil and gas properties are depreciated using the unit-of-
production method. Unit-of production rates are based on 1P
proved reserves, which are oil, gas and other mineral reserves
estimated to be recovered from existing facilities using current
operating methods. Oil and gas volumes are considered
produced once they have been measured through meters at
custody transfer or sales transaction points at the outlet valve
on the
\ufb01
eld storage tank.
Field infrastructure exceeding beyond the life of the
\ufb01
eld is
depreciated over the useful life of the infrastructure using a
straight-line method.
Property, plant and equipment not associated with exploration
and production activities are carried at cost less accumulated
depreciation. These assets are also evaluated for impairment.
28G.
INTANGIBLE ASSETS
Exploration and evaluation activity involves the search for
hydrocarbon resources, the determination of technical
feasibility and the assessment of commercial viability of an
identi
\ufb01
ed resource. For each area of interest, expenditure
incurred in the acquisition of rights to explore and all costs
directly associated with holding the licence such as rental,
training and corporate and social responsibility are capitalised
as exploration and evaluation intangible assets. Signature
bonuses required by licence agreements are capitalised as
exploration and evaluation intangible assets. Other costs
directly associated with the licence are expensed as incurred.
Exploration, evaluation and development expenditure is
recorded at historical cost and allocated to cost pools on an area
of interest.
Expenditure on an area of interest is capitalised and
carried forward where rights to tenure of the area of interest
are current and:
\ue001
it is expected to be recouped through successful
development and exploitation of the area of interest or
alternatively by its sale; or
\ue001
exploration and evaluation activities are continuing in
an area of interest but at reporting date have not yet
reached a stage which permits a reasonable assessment
of the existence or otherwise of economically recoverable
reserves.
Accumulated costs in respect of areas of interest which are
abandoned are written o
\ufb00
in full against pro
\ufb01
t in the period in
which the decision to abandon the area is made.
Projects are advanced to development status when it is
expected that further expenditure can be recouped through
sale or successful development and exploitation of the area of
interest.
All capitalised costs are subject to commercial and management
review, as well as review for indicators of impairment at least
once a year. This is to con
\ufb01
rm the continued intent to develop
or otherwise extract value from the discovery. When this is no
longer the case, the costs are written o
\ufb00
through the statement
of pro
\ufb01
t or loss and other comprehensive income.
When proved reserves of oil and natural gas are identi
\ufb01
ed
and development is sanctioned by management, the relevant
capitalised expenditure is
\ufb01
rst assessed for impairment and (if
required) any impairment loss is recognised, then the remaining
balance is transferred to oil and gas properties.
Proceeds from disposal or farm-out transactions of intangible
exploration assets are used to reduce the carrying amount of
the assets. When proceeds exceed the carrying amount, the
di
\ufb00
erence is recognised as a gain. When the Group disposes of
its full interests, gains or losses are recognised in accordance
with the policy for recognising gains or losses on sale of plant,
property and equipment.
Generally Intangible assets can be viewed inde
\ufb01
nite as they will
be retained on the balance sheet until impaired or transferred
to oil and gas properties. Certain licence related costs
capitalised as intangible assets are deemed to have a
\ufb01
nite life
and are accreted over the life of the licence area.
Depreciation
Licence related costs capitalised as Intangible assets are
depreciated using the unit-of-production method. Unit-of
production rates are based on 1P proved reserves, which are
oil, gas and other mineral reserves estimated to be recovered
from existing facilities using current operating methods. Oil
and gas volumes are considered produced once they have
been measured through meters at custody transfer or sales
transaction points at the outlet valve on the
\ufb01
eld storage tank.
Technical goodwill
Technical goodwill recognised in business combinations
is allocated to each CGU for the purposes of impairment
testing. Impairment is tested on an annual basis or when
there are impairment indicators. Indicators may be speci
\ufb01
c
to an individual CGU or groups of CGUs to which the technical
goodwill is related. When conducting impairment testing,
deferred tax recognised in relation to the acquired licences
reduces the net carrying value prior to the impairment charges.
Impairment is recognised if the recoverable amount of the CGU
(or groups of CGUs) to which the technical goodwill relates to is
less than the carrying amount.
Impairment of goodwill cannot be reversed in future periods.
28H.
REVENUE
(i)
Revenue from petroleum products
Revenue from the sale of crude oil is recognised when a
customer obtains control (\u201csales\u201d or \u201clifting\u201d method), normally
this is when title passes at point of delivery. Revenues from
production of oil properties are recognised based on actual
volumes lifted and sold to customers during the period.
(ii)
Other revenue
Under a production sharing contract, where the group is
required to pay pro
\ufb01
t oil tax and royalties on production
of crude oil, such payments are settled in kind (where the
government lift the crude it is entitled to). The Group presents
a gross-up of the pro
\ufb01
t oil tax as an income tax expense with
a corresponding increase in oil and gas revenues and any
associated royalties are included in the cost of sales.
The Group assesses whether it acts as a principal or agent in
each of its revenue arrangements. The Group has concluded
that in all sales transactions it acts as a principal.
(iii)
Variable consideration
If the consideration in a contract includes a variable amount, the
Group recognises this amount as revenue only to the extent that
it is highly probable that a signi
\ufb01
cant reversal will not occur in
the future.
(iv)
Interest
Interest income is recognised on a time-proportional basis using
the e
\ufb00
ective interest method. This is a method of calculating the
amortised cost of a
\ufb01
nancial asset and allocating the interest
income over the relevant period using the e
\ufb00
ective interest rate,
which is the rate that exactly discounts the estimated future
cash receipts through the expected useful life of the
\ufb01
nancial
asset to the net carrying amount of the
\ufb01
nancial asset.
28I.
TAXES
The income tax expense or bene
\ufb01
t for the period consists of
two components: current and deferred tax.
The current income tax payable or recoverable is calculated
using the tax rates and legislation that have been enacted or
substantively enacted at year-end in each of the jurisdictions
and includes any adjustments for taxes payable or recovery in
respect of prior periods.
Deferred tax assets and liabilities are determined using the
balance sheet liability method based on temporary di
\ufb00
erences
between the carrying value of assets and liabilities for
\ufb01
nancial
reporting purposes and their tax bases. In calculating the
deferred tax assets and liabilities, the tax rates used are those
that have been enacted or substantively enacted by year-end
in each of the jurisdictions and that are expected to apply when
the assets are recovered, or the liabilities are settled.
Revenue-based taxes
In addition to corporate income taxes, the Group\u2019s consolidated
\ufb01
nancial statements also include and recognise as income taxes,
other types of taxes on net income such as certain revenue-
based taxes.
Production-sharing arrangements
According to the production-sharing arrangement (PSA)
in certain licences, the share of the pro
\ufb01
t oil to which the
Government is entitled in any calendar year in accordance
with the PSA is deemed to include a portion representing the
corporate income tax imposed upon and due by the Group. This
amount will be paid directly by the government on behalf of the
Group to the appropriate tax authorities.
The income tax expense
The current income tax is calculated using the PSA, paid in
barrels and booked as income tax and also shown as revenue.
Other income tax relates to the gain on disposal of the farm-out
in Guinea-Bissau included in discontinued operations.
28J.
DEFINED CONTRIBUTION PENSION PLAN
The Group pays contributions into de
\ufb01
ned contribution plans.
Obligations for contributions to de
\ufb01
ned contribution pension
plans are recognised as an expense in the income statement in
the periods during which services are rendered by employees.
28K.
TRADE AND OTHER PAYABLES
Trade and other payables are carried at amortised cost and due
to their short-term nature, they are not discounted.
28L.
PROVISIONS
Decommissioning liability
A decommissioning liability is recognised when the Group has
a present legal or constructive obligation as a result of past
events, and it is probable that an out
\ufb02
ow of resources will be
required to settle the obligation, and a reliable estimate of the
amount of obligation can be made. A corresponding amount
equivalent to the obligation is also recognised as part of the
cost of the related production plant and equipment. The
amount recognised in the estimated cost of decommissioning,
discounted to its present value. Changes in the estimated
timing of decommissioning or decommissioning cost estimates
are dealt with prospectively by recording an adjustment to
the provision, and a corresponding adjustment to production
plant and equipment. The unwinding of the discount on the
decommissioning liability is included as a
\ufb01
nance cost.
An escrow account is maintained by the operator of the licence
and is governed by a joint operating agreement and the
Congolese Government rules. The Group\u2019s share, paid against
the decommissioning liability until the balance sheet date, is
classi
\ufb01
ed as an advance against decommissioning liability in
current assets.
28M.
SHARE CAPITAL
Contributed equity is recognised at the fair value of the
consideration received by the Group, less any capital raising
costs in relation to the issue.
Incremental costs directly attributable to the issue of new
shares or options are shown in equity as a deduction, net of tax,
from the proceeds.
28N.
DIVIDEND DISTRIBUTION
Dividend distribution to the Company\u2019s shareholders is
recognised as a liability in the Group\u2019s
\ufb01
nancial statements
in the period in which the dividends are declared and
appropriately authorised or approved by the Company\u2019s
Shareholders\u2019 General Meeting. Interim dividends proposed
by the Board of Directors are recognised as liabilities upon
declaration.
28O.
JOINT ARRANGEMENTS
Joint arrangements are arrangements of which two or more
parties have joint control. Joint control is the contractual agreed
sharing of control of the arrangement which exists only when
decisions about the relevant activities require unanimous
consent of the parties sharing control. Control is assessed by
applying the principles under IFRS 10 to determine whether the
Group has joint control . Joint arrangements are classi
\ufb01
ed as
either a joint operation or joint venture, based on the rights and
obligations arising from the contractual obligations between
the parties to the arrangement. Considerations in assessing the
classi
\ufb01
cations would include assessments of control that are
based not just on voting rights but on the extent that the joint
arrangement provides the Company with rights to the individual
assets and obligations arising from the joint arrangement
If the arrangement is classi
\ufb01
ed as a joint operation the Company
recognises its:
\ue001
Assets, including its share of any assets held jointly;
\ue001
Liabilities, including its share of any liabilities incurred
jointly;
\ue001
Revenue from the sale of its share of the output arising from
the joint operation;
\ue001
Share of revenue from the sale of the output by the joint
operation; and
\ue001
Expenses, including its share of any expenses incurred
jointly.
A joint arrangement which provides the Company with rights
to the net assets of the arrangement, is classi
\ufb01
ed as a joint
venture and accounted for using the equity method and treated
as an investment . Under the equity method, the cost of the
investment is adjusted by the post-acquisition changes in the
Company\u2019s share of the net assets of the venture.
Where assets are transferred into separate legal entities
concurrent with the entities shares being sold to a third party
thereby resulting in a loss of control of those asset owning
subsidiaries these assets will be treated as a joint venture.
28P.
BUSINESS COMBINATIONS AND GOODWILL
Business combinations are accounted for using the acquisition
method.
The cost of an acquisition is measured as the
aggregate of the fair value at the date of exchange of assets
and liabilities acquired. Where a non-controlling interest exists,
the Group elects whether to measure NCI in the acquiree
at fair value or at the proportionate share of the acquiree\u2019s
identi
\ufb01
able net assets. The initial accounting for a business
combination can be changed if new information about the
fair value at the acquisition date is present. The allocation can
be amended within 12 months of the acquisition date. When
the consideration transferred by the Group in a business
combination includes a contingent consideration arrangement,
the contingent consideration is measured at its acquisition-
date fair value and included as part of the consideration
transferred in a business combination. Changes in the fair
value of the contingent consideration is re-measured to fair
value at subsequent reporting dates with changes in fair value
recognised in the income statement.
Goodwill is recognised as the aggregate of the consideration
transferred and the amount of any non-controlling interest
and deducted by the net of the acquisition-date amounts of
the identi
\ufb01
able assets acquired and the liabilities assumed.
Goodwill is not depreciated but is tested at least annually for
impairment. In connection with this, goodwill is allocated to
cash-generating units or groups of cash-generating units that
are expected to bene
\ufb01
t from synergies from the business
combination.
PetroNor recognises a gain/loss on disposal of subsidiary when
control is lost.", "dimensions": { "concept": "ifrs-full:DisclosureOfMaterialAccountingPolicyInformationExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00265": { "value": "28A.
ADOPTION OF NEW AND REVISED ACCOUNTING
STANDARDS
IASB has issued several amendments to standards or
interpretations to standards e
\ufb00
ective as of 1 January 2024.
PetroNor have adopted these standards in the
\ufb01
nancial year, the
impacts were not material to PetroNor\u2019s consolidated
\ufb01
nancial
statements upon adoption.
The IASB issued IFRS 18 Presentation and Disclosure in Financial
Statements in April 2024, which becomes e
\ufb00
ective for annual
periods beginning on or after 1 January 2027. IFRS 18 introduces
signi
\ufb01
cant changes to the structure and content of the primary
\ufb01
nancial statements, including:
\ue001
A revised format for the statement of pro
\ufb01
t or loss,
including the classi
\ufb01
cation of income and expenses into
\ufb01
ve
categories in the Consolidated statement of comprehensive
income: operating, investing,
\ufb01
nancing, income taxes, and
discontinued operations
\ue001
Introduction of de
\ufb01
ned subtotals such as operating pro
\ufb01
t.
\ue001
Enhanced aggregation and disaggregation requirements to
improve comparability and clarity.
\ue001
Disclosure of management-de
\ufb01
ned performance measures
(MDPMs), promoting transparency around non-GAAP
metrics.
The Group has not early adopted IFRS 18. The standard is
expected to a
\ufb00
ect the presentation and disclosure of the
Group\u2019s
\ufb01
nancial statements but will not impact recognition or
measurement of assets, liabilities, income, or expenses. The
Group is currently assessing the impact of these changes and
will implement necessary updates to its
\ufb01
nancial reporting
systems and processes ahead of the e
\ufb00
ective date.
Impacts of other standards and amendments to standards, and
interpretations of standards, issued but not yet e
\ufb00
ective are not
expected to have a material impact on the Group.", "dimensions": { "concept": "ifrs-full:DescriptionOfInitialApplicationOfStandardsOrInterpretations", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00266": { "value": "28B.
CONSOLIDATION
The consolidated
\ufb01
nancial statements comprise the
\ufb01
nancial
statements of PetroNor E&P ASA (\u201cthe company\u201d, formerly
PetroNor E&P Ltd) and its subsidiaries for the year ended
31 December 2024 (together the Group).
An entity has been assessed as being controlled by the Group
when the Groups is exposed, or has the rights, to variable
returns from its involvement with the entity and has the ability
to a
\ufb00
ect those returns through its power over the entity.
Speci
\ufb01
cally, the Group controls an entity if and only if the Group
has:
\ue001
Power over the entity (i.e., existing rights that give it the
current ability to direct the relevant activities of the entity)
\ue001
Exposure, or rights, to variable returns from its involvement
with the entity, and
\ue001
The ability to use its power over the entity to a
\ufb00
ect its
returns
When the Group has less than a majority of the voting or similar
rights of an entity, the Group considers all relevant facts and
circumstances in assessing whether it has power over an entity,
including:
\ue001
The contractual arrangement with the other vote holders of
the entity
\ue001
Rights arising from other contractual arrangements
\ue001
The Group\u2019s voting rights and potential voting rights
The Group reassesses whether or not it controls an entity if
facts and circumstances indicate that there are changes to
one or more of the three elements of control. Consolidation
of a subsidiary begins when the Group obtains control over
the subsidiary and ceases when the Group loses control of the
subsidiary. Business combinations are accounted for by using
the acquisition method. Assets, liabilities, income and expenses
of a subsidiary acquired or disposed of during the year are
included in the statement of comprehensive income from the
date the Group gains control until the date the Group ceases to
control the subsidiary.
Pro
\ufb01
t or loss and each component of other comprehensive
income (OCI) are attributed to the equity holders of the parent
of the Group and to the non-controlling interests, even if this
results in the non-controlling interests having a de
\ufb01
cit balance.
When necessary, adjustments are made to the
\ufb01
nancial
statements of subsidiaries to bring their accounting policies into
line with the Group\u2019s accounting policies. All intra-group assets
and liabilities, equity, income, expenses and cash
\ufb02
ows relating
to transactions between members of the Group are eliminated
in full on consolidation.
A change in the ownership interest of a subsidiary, without a
loss of control, is accounted for as an equity transaction.
If the Group loses control over a subsidiary, it:
\ue001
Derecognises the assets (including goodwill) and liabilities of
the subsidiary
\ue001
Derecognises the carrying amount of any non-controlling
interests
\ue001
Derecognises the cumulative translation di
\ufb00
erences
recorded in equity
\ue001
Recognises the fair value of the consideration received
\ue001
Recognises the fair value of any investment retained
\ue001
Recognises any surplus or de
\ufb01
cit in pro
\ufb01
t or loss
\ue001
Reclassi
\ufb01
es the parent\u2019s share of components previously
recognised in OCI to pro
\ufb01
t or loss or retained earnings, as
appropriate, as would be required if the Group had directly
disposed of the related assets or liabilities.", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00267": { "value": "28C.
FOREIGN CURRENCY TRANSLATION
Functional and presentation currency
The company has applied United States Dollars, being the
functional currency of all major subsidiaries in the Group, as
its presentation currency. Where the functional currencies of
entities within the consolidated group di
\ufb00
er from United States
Dollars, they have been translated into United States Dollars.
The functional currency of PetroNor E&P ASA Group is United
States Dollars.
Transactions and balances
Transactions in foreign currencies are initially recorded in the
functional currency by applying the exchange rates ruling at
the date of the transaction. Monetary assets and liabilities
denominated in foreign currencies are retranslated at the rate
of exchange ruling at the reporting date and any gains or losses
are recognised in the income statement.
Non-monetary items that are measured in terms of historical
cost in the foreign currency are translated using the exchange
rate as at the date of the initial transaction. Non-monetary
items measured at fair value in a foreign currency are translated
using the exchange rates at the date when the fair value was
determined.
Translation of Group Companies\u2019 functional currency to
presentation currency
On consolidation, the assets and liabilities of foreign operations
are translated into United States Dollars at the rate of
exchange prevailing at the reporting date and their income
and expenditure are translated at exchange rates prevailing
at the dates of the transactions. The exchange di
\ufb00
erences
arising on translation for consolidation are recognised in other
comprehensive income. On disposal of a foreign operation, the
component of other comprehensive income relating to that
particular foreign operation is recognised in pro
\ufb01
t or loss.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00268": { "value": "Functional and presentation currency
The company has applied United States Dollars, being the
functional currency of all major subsidiaries in the Group, as
its presentation currency. Where the functional currencies of
entities within the consolidated group di
\ufb00
er from United States
Dollars, they have been translated into United States Dollars.
The functional currency of PetroNor E&P ASA Group is United
States Dollars.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00271": { "value": "28D.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include cash on hand, deposits held
at call with banks, other short-term highly liquid investments
with original maturities of three months or less, and bank
overdrafts. Bank overdrafts are shown within short-term
borrowings in current liabilities on the Statement of Financial
Position.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00281": { "value": "28E.
TRADE RECEIVABLES
Trade receivables are amounts due from customers for
goods sold or services performed in the ordinary course of
business. They are generally due for settlement within 30 days
and therefore are all classi
\ufb01
ed as current. Trade receivables
are recognised initially at the amount of consideration that
is unconditional unless they contain signi
\ufb01
cant
\ufb01
nancing
components, when they are recognised at fair value. The
group holds the trade receivables with the objective to collect
the contractual cash
\ufb02
ows and therefore measures them
subsequently at amortised cost using the e
\ufb00
ective interest
method.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00282": { "value": "28F.
TANGIBLE ASSETS
Property, plant and equipment
Oil & gas production assets
Oil and gas production assets are aggregated exploration and
evaluation tangible assets and development expenditures
associated with the production of proved reserves.
The cost of development and production assets also includes
the cost of acquisitions and purchases of such assets, directly
attributable overheads and the cost of recognising provisions
for future restoration and decommissioning.
Where major and identi
\ufb01
able parts of the production assets
have di
\ufb00
erent useful lives, they are accounted for as separate
items of property, plant and equipment. Costs of minor repairs
and maintenance are expensed as incurred. Oil and gas
production assets have a
\ufb01
nite life.
Depreciation
Oil and gas properties are depreciated using the unit-of-
production method. Unit-of production rates are based on 1P
proved reserves, which are oil, gas and other mineral reserves
estimated to be recovered from existing facilities using current
operating methods. Oil and gas volumes are considered
produced once they have been measured through meters at
custody transfer or sales transaction points at the outlet valve
on the
\ufb01
eld storage tank.
Field infrastructure exceeding beyond the life of the
\ufb01
eld is
depreciated over the useful life of the infrastructure using a
straight-line method.
Property, plant and equipment not associated with exploration
and production activities are carried at cost less accumulated
depreciation. These assets are also evaluated for impairment.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00283": { "value": "Oil & gas production assets
Oil and gas production assets are aggregated exploration and
evaluation tangible assets and development expenditures
associated with the production of proved reserves.
The cost of development and production assets also includes
the cost of acquisitions and purchases of such assets, directly
attributable overheads and the cost of recognising provisions
for future restoration and decommissioning.
Where major and identi
\ufb01
able parts of the production assets
have di
\ufb00
erent useful lives, they are accounted for as separate
items of property, plant and equipment. Costs of minor repairs
and maintenance are expensed as incurred. Oil and gas
production assets have a
\ufb01
nite life.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForOilAndGasAssetsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00284": { "value": "Depreciation
Oil and gas properties are depreciated using the unit-of-
production method. Unit-of production rates are based on 1P
proved reserves, which are oil, gas and other mineral reserves
estimated to be recovered from existing facilities using current
operating methods. Oil and gas volumes are considered
produced once they have been measured through meters at
custody transfer or sales transaction points at the outlet valve
on the
\ufb01
eld storage tank.
Field infrastructure exceeding beyond the life of the
\ufb01
eld is
depreciated over the useful life of the infrastructure using a
straight-line method.
Property, plant and equipment not associated with exploration
and production activities are carried at cost less accumulated
depreciation. These assets are also evaluated for impairment.Depreciation
Licence related costs capitalised as Intangible assets are
depreciated using the unit-of-production method. Unit-of
production rates are based on 1P proved reserves, which are
oil, gas and other mineral reserves estimated to be recovered
from existing facilities using current operating methods. Oil
and gas volumes are considered produced once they have
been measured through meters at custody transfer or sales
transaction points at the outlet valve on the
\ufb01
eld storage tank.
Technical goodwill
Technical goodwill recognised in business combinations
is allocated to each CGU for the purposes of impairment
testing. Impairment is tested on an annual basis or when
there are impairment indicators. Indicators may be speci
\ufb01
c
to an individual CGU or groups of CGUs to which the technical
goodwill is related. When conducting impairment testing,
deferred tax recognised in relation to the acquired licences
reduces the net carrying value prior to the impairment charges.
Impairment is recognised if the recoverable amount of the CGU
(or groups of CGUs) to which the technical goodwill relates to is
less than the carrying amount.
Impairment of goodwill cannot be reversed in future periods.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00286": { "value": "28G.
INTANGIBLE ASSETS
Exploration and evaluation activity involves the search for
hydrocarbon resources, the determination of technical
feasibility and the assessment of commercial viability of an
identi
\ufb01
ed resource. For each area of interest, expenditure
incurred in the acquisition of rights to explore and all costs
directly associated with holding the licence such as rental,
training and corporate and social responsibility are capitalised
as exploration and evaluation intangible assets. Signature
bonuses required by licence agreements are capitalised as
exploration and evaluation intangible assets. Other costs
directly associated with the licence are expensed as incurred.
Exploration, evaluation and development expenditure is
recorded at historical cost and allocated to cost pools on an area
of interest.
Expenditure on an area of interest is capitalised and
carried forward where rights to tenure of the area of interest
are current and:
\ue001
it is expected to be recouped through successful
development and exploitation of the area of interest or
alternatively by its sale; or
\ue001
exploration and evaluation activities are continuing in
an area of interest but at reporting date have not yet
reached a stage which permits a reasonable assessment
of the existence or otherwise of economically recoverable
reserves.
Accumulated costs in respect of areas of interest which are
abandoned are written o
\ufb00
in full against pro
\ufb01
t in the period in
which the decision to abandon the area is made.
Projects are advanced to development status when it is
expected that further expenditure can be recouped through
sale or successful development and exploitation of the area of
interest.
All capitalised costs are subject to commercial and management
review, as well as review for indicators of impairment at least
once a year. This is to con
\ufb01
rm the continued intent to develop
or otherwise extract value from the discovery. When this is no
longer the case, the costs are written o
\ufb00
through the statement
of pro
\ufb01
t or loss and other comprehensive income.
When proved reserves of oil and natural gas are identi
\ufb01
ed
and development is sanctioned by management, the relevant
capitalised expenditure is
\ufb01
rst assessed for impairment and (if
required) any impairment loss is recognised, then the remaining
balance is transferred to oil and gas properties.
Proceeds from disposal or farm-out transactions of intangible
exploration assets are used to reduce the carrying amount of
the assets. When proceeds exceed the carrying amount, the
di
\ufb00
erence is recognised as a gain. When the Group disposes of
its full interests, gains or losses are recognised in accordance
with the policy for recognising gains or losses on sale of plant,
property and equipment.
Generally Intangible assets can be viewed inde
\ufb01
nite as they will
be retained on the balance sheet until impaired or transferred
to oil and gas properties. Certain licence related costs
capitalised as intangible assets are deemed to have a
\ufb01
nite life
and are accreted over the life of the licence area.
Depreciation
Licence related costs capitalised as Intangible assets are
depreciated using the unit-of-production method. Unit-of
production rates are based on 1P proved reserves, which are
oil, gas and other mineral reserves estimated to be recovered
from existing facilities using current operating methods. Oil
and gas volumes are considered produced once they have
been measured through meters at custody transfer or sales
transaction points at the outlet valve on the
\ufb01
eld storage tank.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsOtherThanGoodwillExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00285": { "value": "28G.
INTANGIBLE ASSETS
Exploration and evaluation activity involves the search for
hydrocarbon resources, the determination of technical
feasibility and the assessment of commercial viability of an
identi
\ufb01
ed resource. For each area of interest, expenditure
incurred in the acquisition of rights to explore and all costs
directly associated with holding the licence such as rental,
training and corporate and social responsibility are capitalised
as exploration and evaluation intangible assets. Signature
bonuses required by licence agreements are capitalised as
exploration and evaluation intangible assets. Other costs
directly associated with the licence are expensed as incurred.
Exploration, evaluation and development expenditure is
recorded at historical cost and allocated to cost pools on an area
of interest.
Expenditure on an area of interest is capitalised and
carried forward where rights to tenure of the area of interest
are current and:
\ue001
it is expected to be recouped through successful
development and exploitation of the area of interest or
alternatively by its sale; or
\ue001
exploration and evaluation activities are continuing in
an area of interest but at reporting date have not yet
reached a stage which permits a reasonable assessment
of the existence or otherwise of economically recoverable
reserves.
Accumulated costs in respect of areas of interest which are
abandoned are written o
\ufb00
in full against pro
\ufb01
t in the period in
which the decision to abandon the area is made.
Projects are advanced to development status when it is
expected that further expenditure can be recouped through
sale or successful development and exploitation of the area of
interest.
All capitalised costs are subject to commercial and management
review, as well as review for indicators of impairment at least
once a year. This is to con
\ufb01
rm the continued intent to develop
or otherwise extract value from the discovery. When this is no
longer the case, the costs are written o
\ufb00
through the statement
of pro
\ufb01
t or loss and other comprehensive income.
When proved reserves of oil and natural gas are identi
\ufb01
ed
and development is sanctioned by management, the relevant
capitalised expenditure is
\ufb01
rst assessed for impairment and (if
required) any impairment loss is recognised, then the remaining
balance is transferred to oil and gas properties.
Proceeds from disposal or farm-out transactions of intangible
exploration assets are used to reduce the carrying amount of
the assets. When proceeds exceed the carrying amount, the
di
\ufb00
erence is recognised as a gain. When the Group disposes of
its full interests, gains or losses are recognised in accordance
with the policy for recognising gains or losses on sale of plant,
property and equipment.
Generally Intangible assets can be viewed inde
\ufb01
nite as they will
be retained on the balance sheet until impaired or transferred
to oil and gas properties. Certain licence related costs
capitalised as intangible assets are deemed to have a
\ufb01
nite life
and are accreted over the life of the licence area.
Depreciation
Licence related costs capitalised as Intangible assets are
depreciated using the unit-of-production method. Unit-of
production rates are based on 1P proved reserves, which are
oil, gas and other mineral reserves estimated to be recovered
from existing facilities using current operating methods. Oil
and gas volumes are considered produced once they have
been measured through meters at custody transfer or sales
transaction points at the outlet valve on the
\ufb01
eld storage tank.
Technical goodwill
Technical goodwill recognised in business combinations
is allocated to each CGU for the purposes of impairment
testing. Impairment is tested on an annual basis or when
there are impairment indicators. Indicators may be speci
\ufb01
c
to an individual CGU or groups of CGUs to which the technical
goodwill is related. When conducting impairment testing,
deferred tax recognised in relation to the acquired licences
reduces the net carrying value prior to the impairment charges.
Impairment is recognised if the recoverable amount of the CGU
(or groups of CGUs) to which the technical goodwill relates to is
less than the carrying amount.
Impairment of goodwill cannot be reversed in future periods.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00291": { "value": "28H.
REVENUE
(i)
Revenue from petroleum products
Revenue from the sale of crude oil is recognised when a
customer obtains control (\u201csales\u201d or \u201clifting\u201d method), normally
this is when title passes at point of delivery. Revenues from
production of oil properties are recognised based on actual
volumes lifted and sold to customers during the period.
(ii)
Other revenue
Under a production sharing contract, where the group is
required to pay pro
\ufb01
t oil tax and royalties on production
of crude oil, such payments are settled in kind (where the
government lift the crude it is entitled to). The Group presents
a gross-up of the pro
\ufb01
t oil tax as an income tax expense with
a corresponding increase in oil and gas revenues and any
associated royalties are included in the cost of sales.
The Group assesses whether it acts as a principal or agent in
each of its revenue arrangements. The Group has concluded
that in all sales transactions it acts as a principal.
(iii)
Variable consideration
If the consideration in a contract includes a variable amount, the
Group recognises this amount as revenue only to the extent that
it is highly probable that a signi
\ufb01
cant reversal will not occur in
the future.
(iv)
Interest
Interest income is recognised on a time-proportional basis using
the e
\ufb00
ective interest method. This is a method of calculating the
amortised cost of a
\ufb01
nancial asset and allocating the interest
income over the relevant period using the e
\ufb00
ective interest rate,
which is the rate that exactly discounts the estimated future
cash receipts through the expected useful life of the
\ufb01
nancial
asset to the net carrying amount of the
\ufb01
nancial asset.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00292": { "value": "(iv)
Interest
Interest income is recognised on a time-proportional basis using
the e
\ufb00
ective interest method. This is a method of calculating the
amortised cost of a
\ufb01
nancial asset and allocating the interest
income over the relevant period using the e
\ufb00
ective interest rate,
which is the rate that exactly discounts the estimated future
cash receipts through the expected useful life of the
\ufb01
nancial
asset to the net carrying amount of the
\ufb01
nancial asset.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInterestIncomeAndExpenseExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00293": { "value": "28I.
TAXES
The income tax expense or bene
\ufb01
t for the period consists of
two components: current and deferred tax.
The current income tax payable or recoverable is calculated
using the tax rates and legislation that have been enacted or
substantively enacted at year-end in each of the jurisdictions
and includes any adjustments for taxes payable or recovery in
respect of prior periods.
Deferred tax assets and liabilities are determined using the
balance sheet liability method based on temporary di
\ufb00
erences
between the carrying value of assets and liabilities for
\ufb01
nancial
reporting purposes and their tax bases. In calculating the
deferred tax assets and liabilities, the tax rates used are those
that have been enacted or substantively enacted by year-end
in each of the jurisdictions and that are expected to apply when
the assets are recovered, or the liabilities are settled.
Revenue-based taxes
In addition to corporate income taxes, the Group\u2019s consolidated
\ufb01
nancial statements also include and recognise as income taxes,
other types of taxes on net income such as certain revenue-
based taxes.
Production-sharing arrangements
According to the production-sharing arrangement (PSA)
in certain licences, the share of the pro
\ufb01
t oil to which the
Government is entitled in any calendar year in accordance
with the PSA is deemed to include a portion representing the
corporate income tax imposed upon and due by the Group. This
amount will be paid directly by the government on behalf of the
Group to the appropriate tax authorities.
The income tax expense
The current income tax is calculated using the PSA, paid in
barrels and booked as income tax and also shown as revenue.
Other income tax relates to the gain on disposal of the farm-out
in Guinea-Bissau included in discontinued operations.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00294": { "value": "Deferred tax assets and liabilities are determined using the
balance sheet liability method based on temporary di
\ufb00
erences
between the carrying value of assets and liabilities for
\ufb01
nancial
reporting purposes and their tax bases. In calculating the
deferred tax assets and liabilities, the tax rates used are those
that have been enacted or substantively enacted by year-end
in each of the jurisdictions and that are expected to apply when
the assets are recovered, or the liabilities are settled.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00295": { "value": "28J.
DEFINED CONTRIBUTION PENSION PLAN
The Group pays contributions into de
\ufb01
ned contribution plans.
Obligations for contributions to de
\ufb01
ned contribution pension
plans are recognised as an expense in the income statement in
the periods during which services are rendered by employees. ", "dimensions": { "concept": "ifrs-full:DisclosureOfDefinedContributionPlansExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00296": { "value": "28K.
TRADE AND OTHER PAYABLES
Trade and other payables are carried at amortised cost and due
to their short-term nature, they are not discounted.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00297": { "value": "28L.
PROVISIONS
Decommissioning liability
A decommissioning liability is recognised when the Group has
a present legal or constructive obligation as a result of past
events, and it is probable that an out
\ufb02
ow of resources will be
required to settle the obligation, and a reliable estimate of the
amount of obligation can be made. A corresponding amount
equivalent to the obligation is also recognised as part of the
cost of the related production plant and equipment. The
amount recognised in the estimated cost of decommissioning,
discounted to its present value. Changes in the estimated
timing of decommissioning or decommissioning cost estimates
are dealt with prospectively by recording an adjustment to
the provision, and a corresponding adjustment to production
plant and equipment. The unwinding of the discount on the
decommissioning liability is included as a
\ufb01
nance cost.
An escrow account is maintained by the operator of the licence
and is governed by a joint operating agreement and the
Congolese Government rules. The Group\u2019s share, paid against
the decommissioning liability until the balance sheet date, is
classi
\ufb01
ed as an advance against decommissioning liability in
current assets.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00298": { "value": "28M.
SHARE CAPITAL
Contributed equity is recognised at the fair value of the
consideration received by the Group, less any capital raising
costs in relation to the issue.
Incremental costs directly attributable to the issue of new
shares or options are shown in equity as a deduction, net of tax,
from the proceeds.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIssuedCapitalExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00299": { "value": "28N.
DIVIDEND DISTRIBUTION
Dividend distribution to the Company\u2019s shareholders is
recognised as a liability in the Group\u2019s
\ufb01
nancial statements
in the period in which the dividends are declared and
appropriately authorised or approved by the Company\u2019s
Shareholders\u2019 General Meeting. Interim dividends proposed
by the Board of Directors are recognised as liabilities upon
declaration. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDividendsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00306": { "value": "28O.
JOINT ARRANGEMENTS
Joint arrangements are arrangements of which two or more
parties have joint control. Joint control is the contractual agreed
sharing of control of the arrangement which exists only when
decisions about the relevant activities require unanimous
consent of the parties sharing control. Control is assessed by
applying the principles under IFRS 10 to determine whether the
Group has joint control . Joint arrangements are classi
\ufb01
ed as
either a joint operation or joint venture, based on the rights and
obligations arising from the contractual obligations between
the parties to the arrangement. Considerations in assessing the
classi
\ufb01
cations would include assessments of control that are
based not just on voting rights but on the extent that the joint
arrangement provides the Company with rights to the individual
assets and obligations arising from the joint arrangement
If the arrangement is classi
\ufb01
ed as a joint operation the Company
recognises its:
\ue001
Assets, including its share of any assets held jointly;
\ue001
Liabilities, including its share of any liabilities incurred
jointly;
\ue001
Revenue from the sale of its share of the output arising from
the joint operation;
\ue001
Share of revenue from the sale of the output by the joint
operation; and
\ue001
Expenses, including its share of any expenses incurred
jointly.
A joint arrangement which provides the Company with rights
to the net assets of the arrangement, is classi
\ufb01
ed as a joint
venture and accounted for using the equity method and treated
as an investment . Under the equity method, the cost of the
investment is adjusted by the post-acquisition changes in the
Company\u2019s share of the net assets of the venture.
Where assets are transferred into separate legal entities
concurrent with the entities shares being sold to a third party
thereby resulting in a loss of control of those asset owning
subsidiaries these assets will be treated as a joint venture.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00311": { "value": "28P.
BUSINESS COMBINATIONS AND GOODWILL
Business combinations are accounted for using the acquisition
method.
The cost of an acquisition is measured as the
aggregate of the fair value at the date of exchange of assets
and liabilities acquired. Where a non-controlling interest exists,
the Group elects whether to measure NCI in the acquiree
at fair value or at the proportionate share of the acquiree\u2019s
identi
\ufb01
able net assets. The initial accounting for a business
combination can be changed if new information about the
fair value at the acquisition date is present. The allocation can
be amended within 12 months of the acquisition date. When
the consideration transferred by the Group in a business
combination includes a contingent consideration arrangement,
the contingent consideration is measured at its acquisition-
date fair value and included as part of the consideration
transferred in a business combination. Changes in the fair
value of the contingent consideration is re-measured to fair
value at subsequent reporting dates with changes in fair value
recognised in the income statement.
Goodwill is recognised as the aggregate of the consideration
transferred and the amount of any non-controlling interest
and deducted by the net of the acquisition-date amounts of
the identi
\ufb01
able assets acquired and the liabilities assumed.
Goodwill is not depreciated but is tested at least annually for
impairment. In connection with this, goodwill is allocated to
cash-generating units or groups of cash-generating units that
are expected to bene
\ufb01
t from synergies from the business
combination.
PetroNor recognises a gain/loss on disposal of subsidiary when
control is lost.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00310": { "value": "28P.
BUSINESS COMBINATIONS AND GOODWILL
Business combinations are accounted for using the acquisition
method.
The cost of an acquisition is measured as the
aggregate of the fair value at the date of exchange of assets
and liabilities acquired. Where a non-controlling interest exists,
the Group elects whether to measure NCI in the acquiree
at fair value or at the proportionate share of the acquiree\u2019s
identi
\ufb01
able net assets. The initial accounting for a business
combination can be changed if new information about the
fair value at the acquisition date is present. The allocation can
be amended within 12 months of the acquisition date. When
the consideration transferred by the Group in a business
combination includes a contingent consideration arrangement,
the contingent consideration is measured at its acquisition-
date fair value and included as part of the consideration
transferred in a business combination. Changes in the fair
value of the contingent consideration is re-measured to fair
value at subsequent reporting dates with changes in fair value
recognised in the income statement.
Goodwill is recognised as the aggregate of the consideration
transferred and the amount of any non-controlling interest
and deducted by the net of the acquisition-date amounts of
the identi
\ufb01
able assets acquired and the liabilities assumed.
Goodwill is not depreciated but is tested at least annually for
impairment. In connection with this, goodwill is allocated to
cash-generating units or groups of cash-generating units that
are expected to bene
\ufb01
t from synergies from the business
combination.
PetroNor recognises a gain/loss on disposal of subsidiary when
control is lost.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00307": { "value": "28P.
BUSINESS COMBINATIONS AND GOODWILL
Business combinations are accounted for using the acquisition
method.
The cost of an acquisition is measured as the
aggregate of the fair value at the date of exchange of assets
and liabilities acquired. Where a non-controlling interest exists,
the Group elects whether to measure NCI in the acquiree
at fair value or at the proportionate share of the acquiree\u2019s
identi
\ufb01
able net assets. The initial accounting for a business
combination can be changed if new information about the
fair value at the acquisition date is present. The allocation can
be amended within 12 months of the acquisition date. When
the consideration transferred by the Group in a business
combination includes a contingent consideration arrangement,
the contingent consideration is measured at its acquisition-
date fair value and included as part of the consideration
transferred in a business combination. Changes in the fair
value of the contingent consideration is re-measured to fair
value at subsequent reporting dates with changes in fair value
recognised in the income statement.
Goodwill is recognised as the aggregate of the consideration
transferred and the amount of any non-controlling interest
and deducted by the net of the acquisition-date amounts of
the identi
\ufb01
able assets acquired and the liabilities assumed.
Goodwill is not depreciated but is tested at least annually for
impairment. In connection with this, goodwill is allocated to
cash-generating units or groups of cash-generating units that
are expected to bene
\ufb01
t from synergies from the business
combination.
PetroNor recognises a gain/loss on disposal of subsidiary when
control is lost.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsAndGoodwillExplanatory", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "TagsThatMustBeAppliedIfCorrespondingInformationIsPresentInAReport_Label_00187": { "value": "Fr\u00f8yas gate 13 0273 Oslo Norway", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:984500AEEH2D2AK42C11", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } } } }