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"value": "INTRODUCTION Panoro\u2019s classification of reserves and resources complies with the guidelines established by the Oslo Stock Exchange and are based on the definitions set by the Petroleum Resources Management System (PRMS), sponsored by the Society of Petroleum Engineers/ World Petroleum Council/ American Association of Petroleum Geologists/ Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE) as issued in June 2018. Reserves are the volume of hydrocarbons that are expected to be produced from known accumulations: \u2022 On Production \u2022 Approved for Development \u2022 Justified for Development Reserves are also classified according to the associated risks and probability that the reserves will be actually produced. 1P \u2013 Proved reserves represent volumes that will be recovered with 90% probability 2P \u2013 Proved + Probable represent volumes that will be recovered with 50% probability 3P \u2013 Proved + Probable + Possible volumes that will be recovered with 10% probability. Contingent Resources are the volumes of hydrocarbons expected to be produced from known accumulations: \u2022 In planning phase \u2022 Where development is likely \u2022 Where development is unlikely with present basic assumptions \u2022 Under evaluation Contingent Resources are reported as 1C, 2C, and 3C, reflecting similar probabilities as reserves. DISCLAIMER The information provided in this report reflects reservoir assessments, which in general must be recognised as subjective processes of estimating hydrocarbon volumes that cannot be measured in an exact way. It should also be recognised that results of recent and future drilling, testing, production and new technology applications may justify revisions that could be material. Certain assumptions on the future beyond Panoro\u2019s control have been made. These include assumptions made regarding market variations affecting both product prices and investment levels. As a result, actual developments may deviate materially from what is stated in this report. The estimates in this report are based on third party assessments prepared by Netherland Sewell and Associates Inc. (NSAI). ANNUAL STATEMENT OF RESERVES 2024
PANORO ASSETS PORTFOLIO The Panoro portfolio reported here for year end 2024 is considered to comprise assets with reserves and contingent resources being the Block G license in Equatorial Guinea, the Dussafu license in Gabon and the TPS Assets in Tunisia. A summary description of these assets with reserves and contingent resources with their status as of 31 December 2024 is included below. For additional background information on the assets, refer to the company\u2019s website. Unless otherwise specified, all reserves figures quoted in this report are net to Panoro\u2019s working interest. BLOCK G: Offshore Equatorial Guinea Operator: Trident Energy, Panoro 14.25% The Block G assets comprise a number of oil fields offshore Equatorial Guinea The Block G license covers an area containing the Ceiba field and the Okume complex. The Okume complex consists of five separate oil fields. The fields in Block G started production in 2000-2002 and oil is produced through a number of wells either subsea or from fixed platforms and tied back to a FPSO. Production from Block G during 2024 amounted to 9.16 MMbbls gross. In April 2025 NSAI certified (3rd party) reserves and resources for the Block G licence. As of the end of December 2024, the Block G licence contained gross 1P Proved Reserves of 83.0 MMbbls in the Ceiba and Okume Complex fields. Gross 2P Proved plus Probable Reserves amounted to 114.6 MMbbls in the same fields. Gross 3P Proved plus Probable plus Possible Reserves in these fields amounted to 147.4 MMbbls. In addition to these Reserves NSAI also certified gross unrisked 1C Contingent Resources of 30.6 MMbbls, gross unrisked 2C Contingent Resources of 70.1 MMbbls, and gross unrisked 3C Contingent Resources of 120.9 MMbbls in the Block G licence area. These evaluations yield the following Reserves net to Panoro\u2019s working interest of 14.25%: 1P Proved Reserves of 11.82 MMbbls, 2P Proved plus Probable Reserves of 16.33 MMbbls and 3P Proved plus Probable plus Possible Reserves of 21.00 MMbbls. Additional unrisked Contingent Resources net to Panoro\u2019s working interest of 14.25% are 4.4 MMbbls 1C, 10.0 MMbbls 2C and 17.2 MMbbls 3C. These Reserves and Contingent Resources are Panoro\u2019s net working interest volumes before deductions for royalties and other taxes. Panoro\u2019s net entitlement 1P reserves are 9.83 MMbbls, net entitlement 2P reserves are 13.30 MMbbls and net entitlement 3P reserves are 16.72 MMbbls.
DUSSAFU: Offshore Gabon Operator: BW Energy, Panoro 17.4997% The Dussafu license contains the producing Tortue, Hibiscus and Hibiscus South fields Dussafu is a development and exploitation licence covering an area containing several oil fields, the most recent discovery being the Hibiscus South field. In 2014 an Exclusive Exploitation Authorisation (EEA) for an 850.5 km 2 area within the Dussafu PSC was awarded. The first field in the EEA area, Tortue, started oil production in 2018. Production from the Dussafu license during 2024 amounted to 10.13 MMbbls gross. In March 2025 NSAI certified (3rd party) reserves and resources for the Dussafu licence. As of the end of December 2024, the Dussafu licence contained gross 1P Proved Reserves of 80.1 MMbbls. Gross 2P Proved plus Probable Reserves amounted to 118.6 MMbbls. Gross 3P Proved plus Probable plus Possible Reserves in Dussafu amounted to 167.5 MMbbls. In addition to these Reserves NSAI also certified gross unrisked 1C Contingent Resources of 24.7 MMbbls, gross 2C Contingent Resources of 49.4 MMbbls, and gross 3C Contingent Resources of 95.6 MMbbls in the Dussafu licence area. These evaluations yield the following Reserves net to Panoro\u2019s working interest of 17.5%: 1P Proved Reserves of 14.02 MMbbls, 2P Proved plus Probable Reserves of 20.75 MMbbls and 3P Proved plus Probable plus Possible Reserves of 29.31 MMbbls. Additional unrisked Contingent Resources net to Panoro\u2019s working interest of 17.5% are 4.3 MMbbls 1C, 8.6 MMbbls 2C and 16.7 MMbbls 3C. These Reserves and Contingent Resources are Panoro\u2019s net working interest volumes before deductions for royalties and other taxes. Panoro\u2019s net entitlement 1P reserves are 10.69 MMbbls, net entitlement 2P reserves are 14.40 MMbbls and net entitlement 3P reserves are 18.40 MMbbls. TPS ASSETS: Onshore and Offshore Tunisia Operator: TPS, Panoro 49.0% The TPS Assets comprise five oil field concessions in the region of the city of Sfax, onshore and shallow water offshore Tunisia The concessions are Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba. The oil fields were discovered in the 1980\u2019s and early 1990\u2019s and have produced a total of approximately 63 million barrels of oil to date. Production from the TPS assets amounted to 1.15 MMbbls gross in 2024. In March 2025 NSAI certified (3rd party) reserves and resources for the TPS licences. As of the end of December 2024 gross field reserves amount to 1P Proved Reserves of 7.6 MMbbls, 2P Proved plus Probable Reserves of 10.6 MMbbls and 3P Proved plus Probable plus Possible Reserves of 13.7 MMbbls. Panoro\u2019s net working interest 1P Proved reserves are 3.70 MMbbls, 2P Proved plus Probable are 5.20 MMbbls and 3P Proved plus Probable plus Possible are 6.70 MMbbls. In addition to these reserves, NSAI also assessed gross 1C Contingent Resources of 8.9 MMbbls, 2C Contingent Resources of 14.2 MMbbls and 3C Contingent Resources of 22.4 MMbbls. Panoro\u2019s net working interest 1C Contingent Resource is 4.4 MMbbls, net working interest 2C Contingent Resource is 7.0 MMbbls and net working interest 3C Contingent Resource is 11.0 MMbbls. These Reserves and Contingent Resources are Panoro\u2019s net volumes before deductions for royalties and other taxes. Panoro\u2019s net entitlement 1P reserves are 3.23 MMbbls, net entitlement 2P reserves are 4.54 MMbbls and net entitlement 3P reserves are 5.85 MMbbls.
MANAGEMENT DISCUSSION AND ANALYSIS Panoro uses the services of NSAI for third party verifications of its reserves and resources. All evaluations are based on standard industry practice and methodology for production decline analysis and reservoir modelling based on geological and geophysical analysis. The following discussions are a comparison of the volumes reported in previous reports, along with a discussion of the consequences for the year-end 2024 ASR. Block G: In 2024 certain contingent resources projects were re-classified as reserves in line with the operators longer term planning, this resulted in an increase in reserves for the Ceiba and Okume fields. Remaining contingent resources in the Block G fields are associated with projects that have not yet been approved and potential production beyond the license expiry dates of the fields. Some of these contingent resources may be re-assigned as reserves if certain projects are approved or license terms further extended. Dussafu: Following the drilling of the Hibiscus South discovery and the northern extension of the Hibiscus field in 2024, combined with stronger-than-anticipated well performance across the Hibiscus area, additional reserves were booked for both the Hibiscus and Hibiscus South fields. The remaining fields in Dussafu (Walt Whitman, Moubenga and Hibiscus North) and extensions to the other fields are classified as Contingent Resources. A decision to develop these fields will trigger a re-assignment of these resources as reserves and a possible re-determination of their volumes. TPS: Some minor modifications were made to forward reserve projections based on well performance in 2024. Contingent Resources may be re-assigned as reserves if certain projects are approved or license terms extended. ASSUMPTIONS: The commerciality and economic tests for all of the reserves volumes were based on the following Brent Crude future oil price adjusted for price differentials: Period Ending Oil Price 31 December USD/bbl 2025 76 2026 79 2027 80 2028 83 2029 85 2030 88 2031 91 2032 93 2033 96 2034 99 2035 102 2036 104 2037 107 2038 110 2039 113 Thereafter 115
2024 \u2013 2P DEVELOPMENT (WORKING INTEREST) 2P Reserves Development MMBOE Balance (previous ASR \u2013 31 December 2023) 34.7 Production 2024 (3.6) Extensions and discoveries since previous ASR 5.9 Revisions of previous estimates 5.3 Balance (revised ASR) as of 31 December 2024 42.3 Panoro\u2019s total 1P working interest reserves at end of 2024 amount to 29.54 MMbbls. Panoro\u2019s 2P reserves amount to 42.27 MMbbls and Panoro\u2019s 3P reserves amount to 57.01 MMbbls. Panoro\u2019s Contingent Resource base includes discoveries of varying degrees of maturity towards development decisions. By the end of 2024, Panoro\u2019s assets contained a total un-risked 2C working interest volume of 25.6 MMbbls. 24 April 2025 John Hamilton CEO
NOTE 26: RESERVES (UNAUDITED) The Group has adopted a policy of regional reserve reporting using external third-party companies to audit its work and certify reserves and resources according to the guidelines established by the Oslo Stock Exchange (\u201cOSE\u201d). Reserve and contingent resource estimates comply with the definitions 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 June 2018. Panoro uses the services of Netherland Sewell & Associates (\u201cNSAI\u201d) for third party verifications of its reserves. Please refer to the Annual Statement of Reserves on page 28 for details.
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"reg-ix-362": {
"value": "NOTE 1: CORPORATE INFORMATION The parent company, Panoro Energy ASA
(\u201cthe Company\u201d), was incorporated on 28 April 2009 as a public
limited company
under the Norwegian Public Limited Companies Act
. The registered organisation number of
the Company is 994 051 067 and its registered office is
c/o Advokatfirmaet Schj\u00f8dt AS, Tordenskiolds gate
12, P.O. Box 2444 Solli, 0201 Oslo,
Norway
.
The Company and its subsidiaries (\u201cPanoro\u201d or the \u201cGroup\u201d) are engaged in the exploration and production of oil and gas
resources
in North, West and Southern Africa
.
The consolidated financial statements of the Group for the year ended 31
December 2024 were authorised for issue by the Board of Directors on 24 April 2025.
The Company regularly evaluates its financial position, cash flow forecasts and its compliance with financial covenants by considering multiple combinations of oil and gas prices, production volumes, and operational spend scenarios. As required under the Norwegian Accounting Act, the Company\u2019s Board of Directors conducted a review of the going concern assumption considering all relevant information available up to the date the Panoro consolidated and Company accounts are issued and taking into account all available information about the future covering at least 12 months from the end of the reporting period. The Board of Directors\u2019 review included, in particular, assessment of the Group\u2019s projected cash reserves and access to financing arrangements, debt maturities, operational outlook and work programs, while maintaining appropriate headroom in respect of sound equity, liquidity and financial covenant compliance throughout the assessment period. Following its review, the Board of Directors confirmed, pursuant to the Norwegian Accounting Act section 3-3a, that the requirements of the going concern assumption are met and that these financial statements have been prepared on that basis. The Company\u2019s shares are traded on the Oslo Stock Exchange under the ticker symbol PEN. The Company\u2019s corporate bond is listed on Nordic Alternative Bond Market with ticker symbol PEN01.
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-363": {
"value": "Panoro Energy ASA",
"dimensions": {
"concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-364": {
"value": "public limited company",
"dimensions": {
"concept": "ifrs-full:LegalFormOfEntity",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-365": {
"value": " under the Norwegian Public Limited Companies Act",
"dimensions": {
"concept": "ifrs-full:CountryOfIncorporation",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-366": {
"value": "c/o Advokatfirmaet Schj\u00f8dt AS, Tordenskiolds gate 12, P.O. Box 2444 Solli, 0201 Oslo, Norway",
"dimensions": {
"concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-367": {
"value": "Norway",
"dimensions": {
"concept": "ifrs-full:DomicileOfEntity",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-368": {
"value": "The Company and its subsidiaries (\u201cPanoro\u201d or the \u201cGroup\u201d) are engaged in the exploration and production of oil and gas resources",
"dimensions": {
"concept": "ifrs-full:DescriptionOfNatureOfEntitysOperationsAndPrincipalActivities",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-369": {
"value": " in North, West and Southern Africa",
"dimensions": {
"concept": "ifrs-full:PrincipalPlaceOfBusiness",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-370": {
"value": "The consolidated financial statements of the Group for the year ended 31
December 2024 were authorised for issue by the Board of Directors on 24 April 2025.
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAuthorisationOfFinancialStatementsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-371": {
"value": "The Company regularly evaluates its financial position, cash flow forecasts and its compliance with financial covenants by considering multiple combinations of oil and gas prices, production volumes, and operational spend scenarios. As required under the Norwegian Accounting Act, the Company\u2019s Board of Directors conducted a review of the going concern assumption considering all relevant information available up to the date the Panoro consolidated and Company accounts are issued and taking into account all available information about the future covering at least 12 months from the end of the reporting period. The Board of Directors\u2019 review included, in particular, assessment of the Group\u2019s projected cash reserves and access to financing arrangements, debt maturities, operational outlook and work programs, while maintaining appropriate headroom in respect of sound equity, liquidity and financial covenant compliance throughout the assessment period. Following its review, the Board of Directors confirmed, pursuant to the Norwegian Accounting Act section 3-3a, that the requirements of the going concern assumption are met and that these financial statements have been prepared on that basis. The Company\u2019s shares are traded on the Oslo Stock Exchange under the ticker symbol PEN. The Company\u2019s corporate bond is listed on Nordic Alternative Bond Market with ticker symbol PEN01.
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGoingConcernExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-372": {
"value": "NOTE 2: BASIS OF PREPARATION The consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards (IFRS Accounting Standards
) as adopted by the European Union (\u201cEU\u201d).
The consolidated financial statements are
prepared on a historical cost basis, except for certain financial instruments which have been measured at fair value. The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all years presented, unless otherwise stated.
The consolidated financial statements are presented in USD, which is the functional currency of Panoro Energy ASA. The amounts in these financial statements have been rounded to the nearest USD thousand unless otherwise stated.
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-373": {
"value": "The consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards (IFRS Accounting Standards
) as adopted by the European Union (\u201cEU\u201d).
",
"dimensions": {
"concept": "ifrs-full:StatementOfIFRSCompliance",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-374": {
"value": " The consolidated financial statements are
prepared on a historical cost basis, except for certain financial instruments which have been measured at fair value. The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all years presented, unless otherwise stated.
Note 2.4: Material accounting policy information 2.4.1 Interests in associated companies and joint arrangements A joint arrangement is an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities (being those that significantly affect the returns of the arrangement) require unanimous consent of the parties sharing control. Associated companies are those entities in which the Group has significant influence but not control or joint control over the financial and operating policies. Investments in associated companies are accounted for in the consolidated financial statements using the equity method of accounting. Equity accounting involves recording investments in associated companies initially at cost and recognising the Group\u2019s share of its associated companies\u2019 post-acquisition results and its share of post- acquisition movements in reserves against the carrying amount of the investments. When the Group\u2019s share of losses in an associated company equals or exceeds its interest in the associated company, including any other unsecured receivables, the Group does not recognise further losses, unless it has incurred obligations or made payments on behalf of the associated company. Joint arrangements, which are arrangements of which the Group has joint control together with one or more parties, are classified into joint ventures and joint operations. Joint ventures are joint arrangements in which the parties that share control have rights to the net assets of the arrangement. Joint operations are joint arrangements in which the parties that share joint control have rights to the assets, and obligations for the liabilities, relating to the arrangement. For joint operations, the Group\u2019s share of all assets, liabilities, income and expenses is included in the consolidated financial statements. Acquisitions of interests in a joint operation, in which the activity of the joint operation constitutes a business, are accounted for according to the relevant IFRS 3 principles of accounting for business combinations. On 11 December 2018, the Company entered into a joint arrangement through a shareholder agreement with Beender Petroleum Tunisia Limited (\u201cBeender\u201d), whereby Panoro and Beender jointly own and control 60% and 40% respectively of Sfax Petroleum Corporation AS (\u201cSfax\u201d). Sfax, through its subsidiaries holds 100% shares of Panoro Tunisia Production AS (\u201cPTP\u201d) and Panoro Tunisia Exploration AS (\u201cPTE\u201d). As such, the arrangement is a joint operation and all numbers and volume information relating to the Company\u2019s Tunisian operations and transactions represents the Group\u2019s 60% interest, unless otherwise stated.
On 24 April 2023 (the \u201cCompletion Date\u201d), Panoro acquired Beender\u2019s 40% of the shares of Sfax and as a result of the transaction, Sfax became a wholly owned subsidiary of Panoro. The Tunisian operations were accounted for at 60% as outlined above up to the Completion Date and as a fully owned subsidiary at 100% thereafter. Further details can be found in
Note 14: Business Combinations. Joint operations A joint operation is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities, relating to the arrangement. In relation to its interests in joint operations, the Group recognises its: \u2022 Assets, including its share of any assets held jointly \u2022 Liabilities, including its share of any liabilities incurred jointly \u2022 Revenue from the sale of its share of the output arising from the joint operation \u2022 Expenses, including its share of any expenses incurred jointly Reimbursement of costs of the operator of the joint arrangement When the Group, acting as an operator or manager of a joint arrangement, receives reimbursement of direct costs recharged to the joint arrangement, such recharges represent reimbursements of costs that the operator incurred as an agent for the joint arrangement and therefore have no effect on profit or loss. 2.4.2 Foreign Currency translation Items included in the financial statements of each of the Group\u2019s entities are measured using the currency of the primary economic environment in which the entity operates (\u2018the functional currency\u2019). The functional currency of the Group\u2019s subsidiaries and jointly controlled companies incorporated in Gabon, Nigeria, Cyprus, Netherlands, Norway, Austria and the Cayman Islands is the US dollar (\u2018USD\u2019). In the consolidated financial statements, the assets and liabilities of non-USD functional currency balances are translated into USD at the rate of exchange ruling at the balance sheet date. The results and cash flows of non-USD functional currency subsidiaries are translated into USD using applicable average rates as an approximation for the exchange rates prevailing at the dates of the different transactions. Foreign exchange adjustments arising when the opening net assets and the profits for the year retained by non-USD functional currency subsidiaries are translated into USD are taken to a separate component of equity. The foreign exchange rates applied were: 2024 2023 Average rate Reporting date rate Average rate Reporting date rate Norwegian Kroner / USD 10.7582 11.3578 10.5614 10.1566 USD / British Pound Sterling 1.2779 1.2529 1.2436 1.2747 USD / Tunisian Dinar 3.0972 3.0650 3.1069 3.0657 Transactions in foreign currencies are initially recorded at the functional currency spot rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency spot rate of exchange ruling at the reporting date. All differences are taken to the income statement. Non-monetary items that are measured in terms of historical cost in foreign currency are translated using the spot exchange rates as at the dates of the initial transactions. 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.
2.4.3 Business combinations and goodwill In order to consider an acquisition as a business combination, the acquired asset or groups of assets must constitute a business (an integrated set of operations and assets conducted and managed for the purpose of providing a return to the investors). The combination consists of inputs and processes applied to these inputs that have the ability to create output. Acquired businesses are included in the financial statements from the transaction date. The transaction date is defined as the date on which the Group achieves control over the financial and operating assets. This date may differ from the actual date on
which the assets are transferred. Comparative figures are not adjusted for acquired, sold or liquidated businesses. On acquisition of a licence that involves the right to explore for and produce petroleum resources, it is considered in each case whether the acquisition should be treated as a business combination or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value and the amount of any NCI in the acquiree. For each business combination, the Group elects whether to measure NCI in the acquiree at fair value or at the proportionate share of the acquiree\u2019s identifiable net assets. Acquisition related costs are expensed as incurred and included in administrative expenses. When the Group acquires a business, it assesses the assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree. Those acquired petroleum reserves and resources that can be reliably measured are recognised separately in the assessment of fair values on acquisition. Other potential reserves, resources and rights, for which fair values cannot be reliably measured, are not recognised separately, but instead are subsumed in goodwill. Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9 Financial Instruments is measured at fair value, with changes in fair value recognised either in the statement of profit or loss or as a change to other comprehensive income. If the contingent consideration is not within the scope of IFRS 9, it is measured in accordance with the appropriate IFRS Accounting Standards. Contingent consideration that is classified as equity is not re- measured, and subsequent settlement is accounted for within equity. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for NCI over the fair value of the identifiable net assets acquired and liabilities assumed. If the fair value of the identifiable net assets acquired is in excess of the aggregate consideration transferred (bargain purchase), before recognising a gain, the Group reassesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognised at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognised in the statement of profit or loss and other comprehensive income. After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group\u2019s cash generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Where goodwill forms part of a CGU and part of the operation in that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed of in these circumstances is measured based on the relative values of the disposed operation and the portion of the CGU retained.
2.4.4 License interests, exploration and evaluation assets, and field investments, and depreciation The Group applies the \u2018successful efforts\u2019 method of accounting for Exploration and Evaluation (\u2018E&E\u2019) costs, in accordance with IFRS 6 \u2018Exploration for and Evaluation of Mineral Resources\u2019. E&E expenditure is capitalised when it is considered probable that future economic benefits will be recoverable. Costs that are known at the time of incurrence to fail to meet this criterion are generally charged to expense in the period they are incurred. E&E expenditure capitalised as intangible assets includes license acquisition costs, and exploration drilling, geological and geophysical costs and any other directly attributable costs. E&E expenditure, which is not sufficiently related to a specific mineral resource to support capitalisation, is expensed as incurred. E&E assets are carried forward, until the existence, or otherwise, of commercial reserves have been determined subject to certain limitations including review for indications of impairment. If no reserves are found the costs to drill exploratory wells, including exploratory geological and geophysical costs and costs of carrying and retaining unproved properties, are written off. Once commercial reserves have been discovered, the carrying value after any impairment loss of the relevant E&E assets is transferred to development tangible and intangible assets. No depreciation and/or amortisation are charged during the exploration and development phase. If however, commercial reserves have not been discovered, the capitalised costs are charged to expense after the conclusion of appraisal activities.
Development assets Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of commercially proven development wells, is capitalised within property, plant and equipment according to nature. When development is completed on a specific field, these costs are transferred to production assets. No depreciation or amortisation is charged during the Exploration and Evaluation phase.
Farm-outs \u2013 in the exploration and evaluation phase The Group does not record any expenditure made by the farmee on its account. It also does not recognise any gain or loss on its exploration and evaluation farm-out arrangements but redesignates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously capitalised in relation to the whole interest with any excess accounted for by the Group as a gain on disposal. Development costs Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalised within oil and gas properties. Oil & gas production assets Development and production assets are accumulated on a cash-generating unit basis and represent the cost of developing the commercial reserves discovered and bringing them into production together with E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined in accounting policy above. 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 identifiable parts of the production assets have different useful lives, they are accounted for as separate items of property, plant and equipment. Costs of minor repairs and maintenance are expensed as incurred. Depreciation/amortisation Oil and gas properties are not depleted until production commences. Costs relating to each single field cost centre are depleted on a unit of production method based on the commercial proved and probable reserves for that cost centre. The depletion calculation takes account of the estimated future costs of development of management\u2019s assessment of proved and probable reserves, reflecting risks applicable to the specific assets. Changes in reserve quantities and cost estimates are recognised prospectively from the last reporting date. Field infrastructure exceeding beyond the life of the field is depreciated over the useful life of the infrastructure using a straight- line method. Depreciation/amortisation on assets held for sale is ceased from the date of such classification.
Impairment \u2013 exploration and evaluation assets E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount exceeds the recoverable amount and when they are reclassified to PP&E assets. For the purpose of impairment testing, E&E assets are grouped by concession or field with other E&E and PP&E assets belonging to the same CGU. The impairment loss will be calculated as the excess of the carrying value over recoverable amount of the E&E impairment grouping and any resulting impairment loss is recognised in profit or loss. The recoverable amount of a CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In assessing fair value less costs to sell, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risk specific to the asset. Fair value less costs to sell is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves.
Impairment \u2013 proved oil and gas production properties and intangible assets Proven oil and gas properties and intangible assets are reviewed annually for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset\u2019s carrying amount exceeds its recoverable amount. The carrying value is compared against the expected recoverable amount of the asset, generally by net present value of the future net cash flows, expected to be derived from
production of commercial reserves or consideration expected to be achieved through the sale of its interest in an arms-length transaction, less any associated costs to sell. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped together where there are common facilities.
Climate considerations in impairment assessment Climate change and transition to a lower carbon economy is considered in the impairment assessments. In the context of assessing the potential impact on the book values related to the Group\u2019s oil and gas assets, certain climate considerations are factored into the Group\u2019s estimation of cash flows that are applied in the calculation of recoverable amount. This includes factoring in current legislation in jurisdictions where the Group has operations and estimation of future levels of environmental taxes, if any. An energy transition is likely to impact the future oil and gas prices which in turn may affect the recoverable amount of the oil and gas assets. Indirectly, climate considerations are also assessed in the forecasting of oil and gas prices where supply and demand are considered. A significant reduction in the Company\u2019s oil and gas price assumptions would result in impairments on certain production and development assets including intangible assets that are subject to impairment assessment under IAS 36, but an opposite revision in the price assumptions would lead to limited impairment reversals as most of the impairments recognized were related to impairment of goodwill which cannot be reversed under IFRS Accounting Standards. In the context of testing robustness of the oil and gas assets against the scenarios from the International Energy Agency (IEA), the Company has applied the Net Zero Emissions Scenario, Stated Policies Scenario and Sustainable Development Scenario as published by the IEA as part of the World Energy Outlook (WEO) reports. These scenarios are commonly applied by peer companies and the Company believes are useful to investors and other stakeholders in assessing portfolio resilience across companies in the industry. For more details, see Note 10.2: Impairment in Oil and Gas Interests.
2.4.5 Financial instruments 2.4.5.1 Derivative financial instruments and hedge accounting The Group enters into derivative financial instruments including zero cost collars and commodity swaps to manage its exposure to volatility in the commodity prices realised for a proportion of its crude oil production. All derivative financial instruments are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re- measured at their fair value at each period end. Apart from those derivatives designated as qualifying cash flow hedging instruments, all changes in fair value are recorded as financial income or expense in the year in which they arise, otherwise they are recognised in other comprehensive income. For derivatives not designed as qualifying for cash flow hedging, the fair value at balance sheet date is based on fair value provided by the counterparties with whom the trades have been entered into. The derivatives are valued using a Black- Scholes based methodology. The inputs to these valuations include price of oil and its volatility. Fair value is the amount for which a financial asset, liability or instrument could be exchanged between knowledgeable and willing parties in an arm\u2019s length transaction. It is determined by reference to quoted market prices adjusted for estimated transaction costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models and estimated discounted values of cash flows.
2.4.5.2 Financial assets Financial assets are recognised initially at fair value, normally being the transaction price. In the case of financial assets not at fair value through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their classification, as set out below.
The group derecognises financial assets when the
contractual rights to the cash flows expire or the financial asset is transferred to a third party. This includes the derecognition of receivables for which discounting arrangements are entered into. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics of the financial asset.
Financial assets measured at amortised cost Financial assets are classified as measured at amortised cost when they are held in a business model the objective of which is to collect contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortised cost using the effective interest method if the time value of money is significant. Gains and losses are recognised in profit or loss when the assets are derecognised or impaired and when interest is recognised using the effective interest method. This category of financial assets includes trade and other receivables. Financial assets measured at fair value through profit or loss Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at amortised cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives and listed equity investments, other than those designated as effective hedging instruments, are included in this category. Dividends on listed equity investments are recognised as other income in the statement of profit or loss when the right of payment has been established.
Cash equivalents Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortised cost.
Impairment of financial assets measured at amortised cost The group assesses on a forward-looking basis the expected credit losses associated with financial assets classified as measured at amortised cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit risk. Since this is typically less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group's in-scope financial assets. The measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit loss is estimated as the difference between the asset\u2019s carrying amount and the present value of the future cash flows the group expects to receive discounted at the financial asset\u2019s original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognised in the income statement. A financial asset or group of financial assets classified as measured at amortised cost is considered to be credit- impaired if there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due.
2.4.5.3 Financial liabilities The measurement of financial liabilities depends on their classification as follows: Financial liabilities measured at fair value through profit or loss Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.
Financial liabilities measured at amortised cost Other financial liabilities, including borrowings, are initially measured at fair value, net of transaction costs. Other financial liabilities are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis. This category of financial liabilities includes trade and other payables and finance debt. 2.4.6 Fair value measurement and hierarchy The Group measures derivatives at fair value at each balance sheet date and, for the purposes of impairment testing, uses fair value less costs of disposal to determine the recoverable amount of some of its non-financial assets. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place either: \u2022 In the principal market for the asset or liability, or \u2022 In the absence of a principal market, in the most advantageous market for the asset or liability The principal or the most advantageous market must be accessible by the Group. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use.
The Group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximising the use of relevant observable inputs and minimising the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the financial statements are categorised within the fair value hierarchy, described as follows, based on the lowest-level input that is significant to the fair value measurement as a whole: \u2022 Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities, \u2022 Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and \u2022 Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data. For assets and liabilities that are recognised in the financial statements on a recurring basis, the Group determines whether transfers have occurred between levels in the hierarchy by reassessing categorisation (based on the lowest-level input that is significant to the fair value measurement as a whole) at the end of each reporting period. For the purpose of fair value disclosures, the Group has determined classes of assets and liabilities based on the nature, characteristics and risks of the asset or liability and the level of the fair value hierarchy as explained above.
2.4.7 Provisions General Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Group expects some or all of the provision to be reimbursed, for example under an insurance contract, the reimbursement is recognised as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is recognised through profit and loss net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as interest expense. The present obligation under onerous contracts is recognised as a provision.
2.4.8 Asset retirement obligation An asset retirement 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 outflow 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 asset retirement, discounted to its present value. Changes in the estimated timing of asset retirement or asset retirement 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 asset retirement provision is included as a finance cost.
2.4.9 Income tax Income tax expense represents the sum of the tax currently payable and movement in deferred tax. Current tax Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted by the reporting date, in the countries where the Group operates and generates taxable income. Current income tax relating to items recognised directly in equity is recognised in equity and not in the income statement. Management periodically evaluates positions taken in the tax returns with respect to situations which applicable tax regulations are subject to interpretation and established provisions where appropriate. Deferred tax Deferred tax is provided using the liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred income tax liabilities are recognised for all taxable temporary differences, except:
\u2022 Where the deferred tax liability arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affect neither the accounting profit nor taxable profit or loss; and \u2022 In respect of taxable temporary differences associated with investments in subsidiaries, associates and interest in joint ventures, where the timing of the reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred tax assets are recognised for all deductible temporary differences; carry forward to unused tax credits and unused tax losses, to the extent that it is probable that future taxable profit will be available against which the deductible temporary differences and the carry forward of unused tax credits and unused tax losses can be utilised except: \u2022 Where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and \u2022 In respect of deductible temporary differences associate with investments in subsidiaries, associate and interest in joint ventures, deferred income tax assets are recognised only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilised. The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient future taxable profit will be available to allow all or part of the deferred tax asset to be utilised. Unrecognised deferred tax assets are reassessed at each reporting date and are recognised to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realised or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the reporting date. Deferred tax relating to items recognised directly in equity is recognised in equity and not in the income statement. Deferred tax assets and deferred tax liabilities are offset, if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority. Tax benefits acquired as part of a business combination, but not satisfying the criteria for separate recognition at that date, would be recognised subsequently if new information about facts and circumstances arose. The adjustment would either be treated as a reduction to goodwill (as long as it does not exceed goodwill) if it occurred during the measurement period or in profit or loss.
Production-sharing arrangements According to the production-sharing arrangement (PSA) in certain licenses, the share of the profit 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 Group to the appropriate tax authorities. This portion of income tax and revenue are presented separately in income statement. Sales tax Revenues, expenses and assets are recognised net of the amount of sales tax except: Sales tax is recognised as part of the cost of acquisition of the asset or as part of the expense item as applicable if the sales tax incurred on a purchase of assets or services is not recoverable from taxation authorities. Receivables and payables that are stated with the amount of sales tax included. The net amount of sales tax recoverable from, or payable to, taxation authorities is included as part of receivables or payables in the statement of financial position.
2.4.10 Revenue recognition 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. Where the Group has lifted and sold more than the ownership interest, an accrual is recognised for the cost of the overlift. Where the Group has lifted and sold less than the ownership interest, costs are deferred for the underlift. Overlift and underlift on the Consolidated statement of financial position date are valued at
production costs. Lifting imbalances are a part of the operating cycle and as such classified as other current liabilities/assets. Under a production sharing contract, where the group is required to pay profit oil tax on production of crude oil, such payment can either be settled (i) in kind (where the government lift the crude it is entitled to); or (ii) in cash (where the Group sells the crude and pays the taxes in cash). The group presents a gross-up of the profit oil tax as an income tax expense with a corresponding increase in oil and gas revenues. Interest income and financial instruments measured at amortised cost Interest income is recognised on an accruals basis. For all financial instruments measured at amortised cost and interest- bearing financial assets measured at fair value through profit and loss, interest income or expense is recorded using the effective interest rate (EIR), which is the rate that exactly discounts the estimated future cash payments or receipts through the expected life of the financial instrument or a shorter period, where appropriate, to the net carrying amount of the financial asset or liability. Interest revenue is included in finance income in income statement.
2.4.11 Inventories Inventories, consisting of crude oil, and drilling and maintenance materials, are stated at the lower of cost and net realisable value. Costs comprise costs of purchase, costs of conversion and other costs incurred in bringing the inventories to their present location and condition. Weighted average cost is used to determine the cost of ordinarily inter-changeable items.
2.4.12 Share-based payment transactions Employees (including senior executives) of the Group may receive remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments (equity-settled transactions). Equity-settled transactions The cost of equity-settled transactions is recognised, together with a corresponding increase in additional paid in capital reserve in equity, over the period in which the performance and/or service conditions are fulfilled. The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group\u2019s best estimate of the number of equity instruments that will ultimately vest. The income statement expense or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period and is recognised in share-based payments expense. No expense is recognised for awards that do not ultimately vest, except for equity-settled transactions for which vesting are conditional upon a market or non-vesting condition. These are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance and/or service conditions are satisfied. When the terms of an equity-settled transaction award are modified, the minimum expense recognised is the expense as if the terms had not been modified, if the original terms of the award are met. An additional expense is recognised for any modification that increases the total fair value of the share-based payment transaction or is otherwise beneficial to the employee as measured at the date of modification. When an equity-settled award is cancelled, it is treated as if it vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. This includes any award where non-vesting conditions within the control of either the entity or the employee are not met. However, if a new award is substituted for the cancelled award and designated as a replacement award on the date that it is granted, the cancelled and new awards are treated as if they were a modification of the original award, as described in the previous paragraph. The dilutive effect of outstanding options is reflected as additional share dilution in the computation of diluted earnings per share.
2.4.13 Impairment of non-oil and gas interests Non-financial assets Assets that are subject to amortisation or depreciation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Goodwill is assessed for impairment on an annual basis. An impairment loss is recognised for the amount by which the asset\u2019s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset\u2019s fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash inflows (cash-generating units). Non-financial assets that were previously impaired are reviewed for possible reversal of the impairment at each reporting date.
An assessment is made at each reporting date to determine whether there is an indication that previously recognised impairment losses may no longer exist or may have decreased. If such indication exists, the asset\u2019s recoverable amount is estimated. A previously recognised impairment loss is reversed only if there has been a change in the assumptions used to determine the asset\u2019s recoverable amount since the last impairment loss was recognised. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. Such a reversal is recognised in the income statement. After such a reversal the depreciation charge is adjusted in future periods to allocate the asset\u2019s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.
Financial assets Assets carried at amortised cost If there is objective evidence that an impairment loss on assets carried at amortised cost has been incurred, the amount of the loss is measured as the difference between the assets\u2019 carrying amount and the present value of estimated future cash flows (excluding future expected credit losses that have not been incurred) discounted at the financial asset\u2019s original effective interest rate (i.e. the effective interest rate computed at initial recognition). The carrying amount of the asset is reduced through use of an allowance account. The amount of the loss shall be recognised in the income statement. If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised, the previously recognised impairment loss is reversed, to the extent that the carrying value of the asset does not exceed its amortised cost at the reversal date, any subsequent reversal of an impairment loss is recognised in the income statement.
The consolidated financial statements are presented in USD, which is the functional currency of Panoro Energy ASA. The amounts in these financial statements have been rounded to the nearest USD thousand unless otherwise stated.
",
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"concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory",
"language": "en",
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"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
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"reg-ix-376": {
"value": "Note 2.1: Changes in significant accounting policies Standards, amendments to standards, and interpretations of standards, issued but not yet effective, are either not expected to materially impact the Company\u2019s consolidated financial statements, or are not expected to be relevant to the Company's consolidated financial statements upon adoption.
Note 2.5: New and amended standards and interpretations No standard amendments or interpretations of standards effective as of 1 January 2024 and adopted by Panoro, were material to the Group\u2019s Consolidated financial statements upon adoption. Note 2.6: Standards issued but not yet effective In April 2024, the IASB issued IFRS 18, which will replace IAS 1 effective from 1 January 2027. The new standard introduces several key requirements: \u2022 Entities must classify all income and expenses into five categories in the Consolidated Statement of Income: operating, investing, financing, income taxes, and discontinued operations. \u2022 A newly-defined operating profit subtotal must be presented. \u2022 Management-defined performance measures (MPMs) are to be disclosed in a single note to the financial statements. \u2022 Enhanced guidance for aggregating and disaggregating information in financial statements. \u2022 Additionally, entities are required to use the operating profit subtotal as the starting point for the Consolidated Statement of Cash Flows when presenting cash flows provided by operating activities under the indirect method. IFRS 18 applies retrospectively and allows for earlier application if disclosed. The Group is currently evaluating the impact of IFRS 18 on its financial statements.
",
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"concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
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"reg-ix-377": {
"value": "Note 2.2: Basis of consolidation The consolidated financial statements include Panoro Energy ASA and its subsidiaries as of December 31 for each year. Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Group obtains control, and continue to be consolidated until the date that such control ceases. The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.
All intra-group balances, transactions and unrealised gains and losses resulting from intra-group transactions and dividends are eliminated in full. Non-controlling interests in subsidiaries are identified separately from the Group\u2019s equity therein. Total comprehensive income is attributed to non-controlling interests even if this results in the non-controlling interests having a deficit balance.
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: \u2022 derecognises the assets (including goodwill) and liabilities of the subsidiary \u2022 derecognises the carrying amount of any non-controlling interest (NCI) \u2022 derecognises the cumulative translation differences recognised in equity \u2022 recognises the fair value of the consideration received \u2022 recognises the fair value of any investment retained \u2022 recognises any surplus or deficit in profit or loss \u2022 reclassifies the parent\u2019s share of components previously recognised in other comprehensive income to profit or loss or retained earnings, as appropriate. The purchase method of accounting is applied for business combinations. The cost of the acquisition is measured as the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed, and equity instruments issued by the acquirer, in exchange for control of the acquirer. If the initial accounting for a business combination can only be determined provisionally, then provisional values are used. However, these provisional values may be adjusted within 12 months from the date of the combination.
",
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"concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-378": {
"value": "The consolidated financial statements include Panoro Energy ASA and its subsidiaries as of December 31 for each year. Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Group obtains control, and continue to be consolidated until the date that such control ceases. The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.
All intra-group balances, transactions and unrealised gains and losses resulting from intra-group transactions and dividends are eliminated in full. Non-controlling interests in subsidiaries are identified separately from the Group\u2019s equity therein. Total comprehensive income is attributed to non-controlling interests even if this results in the non-controlling interests having a deficit balance.
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: \u2022 derecognises the assets (including goodwill) and liabilities of the subsidiary \u2022 derecognises the carrying amount of any non-controlling interest (NCI) \u2022 derecognises the cumulative translation differences recognised in equity \u2022 recognises the fair value of the consideration received \u2022 recognises the fair value of any investment retained \u2022 recognises any surplus or deficit in profit or loss \u2022 reclassifies the parent\u2019s share of components previously recognised in other comprehensive income to profit or loss or retained earnings, as appropriate. The purchase method of accounting is applied for business combinations. The cost of the acquisition is measured as the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed, and equity instruments issued by the acquirer, in exchange for control of the acquirer. If the initial accounting for a business combination can only be determined provisionally, then provisional values are used. However, these provisional values may be adjusted within 12 months from the date of the combination.
Non-controlling interests in subsidiaries are identified separately from the Group\u2019s equity therein. Total comprehensive income is attributed to non-controlling interests even if this results in the non-controlling interests having a deficit balance.
",
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"concept": "ifrs-full:DescriptionOfAccountingPolicyForTransactionsWithNoncontrollingInterestsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
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"reg-ix-380": {
"value": "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: \u2022 derecognises the assets (including goodwill) and liabilities of the subsidiary \u2022 derecognises the carrying amount of any non-controlling interest (NCI) \u2022 derecognises the cumulative translation differences recognised in equity \u2022 recognises the fair value of the consideration received \u2022 recognises the fair value of any investment retained \u2022 recognises any surplus or deficit in profit or loss \u2022 reclassifies the parent\u2019s share of components previously recognised in other comprehensive income to profit or loss or retained earnings, as appropriate. The purchase method of accounting is applied for business combinations. The cost of the acquisition is measured as the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed, and equity instruments issued by the acquirer, in exchange for control of the acquirer. If the initial accounting for a business combination can only be determined provisionally, then provisional values are used. However, these provisional values may be adjusted within 12 months from the date of the combination.
2.4.3 Business combinations and goodwill In order to consider an acquisition as a business combination, the acquired asset or groups of assets must constitute a business (an integrated set of operations and assets conducted and managed for the purpose of providing a return to the investors). The combination consists of inputs and processes applied to these inputs that have the ability to create output. Acquired businesses are included in the financial statements from the transaction date. The transaction date is defined as the date on which the Group achieves control over the financial and operating assets. This date may differ from the actual date on
which the assets are transferred. Comparative figures are not adjusted for acquired, sold or liquidated businesses. On acquisition of a licence that involves the right to explore for and produce petroleum resources, it is considered in each case whether the acquisition should be treated as a business combination or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value and the amount of any NCI in the acquiree. For each business combination, the Group elects whether to measure NCI in the acquiree at fair value or at the proportionate share of the acquiree\u2019s identifiable net assets. Acquisition related costs are expensed as incurred and included in administrative expenses. When the Group acquires a business, it assesses the assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree. Those acquired petroleum reserves and resources that can be reliably measured are recognised separately in the assessment of fair values on acquisition. Other potential reserves, resources and rights, for which fair values cannot be reliably measured, are not recognised separately, but instead are subsumed in goodwill. Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9 Financial Instruments is measured at fair value, with changes in fair value recognised either in the statement of profit or loss or as a change to other comprehensive income. If the contingent consideration is not within the scope of IFRS 9, it is measured in accordance with the appropriate IFRS Accounting Standards. Contingent consideration that is classified as equity is not re- measured, and subsequent settlement is accounted for within equity. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for NCI over the fair value of the identifiable net assets acquired and liabilities assumed. If the fair value of the identifiable net assets acquired is in excess of the aggregate consideration transferred (bargain purchase), before recognising a gain, the Group reassesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognised at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognised in the statement of profit or loss and other comprehensive income. After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group\u2019s cash generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Where goodwill forms part of a CGU and part of the operation in that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed of in these circumstances is measured based on the relative values of the disposed operation and the portion of the CGU retained.
Note 2.3: Significant accounting judgments, estimates and assumptions 2.3.1. Estimates and assumptions The preparation of the financial statements in conformity with IFRS Accounting Standards as adopted by the EU and application of the Group\u2019s accounting policies require management to make judgements, estimates and assumptions that affect the reported amounts of assets, liabilities and contingent liabilities at the date of the consolidated financial statements and reported amounts of revenues and expenses during the reporting period. Judgements, estimates and assumptions are continuously evaluated and are based on management\u2019s experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. However, actual outcomes can differ from these estimates. In particular, significant areas of uncertainty considered by management in preparing the consolidated financial statements are as follows: Business combinations and goodwill Acquisitions are accounted for as described in 2.4.3 Business combinations and goodwill Significant areas requiring judgement, estimate and assumption to apply to establish the appropriate accounting treatment of such acquisitions include fair value of contingent consideration, assessment and appropriate classification of assumed assets and liabilities and recognition of goodwill where fair values cannot reliably be measured. Hydrocarbon reserve estimates Hydrocarbon reserves are estimates of the amounts of hydrocarbons that can be economically and legally extracted from the Group\u2019s oil and gas properties. The Group estimates its commercial reserves based on information compiled by appropriately qualified 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 Group estimates and reports hydrocarbon reserves in line with the principles contained in the SPE Petroleum Resources Management Reporting System (PRMS) framework and generally obtains independent evaluations for each asset whenever new information becomes available that materially influences the reported results. As the economic assumptions used may
change and as additional geological information is obtained during the operation of a field, estimates of recoverable reserves may change. Such changes may impact the Group\u2019s reported financial position and results, which include: \u2022 The carrying value of exploration and evaluation assets; oil and gas properties; property, plant and equipment; and goodwill may be affected due to changes in estimated future cash flows \u2022 Depreciation and amortisation charges in the statement of profit or loss and other comprehensive income may change where such charges are determined using the UOP method, or where the useful life of the related assets change \u2022 Provisions for decommissioning may change \u2014 where changes to the reserve estimates affect expectations about when such activities will occur and the associated cost of these activities \u2022 The recognition and carrying value of deferred tax assets may change due to changes in the judgements regarding the existence of such assets and in estimates of the likely recovery of such assets. Risk relating to outbreak of war The estimation of future oil and gas prices and discount rates is used in determining the recoverable amounts of cash- generating units, individual assets and the Group\u2019s asset retirement costs. Risks related to the outbreak of war could result in higher energy prices amid concerns for regional energy shortages, inflationary pressures, and higher interest rates affecting discount rates. Income and deferred taxes The Group recognises the net future tax benefit related to deferred income tax assets to the extent that it is probable that the deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of deferred income tax assets requires the Group to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws in each jurisdiction, to the extent that future cash flows and taxable income differ significantly from estimates. The ability of the Group to realise the net deferred tax assets recorded at the date of the statement of financial position could be impacted. In addition, future changes in tax laws in the jurisdictions in which the Group operates could limit the ability of the Group to obtain tax deductions in future periods. The Group is also subject to taxes under profit sharing contracts which are paid in kind as State share of profit oil. The value assigned to such taxes is subject to estimation, which may be different to the Company\u2019s realised oil prices for revenue recognition. Impairment indicators The Group assesses each cash-generating unit annually to determine whether an indication of impairment exists. When an indication of impairment exists, a formal estimate of the recoverable amount is made. The recoverable amounts of cash-generating units and individual assets have been determined based on the higher of value- in-use calculations and fair values less costs to sell, or if relevant, a combination of these two models. These calculations require the use of estimates and assumptions. It is reasonably possible that the oil price assumption may change which may then impact the estimated life of the field and may then require a material adjustment to the carrying value of tangible assets. The impacts of energy transition and climate considerations are embedded in the long-term price assumptions. The Group monitors internal and external indicators of impairment relating to its tangible and intangible assets. Asset retirement obligations Asset retirement 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 asset retirement 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, significant estimates and assumptions are made in determining the provision for asset retirement obligation. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The provision at reporting date represents management\u2019s best estimate of the present value of the future asset retirement costs required. Technical risk in development of oil and gas fields The development of the oil and gas fields, in which the Group has an ownership, is associated with significant technical risk and uncertainty with regards to timing of additional production from new development activities. Risks include, but are not limited to, cost overruns, production disruptions as well as delays compared to initial plans laid out by the operator. Some of
the most important risk factors are related to the determination of reserves, the recoverability of reserves, and the planning of a cost efficient and suitable production method. There are also technical risks present in the production phase that may cause cost overruns, failed investment and destruction of wells and reservoirs. Estimates have been made after taking into account information available to management and factors in unknown uncertainties as of the date of the balance sheet. Contingencies By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events. 2.3.2. Judgments In the process of applying the Group\u2019s accounting policies, the directors have made the following judgments, apart from those involving estimates, which have the most significant effect on the amounts recognised in the consolidated financial statements: Exploration and evaluation expenditures The application of the Group\u2019s accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely, from future either exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and resources is itself an estimation process that requires varying degrees of uncertainty depending on how the resources are classified. These estimates directly impact when the Group defers exploration and evaluation expenditure. The deferral policy requires management to make certain estimates and assumptions about future events and circumstances, in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available. If, after expenditure is capitalised, information becomes available suggesting that the recovery of the expenditure is unlikely, the relevant capitalised amount is written off in the statement of profit or loss and other comprehensive income in the period when the new information becomes available.
Climate considerations in impairment assessment Climate change and transition to a lower carbon economy is considered in the impairment assessments. In the context of assessing the potential impact on the book values related to the Group\u2019s oil and gas assets, certain climate considerations are factored into the Group\u2019s estimation of cash flows that are applied in the calculation of recoverable amount. This includes factoring in current legislation in jurisdictions where the Group has operations and estimation of future levels of environmental taxes, if any. An energy transition is likely to impact the future oil and gas prices which in turn may affect the recoverable amount of the oil and gas assets. Indirectly, climate considerations are also assessed in the forecasting of oil and gas prices where supply and demand are considered. A significant reduction in the Company\u2019s oil and gas price assumptions would result in impairments on certain production and development assets including intangible assets that are subject to impairment assessment under IAS 36, but an opposite revision in the price assumptions would lead to limited impairment reversals as most of the impairments recognized were related to impairment of goodwill which cannot be reversed under IFRS Accounting Standards. In the context of testing robustness of the oil and gas assets against the scenarios from the International Energy Agency (IEA), the Company has applied the Net Zero Emissions Scenario, Stated Policies Scenario and Sustainable Development Scenario as published by the IEA as part of the World Energy Outlook (WEO) reports. These scenarios are commonly applied by peer companies and the Company believes are useful to investors and other stakeholders in assessing portfolio resilience across companies in the industry. For more details, see Note 10.2: Impairment in Oil and Gas Interests.
",
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"reg-ix-382": {
"value": "2.4.1 Interests in associated companies and joint arrangements A joint arrangement is an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities (being those that significantly affect the returns of the arrangement) require unanimous consent of the parties sharing control. Associated companies are those entities in which the Group has significant influence but not control or joint control over the financial and operating policies. Investments in associated companies are accounted for in the consolidated financial statements using the equity method of accounting. Equity accounting involves recording investments in associated companies initially at cost and recognising the Group\u2019s share of its associated companies\u2019 post-acquisition results and its share of post- acquisition movements in reserves against the carrying amount of the investments. When the Group\u2019s share of losses in an associated company equals or exceeds its interest in the associated company, including any other unsecured receivables, the Group does not recognise further losses, unless it has incurred obligations or made payments on behalf of the associated company. Joint arrangements, which are arrangements of which the Group has joint control together with one or more parties, are classified into joint ventures and joint operations. Joint ventures are joint arrangements in which the parties that share control have rights to the net assets of the arrangement. Joint operations are joint arrangements in which the parties that share joint control have rights to the assets, and obligations for the liabilities, relating to the arrangement. For joint operations, the Group\u2019s share of all assets, liabilities, income and expenses is included in the consolidated financial statements. Acquisitions of interests in a joint operation, in which the activity of the joint operation constitutes a business, are accounted for according to the relevant IFRS 3 principles of accounting for business combinations. On 11 December 2018, the Company entered into a joint arrangement through a shareholder agreement with Beender Petroleum Tunisia Limited (\u201cBeender\u201d), whereby Panoro and Beender jointly own and control 60% and 40% respectively of Sfax Petroleum Corporation AS (\u201cSfax\u201d). Sfax, through its subsidiaries holds 100% shares of Panoro Tunisia Production AS (\u201cPTP\u201d) and Panoro Tunisia Exploration AS (\u201cPTE\u201d). As such, the arrangement is a joint operation and all numbers and volume information relating to the Company\u2019s Tunisian operations and transactions represents the Group\u2019s 60% interest, unless otherwise stated.
On 24 April 2023 (the \u201cCompletion Date\u201d), Panoro acquired Beender\u2019s 40% of the shares of Sfax and as a result of the transaction, Sfax became a wholly owned subsidiary of Panoro. The Tunisian operations were accounted for at 60% as outlined above up to the Completion Date and as a fully owned subsidiary at 100% thereafter. Further details can be found in
",
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"reg-ix-383": {
"value": "2.4.1 Interests in associated companies and joint arrangements A joint arrangement is an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities (being those that significantly affect the returns of the arrangement) require unanimous consent of the parties sharing control. Associated companies are those entities in which the Group has significant influence but not control or joint control over the financial and operating policies. Investments in associated companies are accounted for in the consolidated financial statements using the equity method of accounting. Equity accounting involves recording investments in associated companies initially at cost and recognising the Group\u2019s share of its associated companies\u2019 post-acquisition results and its share of post- acquisition movements in reserves against the carrying amount of the investments. When the Group\u2019s share of losses in an associated company equals or exceeds its interest in the associated company, including any other unsecured receivables, the Group does not recognise further losses, unless it has incurred obligations or made payments on behalf of the associated company. Joint arrangements, which are arrangements of which the Group has joint control together with one or more parties, are classified into joint ventures and joint operations. Joint ventures are joint arrangements in which the parties that share control have rights to the net assets of the arrangement. Joint operations are joint arrangements in which the parties that share joint control have rights to the assets, and obligations for the liabilities, relating to the arrangement. For joint operations, the Group\u2019s share of all assets, liabilities, income and expenses is included in the consolidated financial statements. Acquisitions of interests in a joint operation, in which the activity of the joint operation constitutes a business, are accounted for according to the relevant IFRS 3 principles of accounting for business combinations. On 11 December 2018, the Company entered into a joint arrangement through a shareholder agreement with Beender Petroleum Tunisia Limited (\u201cBeender\u201d), whereby Panoro and Beender jointly own and control 60% and 40% respectively of Sfax Petroleum Corporation AS (\u201cSfax\u201d). Sfax, through its subsidiaries holds 100% shares of Panoro Tunisia Production AS (\u201cPTP\u201d) and Panoro Tunisia Exploration AS (\u201cPTE\u201d). As such, the arrangement is a joint operation and all numbers and volume information relating to the Company\u2019s Tunisian operations and transactions represents the Group\u2019s 60% interest, unless otherwise stated.
On 24 April 2023 (the \u201cCompletion Date\u201d), Panoro acquired Beender\u2019s 40% of the shares of Sfax and as a result of the transaction, Sfax became a wholly owned subsidiary of Panoro. The Tunisian operations were accounted for at 60% as outlined above up to the Completion Date and as a fully owned subsidiary at 100% thereafter. Further details can be found in
Note 14: Business Combinations. Joint operations A joint operation is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities, relating to the arrangement. In relation to its interests in joint operations, the Group recognises its: \u2022 Assets, including its share of any assets held jointly \u2022 Liabilities, including its share of any liabilities incurred jointly \u2022 Revenue from the sale of its share of the output arising from the joint operation \u2022 Expenses, including its share of any expenses incurred jointly Reimbursement of costs of the operator of the joint arrangement When the Group, acting as an operator or manager of a joint arrangement, receives reimbursement of direct costs recharged to the joint arrangement, such recharges represent reimbursements of costs that the operator incurred as an agent for the joint arrangement and therefore have no effect on profit or loss. 2.4.2 Foreign Currency translation Items included in the financial statements of each of the Group\u2019s entities are measured using the currency of the primary economic environment in which the entity operates (\u2018the functional currency\u2019). The functional currency of the Group\u2019s subsidiaries and jointly controlled companies incorporated in Gabon, Nigeria, Cyprus, Netherlands, Norway, Austria and the Cayman Islands is the US dollar (\u2018USD\u2019). In the consolidated financial statements, the assets and liabilities of non-USD functional currency balances are translated into USD at the rate of exchange ruling at the balance sheet date. The results and cash flows of non-USD functional currency subsidiaries are translated into USD using applicable average rates as an approximation for the exchange rates prevailing at the dates of the different transactions. Foreign exchange adjustments arising when the opening net assets and the profits for the year retained by non-USD functional currency subsidiaries are translated into USD are taken to a separate component of equity. The foreign exchange rates applied were: 2024 2023 Average rate Reporting date rate Average rate Reporting date rate Norwegian Kroner / USD 10.7582 11.3578 10.5614 10.1566 USD / British Pound Sterling 1.2779 1.2529 1.2436 1.2747 USD / Tunisian Dinar 3.0972 3.0650 3.1069 3.0657 Transactions in foreign currencies are initially recorded at the functional currency spot rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency spot rate of exchange ruling at the reporting date. All differences are taken to the income statement. Non-monetary items that are measured in terms of historical cost in foreign currency are translated using the spot exchange rates as at the dates of the initial transactions. 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.
",
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"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-385": {
"value": "2.4.3 Business combinations and goodwill In order to consider an acquisition as a business combination, the acquired asset or groups of assets must constitute a business (an integrated set of operations and assets conducted and managed for the purpose of providing a return to the investors). The combination consists of inputs and processes applied to these inputs that have the ability to create output. Acquired businesses are included in the financial statements from the transaction date. The transaction date is defined as the date on which the Group achieves control over the financial and operating assets. This date may differ from the actual date on
which the assets are transferred. Comparative figures are not adjusted for acquired, sold or liquidated businesses. On acquisition of a licence that involves the right to explore for and produce petroleum resources, it is considered in each case whether the acquisition should be treated as a business combination or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value and the amount of any NCI in the acquiree. For each business combination, the Group elects whether to measure NCI in the acquiree at fair value or at the proportionate share of the acquiree\u2019s identifiable net assets. Acquisition related costs are expensed as incurred and included in administrative expenses. When the Group acquires a business, it assesses the assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree. Those acquired petroleum reserves and resources that can be reliably measured are recognised separately in the assessment of fair values on acquisition. Other potential reserves, resources and rights, for which fair values cannot be reliably measured, are not recognised separately, but instead are subsumed in goodwill. Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9 Financial Instruments is measured at fair value, with changes in fair value recognised either in the statement of profit or loss or as a change to other comprehensive income. If the contingent consideration is not within the scope of IFRS 9, it is measured in accordance with the appropriate IFRS Accounting Standards. Contingent consideration that is classified as equity is not re- measured, and subsequent settlement is accounted for within equity. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for NCI over the fair value of the identifiable net assets acquired and liabilities assumed. If the fair value of the identifiable net assets acquired is in excess of the aggregate consideration transferred (bargain purchase), before recognising a gain, the Group reassesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognised at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognised in the statement of profit or loss and other comprehensive income. After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group\u2019s cash generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Where goodwill forms part of a CGU and part of the operation in that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed of in these circumstances is measured based on the relative values of the disposed operation and the portion of the CGU retained.
2.4.3 Business combinations and goodwill In order to consider an acquisition as a business combination, the acquired asset or groups of assets must constitute a business (an integrated set of operations and assets conducted and managed for the purpose of providing a return to the investors). The combination consists of inputs and processes applied to these inputs that have the ability to create output. Acquired businesses are included in the financial statements from the transaction date. The transaction date is defined as the date on which the Group achieves control over the financial and operating assets. This date may differ from the actual date on
which the assets are transferred. Comparative figures are not adjusted for acquired, sold or liquidated businesses. On acquisition of a licence that involves the right to explore for and produce petroleum resources, it is considered in each case whether the acquisition should be treated as a business combination or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value and the amount of any NCI in the acquiree. For each business combination, the Group elects whether to measure NCI in the acquiree at fair value or at the proportionate share of the acquiree\u2019s identifiable net assets. Acquisition related costs are expensed as incurred and included in administrative expenses. When the Group acquires a business, it assesses the assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree. Those acquired petroleum reserves and resources that can be reliably measured are recognised separately in the assessment of fair values on acquisition. Other potential reserves, resources and rights, for which fair values cannot be reliably measured, are not recognised separately, but instead are subsumed in goodwill. Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9 Financial Instruments is measured at fair value, with changes in fair value recognised either in the statement of profit or loss or as a change to other comprehensive income. If the contingent consideration is not within the scope of IFRS 9, it is measured in accordance with the appropriate IFRS Accounting Standards. Contingent consideration that is classified as equity is not re- measured, and subsequent settlement is accounted for within equity. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for NCI over the fair value of the identifiable net assets acquired and liabilities assumed. If the fair value of the identifiable net assets acquired is in excess of the aggregate consideration transferred (bargain purchase), before recognising a gain, the Group reassesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognised at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognised in the statement of profit or loss and other comprehensive income. After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group\u2019s cash generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Where goodwill forms part of a CGU and part of the operation in that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed of in these circumstances is measured based on the relative values of the disposed operation and the portion of the CGU retained.
",
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},
"reg-ix-387": {
"value": "2.4.4 License interests, exploration and evaluation assets, and field investments, and depreciation The Group applies the \u2018successful efforts\u2019 method of accounting for Exploration and Evaluation (\u2018E&E\u2019) costs, in accordance with IFRS 6 \u2018Exploration for and Evaluation of Mineral Resources\u2019. E&E expenditure is capitalised when it is considered probable that future economic benefits will be recoverable. Costs that are known at the time of incurrence to fail to meet this criterion are generally charged to expense in the period they are incurred. E&E expenditure capitalised as intangible assets includes license acquisition costs, and exploration drilling, geological and geophysical costs and any other directly attributable costs. E&E expenditure, which is not sufficiently related to a specific mineral resource to support capitalisation, is expensed as incurred. E&E assets are carried forward, until the existence, or otherwise, of commercial reserves have been determined subject to certain limitations including review for indications of impairment. If no reserves are found the costs to drill exploratory wells, including exploratory geological and geophysical costs and costs of carrying and retaining unproved properties, are written off. Once commercial reserves have been discovered, the carrying value after any impairment loss of the relevant E&E assets is transferred to development tangible and intangible assets. No depreciation and/or amortisation are charged during the exploration and development phase. If however, commercial reserves have not been discovered, the capitalised costs are charged to expense after the conclusion of appraisal activities.
Development assets Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of commercially proven development wells, is capitalised within property, plant and equipment according to nature. When development is completed on a specific field, these costs are transferred to production assets. No depreciation or amortisation is charged during the Exploration and Evaluation phase.
Farm-outs \u2013 in the exploration and evaluation phase The Group does not record any expenditure made by the farmee on its account. It also does not recognise any gain or loss on its exploration and evaluation farm-out arrangements but redesignates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously capitalised in relation to the whole interest with any excess accounted for by the Group as a gain on disposal. Development costs Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalised within oil and gas properties. Oil & gas production assets Development and production assets are accumulated on a cash-generating unit basis and represent the cost of developing the commercial reserves discovered and bringing them into production together with E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined in accounting policy above. 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 identifiable parts of the production assets have different useful lives, they are accounted for as separate items of property, plant and equipment. Costs of minor repairs and maintenance are expensed as incurred. Depreciation/amortisation Oil and gas properties are not depleted until production commences. Costs relating to each single field cost centre are depleted on a unit of production method based on the commercial proved and probable reserves for that cost centre. The depletion calculation takes account of the estimated future costs of development of management\u2019s assessment of proved and probable reserves, reflecting risks applicable to the specific assets. Changes in reserve quantities and cost estimates are recognised prospectively from the last reporting date. Field infrastructure exceeding beyond the life of the field is depreciated over the useful life of the infrastructure using a straight- line method. Depreciation/amortisation on assets held for sale is ceased from the date of such classification.
Impairment \u2013 exploration and evaluation assets E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount exceeds the recoverable amount and when they are reclassified to PP&E assets. For the purpose of impairment testing, E&E assets are grouped by concession or field with other E&E and PP&E assets belonging to the same CGU. The impairment loss will be calculated as the excess of the carrying value over recoverable amount of the E&E impairment grouping and any resulting impairment loss is recognised in profit or loss. The recoverable amount of a CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In assessing fair value less costs to sell, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risk specific to the asset. Fair value less costs to sell is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves.
Impairment \u2013 proved oil and gas production properties and intangible assets Proven oil and gas properties and intangible assets are reviewed annually for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset\u2019s carrying amount exceeds its recoverable amount. The carrying value is compared against the expected recoverable amount of the asset, generally by net present value of the future net cash flows, expected to be derived from
production of commercial reserves or consideration expected to be achieved through the sale of its interest in an arms-length transaction, less any associated costs to sell. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped together where there are common facilities.
Climate considerations in impairment assessment Climate change and transition to a lower carbon economy is considered in the impairment assessments. In the context of assessing the potential impact on the book values related to the Group\u2019s oil and gas assets, certain climate considerations are factored into the Group\u2019s estimation of cash flows that are applied in the calculation of recoverable amount. This includes factoring in current legislation in jurisdictions where the Group has operations and estimation of future levels of environmental taxes, if any. An energy transition is likely to impact the future oil and gas prices which in turn may affect the recoverable amount of the oil and gas assets. Indirectly, climate considerations are also assessed in the forecasting of oil and gas prices where supply and demand are considered. A significant reduction in the Company\u2019s oil and gas price assumptions would result in impairments on certain production and development assets including intangible assets that are subject to impairment assessment under IAS 36, but an opposite revision in the price assumptions would lead to limited impairment reversals as most of the impairments recognized were related to impairment of goodwill which cannot be reversed under IFRS Accounting Standards. In the context of testing robustness of the oil and gas assets against the scenarios from the International Energy Agency (IEA), the Company has applied the Net Zero Emissions Scenario, Stated Policies Scenario and Sustainable Development Scenario as published by the IEA as part of the World Energy Outlook (WEO) reports. These scenarios are commonly applied by peer companies and the Company believes are useful to investors and other stakeholders in assessing portfolio resilience across companies in the industry. For more details, see Note 10.2: Impairment in Oil and Gas Interests.
The Group applies the \u2018successful efforts\u2019 method of accounting for Exploration and Evaluation (\u2018E&E\u2019) costs, in accordance with IFRS 6 \u2018Exploration for and Evaluation of Mineral Resources\u2019. E&E expenditure is capitalised when it is considered probable that future economic benefits will be recoverable. Costs that are known at the time of incurrence to fail to meet this criterion are generally charged to expense in the period they are incurred. E&E expenditure capitalised as intangible assets includes license acquisition costs, and exploration drilling, geological and geophysical costs and any other directly attributable costs. E&E expenditure, which is not sufficiently related to a specific mineral resource to support capitalisation, is expensed as incurred. E&E assets are carried forward, until the existence, or otherwise, of commercial reserves have been determined subject to certain limitations including review for indications of impairment. If no reserves are found the costs to drill exploratory wells, including exploratory geological and geophysical costs and costs of carrying and retaining unproved properties, are written off. Once commercial reserves have been discovered, the carrying value after any impairment loss of the relevant E&E assets is transferred to development tangible and intangible assets. No depreciation and/or amortisation are charged during the exploration and development phase. If however, commercial reserves have not been discovered, the capitalised costs are charged to expense after the conclusion of appraisal activities.
Development assets Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of commercially proven development wells, is capitalised within property, plant and equipment according to nature. When development is completed on a specific field, these costs are transferred to production assets. No depreciation or amortisation is charged during the Exploration and Evaluation phase.
Impairment \u2013 exploration and evaluation assets E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount exceeds the recoverable amount and when they are reclassified to PP&E assets. For the purpose of impairment testing, E&E assets are grouped by concession or field with other E&E and PP&E assets belonging to the same CGU. The impairment loss will be calculated as the excess of the carrying value over recoverable amount of the E&E impairment grouping and any resulting impairment loss is recognised in profit or loss. The recoverable amount of a CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In assessing fair value less costs to sell, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risk specific to the asset. Fair value less costs to sell is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForExplorationAndEvaluationExpenditures",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-389": {
"value": "Development assets Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of commercially proven development wells, is capitalised within property, plant and equipment according to nature. When development is completed on a specific field, these costs are transferred to production assets. No depreciation or amortisation is charged during the Exploration and Evaluation phase.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-390": {
"value": "Farm-outs \u2013 in the exploration and evaluation phase The Group does not record any expenditure made by the farmee on its account. It also does not recognise any gain or loss on its exploration and evaluation farm-out arrangements but redesignates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously capitalised in relation to the whole interest with any excess accounted for by the Group as a gain on disposal. Development costs Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalised within oil and gas properties. Oil & gas production assets Development and production assets are accumulated on a cash-generating unit basis and represent the cost of developing the commercial reserves discovered and bringing them into production together with E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined in accounting policy above. 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 identifiable parts of the production assets have different useful lives, they are accounted for as separate items of property, plant and equipment. Costs of minor repairs and maintenance are expensed as incurred. Depreciation/amortisation Oil and gas properties are not depleted until production commences. Costs relating to each single field cost centre are depleted on a unit of production method based on the commercial proved and probable reserves for that cost centre. The depletion calculation takes account of the estimated future costs of development of management\u2019s assessment of proved and probable reserves, reflecting risks applicable to the specific assets. Changes in reserve quantities and cost estimates are recognised prospectively from the last reporting date. Field infrastructure exceeding beyond the life of the field is depreciated over the useful life of the infrastructure using a straight- line method. Depreciation/amortisation on assets held for sale is ceased from the date of such classification.
Impairment \u2013 proved oil and gas production properties and intangible assets Proven oil and gas properties and intangible assets are reviewed annually for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset\u2019s carrying amount exceeds its recoverable amount. The carrying value is compared against the expected recoverable amount of the asset, generally by net present value of the future net cash flows, expected to be derived from
production of commercial reserves or consideration expected to be achieved through the sale of its interest in an arms-length transaction, less any associated costs to sell. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped together where there are common facilities.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForOilAndGasAssetsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-391": {
"value": "Depreciation/amortisation Oil and gas properties are not depleted until production commences. Costs relating to each single field cost centre are depleted on a unit of production method based on the commercial proved and probable reserves for that cost centre. The depletion calculation takes account of the estimated future costs of development of management\u2019s assessment of proved and probable reserves, reflecting risks applicable to the specific assets. Changes in reserve quantities and cost estimates are recognised prospectively from the last reporting date. Field infrastructure exceeding beyond the life of the field is depreciated over the useful life of the infrastructure using a straight- line method. Depreciation/amortisation on assets held for sale is ceased from the date of such classification.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-392": {
"value": "Impairment \u2013 exploration and evaluation assets E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount exceeds the recoverable amount and when they are reclassified to PP&E assets. For the purpose of impairment testing, E&E assets are grouped by concession or field with other E&E and PP&E assets belonging to the same CGU. The impairment loss will be calculated as the excess of the carrying value over recoverable amount of the E&E impairment grouping and any resulting impairment loss is recognised in profit or loss. The recoverable amount of a CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In assessing fair value less costs to sell, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risk specific to the asset. Fair value less costs to sell is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves.
Impairment \u2013 proved oil and gas production properties and intangible assets Proven oil and gas properties and intangible assets are reviewed annually for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset\u2019s carrying amount exceeds its recoverable amount. The carrying value is compared against the expected recoverable amount of the asset, generally by net present value of the future net cash flows, expected to be derived from
production of commercial reserves or consideration expected to be achieved through the sale of its interest in an arms-length transaction, less any associated costs to sell. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped together where there are common facilities.
Climate considerations in impairment assessment Climate change and transition to a lower carbon economy is considered in the impairment assessments. In the context of assessing the potential impact on the book values related to the Group\u2019s oil and gas assets, certain climate considerations are factored into the Group\u2019s estimation of cash flows that are applied in the calculation of recoverable amount. This includes factoring in current legislation in jurisdictions where the Group has operations and estimation of future levels of environmental taxes, if any. An energy transition is likely to impact the future oil and gas prices which in turn may affect the recoverable amount of the oil and gas assets. Indirectly, climate considerations are also assessed in the forecasting of oil and gas prices where supply and demand are considered. A significant reduction in the Company\u2019s oil and gas price assumptions would result in impairments on certain production and development assets including intangible assets that are subject to impairment assessment under IAS 36, but an opposite revision in the price assumptions would lead to limited impairment reversals as most of the impairments recognized were related to impairment of goodwill which cannot be reversed under IFRS Accounting Standards. In the context of testing robustness of the oil and gas assets against the scenarios from the International Energy Agency (IEA), the Company has applied the Net Zero Emissions Scenario, Stated Policies Scenario and Sustainable Development Scenario as published by the IEA as part of the World Energy Outlook (WEO) reports. These scenarios are commonly applied by peer companies and the Company believes are useful to investors and other stakeholders in assessing portfolio resilience across companies in the industry. For more details, see Note 10.2: Impairment in Oil and Gas Interests.
Non-financial assets Assets that are subject to amortisation or depreciation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Goodwill is assessed for impairment on an annual basis. An impairment loss is recognised for the amount by which the asset\u2019s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset\u2019s fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash inflows (cash-generating units). Non-financial assets that were previously impaired are reviewed for possible reversal of the impairment at each reporting date.
An assessment is made at each reporting date to determine whether there is an indication that previously recognised impairment losses may no longer exist or may have decreased. If such indication exists, the asset\u2019s recoverable amount is estimated. A previously recognised impairment loss is reversed only if there has been a change in the assumptions used to determine the asset\u2019s recoverable amount since the last impairment loss was recognised. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. Such a reversal is recognised in the income statement. After such a reversal the depreciation charge is adjusted in future periods to allocate the asset\u2019s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfNonfinancialAssetsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-393": {
"value": "2.4.5 Financial instruments 2.4.5.1 Derivative financial instruments and hedge accounting The Group enters into derivative financial instruments including zero cost collars and commodity swaps to manage its exposure to volatility in the commodity prices realised for a proportion of its crude oil production. All derivative financial instruments are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re- measured at their fair value at each period end. Apart from those derivatives designated as qualifying cash flow hedging instruments, all changes in fair value are recorded as financial income or expense in the year in which they arise, otherwise they are recognised in other comprehensive income. For derivatives not designed as qualifying for cash flow hedging, the fair value at balance sheet date is based on fair value provided by the counterparties with whom the trades have been entered into. The derivatives are valued using a Black- Scholes based methodology. The inputs to these valuations include price of oil and its volatility. Fair value is the amount for which a financial asset, liability or instrument could be exchanged between knowledgeable and willing parties in an arm\u2019s length transaction. It is determined by reference to quoted market prices adjusted for estimated transaction costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models and estimated discounted values of cash flows.
2.4.5.2 Financial assets Financial assets are recognised initially at fair value, normally being the transaction price. In the case of financial assets not at fair value through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their classification, as set out below.
The group derecognises financial assets when the
contractual rights to the cash flows expire or the financial asset is transferred to a third party. This includes the derecognition of receivables for which discounting arrangements are entered into. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics of the financial asset.
Financial assets measured at amortised cost Financial assets are classified as measured at amortised cost when they are held in a business model the objective of which is to collect contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortised cost using the effective interest method if the time value of money is significant. Gains and losses are recognised in profit or loss when the assets are derecognised or impaired and when interest is recognised using the effective interest method. This category of financial assets includes trade and other receivables. Financial assets measured at fair value through profit or loss Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at amortised cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives and listed equity investments, other than those designated as effective hedging instruments, are included in this category. Dividends on listed equity investments are recognised as other income in the statement of profit or loss when the right of payment has been established.
Cash equivalents Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortised cost.
Impairment of financial assets measured at amortised cost The group assesses on a forward-looking basis the expected credit losses associated with financial assets classified as measured at amortised cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit risk. Since this is typically less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group's in-scope financial assets. The measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit loss is estimated as the difference between the asset\u2019s carrying amount and the present value of the future cash flows the group expects to receive discounted at the financial asset\u2019s original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognised in the income statement. A financial asset or group of financial assets classified as measured at amortised cost is considered to be credit- impaired if there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due.
2.4.5.3 Financial liabilities The measurement of financial liabilities depends on their classification as follows: Financial liabilities measured at fair value through profit or loss Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.
Financial liabilities measured at amortised cost Other financial liabilities, including borrowings, are initially measured at fair value, net of transaction costs. Other financial liabilities are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis. This category of financial liabilities includes trade and other payables and finance debt. 2.4.5.1 Derivative financial instruments and hedge accounting The Group enters into derivative financial instruments including zero cost collars and commodity swaps to manage its exposure to volatility in the commodity prices realised for a proportion of its crude oil production. All derivative financial instruments are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re- measured at their fair value at each period end. Apart from those derivatives designated as qualifying cash flow hedging instruments, all changes in fair value are recorded as financial income or expense in the year in which they arise, otherwise they are recognised in other comprehensive income. For derivatives not designed as qualifying for cash flow hedging, the fair value at balance sheet date is based on fair value provided by the counterparties with whom the trades have been entered into. The derivatives are valued using a Black- Scholes based methodology. The inputs to these valuations include price of oil and its volatility. Fair value is the amount for which a financial asset, liability or instrument could be exchanged between knowledgeable and willing parties in an arm\u2019s length transaction. It is determined by reference to quoted market prices adjusted for estimated transaction costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models and estimated discounted values of cash flows.
2.4.5.1 Derivative financial instruments and hedge accounting The Group enters into derivative financial instruments including zero cost collars and commodity swaps to manage its exposure to volatility in the commodity prices realised for a proportion of its crude oil production. All derivative financial instruments are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re- measured at their fair value at each period end. Apart from those derivatives designated as qualifying cash flow hedging instruments, all changes in fair value are recorded as financial income or expense in the year in which they arise, otherwise they are recognised in other comprehensive income. For derivatives not designed as qualifying for cash flow hedging, the fair value at balance sheet date is based on fair value provided by the counterparties with whom the trades have been entered into. The derivatives are valued using a Black- Scholes based methodology. The inputs to these valuations include price of oil and its volatility. Fair value is the amount for which a financial asset, liability or instrument could be exchanged between knowledgeable and willing parties in an arm\u2019s length transaction. It is determined by reference to quoted market prices adjusted for estimated transaction costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models and estimated discounted values of cash flows.
2.4.5.1 Derivative financial instruments and hedge accounting The Group enters into derivative financial instruments including zero cost collars and commodity swaps to manage its exposure to volatility in the commodity prices realised for a proportion of its crude oil production. All derivative financial instruments are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re- measured at their fair value at each period end. Apart from those derivatives designated as qualifying cash flow hedging instruments, all changes in fair value are recorded as financial income or expense in the year in which they arise, otherwise they are recognised in other comprehensive income. For derivatives not designed as qualifying for cash flow hedging, the fair value at balance sheet date is based on fair value provided by the counterparties with whom the trades have been entered into. The derivatives are valued using a Black- Scholes based methodology. The inputs to these valuations include price of oil and its volatility. Fair value is the amount for which a financial asset, liability or instrument could be exchanged between knowledgeable and willing parties in an arm\u2019s length transaction. It is determined by reference to quoted market prices adjusted for estimated transaction costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models and estimated discounted values of cash flows.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-397": {
"value": "2.4.5.2 Financial assets Financial assets are recognised initially at fair value, normally being the transaction price. In the case of financial assets not at fair value through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their classification, as set out below.
The group derecognises financial assets when the
contractual rights to the cash flows expire or the financial asset is transferred to a third party. This includes the derecognition of receivables for which discounting arrangements are entered into. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics of the financial asset.
Financial assets measured at amortised cost Financial assets are classified as measured at amortised cost when they are held in a business model the objective of which is to collect contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortised cost using the effective interest method if the time value of money is significant. Gains and losses are recognised in profit or loss when the assets are derecognised or impaired and when interest is recognised using the effective interest method. This category of financial assets includes trade and other receivables. Financial assets measured at fair value through profit or loss Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at amortised cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives and listed equity investments, other than those designated as effective hedging instruments, are included in this category. Dividends on listed equity investments are recognised as other income in the statement of profit or loss when the right of payment has been established.
Cash equivalents Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortised cost.
Impairment of financial assets measured at amortised cost The group assesses on a forward-looking basis the expected credit losses associated with financial assets classified as measured at amortised cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit risk. Since this is typically less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group's in-scope financial assets. The measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit loss is estimated as the difference between the asset\u2019s carrying amount and the present value of the future cash flows the group expects to receive discounted at the financial asset\u2019s original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognised in the income statement. A financial asset or group of financial assets classified as measured at amortised cost is considered to be credit- impaired if there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due.
The group derecognises financial assets when the
contractual rights to the cash flows expire or the financial asset is transferred to a third party. This includes the derecognition of receivables for which discounting arrangements are entered into. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics of the financial asset.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDerecognitionOfFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-399": {
"value": "Financial assets measured at fair value through profit or loss Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at amortised cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives and listed equity investments, other than those designated as effective hedging instruments, are included in this category. Dividends on listed equity investments are recognised as other income in the statement of profit or loss when the right of payment has been established.
Financial liabilities measured at fair value through profit or loss Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-400": {
"value": "Cash equivalents Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortised cost.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-401": {
"value": "Impairment of financial assets measured at amortised cost The group assesses on a forward-looking basis the expected credit losses associated with financial assets classified as measured at amortised cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit risk. Since this is typically less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group's in-scope financial assets. The measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit loss is estimated as the difference between the asset\u2019s carrying amount and the present value of the future cash flows the group expects to receive discounted at the financial asset\u2019s original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognised in the income statement. A financial asset or group of financial assets classified as measured at amortised cost is considered to be credit- impaired if there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due.
Financial assets Assets carried at amortised cost If there is objective evidence that an impairment loss on assets carried at amortised cost has been incurred, the amount of the loss is measured as the difference between the assets\u2019 carrying amount and the present value of estimated future cash flows (excluding future expected credit losses that have not been incurred) discounted at the financial asset\u2019s original effective interest rate (i.e. the effective interest rate computed at initial recognition). The carrying amount of the asset is reduced through use of an allowance account. The amount of the loss shall be recognised in the income statement. If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised, the previously recognised impairment loss is reversed, to the extent that the carrying value of the asset does not exceed its amortised cost at the reversal date, any subsequent reversal of an impairment loss is recognised in the income statement.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfFinancialAssetsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-402": {
"value": "2.4.5.3 Financial liabilities The measurement of financial liabilities depends on their classification as follows: Financial liabilities measured at fair value through profit or loss Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.
Financial liabilities measured at amortised cost Other financial liabilities, including borrowings, are initially measured at fair value, net of transaction costs. Other financial liabilities are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis. This category of financial liabilities includes trade and other payables and finance debt. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-403": {
"value": "2.4.6 Fair value measurement and hierarchy The Group measures derivatives at fair value at each balance sheet date and, for the purposes of impairment testing, uses fair value less costs of disposal to determine the recoverable amount of some of its non-financial assets. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place either: \u2022 In the principal market for the asset or liability, or \u2022 In the absence of a principal market, in the most advantageous market for the asset or liability The principal or the most advantageous market must be accessible by the Group. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use.
The Group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximising the use of relevant observable inputs and minimising the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the financial statements are categorised within the fair value hierarchy, described as follows, based on the lowest-level input that is significant to the fair value measurement as a whole: \u2022 Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities, \u2022 Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and \u2022 Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data. For assets and liabilities that are recognised in the financial statements on a recurring basis, the Group determines whether transfers have occurred between levels in the hierarchy by reassessing categorisation (based on the lowest-level input that is significant to the fair value measurement as a whole) at the end of each reporting period. For the purpose of fair value disclosures, the Group has determined classes of assets and liabilities based on the nature, characteristics and risks of the asset or liability and the level of the fair value hierarchy as explained above.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFairValueMeasurementExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-404": {
"value": "2.4.7 Provisions General Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Group expects some or all of the provision to be reimbursed, for example under an insurance contract, the reimbursement is recognised as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is recognised through profit and loss net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as interest expense. The present obligation under onerous contracts is recognised as a provision.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-405": {
"value": "2.4.8 Asset retirement obligation An asset retirement 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 outflow 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 asset retirement, discounted to its present value. Changes in the estimated timing of asset retirement or asset retirement 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 asset retirement provision is included as a finance cost.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-406": {
"value": "2.4.9 Income tax Income tax expense represents the sum of the tax currently payable and movement in deferred tax. Current tax Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted by the reporting date, in the countries where the Group operates and generates taxable income. Current income tax relating to items recognised directly in equity is recognised in equity and not in the income statement. Management periodically evaluates positions taken in the tax returns with respect to situations which applicable tax regulations are subject to interpretation and established provisions where appropriate. Deferred tax Deferred tax is provided using the liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred income tax liabilities are recognised for all taxable temporary differences, except:
\u2022 Where the deferred tax liability arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affect neither the accounting profit nor taxable profit or loss; and \u2022 In respect of taxable temporary differences associated with investments in subsidiaries, associates and interest in joint ventures, where the timing of the reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred tax assets are recognised for all deductible temporary differences; carry forward to unused tax credits and unused tax losses, to the extent that it is probable that future taxable profit will be available against which the deductible temporary differences and the carry forward of unused tax credits and unused tax losses can be utilised except: \u2022 Where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and \u2022 In respect of deductible temporary differences associate with investments in subsidiaries, associate and interest in joint ventures, deferred income tax assets are recognised only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilised. The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient future taxable profit will be available to allow all or part of the deferred tax asset to be utilised. Unrecognised deferred tax assets are reassessed at each reporting date and are recognised to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realised or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the reporting date. Deferred tax relating to items recognised directly in equity is recognised in equity and not in the income statement. Deferred tax assets and deferred tax liabilities are offset, if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority. Tax benefits acquired as part of a business combination, but not satisfying the criteria for separate recognition at that date, would be recognised subsequently if new information about facts and circumstances arose. The adjustment would either be treated as a reduction to goodwill (as long as it does not exceed goodwill) if it occurred during the measurement period or in profit or loss.
Production-sharing arrangements According to the production-sharing arrangement (PSA) in certain licenses, the share of the profit 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 Group to the appropriate tax authorities. This portion of income tax and revenue are presented separately in income statement. Deferred tax Deferred tax is provided using the liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred income tax liabilities are recognised for all taxable temporary differences, except:
\u2022 Where the deferred tax liability arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affect neither the accounting profit nor taxable profit or loss; and \u2022 In respect of taxable temporary differences associated with investments in subsidiaries, associates and interest in joint ventures, where the timing of the reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred tax assets are recognised for all deductible temporary differences; carry forward to unused tax credits and unused tax losses, to the extent that it is probable that future taxable profit will be available against which the deductible temporary differences and the carry forward of unused tax credits and unused tax losses can be utilised except: \u2022 Where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and \u2022 In respect of deductible temporary differences associate with investments in subsidiaries, associate and interest in joint ventures, deferred income tax assets are recognised only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilised. The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient future taxable profit will be available to allow all or part of the deferred tax asset to be utilised. Unrecognised deferred tax assets are reassessed at each reporting date and are recognised to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realised or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the reporting date. Deferred tax relating to items recognised directly in equity is recognised in equity and not in the income statement. Deferred tax assets and deferred tax liabilities are offset, if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority. Tax benefits acquired as part of a business combination, but not satisfying the criteria for separate recognition at that date, would be recognised subsequently if new information about facts and circumstances arose. The adjustment would either be treated as a reduction to goodwill (as long as it does not exceed goodwill) if it occurred during the measurement period or in profit or loss.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-408": {
"value": "Sales tax Revenues, expenses and assets are recognised net of the amount of sales tax except: Sales tax is recognised as part of the cost of acquisition of the asset or as part of the expense item as applicable if the sales tax incurred on a purchase of assets or services is not recoverable from taxation authorities. Receivables and payables that are stated with the amount of sales tax included. The net amount of sales tax recoverable from, or payable to, taxation authorities is included as part of receivables or payables in the statement of financial position.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForTaxesOtherThanIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-409": {
"value": "2.4.10 Revenue recognition 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. Where the Group has lifted and sold more than the ownership interest, an accrual is recognised for the cost of the overlift. Where the Group has lifted and sold less than the ownership interest, costs are deferred for the underlift. Overlift and underlift on the Consolidated statement of financial position date are valued at
production costs. Lifting imbalances are a part of the operating cycle and as such classified as other current liabilities/assets. Under a production sharing contract, where the group is required to pay profit oil tax on production of crude oil, such payment can either be settled (i) in kind (where the government lift the crude it is entitled to); or (ii) in cash (where the Group sells the crude and pays the taxes in cash). The group presents a gross-up of the profit oil tax as an income tax expense with a corresponding increase in oil and gas revenues. Interest income and financial instruments measured at amortised cost Interest income is recognised on an accruals basis. For all financial instruments measured at amortised cost and interest- bearing financial assets measured at fair value through profit and loss, interest income or expense is recorded using the effective interest rate (EIR), which is the rate that exactly discounts the estimated future cash payments or receipts through the expected life of the financial instrument or a shorter period, where appropriate, to the net carrying amount of the financial asset or liability. Interest revenue is included in finance income in income statement.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-410": {
"value": "Interest income and financial instruments measured at amortised cost Interest income is recognised on an accruals basis. For all financial instruments measured at amortised cost and interest- bearing financial assets measured at fair value through profit and loss, interest income or expense is recorded using the effective interest rate (EIR), which is the rate that exactly discounts the estimated future cash payments or receipts through the expected life of the financial instrument or a shorter period, where appropriate, to the net carrying amount of the financial asset or liability. Interest revenue is included in finance income in income statement.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForInterestIncomeAndExpenseExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-411": {
"value": "2.4.11 Inventories Inventories, consisting of crude oil, and drilling and maintenance materials, are stated at the lower of cost and net realisable value. Costs comprise costs of purchase, costs of conversion and other costs incurred in bringing the inventories to their present location and condition. Weighted average cost is used to determine the cost of ordinarily inter-changeable items.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForMeasuringInventories",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-412": {
"value": "2.4.12 Share-based payment transactions Employees (including senior executives) of the Group may receive remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments (equity-settled transactions). Equity-settled transactions The cost of equity-settled transactions is recognised, together with a corresponding increase in additional paid in capital reserve in equity, over the period in which the performance and/or service conditions are fulfilled. The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group\u2019s best estimate of the number of equity instruments that will ultimately vest. The income statement expense or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period and is recognised in share-based payments expense. No expense is recognised for awards that do not ultimately vest, except for equity-settled transactions for which vesting are conditional upon a market or non-vesting condition. These are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance and/or service conditions are satisfied. When the terms of an equity-settled transaction award are modified, the minimum expense recognised is the expense as if the terms had not been modified, if the original terms of the award are met. An additional expense is recognised for any modification that increases the total fair value of the share-based payment transaction or is otherwise beneficial to the employee as measured at the date of modification. When an equity-settled award is cancelled, it is treated as if it vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. This includes any award where non-vesting conditions within the control of either the entity or the employee are not met. However, if a new award is substituted for the cancelled award and designated as a replacement award on the date that it is granted, the cancelled and new awards are treated as if they were a modification of the original award, as described in the previous paragraph. The dilutive effect of outstanding options is reflected as additional share dilution in the computation of diluted earnings per share.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForSharebasedPaymentTransactionsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-413": {
"value": "2.4.13 Impairment of non-oil and gas interests Non-financial assets Assets that are subject to amortisation or depreciation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Goodwill is assessed for impairment on an annual basis. An impairment loss is recognised for the amount by which the asset\u2019s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset\u2019s fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash inflows (cash-generating units). Non-financial assets that were previously impaired are reviewed for possible reversal of the impairment at each reporting date.
An assessment is made at each reporting date to determine whether there is an indication that previously recognised impairment losses may no longer exist or may have decreased. If such indication exists, the asset\u2019s recoverable amount is estimated. A previously recognised impairment loss is reversed only if there has been a change in the assumptions used to determine the asset\u2019s recoverable amount since the last impairment loss was recognised. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. Such a reversal is recognised in the income statement. After such a reversal the depreciation charge is adjusted in future periods to allocate the asset\u2019s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.
Financial assets Assets carried at amortised cost If there is objective evidence that an impairment loss on assets carried at amortised cost has been incurred, the amount of the loss is measured as the difference between the assets\u2019 carrying amount and the present value of estimated future cash flows (excluding future expected credit losses that have not been incurred) discounted at the financial asset\u2019s original effective interest rate (i.e. the effective interest rate computed at initial recognition). The carrying amount of the asset is reduced through use of an allowance account. The amount of the loss shall be recognised in the income statement. If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised, the previously recognised impairment loss is reversed, to the extent that the carrying value of the asset does not exceed its amortised cost at the reversal date, any subsequent reversal of an impairment loss is recognised in the income statement.
NOTE 3: OPERATING SEGMENTS The Group operated predominantly in four business segments being the exploration and production of oil and gas in Equatorial Guinea, Gabon, Tunisia and South Africa. The Group\u2019s reportable segments, for both management and financial reporting purposes, are as follows: \u2022 The Equatorial Guinea segment holds: - Block G, consisting of the Ceiba Field and Okume Complex in which the Group owns a 14.25% working interest. - Exploration blocks S, EG-01 and EG-23 in which the Group owns working interests of 12%, 56% and 80% respectively. \u2022 The Gabon segment holds the Dussafu licence representing the Group\u2019s 17.4997% working interest in the Dussafu Marin exploration licence in Gabon, and the 25% working interest in the Niosi and Guduma licenses \u2022 The Tunisia segment holds the following assets: - Sfax Offshore Exploration Permit: Panoro Tunisia Exploration AS (Operator, 87.5% interest net to Panoro (2022: 52.5%*)), under relinquishment - The Hammamet Offshore Exploration Permit: Medco (Operator), Panoro Tunisia Exploration AS (46% interest net to Panoro (2022: 27.6%*)), under relinquishment - TPS Assets: ETAP, 51% and Panoro TPS (UK) Production Limited, 49% (2022: 29.4%* interest net to Panoro). * Figures represent net participation interest in proportion to Panoro\u2019s equity holding in Sfax Petroleum Corporation AS (\u201cSfax\u201d) before the acquisition of the remaining 40% interest in Sfax described in Note 14: Business Combinations. \u2022 The \u2018South Africa\u2019 segment holds 100% interest in Exploration Right 376, South African Karoo region. \u2022 The \u2018Corporate and others\u2019 category consists of head office and service company operations that are not directly attributable to the other segments. Further, it also includes the residual corporate business in Brazil which is expected to be dormant in the foreseeable future. Management monitors the operating results of business segments separately for the purpose of making decisions about resources to be allocated and of assessing performance. Segment performance is evaluated based on capital and general expenditure.
Details of Group segments are reported below: 2024 USD 000 Equatorial Guinea Gabon Tunisia South Africa Corporate Total Revenue (net) * 101,424 149,926 33,708 - - 285,058 EBITDA ** 48,497 94,386 17,316 (173) (7,839) 152,187 Depreciation (21,776) (25,246) (7,097) - (210) (54,329) Impairment (charge)/reversal - - - - - - Exploration costs written off - - (464) - - (464) Segment assets 298,163 277,129 94,331 153 45,780 715,556 Additions to licences, production, E&E and development assets *** 62,280 44,637 (3,941) - - 102,976 2023 USD 000 Equatorial Guinea Gabon Tunisia South Africa Corporate Total Revenue (net) * 110,843 71,270 45,363 - - 227,476 EBITDA ** 69,204 43,672 27,764 (695) (4,831) 135,114 Depreciation (15,280) (17,684) (6,463) - (260) (39,687) Impairment (charge)/reversal - - - - - - Segment assets 243,174 257,906 74,349 151 36,801 612,381 Additions to licences, production, E&E and development assets *** 20,942 45,239 36,958 - - 103,139 * Gabon revenue increases due to new wells coming online leading to higher production, coupled with more frequent liftings. Revenue excludes any intercompany revenue. ** Lower EBITDA in Equatorial Guinea is a result of lower average realised oil prices for 2024 compared to 2023 and a higher operating expense burden. Non-recurring insurance claim payouts further reduced operating expense levels in 2023. *** Excludes effect on production assets and equipment of the reassessment of decommissioning liabilities of USD 10.6 million (2023: USD 11.6 million), refer to Note 15: Asset Retirement Obligation. Includes additions from acquisitions in 2023 of USD 11.8 million, see Note 14: Business Combinations. Revenue from major sources from continuing operations: USD 000 2024 2023 Oil revenue (net) 267,886 217,985 Other revenue 17,172 9,491 Total revenue 285,058 227,476 There are no differences in the nature of measurement methods used on segment level compared with the consolidated financial statements. The oil revenue from continuing operations relates to sale of hydrocarbons from three assets, Block G in Equatorial Guinea, Dussafu in Gabon and TPS in Tunisia. The Group has local obligations in Tunisia and 20% of produced volumes are sold to the Tunisian State Oil Company, Entreprise Tunisienne D\u2019 Activites Petrolieres (ETAP) in order to fulfil the Group\u2019s domestic market obligations. All sales in 2024 from the Group\u2019s production arose from three key customers. Other revenue consists of estimated State profit oil of USD 17 million (2023: USD 10.9 million) with a corresponding amount as income tax (see Note 2.4.9 Income tax) and the trading profit of domestic market obligation transactions of USD 0.1 million (2023: loss of USD 1.4 million) consisting of cost of crude oil bought in at a cost of USD 10 million offset by the sale of this oil for USD 10.1 million. State profit oil and domestic market obligations are conditions specified under the terms of the Dussafu PSC.
As summary of the licence interests are as follows: Licence area Panoro\u2019s interest Country Expiry of current phase Block G 15% Equatorial Guinea December 2040 Dussafu Marin permit* 17.4997% Gabon September 2028* Sfax Offshore Exploration Permit 87.5% (Operator) Tunisia Under relinquishment Hammamet Offshore Exploration Permit 46% Tunisia Under relinquishment Block S 12% Equatorial Guinea December 2025 Block EG-01 56% (Operator) Equatorial Guinea February 2026 TCP 12/2/218 *** 100% (Operator) South Africa June 2023 Block EG-23 80% (Operator) Equatorial Guinea March 2028 Niosi Marin permit 25.0% Gabon March 2030 Guduma Marin permit 25.0% Gabon March 2028 TPS Assets: Cercina ** February 2024 Cercina South November 2034 Gremda / El Ain 49.0% Tunisia December 2034 Guebiba June 2033 Rhemoura ** January 2023 * The Ruche area Exclusive Exploitation Authorisation (\u201cEEA\u201d) under the Dussafu Marin PSC is effective from commencement of production for a period of 10 years. If, at the end of this ten-year term commercial exploitation is still possible from the Ruche area, the EEA shall be renewed at the contractor\u2019s request for a further period of five years. Subsequent to this, the EEA may be renewed a second time for a further period of five years. ** In process of being renewed. *** In process of conversion to ER 376.
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-415": {
"value": "Revenue from major sources from continuing operations: USD 000 2024 2023 Oil revenue (net) 267,886 217,985 Other revenue 17,172 9,491 Total revenue 285,058 227,476 There are no differences in the nature of measurement methods used on segment level compared with the consolidated financial statements. The oil revenue from continuing operations relates to sale of hydrocarbons from three assets, Block G in Equatorial Guinea, Dussafu in Gabon and TPS in Tunisia. The Group has local obligations in Tunisia and 20% of produced volumes are sold to the Tunisian State Oil Company, Entreprise Tunisienne D\u2019 Activites Petrolieres (ETAP) in order to fulfil the Group\u2019s domestic market obligations. All sales in 2024 from the Group\u2019s production arose from three key customers. Other revenue consists of estimated State profit oil of USD 17 million (2023: USD 10.9 million) with a corresponding amount as income tax (see Note 2.4.9 Income tax) and the trading profit of domestic market obligation transactions of USD 0.1 million (2023: loss of USD 1.4 million) consisting of cost of crude oil bought in at a cost of USD 10 million offset by the sale of this oil for USD 10.1 million. State profit oil and domestic market obligations are conditions specified under the terms of the Dussafu PSC.
Revenue from major sources from continuing operations: USD 000 2024 2023 Oil revenue (net) 267,886 217,985 Other revenue 17,172 9,491 Total revenue 285,058 227,476 There are no differences in the nature of measurement methods used on segment level compared with the consolidated financial statements. The oil revenue from continuing operations relates to sale of hydrocarbons from three assets, Block G in Equatorial Guinea, Dussafu in Gabon and TPS in Tunisia. The Group has local obligations in Tunisia and 20% of produced volumes are sold to the Tunisian State Oil Company, Entreprise Tunisienne D\u2019 Activites Petrolieres (ETAP) in order to fulfil the Group\u2019s domestic market obligations. All sales in 2024 from the Group\u2019s production arose from three key customers. Other revenue consists of estimated State profit oil of USD 17 million (2023: USD 10.9 million) with a corresponding amount as income tax (see Note 2.4.9 Income tax) and the trading profit of domestic market obligation transactions of USD 0.1 million (2023: loss of USD 1.4 million) consisting of cost of crude oil bought in at a cost of USD 10 million offset by the sale of this oil for USD 10.1 million. State profit oil and domestic market obligations are conditions specified under the terms of the Dussafu PSC.
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRevenueExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-417": {
"value": "NOTE 4: OPERATING RESULT Operating profit is stated after charging: USD 000 Note 2024 2023 Employee benefits expense 6,387 6,067 Depreciation 8, 9 54,329 39,687 Acquisition and project related costs (i) 223 811 (i) Acquisition and project related costs relate to business development activities.
Note 4.1: Exploration related costs Exploration costs written off amounting to USD 0.5 million relate to the expiry of SOEP at the end of 2024. Non-capitalisable exploration costs of USD 0.4 million was incurred during 2023. The Company was awarded a 56% participating interest (70% cost bearing) and operatorship of Block EG-01, offshore Equatorial Guinea and farmed-in to the Kosmos Energy operated Block S offshore Equatorial Guinea with a 12% non-operated interest. Costs incurred on these new interests are capitalised as exploration assets.
Note 4.4: Management remuneration Executive management consists of the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO) as described below. Executive management remuneration is summarised below: 2024 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2024 Fair value of RSUs expensed John Hamilton, CEO 603 198 10 13 824 189,615 563 Qazi Qadeer, CFO 393 130 5 13 541 93,509 273 Total 996 328 15 26 1,365 283,124 836 2023 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2023 Fair value of RSUs expensed John Hamilton, CEO 534 187 12 11 744 195,419 527 Qazi Qadeer, CFO 348 123 5 11 487 96,371 239 Total 882 310 17 22 1,231 291,790 766 (i) Under the terms of employment, the CEO and the CFO in general are required to give at least six month\u2019s written notice prior to leaving Panoro. (ii) Per the respective terms of employment, the CEO is entitled to 12 months of base salary in the event of a change of control; whereby a tender offer is made or consummated for the ownership of more than 50% or more of the outstanding voting securities of the Company; or the Company is merged or consolidated with another corporation and as a result of such merger or consolidation less than 50.1% of the outstanding voting securities of the surviving entity or resulting corporation are owned in the aggregate by the persons, by the entities or persons who were shareholders of the Company immediately prior to such merger or consolidation; or the Company sells substantially all of its assets to another corporation that is not a wholly owned subsidiary. The CFO is entitled to 6 months of base salary in the event of a change of control. (iii) In June 2024, 640,032 Restricted Share Units were awarded under and in accordance with the Company\u2019s RSU scheme to the employees of the Company under the long-term incentive compensation plan approved by the shareholders. One Restricted Share Unit (\u201cRSU\u201d) entitles the holder to receive one share of capital stock of the Company against payment in cash of the par value for the share. The par value is currently NOK 0.05 per share. Vesting of the RSUs is time based, where 1/3 of the RSUs vest after one year, 1/3 vest after 2 years, and the final 1/3 vest after 3 years from grant. The Board of Directors, at its discretion can grant a non-standard vesting period which was the case in some prior year awards. RSUs vest automatically at the respective vesting dates and the holder will be issued the applicable number of shares as soon as possible thereafter. (iv) All salaries, bonuses and benefit payments have been expensed as incurred. (v) All bonuses were approved by the Board of Directors. Refer to Note 18: Share based payments for further information on the Restricted Share Units scheme.
Note 4.5: Board of Directors remuneration The remuneration of the members of the Board is determined on a yearly basis by the Company at its Annual General Meeting. The directors may also be reimbursed for, inter alia, travelling, hotel and other expenses incurred by them in attending meetings of the directors or in connection with the business of Panoro Energy ASA. A director who has been given a special assignment, besides his/her normal duties as a director of the Board, in relation to the business of Panoro Energy ASA may be paid such extra remuneration as the directors may determine. Remuneration to members of the Board of Directors is summarised below: 2024 Short term benefits USD 000 (unless stated otherwise) Directors remuneration Number of share options awarded in 2024 Fair value of share options expensed Julien Balkany (Chairman of the Board of Directors) 106 - 2 Torstein Sanness (Deputy Chairman of the Board of Directors) 76 - 1 Alexandra Herger 66 - 1 Garrett Soden 69 - 1 Gunnvor Ellingsen 69 - 8 Former directors * - - 7 Total 386 - 20 2023 Short term benefits USD 000 (unless stated otherwise) Directors remuneration Number of share options awarded in 2023 Fair value of share options expensed Julien Balkany (Chairman of the Board of Directors) 106 - 9 Torstein Sanness (Deputy Chairman of the Board of Directors) 74 - 5 Grace Reksten Skaugen (stepped down during the year) 25 - 11 Alexandra Herger 66 - 5 Hilde \u00c5dland (stepped down during the year) 24 - 6 Garrett Soden 67 - 5 Gunnvor Ellingsen 43 24,000 6 Total 405 24,000 47 * Fair value of share options expensed during the year relate to former directors Grace Reksten Skaugen and Hilde \u00c5dland. The Chairman of the Board of Directors\u2019 annual remuneration is USD 88,000 and the annual remuneration for the Deputy Chairman of the Board is USD 55,000. The remaining Directors\u2019 annual remuneration is USD 48,000. Members of the Audit Committee, the Remuneration Committee and the Sustainability Committee each receive USD 6,000 annually per committee, whereas the Chairman of each committee receives USD 9,000 annually. No loans have been given to, or guarantees given on the behalf of, any members of the Management Group, the Board or other elected corporate bodies.
Note 4.6: Pension plan The Company is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension (\u201cLov om obligatorisk tjenestepensjon\u201d). The Company contributes to an external defined contribution scheme and therefore no pension liability is recognised in the statement of financial position. As of 31 December 2024, the Company had no employees at parent company level and this pension plan is no longer in operation (31 December 2023: Nil). In the UK, the Company\u2019s subsidiary that employs staff, contributes a fixed amount per Company policy in an external defined contribution scheme. As such, no pension liability is recognised in the statement of financial position in relation to the Company\u2019s London based employees. No occupational pension scheme is mandated in Tunisia. Companies are required to pay a fixed percentage of gross salary of each employee as \u201csocial security\u201d to the government authorities, in addition to a fixed deduction from gross monthly salary as employee contribution. As such, no pension liability is recognised in the statement of financial position for these deductions. For contributions made to the external defined scheme 2024 and 2023, refer to Note 4.2:
Employee benefit expenses
.
Note 4.7: Auditors\u2019 remuneration Fees, excluding VAT, to the auditors are included in general and administrative expense and are shown below: USD 000 2024 2023 Ernst & Young Statutory Audit 291 272 Total Audit Services 291 272 Non-audit Services - - Total 291 272
NOTE 4: OPERATING RESULT Operating profit is stated after charging: USD 000 Note 2024 2023 Employee benefits expense 6,387 6,067 Depreciation 8, 9 54,329 39,687 Acquisition and project related costs (i) 223 811 (i) Acquisition and project related costs relate to business development activities.
Note 4.1: Exploration related costs Exploration costs written off amounting to USD 0.5 million relate to the expiry of SOEP at the end of 2024. Non-capitalisable exploration costs of USD 0.4 million was incurred during 2023. The Company was awarded a 56% participating interest (70% cost bearing) and operatorship of Block EG-01, offshore Equatorial Guinea and farmed-in to the Kosmos Energy operated Block S offshore Equatorial Guinea with a 12% non-operated interest. Costs incurred on these new interests are capitalised as exploration assets.
Note 4.2: Employee benefit expenses General and administrative expenses include wages, employer\u2019s contribution and other compensation as detailed below: USD 000 2024 2023 Salaries 5,191 4,843 Employers' contribution 640 640 Pension costs 335 280 Other compensation 221 304 Total 6,387 6,067 The number of employees in the Group as at year end is detailed below: 2024 2023 Number of employees 29 24 The number of employees does not include temporary contract staff and personnel employed by joint ventures where the group is participating as non-operated partner.
Note 4.3: Board of Directors statement on remuneration of executives Statement for the current year (2024) In accordance with the Norwegian Public Limited Liability Companies Act \u00a76-16a, the Board of Directors must prepare a statement on remuneration of executives. These statements can be referred to on page 97 of this report. Note 4.4: Management remuneration Executive management consists of the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO) as described below. Executive management remuneration is summarised below: 2024 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2024 Fair value of RSUs expensed John Hamilton, CEO 603 198 10 13 824 189,615 563 Qazi Qadeer, CFO 393 130 5 13 541 93,509 273 Total 996 328 15 26 1,365 283,124 836 2023 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2023 Fair value of RSUs expensed John Hamilton, CEO 534 187 12 11 744 195,419 527 Qazi Qadeer, CFO 348 123 5 11 487 96,371 239 Total 882 310 17 22 1,231 291,790 766 (i) Under the terms of employment, the CEO and the CFO in general are required to give at least six month\u2019s written notice prior to leaving Panoro. (ii) Per the respective terms of employment, the CEO is entitled to 12 months of base salary in the event of a change of control; whereby a tender offer is made or consummated for the ownership of more than 50% or more of the outstanding voting securities of the Company; or the Company is merged or consolidated with another corporation and as a result of such merger or consolidation less than 50.1% of the outstanding voting securities of the surviving entity or resulting corporation are owned in the aggregate by the persons, by the entities or persons who were shareholders of the Company immediately prior to such merger or consolidation; or the Company sells substantially all of its assets to another corporation that is not a wholly owned subsidiary. The CFO is entitled to 6 months of base salary in the event of a change of control. (iii) In June 2024, 640,032 Restricted Share Units were awarded under and in accordance with the Company\u2019s RSU scheme to the employees of the Company under the long-term incentive compensation plan approved by the shareholders. One Restricted Share Unit (\u201cRSU\u201d) entitles the holder to receive one share of capital stock of the Company against payment in cash of the par value for the share. The par value is currently NOK 0.05 per share. Vesting of the RSUs is time based, where 1/3 of the RSUs vest after one year, 1/3 vest after 2 years, and the final 1/3 vest after 3 years from grant. The Board of Directors, at its discretion can grant a non-standard vesting period which was the case in some prior year awards. RSUs vest automatically at the respective vesting dates and the holder will be issued the applicable number of shares as soon as possible thereafter. (iv) All salaries, bonuses and benefit payments have been expensed as incurred. (v) All bonuses were approved by the Board of Directors. Refer to Note 18: Share based payments for further information on the Restricted Share Units scheme.
Note 4.5: Board of Directors remuneration The remuneration of the members of the Board is determined on a yearly basis by the Company at its Annual General Meeting. The directors may also be reimbursed for, inter alia, travelling, hotel and other expenses incurred by them in attending meetings of the directors or in connection with the business of Panoro Energy ASA. A director who has been given a special assignment, besides his/her normal duties as a director of the Board, in relation to the business of Panoro Energy ASA may be paid such extra remuneration as the directors may determine. Remuneration to members of the Board of Directors is summarised below: 2024 Short term benefits USD 000 (unless stated otherwise) Directors remuneration Number of share options awarded in 2024 Fair value of share options expensed Julien Balkany (Chairman of the Board of Directors) 106 - 2 Torstein Sanness (Deputy Chairman of the Board of Directors) 76 - 1 Alexandra Herger 66 - 1 Garrett Soden 69 - 1 Gunnvor Ellingsen 69 - 8 Former directors * - - 7 Total 386 - 20 2023 Short term benefits USD 000 (unless stated otherwise) Directors remuneration Number of share options awarded in 2023 Fair value of share options expensed Julien Balkany (Chairman of the Board of Directors) 106 - 9 Torstein Sanness (Deputy Chairman of the Board of Directors) 74 - 5 Grace Reksten Skaugen (stepped down during the year) 25 - 11 Alexandra Herger 66 - 5 Hilde \u00c5dland (stepped down during the year) 24 - 6 Garrett Soden 67 - 5 Gunnvor Ellingsen 43 24,000 6 Total 405 24,000 47 * Fair value of share options expensed during the year relate to former directors Grace Reksten Skaugen and Hilde \u00c5dland. The Chairman of the Board of Directors\u2019 annual remuneration is USD 88,000 and the annual remuneration for the Deputy Chairman of the Board is USD 55,000. The remaining Directors\u2019 annual remuneration is USD 48,000. Members of the Audit Committee, the Remuneration Committee and the Sustainability Committee each receive USD 6,000 annually per committee, whereas the Chairman of each committee receives USD 9,000 annually. No loans have been given to, or guarantees given on the behalf of, any members of the Management Group, the Board or other elected corporate bodies.
Note 4.6: Pension plan The Company is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension (\u201cLov om obligatorisk tjenestepensjon\u201d). The Company contributes to an external defined contribution scheme and therefore no pension liability is recognised in the statement of financial position. As of 31 December 2024, the Company had no employees at parent company level and this pension plan is no longer in operation (31 December 2023: Nil). In the UK, the Company\u2019s subsidiary that employs staff, contributes a fixed amount per Company policy in an external defined contribution scheme. As such, no pension liability is recognised in the statement of financial position in relation to the Company\u2019s London based employees. No occupational pension scheme is mandated in Tunisia. Companies are required to pay a fixed percentage of gross salary of each employee as \u201csocial security\u201d to the government authorities, in addition to a fixed deduction from gross monthly salary as employee contribution. As such, no pension liability is recognised in the statement of financial position for these deductions. For contributions made to the external defined scheme 2024 and 2023, refer to Note 4.2:
Employee benefit expenses
.
Note 4.7: Auditors\u2019 remuneration Fees, excluding VAT, to the auditors are included in general and administrative expense and are shown below: USD 000 2024 2023 Ernst & Young Statutory Audit 291 272 Total Audit Services 291 272 Non-audit Services - - Total 291 272
Operating profit is stated after charging: USD 000 Note 2024 2023 Employee benefits expense 6,387 6,067 Depreciation 8, 9 54,329 39,687 Acquisition and project related costs (i) 223 811 (i) Acquisition and project related costs relate to business development activities.
Note 4.2: Employee benefit expenses General and administrative expenses include wages, employer\u2019s contribution and other compensation as detailed below: USD 000 2024 2023 Salaries 5,191 4,843 Employers' contribution 640 640 Pension costs 335 280 Other compensation 221 304 Total 6,387 6,067 The number of employees in the Group as at year end is detailed below: 2024 2023 Number of employees 29 24 The number of employees does not include temporary contract staff and personnel employed by joint ventures where the group is participating as non-operated partner.
",
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"concept": "ifrs-full:DisclosureOfExpensesByNatureExplanatory",
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"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-420": {
"value": "Note 4.1: Exploration related costs Exploration costs written off amounting to USD 0.5 million relate to the expiry of SOEP at the end of 2024. Non-capitalisable exploration costs of USD 0.4 million was incurred during 2023. The Company was awarded a 56% participating interest (70% cost bearing) and operatorship of Block EG-01, offshore Equatorial Guinea and farmed-in to the Kosmos Energy operated Block S offshore Equatorial Guinea with a 12% non-operated interest. Costs incurred on these new interests are capitalised as exploration assets.
Note 9.1: Licenses, Exploration and Evaluation Assets, Development Assets 2024 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2024 10,311 83,090 Additions 9,551 7,141 Transfer to Production Assets - (4,256) At 31 December 2024 19,862 85,975 Net carrying value at 31 December 2024 19,862 85,975 2023 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2023 2,595 122,823 Additions 5,960 27,742 Transfer to Production Assets - (69,460) Additions through Acquisition (Note 14) 1,756 1,985 At 31 December 2023 10,311 83,090 Net carrying value at 31 December 2023 10,311 83,090 Note 9.2: Production rights USD 000 2024 2023 Acquisition cost At 1 January 181,559 173,975 Depreciation charge for the year (19,296) (17,602) Additions through Acquisition (Note 14) - 25,160 Other additions 9 26 At 31 December 162,272 181,559
",
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"reg-ix-421": {
"value": "Note 4.2: Employee benefit expenses General and administrative expenses include wages, employer\u2019s contribution and other compensation as detailed below: USD 000 2024 2023 Salaries 5,191 4,843 Employers' contribution 640 640 Pension costs 335 280 Other compensation 221 304 Total 6,387 6,067 The number of employees in the Group as at year end is detailed below: 2024 2023 Number of employees 29 24 The number of employees does not include temporary contract staff and personnel employed by joint ventures where the group is participating as non-operated partner.
Note 4.3: Board of Directors statement on remuneration of executives Statement for the current year (2024) In accordance with the Norwegian Public Limited Liability Companies Act \u00a76-16a, the Board of Directors must prepare a statement on remuneration of executives. These statements can be referred to on page 97 of this report. Note 4.4: Management remuneration Executive management consists of the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO) as described below. Executive management remuneration is summarised below: 2024 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2024 Fair value of RSUs expensed John Hamilton, CEO 603 198 10 13 824 189,615 563 Qazi Qadeer, CFO 393 130 5 13 541 93,509 273 Total 996 328 15 26 1,365 283,124 836 2023 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2023 Fair value of RSUs expensed John Hamilton, CEO 534 187 12 11 744 195,419 527 Qazi Qadeer, CFO 348 123 5 11 487 96,371 239 Total 882 310 17 22 1,231 291,790 766 (i) Under the terms of employment, the CEO and the CFO in general are required to give at least six month\u2019s written notice prior to leaving Panoro. (ii) Per the respective terms of employment, the CEO is entitled to 12 months of base salary in the event of a change of control; whereby a tender offer is made or consummated for the ownership of more than 50% or more of the outstanding voting securities of the Company; or the Company is merged or consolidated with another corporation and as a result of such merger or consolidation less than 50.1% of the outstanding voting securities of the surviving entity or resulting corporation are owned in the aggregate by the persons, by the entities or persons who were shareholders of the Company immediately prior to such merger or consolidation; or the Company sells substantially all of its assets to another corporation that is not a wholly owned subsidiary. The CFO is entitled to 6 months of base salary in the event of a change of control. (iii) In June 2024, 640,032 Restricted Share Units were awarded under and in accordance with the Company\u2019s RSU scheme to the employees of the Company under the long-term incentive compensation plan approved by the shareholders. One Restricted Share Unit (\u201cRSU\u201d) entitles the holder to receive one share of capital stock of the Company against payment in cash of the par value for the share. The par value is currently NOK 0.05 per share. Vesting of the RSUs is time based, where 1/3 of the RSUs vest after one year, 1/3 vest after 2 years, and the final 1/3 vest after 3 years from grant. The Board of Directors, at its discretion can grant a non-standard vesting period which was the case in some prior year awards. RSUs vest automatically at the respective vesting dates and the holder will be issued the applicable number of shares as soon as possible thereafter. (iv) All salaries, bonuses and benefit payments have been expensed as incurred. (v) All bonuses were approved by the Board of Directors. Refer to Note 18: Share based payments for further information on the Restricted Share Units scheme.
Note 4.5: Board of Directors remuneration The remuneration of the members of the Board is determined on a yearly basis by the Company at its Annual General Meeting. The directors may also be reimbursed for, inter alia, travelling, hotel and other expenses incurred by them in attending meetings of the directors or in connection with the business of Panoro Energy ASA. A director who has been given a special assignment, besides his/her normal duties as a director of the Board, in relation to the business of Panoro Energy ASA may be paid such extra remuneration as the directors may determine. Remuneration to members of the Board of Directors is summarised below: 2024 Short term benefits USD 000 (unless stated otherwise) Directors remuneration Number of share options awarded in 2024 Fair value of share options expensed Julien Balkany (Chairman of the Board of Directors) 106 - 2 Torstein Sanness (Deputy Chairman of the Board of Directors) 76 - 1 Alexandra Herger 66 - 1 Garrett Soden 69 - 1 Gunnvor Ellingsen 69 - 8 Former directors * - - 7 Total 386 - 20 2023 Short term benefits USD 000 (unless stated otherwise) Directors remuneration Number of share options awarded in 2023 Fair value of share options expensed Julien Balkany (Chairman of the Board of Directors) 106 - 9 Torstein Sanness (Deputy Chairman of the Board of Directors) 74 - 5 Grace Reksten Skaugen (stepped down during the year) 25 - 11 Alexandra Herger 66 - 5 Hilde \u00c5dland (stepped down during the year) 24 - 6 Garrett Soden 67 - 5 Gunnvor Ellingsen 43 24,000 6 Total 405 24,000 47 * Fair value of share options expensed during the year relate to former directors Grace Reksten Skaugen and Hilde \u00c5dland. The Chairman of the Board of Directors\u2019 annual remuneration is USD 88,000 and the annual remuneration for the Deputy Chairman of the Board is USD 55,000. The remaining Directors\u2019 annual remuneration is USD 48,000. Members of the Audit Committee, the Remuneration Committee and the Sustainability Committee each receive USD 6,000 annually per committee, whereas the Chairman of each committee receives USD 9,000 annually. No loans have been given to, or guarantees given on the behalf of, any members of the Management Group, the Board or other elected corporate bodies.
Note 4.6: Pension plan The Company is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension (\u201cLov om obligatorisk tjenestepensjon\u201d). The Company contributes to an external defined contribution scheme and therefore no pension liability is recognised in the statement of financial position. As of 31 December 2024, the Company had no employees at parent company level and this pension plan is no longer in operation (31 December 2023: Nil). In the UK, the Company\u2019s subsidiary that employs staff, contributes a fixed amount per Company policy in an external defined contribution scheme. As such, no pension liability is recognised in the statement of financial position in relation to the Company\u2019s London based employees. No occupational pension scheme is mandated in Tunisia. Companies are required to pay a fixed percentage of gross salary of each employee as \u201csocial security\u201d to the government authorities, in addition to a fixed deduction from gross monthly salary as employee contribution. As such, no pension liability is recognised in the statement of financial position for these deductions. For contributions made to the external defined scheme 2024 and 2023, refer to Note 4.2:
Employee benefit expenses
",
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"concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory",
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"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
}
},
"reg-ix-422": {
"value": "Note 4.2: Employee benefit expenses General and administrative expenses include wages, employer\u2019s contribution and other compensation as detailed below: USD 000 2024 2023 Salaries 5,191 4,843 Employers' contribution 640 640 Pension costs 335 280 Other compensation 221 304 Total 6,387 6,067 The number of employees in the Group as at year end is detailed below: 2024 2023 Number of employees 29 24 The number of employees does not include temporary contract staff and personnel employed by joint ventures where the group is participating as non-operated partner.
Note 4.3: Board of Directors statement on remuneration of executives Statement for the current year (2024) In accordance with the Norwegian Public Limited Liability Companies Act \u00a76-16a, the Board of Directors must prepare a statement on remuneration of executives. These statements can be referred to on page 97 of this report. Note 4.2: Employee benefit expenses General and administrative expenses include wages, employer\u2019s contribution and other compensation as detailed below: USD 000 2024 2023 Salaries 5,191 4,843 Employers' contribution 640 640 Pension costs 335 280 Other compensation 221 304 Total 6,387 6,067 The number of employees in the Group as at year end is detailed below: 2024 2023 Number of employees 29 24 The number of employees does not include temporary contract staff and personnel employed by joint ventures where the group is participating as non-operated partner.
Note 4.3: Board of Directors statement on remuneration of executives Statement for the current year (2024) In accordance with the Norwegian Public Limited Liability Companies Act \u00a76-16a, the Board of Directors must prepare a statement on remuneration of executives. These statements can be referred to on page 97 of this report. Note 4.4: Management remuneration Executive management consists of the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO) as described below. Executive management remuneration is summarised below: 2024 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2024 Fair value of RSUs expensed John Hamilton, CEO 603 198 10 13 824 189,615 563 Qazi Qadeer, CFO 393 130 5 13 541 93,509 273 Total 996 328 15 26 1,365 283,124 836 2023 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2023 Fair value of RSUs expensed John Hamilton, CEO 534 187 12 11 744 195,419 527 Qazi Qadeer, CFO 348 123 5 11 487 96,371 239 Total 882 310 17 22 1,231 291,790 766 (i) Under the terms of employment, the CEO and the CFO in general are required to give at least six month\u2019s written notice prior to leaving Panoro. (ii) Per the respective terms of employment, the CEO is entitled to 12 months of base salary in the event of a change of control; whereby a tender offer is made or consummated for the ownership of more than 50% or more of the outstanding voting securities of the Company; or the Company is merged or consolidated with another corporation and as a result of such merger or consolidation less than 50.1% of the outstanding voting securities of the surviving entity or resulting corporation are owned in the aggregate by the persons, by the entities or persons who were shareholders of the Company immediately prior to such merger or consolidation; or the Company sells substantially all of its assets to another corporation that is not a wholly owned subsidiary. The CFO is entitled to 6 months of base salary in the event of a change of control. (iii) In June 2024, 640,032 Restricted Share Units were awarded under and in accordance with the Company\u2019s RSU scheme to the employees of the Company under the long-term incentive compensation plan approved by the shareholders. One Restricted Share Unit (\u201cRSU\u201d) entitles the holder to receive one share of capital stock of the Company against payment in cash of the par value for the share. The par value is currently NOK 0.05 per share. Vesting of the RSUs is time based, where 1/3 of the RSUs vest after one year, 1/3 vest after 2 years, and the final 1/3 vest after 3 years from grant. The Board of Directors, at its discretion can grant a non-standard vesting period which was the case in some prior year awards. RSUs vest automatically at the respective vesting dates and the holder will be issued the applicable number of shares as soon as possible thereafter. (iv) All salaries, bonuses and benefit payments have been expensed as incurred. (v) All bonuses were approved by the Board of Directors. Refer to Note 18: Share based payments for further information on the Restricted Share Units scheme.
Note 4.5: Board of Directors remuneration The remuneration of the members of the Board is determined on a yearly basis by the Company at its Annual General Meeting. The directors may also be reimbursed for, inter alia, travelling, hotel and other expenses incurred by them in attending meetings of the directors or in connection with the business of Panoro Energy ASA. A director who has been given a special assignment, besides his/her normal duties as a director of the Board, in relation to the business of Panoro Energy ASA may be paid such extra remuneration as the directors may determine. Remuneration to members of the Board of Directors is summarised below: 2024 Short term benefits USD 000 (unless stated otherwise) Directors remuneration Number of share options awarded in 2024 Fair value of share options expensed Julien Balkany (Chairman of the Board of Directors) 106 - 2 Torstein Sanness (Deputy Chairman of the Board of Directors) 76 - 1 Alexandra Herger 66 - 1 Garrett Soden 69 - 1 Gunnvor Ellingsen 69 - 8 Former directors * - - 7 Total 386 - 20 2023 Short term benefits USD 000 (unless stated otherwise) Directors remuneration Number of share options awarded in 2023 Fair value of share options expensed Julien Balkany (Chairman of the Board of Directors) 106 - 9 Torstein Sanness (Deputy Chairman of the Board of Directors) 74 - 5 Grace Reksten Skaugen (stepped down during the year) 25 - 11 Alexandra Herger 66 - 5 Hilde \u00c5dland (stepped down during the year) 24 - 6 Garrett Soden 67 - 5 Gunnvor Ellingsen 43 24,000 6 Total 405 24,000 47 * Fair value of share options expensed during the year relate to former directors Grace Reksten Skaugen and Hilde \u00c5dland. The Chairman of the Board of Directors\u2019 annual remuneration is USD 88,000 and the annual remuneration for the Deputy Chairman of the Board is USD 55,000. The remaining Directors\u2019 annual remuneration is USD 48,000. Members of the Audit Committee, the Remuneration Committee and the Sustainability Committee each receive USD 6,000 annually per committee, whereas the Chairman of each committee receives USD 9,000 annually. No loans have been given to, or guarantees given on the behalf of, any members of the Management Group, the Board or other elected corporate bodies.
Note 4.6: Pension plan The Company is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension (\u201cLov om obligatorisk tjenestepensjon\u201d). The Company contributes to an external defined contribution scheme and therefore no pension liability is recognised in the statement of financial position. As of 31 December 2024, the Company had no employees at parent company level and this pension plan is no longer in operation (31 December 2023: Nil). In the UK, the Company\u2019s subsidiary that employs staff, contributes a fixed amount per Company policy in an external defined contribution scheme. As such, no pension liability is recognised in the statement of financial position in relation to the Company\u2019s London based employees. No occupational pension scheme is mandated in Tunisia. Companies are required to pay a fixed percentage of gross salary of each employee as \u201csocial security\u201d to the government authorities, in addition to a fixed deduction from gross monthly salary as employee contribution. As such, no pension liability is recognised in the statement of financial position for these deductions. For contributions made to the external defined scheme 2024 and 2023, refer to Note 4.2:
Employee benefit expenses
.
Note 4.4: Management remuneration Executive management consists of the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO) as described below. Executive management remuneration is summarised below: 2024 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2024 Fair value of RSUs expensed John Hamilton, CEO 603 198 10 13 824 189,615 563 Qazi Qadeer, CFO 393 130 5 13 541 93,509 273 Total 996 328 15 26 1,365 283,124 836 2023 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2023 Fair value of RSUs expensed John Hamilton, CEO 534 187 12 11 744 195,419 527 Qazi Qadeer, CFO 348 123 5 11 487 96,371 239 Total 882 310 17 22 1,231 291,790 766 (i) Under the terms of employment, the CEO and the CFO in general are required to give at least six month\u2019s written notice prior to leaving Panoro. (ii) Per the respective terms of employment, the CEO is entitled to 12 months of base salary in the event of a change of control; whereby a tender offer is made or consummated for the ownership of more than 50% or more of the outstanding voting securities of the Company; or the Company is merged or consolidated with another corporation and as a result of such merger or consolidation less than 50.1% of the outstanding voting securities of the surviving entity or resulting corporation are owned in the aggregate by the persons, by the entities or persons who were shareholders of the Company immediately prior to such merger or consolidation; or the Company sells substantially all of its assets to another corporation that is not a wholly owned subsidiary. The CFO is entitled to 6 months of base salary in the event of a change of control. (iii) In June 2024, 640,032 Restricted Share Units were awarded under and in accordance with the Company\u2019s RSU scheme to the employees of the Company under the long-term incentive compensation plan approved by the shareholders. One Restricted Share Unit (\u201cRSU\u201d) entitles the holder to receive one share of capital stock of the Company against payment in cash of the par value for the share. The par value is currently NOK 0.05 per share. Vesting of the RSUs is time based, where 1/3 of the RSUs vest after one year, 1/3 vest after 2 years, and the final 1/3 vest after 3 years from grant. The Board of Directors, at its discretion can grant a non-standard vesting period which was the case in some prior year awards. RSUs vest automatically at the respective vesting dates and the holder will be issued the applicable number of shares as soon as possible thereafter. (iv) All salaries, bonuses and benefit payments have been expensed as incurred. (v) All bonuses were approved by the Board of Directors. Refer to Note 18: Share based payments for further information on the Restricted Share Units scheme.
Note 4.5: Board of Directors remuneration The remuneration of the members of the Board is determined on a yearly basis by the Company at its Annual General Meeting. The directors may also be reimbursed for, inter alia, travelling, hotel and other expenses incurred by them in attending meetings of the directors or in connection with the business of Panoro Energy ASA. A director who has been given a special assignment, besides his/her normal duties as a director of the Board, in relation to the business of Panoro Energy ASA may be paid such extra remuneration as the directors may determine. Remuneration to members of the Board of Directors is summarised below: 2024 Short term benefits USD 000 (unless stated otherwise) Directors remuneration Number of share options awarded in 2024 Fair value of share options expensed Julien Balkany (Chairman of the Board of Directors) 106 - 2 Torstein Sanness (Deputy Chairman of the Board of Directors) 76 - 1 Alexandra Herger 66 - 1 Garrett Soden 69 - 1 Gunnvor Ellingsen 69 - 8 Former directors * - - 7 Total 386 - 20 2023 Short term benefits USD 000 (unless stated otherwise) Directors remuneration Number of share options awarded in 2023 Fair value of share options expensed Julien Balkany (Chairman of the Board of Directors) 106 - 9 Torstein Sanness (Deputy Chairman of the Board of Directors) 74 - 5 Grace Reksten Skaugen (stepped down during the year) 25 - 11 Alexandra Herger 66 - 5 Hilde \u00c5dland (stepped down during the year) 24 - 6 Garrett Soden 67 - 5 Gunnvor Ellingsen 43 24,000 6 Total 405 24,000 47 * Fair value of share options expensed during the year relate to former directors Grace Reksten Skaugen and Hilde \u00c5dland. The Chairman of the Board of Directors\u2019 annual remuneration is USD 88,000 and the annual remuneration for the Deputy Chairman of the Board is USD 55,000. The remaining Directors\u2019 annual remuneration is USD 48,000. Members of the Audit Committee, the Remuneration Committee and the Sustainability Committee each receive USD 6,000 annually per committee, whereas the Chairman of each committee receives USD 9,000 annually. No loans have been given to, or guarantees given on the behalf of, any members of the Management Group, the Board or other elected corporate bodies.
NOTE 23: RELATED PARTIES TRANSACTIONS Details of related party transactions are set out in the parent stand-alone financial statements, Note 8: Related party transactions and balances.
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"reg-ix-425": {
"value": "Note 4.7: Auditors\u2019 remuneration Fees, excluding VAT, to the auditors are included in general and administrative expense and are shown below: USD 000 2024 2023 Ernst & Young Statutory Audit 291 272 Total Audit Services 291 272 Non-audit Services - - Total 291 272
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"reg-ix-426": {
"value": "NOTE 5: FINANCE, INTEREST AND OTHER INCOME AND EXPENSE P- USD 000 Note 2024 2023 Unrealised (gain)/loss on commodity hedges 20 - 133 Realised (gain)/loss on commodity hedges 20 315 595 Interest income from placements and deposits (143) (81) Interest expense - Loans and borrowings 16,630 11,604 Unrealised gain/loss on listed equity investments 12 - (75) Realised gain/loss on listed equity investments 12 - 101 Unrealised gain/loss on other investments 12 6 - Other financial costs - Bank charges and ARO unwinding 4,201 6,907 Total - Net (income) / expense 21,009 19,184
Note 5.1: Loans and borrowings Note 5.1.1 Senior Secured Bond Current and non-current portion of the outstanding balance of the Senior Secured Bond as of the date of the statement of financial position is as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-current Total Senior Secured Bond Principal outstanding - 150,000 150,000 - - - Accumulated interest accrued 854 - 854 - - - Unamortised borrowing costs (1,407) (3,512) (4,919) - - - (553) 146,488 145,935 - - - On 27 November 2024, the Company issued a 5-year Senior Secured Bond of USD 150 million at 99.2% of nominal value with a coupon rate of 10.25%. Proceeds of the bond issue were received on 19 December 2024 and used in part to fully repay the principal and accrued interest amount outstanding under the Senior Secured Borrowing Base facility. The Bond is repayable in three annual instalments of USD 25 million starting on 11 December 2026 with the final balance of USD 75 million to be settled on 11 December 2029. Interest is payable twice a year on 11 June and 11 December. Key financial covenants are required to be tested each quarter. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include the following:
(i) Leverage ratio (being total net debt to adjusted EBITDA as per defined bond terms) less than 2:1; and (ii) Liquidity of higher of USD 15 million or 10% of Total Debt. The Company was not in breach of any financial covenants as at 31 December 2024. Un-amortised borrowing costs include structuring fees and directly attributable third-party costs. These costs are expensed using an effective interest rate of 11.6% per annum over the remaining term of the facility. Note 5.1.2 Senior Secured Borrowing Base facility Current and non-current portion of the outstanding balance of the Senior Secured Borrowing Base facility as of the date of the statement of financial position is as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-current Total Senior Secured Borrowing Base facility Principal outstanding - - - 26,420 44,033 70,453 Accumulated interest accrued - - - - - - Unamortised borrowing costs - - - (349) (615) (964) - - - 26,071 43,418 69,489 On 29 March 2021, Panoro signed a fully underwritten acquisition finance loan facility of up to USD 90 million arranged by Trafigura, one of the world\u2019s leading independent commodity trading and logistics houses, with Mauritius Commercial Bank as mandated lead arranger and facility agent. The loan was made available in two tranches, Tranche A of up to USD 55 million which was drawn down in full on 30 March 2021 and Tranche B of up to USD 35 million which was drawn down in full on 9 June 2021. The drawn-down amount under the loan amortises over a 5 year term from 31 March 2021 and carries an annual interest rate of USD 3-month LIBOR plus 7.5%. On 18 April 2023, Panoro finalised an amendment to the Senior Secured Reserve Based Borrowing facility for an additional USD 15.3 million Tranche C funding against the Tunisian TPS assets, USD 15 million was drawn down on completion and the remaining USD 0.3 million utilised to cover arrangement fees. This additional tranche will amortise over the remaining period of the original loan ending on 30 March 2026. As part of the amendment, the annual interest rate for the entire facility was changed from 3-month LIBOR plus 7.5% to 3-month SOFR plus 7.5%. Panoro successfully concluded a redetermination of the facility during the first quarter, resulting in an increase to borrowing headroom and extension of facility duration by 24 months to 31 March 2028. As a result, the Company made a USD 10 million drawdown under the facility. A further amendment for an additional USD 20 million was agreed on 7 October and drawn down the next day, secured against the TPS, Block G and Dussafu assets. The interest rate for this tranche was 3-month SOFR plus 10.5% per annum. This facility was cancelled in December 2024 and repaid in full using a portion of the issue proceeds of the issue of the Senior Secured Bond in Note 5.1.1 Senior Secured Bond above. Key financial covenants were tested at 30 September and 31 March and included the following: (i) Group Net debt/EBITDA: \u22643.0 (ii) Minimum cash balance of USD 7.0 million to be maintained in the account of the Borrower (iii) Field life coverage ratio: 1.5x (iv) Loan life coverage ratio: 1.3x (v) Group Liquidity Test: 1.2x (Borrower and subsidiaries) Un-amortised borrowing costs included structuring fees and directly attributable third-party costs. These costs were expensed using an effective interest rate of 16.7% per annum at the repayment date and the remaining balance of USD 1.6 million was written off to the income statement at that time. The Group has an advance facility of USD 25 million with Trafigura. At 31 December 2024 there were no amounts owing under this facility (31 December: USD 23.8 million). The advance is short term and settled from the upcoming crude liftings proceeds.
Note 5.2: Changes in liabilities with cash flow movements from Financing Activities The changes in liabilities whose cash flow movements are disclosed as part of financing activities in the cash flow statement are as follows: USD 000 2024 2023 At 1 January 69,819 79,625 Cash flows: Drawdown of Secured Loans, net of fees 180,000 15,000 Repayment of Secured Loans (100,627) (25,450) Repayment of non-recourse loan - (653) Realised gain/(loss) on commodity hedges (315) - Borrowing costs, including arrangement fees (14,963) (10,382) Lease liability payments (240) (230) Non-cash changes: Unwinding of unamortised borrowing cost and finance charges 1,628 1,701 Interest accrued 10,435 9,973 Movement in unrealised hedges 315 - Initial recognition lease under IFRS 16 - 377 Foreign exchange movements - (141) At 31 December 146,052 69,820
NOTE 5: FINANCE, INTEREST AND OTHER INCOME AND EXPENSE P- USD 000 Note 2024 2023 Unrealised (gain)/loss on commodity hedges 20 - 133 Realised (gain)/loss on commodity hedges 20 315 595 Interest income from placements and deposits (143) (81) Interest expense - Loans and borrowings 16,630 11,604 Unrealised gain/loss on listed equity investments 12 - (75) Realised gain/loss on listed equity investments 12 - 101 Unrealised gain/loss on other investments 12 6 - Other financial costs - Bank charges and ARO unwinding 4,201 6,907 Total - Net (income) / expense 21,009 19,184
Note 5.1: Loans and borrowings Note 5.1.1 Senior Secured Bond Current and non-current portion of the outstanding balance of the Senior Secured Bond as of the date of the statement of financial position is as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-current Total Senior Secured Bond Principal outstanding - 150,000 150,000 - - - Accumulated interest accrued 854 - 854 - - - Unamortised borrowing costs (1,407) (3,512) (4,919) - - - (553) 146,488 145,935 - - - On 27 November 2024, the Company issued a 5-year Senior Secured Bond of USD 150 million at 99.2% of nominal value with a coupon rate of 10.25%. Proceeds of the bond issue were received on 19 December 2024 and used in part to fully repay the principal and accrued interest amount outstanding under the Senior Secured Borrowing Base facility. The Bond is repayable in three annual instalments of USD 25 million starting on 11 December 2026 with the final balance of USD 75 million to be settled on 11 December 2029. Interest is payable twice a year on 11 June and 11 December. Key financial covenants are required to be tested each quarter. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include the following:
(i) Leverage ratio (being total net debt to adjusted EBITDA as per defined bond terms) less than 2:1; and (ii) Liquidity of higher of USD 15 million or 10% of Total Debt. The Company was not in breach of any financial covenants as at 31 December 2024. Un-amortised borrowing costs include structuring fees and directly attributable third-party costs. These costs are expensed using an effective interest rate of 11.6% per annum over the remaining term of the facility. Note 5.1.2 Senior Secured Borrowing Base facility Current and non-current portion of the outstanding balance of the Senior Secured Borrowing Base facility as of the date of the statement of financial position is as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-current Total Senior Secured Borrowing Base facility Principal outstanding - - - 26,420 44,033 70,453 Accumulated interest accrued - - - - - - Unamortised borrowing costs - - - (349) (615) (964) - - - 26,071 43,418 69,489 On 29 March 2021, Panoro signed a fully underwritten acquisition finance loan facility of up to USD 90 million arranged by Trafigura, one of the world\u2019s leading independent commodity trading and logistics houses, with Mauritius Commercial Bank as mandated lead arranger and facility agent. The loan was made available in two tranches, Tranche A of up to USD 55 million which was drawn down in full on 30 March 2021 and Tranche B of up to USD 35 million which was drawn down in full on 9 June 2021. The drawn-down amount under the loan amortises over a 5 year term from 31 March 2021 and carries an annual interest rate of USD 3-month LIBOR plus 7.5%. On 18 April 2023, Panoro finalised an amendment to the Senior Secured Reserve Based Borrowing facility for an additional USD 15.3 million Tranche C funding against the Tunisian TPS assets, USD 15 million was drawn down on completion and the remaining USD 0.3 million utilised to cover arrangement fees. This additional tranche will amortise over the remaining period of the original loan ending on 30 March 2026. As part of the amendment, the annual interest rate for the entire facility was changed from 3-month LIBOR plus 7.5% to 3-month SOFR plus 7.5%. Panoro successfully concluded a redetermination of the facility during the first quarter, resulting in an increase to borrowing headroom and extension of facility duration by 24 months to 31 March 2028. As a result, the Company made a USD 10 million drawdown under the facility. A further amendment for an additional USD 20 million was agreed on 7 October and drawn down the next day, secured against the TPS, Block G and Dussafu assets. The interest rate for this tranche was 3-month SOFR plus 10.5% per annum. This facility was cancelled in December 2024 and repaid in full using a portion of the issue proceeds of the issue of the Senior Secured Bond in Note 5.1.1 Senior Secured Bond above. Key financial covenants were tested at 30 September and 31 March and included the following: (i) Group Net debt/EBITDA: \u22643.0 (ii) Minimum cash balance of USD 7.0 million to be maintained in the account of the Borrower (iii) Field life coverage ratio: 1.5x (iv) Loan life coverage ratio: 1.3x (v) Group Liquidity Test: 1.2x (Borrower and subsidiaries) Un-amortised borrowing costs included structuring fees and directly attributable third-party costs. These costs were expensed using an effective interest rate of 16.7% per annum at the repayment date and the remaining balance of USD 1.6 million was written off to the income statement at that time. The Group has an advance facility of USD 25 million with Trafigura. At 31 December 2024 there were no amounts owing under this facility (31 December: USD 23.8 million). The advance is short term and settled from the upcoming crude liftings proceeds.
Note 5.2: Changes in liabilities with cash flow movements from Financing Activities The changes in liabilities whose cash flow movements are disclosed as part of financing activities in the cash flow statement are as follows: USD 000 2024 2023 At 1 January 69,819 79,625 Cash flows: Drawdown of Secured Loans, net of fees 180,000 15,000 Repayment of Secured Loans (100,627) (25,450) Repayment of non-recourse loan - (653) Realised gain/(loss) on commodity hedges (315) - Borrowing costs, including arrangement fees (14,963) (10,382) Lease liability payments (240) (230) Non-cash changes: Unwinding of unamortised borrowing cost and finance charges 1,628 1,701 Interest accrued 10,435 9,973 Movement in unrealised hedges 315 - Initial recognition lease under IFRS 16 - 377 Foreign exchange movements - (141) At 31 December 146,052 69,820
NOTE 5: FINANCE, INTEREST AND OTHER INCOME AND EXPENSE P- USD 000 Note 2024 2023 Unrealised (gain)/loss on commodity hedges 20 - 133 Realised (gain)/loss on commodity hedges 20 315 595 Interest income from placements and deposits (143) (81) Interest expense - Loans and borrowings 16,630 11,604 Unrealised gain/loss on listed equity investments 12 - (75) Realised gain/loss on listed equity investments 12 - 101 Unrealised gain/loss on other investments 12 6 - Other financial costs - Bank charges and ARO unwinding 4,201 6,907 Total - Net (income) / expense 21,009 19,184
Note 5.1: Loans and borrowings Note 5.1.1 Senior Secured Bond Current and non-current portion of the outstanding balance of the Senior Secured Bond as of the date of the statement of financial position is as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-current Total Senior Secured Bond Principal outstanding - 150,000 150,000 - - - Accumulated interest accrued 854 - 854 - - - Unamortised borrowing costs (1,407) (3,512) (4,919) - - - (553) 146,488 145,935 - - - On 27 November 2024, the Company issued a 5-year Senior Secured Bond of USD 150 million at 99.2% of nominal value with a coupon rate of 10.25%. Proceeds of the bond issue were received on 19 December 2024 and used in part to fully repay the principal and accrued interest amount outstanding under the Senior Secured Borrowing Base facility. The Bond is repayable in three annual instalments of USD 25 million starting on 11 December 2026 with the final balance of USD 75 million to be settled on 11 December 2029. Interest is payable twice a year on 11 June and 11 December. Key financial covenants are required to be tested each quarter. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include the following:
(i) Leverage ratio (being total net debt to adjusted EBITDA as per defined bond terms) less than 2:1; and (ii) Liquidity of higher of USD 15 million or 10% of Total Debt. The Company was not in breach of any financial covenants as at 31 December 2024. Un-amortised borrowing costs include structuring fees and directly attributable third-party costs. These costs are expensed using an effective interest rate of 11.6% per annum over the remaining term of the facility. Note 5.1.2 Senior Secured Borrowing Base facility Current and non-current portion of the outstanding balance of the Senior Secured Borrowing Base facility as of the date of the statement of financial position is as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-current Total Senior Secured Borrowing Base facility Principal outstanding - - - 26,420 44,033 70,453 Accumulated interest accrued - - - - - - Unamortised borrowing costs - - - (349) (615) (964) - - - 26,071 43,418 69,489 On 29 March 2021, Panoro signed a fully underwritten acquisition finance loan facility of up to USD 90 million arranged by Trafigura, one of the world\u2019s leading independent commodity trading and logistics houses, with Mauritius Commercial Bank as mandated lead arranger and facility agent. The loan was made available in two tranches, Tranche A of up to USD 55 million which was drawn down in full on 30 March 2021 and Tranche B of up to USD 35 million which was drawn down in full on 9 June 2021. The drawn-down amount under the loan amortises over a 5 year term from 31 March 2021 and carries an annual interest rate of USD 3-month LIBOR plus 7.5%. On 18 April 2023, Panoro finalised an amendment to the Senior Secured Reserve Based Borrowing facility for an additional USD 15.3 million Tranche C funding against the Tunisian TPS assets, USD 15 million was drawn down on completion and the remaining USD 0.3 million utilised to cover arrangement fees. This additional tranche will amortise over the remaining period of the original loan ending on 30 March 2026. As part of the amendment, the annual interest rate for the entire facility was changed from 3-month LIBOR plus 7.5% to 3-month SOFR plus 7.5%. Panoro successfully concluded a redetermination of the facility during the first quarter, resulting in an increase to borrowing headroom and extension of facility duration by 24 months to 31 March 2028. As a result, the Company made a USD 10 million drawdown under the facility. A further amendment for an additional USD 20 million was agreed on 7 October and drawn down the next day, secured against the TPS, Block G and Dussafu assets. The interest rate for this tranche was 3-month SOFR plus 10.5% per annum. This facility was cancelled in December 2024 and repaid in full using a portion of the issue proceeds of the issue of the Senior Secured Bond in Note 5.1.1 Senior Secured Bond above. Key financial covenants were tested at 30 September and 31 March and included the following: (i) Group Net debt/EBITDA: \u22643.0 (ii) Minimum cash balance of USD 7.0 million to be maintained in the account of the Borrower (iii) Field life coverage ratio: 1.5x (iv) Loan life coverage ratio: 1.3x (v) Group Liquidity Test: 1.2x (Borrower and subsidiaries) Un-amortised borrowing costs included structuring fees and directly attributable third-party costs. These costs were expensed using an effective interest rate of 16.7% per annum at the repayment date and the remaining balance of USD 1.6 million was written off to the income statement at that time. The Group has an advance facility of USD 25 million with Trafigura. At 31 December 2024 there were no amounts owing under this facility (31 December: USD 23.8 million). The advance is short term and settled from the upcoming crude liftings proceeds.
Note 5.2: Changes in liabilities with cash flow movements from Financing Activities The changes in liabilities whose cash flow movements are disclosed as part of financing activities in the cash flow statement are as follows: USD 000 2024 2023 At 1 January 69,819 79,625 Cash flows: Drawdown of Secured Loans, net of fees 180,000 15,000 Repayment of Secured Loans (100,627) (25,450) Repayment of non-recourse loan - (653) Realised gain/(loss) on commodity hedges (315) - Borrowing costs, including arrangement fees (14,963) (10,382) Lease liability payments (240) (230) Non-cash changes: Unwinding of unamortised borrowing cost and finance charges 1,628 1,701 Interest accrued 10,435 9,973 Movement in unrealised hedges 315 - Initial recognition lease under IFRS 16 - 377 Foreign exchange movements - (141) At 31 December 146,052 69,820
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"value": "NOTE 5: FINANCE, INTEREST AND OTHER INCOME AND EXPENSE P- USD 000 Note 2024 2023 Unrealised (gain)/loss on commodity hedges 20 - 133 Realised (gain)/loss on commodity hedges 20 315 595 Interest income from placements and deposits (143) (81) Interest expense - Loans and borrowings 16,630 11,604 Unrealised gain/loss on listed equity investments 12 - (75) Realised gain/loss on listed equity investments 12 - 101 Unrealised gain/loss on other investments 12 6 - Other financial costs - Bank charges and ARO unwinding 4,201 6,907 Total - Net (income) / expense 21,009 19,184
NOTE 5: FINANCE, INTEREST AND OTHER INCOME AND EXPENSE P- USD 000 Note 2024 2023 Unrealised (gain)/loss on commodity hedges 20 - 133 Realised (gain)/loss on commodity hedges 20 315 595 Interest income from placements and deposits (143) (81) Interest expense - Loans and borrowings 16,630 11,604 Unrealised gain/loss on listed equity investments 12 - (75) Realised gain/loss on listed equity investments 12 - 101 Unrealised gain/loss on other investments 12 6 - Other financial costs - Bank charges and ARO unwinding 4,201 6,907 Total - Net (income) / expense 21,009 19,184
NOTE 5: FINANCE, INTEREST AND OTHER INCOME AND EXPENSE P- USD 000 Note 2024 2023 Unrealised (gain)/loss on commodity hedges 20 - 133 Realised (gain)/loss on commodity hedges 20 315 595 Interest income from placements and deposits (143) (81) Interest expense - Loans and borrowings 16,630 11,604 Unrealised gain/loss on listed equity investments 12 - (75) Realised gain/loss on listed equity investments 12 - 101 Unrealised gain/loss on other investments 12 6 - Other financial costs - Bank charges and ARO unwinding 4,201 6,907 Total - Net (income) / expense 21,009 19,184
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"value": "Note 5.1: Loans and borrowings Note 5.1.1 Senior Secured Bond Current and non-current portion of the outstanding balance of the Senior Secured Bond as of the date of the statement of financial position is as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-current Total Senior Secured Bond Principal outstanding - 150,000 150,000 - - - Accumulated interest accrued 854 - 854 - - - Unamortised borrowing costs (1,407) (3,512) (4,919) - - - (553) 146,488 145,935 - - - On 27 November 2024, the Company issued a 5-year Senior Secured Bond of USD 150 million at 99.2% of nominal value with a coupon rate of 10.25%. Proceeds of the bond issue were received on 19 December 2024 and used in part to fully repay the principal and accrued interest amount outstanding under the Senior Secured Borrowing Base facility. The Bond is repayable in three annual instalments of USD 25 million starting on 11 December 2026 with the final balance of USD 75 million to be settled on 11 December 2029. Interest is payable twice a year on 11 June and 11 December. Key financial covenants are required to be tested each quarter. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include the following:
(i) Leverage ratio (being total net debt to adjusted EBITDA as per defined bond terms) less than 2:1; and (ii) Liquidity of higher of USD 15 million or 10% of Total Debt. The Company was not in breach of any financial covenants as at 31 December 2024. Un-amortised borrowing costs include structuring fees and directly attributable third-party costs. These costs are expensed using an effective interest rate of 11.6% per annum over the remaining term of the facility. Note 5.1.2 Senior Secured Borrowing Base facility Current and non-current portion of the outstanding balance of the Senior Secured Borrowing Base facility as of the date of the statement of financial position is as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-current Total Senior Secured Borrowing Base facility Principal outstanding - - - 26,420 44,033 70,453 Accumulated interest accrued - - - - - - Unamortised borrowing costs - - - (349) (615) (964) - - - 26,071 43,418 69,489 On 29 March 2021, Panoro signed a fully underwritten acquisition finance loan facility of up to USD 90 million arranged by Trafigura, one of the world\u2019s leading independent commodity trading and logistics houses, with Mauritius Commercial Bank as mandated lead arranger and facility agent. The loan was made available in two tranches, Tranche A of up to USD 55 million which was drawn down in full on 30 March 2021 and Tranche B of up to USD 35 million which was drawn down in full on 9 June 2021. The drawn-down amount under the loan amortises over a 5 year term from 31 March 2021 and carries an annual interest rate of USD 3-month LIBOR plus 7.5%. On 18 April 2023, Panoro finalised an amendment to the Senior Secured Reserve Based Borrowing facility for an additional USD 15.3 million Tranche C funding against the Tunisian TPS assets, USD 15 million was drawn down on completion and the remaining USD 0.3 million utilised to cover arrangement fees. This additional tranche will amortise over the remaining period of the original loan ending on 30 March 2026. As part of the amendment, the annual interest rate for the entire facility was changed from 3-month LIBOR plus 7.5% to 3-month SOFR plus 7.5%. Panoro successfully concluded a redetermination of the facility during the first quarter, resulting in an increase to borrowing headroom and extension of facility duration by 24 months to 31 March 2028. As a result, the Company made a USD 10 million drawdown under the facility. A further amendment for an additional USD 20 million was agreed on 7 October and drawn down the next day, secured against the TPS, Block G and Dussafu assets. The interest rate for this tranche was 3-month SOFR plus 10.5% per annum. This facility was cancelled in December 2024 and repaid in full using a portion of the issue proceeds of the issue of the Senior Secured Bond in Note 5.1.1 Senior Secured Bond above. Key financial covenants were tested at 30 September and 31 March and included the following: (i) Group Net debt/EBITDA: \u22643.0 (ii) Minimum cash balance of USD 7.0 million to be maintained in the account of the Borrower (iii) Field life coverage ratio: 1.5x (iv) Loan life coverage ratio: 1.3x (v) Group Liquidity Test: 1.2x (Borrower and subsidiaries) Un-amortised borrowing costs included structuring fees and directly attributable third-party costs. These costs were expensed using an effective interest rate of 16.7% per annum at the repayment date and the remaining balance of USD 1.6 million was written off to the income statement at that time. The Group has an advance facility of USD 25 million with Trafigura. At 31 December 2024 there were no amounts owing under this facility (31 December: USD 23.8 million). The advance is short term and settled from the upcoming crude liftings proceeds.
",
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"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
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},
"reg-ix-433": {
"value": "Note 5.2: Changes in liabilities with cash flow movements from Financing Activities The changes in liabilities whose cash flow movements are disclosed as part of financing activities in the cash flow statement are as follows: USD 000 2024 2023 At 1 January 69,819 79,625 Cash flows: Drawdown of Secured Loans, net of fees 180,000 15,000 Repayment of Secured Loans (100,627) (25,450) Repayment of non-recourse loan - (653) Realised gain/(loss) on commodity hedges (315) - Borrowing costs, including arrangement fees (14,963) (10,382) Lease liability payments (240) (230) Non-cash changes: Unwinding of unamortised borrowing cost and finance charges 1,628 1,701 Interest accrued 10,435 9,973 Movement in unrealised hedges 315 - Initial recognition lease under IFRS 16 - 377 Foreign exchange movements - (141) At 31 December 146,052 69,820
NOTE 6: LICENCE AND CONTINGENT OBLIGATIONS Licence obligations and contingent obligations were acquired by the Group as part of the acquisition of the Tunisian operations from DNO ASA in July 2018 and consist of provisions for deferred consideration and licence obligations as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-Current Total Deferred consideration - 30 30 - 6,827 6,827 Licence obligations 5,444 - 5,444 1,944 - 1,944 5,444 30 5,474 1,944 6,827 8,771 Deferred consideration represents the fair value of potential future payments to DNO ASA which may become payable once oil is produced from the Sfax Offshore Exploration Permit. This estimate has been determined using probabilistic outcome of the potential recoverable volumes. The total liability, in any event, is capped at USD 13.2 million. Licence obligations represent liability recognised in connection with minimum work programs on the Hammamet permit of USD 1.9 million and Salloum Offshore Exploration Permit of USD 3.5 million. The change in the licence obligations is the result of the expiry of the Sfax Offshore Exploration Permit at the end of 2024 with near-term license obligations falling due within one year. Deferred consideration is no longer application following the relinquishment decision of Sfax Offshore Exploration Permit and has therefore been de-recognised.
NOTE 6: LICENCE AND CONTINGENT OBLIGATIONS Licence obligations and contingent obligations were acquired by the Group as part of the acquisition of the Tunisian operations from DNO ASA in July 2018 and consist of provisions for deferred consideration and licence obligations as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-Current Total Deferred consideration - 30 30 - 6,827 6,827 Licence obligations 5,444 - 5,444 1,944 - 1,944 5,444 30 5,474 1,944 6,827 8,771 Deferred consideration represents the fair value of potential future payments to DNO ASA which may become payable once oil is produced from the Sfax Offshore Exploration Permit. This estimate has been determined using probabilistic outcome of the potential recoverable volumes. The total liability, in any event, is capped at USD 13.2 million. Licence obligations represent liability recognised in connection with minimum work programs on the Hammamet permit of USD 1.9 million and Salloum Offshore Exploration Permit of USD 3.5 million. The change in the licence obligations is the result of the expiry of the Sfax Offshore Exploration Permit at the end of 2024 with near-term license obligations falling due within one year. Deferred consideration is no longer application following the relinquishment decision of Sfax Offshore Exploration Permit and has therefore been de-recognised.
NOTE 17: ACCOUNTS PAYABLE, ACCRUALS AND OTHER LIABILITIES USD 000 2024 2023 Accounts payable 28,583 25,543 Accrued and other liabilities 5,083 3,532 Other non-current liabilities 25,939 8,852 At 31 December 59,605 37,927
NOTE 6: LICENCE AND CONTINGENT OBLIGATIONS Licence obligations and contingent obligations were acquired by the Group as part of the acquisition of the Tunisian operations from DNO ASA in July 2018 and consist of provisions for deferred consideration and licence obligations as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-Current Total Deferred consideration - 30 30 - 6,827 6,827 Licence obligations 5,444 - 5,444 1,944 - 1,944 5,444 30 5,474 1,944 6,827 8,771 Deferred consideration represents the fair value of potential future payments to DNO ASA which may become payable once oil is produced from the Sfax Offshore Exploration Permit. This estimate has been determined using probabilistic outcome of the potential recoverable volumes. The total liability, in any event, is capped at USD 13.2 million. Licence obligations represent liability recognised in connection with minimum work programs on the Hammamet permit of USD 1.9 million and Salloum Offshore Exploration Permit of USD 3.5 million. The change in the licence obligations is the result of the expiry of the Sfax Offshore Exploration Permit at the end of 2024 with near-term license obligations falling due within one year. Deferred consideration is no longer application following the relinquishment decision of Sfax Offshore Exploration Permit and has therefore been de-recognised.
NOTE 17: ACCOUNTS PAYABLE, ACCRUALS AND OTHER LIABILITIES USD 000 2024 2023 Accounts payable 28,583 25,543 Accrued and other liabilities 5,083 3,532 Other non-current liabilities 25,939 8,852 At 31 December 59,605 37,927
NOTE 6: LICENCE AND CONTINGENT OBLIGATIONS Licence obligations and contingent obligations were acquired by the Group as part of the acquisition of the Tunisian operations from DNO ASA in July 2018 and consist of provisions for deferred consideration and licence obligations as follows: USD 000 31 December 2024 31 December 2023 Current Non-current Total Current Non-Current Total Deferred consideration - 30 30 - 6,827 6,827 Licence obligations 5,444 - 5,444 1,944 - 1,944 5,444 30 5,474 1,944 6,827 8,771 Deferred consideration represents the fair value of potential future payments to DNO ASA which may become payable once oil is produced from the Sfax Offshore Exploration Permit. This estimate has been determined using probabilistic outcome of the potential recoverable volumes. The total liability, in any event, is capped at USD 13.2 million. Licence obligations represent liability recognised in connection with minimum work programs on the Hammamet permit of USD 1.9 million and Salloum Offshore Exploration Permit of USD 3.5 million. The change in the licence obligations is the result of the expiry of the Sfax Offshore Exploration Permit at the end of 2024 with near-term license obligations falling due within one year. Deferred consideration is no longer application following the relinquishment decision of Sfax Offshore Exploration Permit and has therefore been de-recognised.
NOTE 17: ACCOUNTS PAYABLE, ACCRUALS AND OTHER LIABILITIES USD 000 2024 2023 Accounts payable 28,583 25,543 Accrued and other liabilities 5,083 3,532 Other non-current liabilities 25,939 8,852 At 31 December 59,605 37,927
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"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
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"reg-ix-438": {
"value": "NOTE 7: INCOME TAX Income tax The major components of income tax in the consolidated statement of comprehensive income related to continuing and discontinued operations were: USD 000 2024 2023 Income Taxes Current income tax (i) 13,527 13,730 PSC based Profit Oil allocation \u2013 current (ii) 17,057 10,885 PSC based income tax - current (iii) 750 17,027 Deferred tax expense / (benefit) (iv) (10,644) (528) Tax adjustments relating to prior years income (3,140) (149) Tax charge / (benefit) for the period 17,550 40,965 (i) Current income tax primarily comprises of tax on income from Tunisian operation. (ii) Under the terms of the Dussafu PSC, the estimated value of the State profit oil is reflected in other revenue, with a corresponding amount as income tax. See Note 3: Operating segments. (iii) PSC based income tax represents tax on income from Block G. See Note 3: Operating segments. (iv) Deferred tax liability recognised has arisen on temporary differences between tax base and accounting base of the production assets in Equatorial Guinea, Gabon and Tunisia and have been calculated using the effective tax rate applicable to the concessions. (v) Tax rates in Tunisia vary by permit and concession and ranges between 50% to 60% applicable to the respective concession\u2019s taxable income. A reconciliation of the income tax expense applicable to the accounting profit before tax at the statutory income tax rate to the expense at the Group\u2019s effective income tax rate is as follows: USD 000 2024 2023 Profit / (loss) before taxation 78,228 74,342 Tax calculated at Norwegian tax rate of 22% 17,169 18,553 Adjustments for local tax rates: Equatorial Guinea 2,503 6,527 Gabon 7,362 455 Tunisia 4,190 8,118 Other (37) 12 Tax calculated at domestic tax rates applicable to profits in the respective countries 31,187 33,665 Tax effect of expenses not deductible (13,196) (21,212) Deferred tax adjustment relating to change in tax rates (16,704) - PSC based Profit Oil allocation 17,057 27,912 Tax effect of losses not utilised in the period 2,346 749 Prior year adjustments (3,140) (149) Tax charge / (benefit) 17,550 40,965 Tax Liabilities Tax liabilities payable of USD 24.5 million as of 31 December 2024 comprised of taxes payable in Equatorial Guinea of USD 18.4 million and Tunisia of USD 5.9 million for production from various concessions and USD 0.2 million in the United Kingdom related to corporate activities (31 December 2023: USD 34.4 million comprised of taxes payable in Equatorial Guinea of USD 21.3 million and Tunisia of USD 13.1 million). Advantage was taken in Tunisia of incentives with a tax value of USD 14.8 million that require investment in government approved projects within four years. During the year, an investment of USD 0.4 million was made via CAPSA Capital Partners in FCPR SWING 3CAPSA, an approved Venture Capital Trust investing in eligible activities.
Deferred tax Deferred tax benefit of USD 10.6 million recognised during the year comprises USD 13.1 million charge in Equatorial Guinea and a USD 2.6 million benefit in Tunisia arising on taxable temporary differences between accounting and tax bases of property, plant and equipment. In addition, a reduction of deferred tax benefit of USD 16.7 million was recognised as a result of tax rates in Equatorial Guinea reducing from 35% to 25% effective from 1 January 2025. The deferred tax liability of USD 62.2 million as of 31 December 2024 is classified as non-current based on the current expectation of timing of such taxes. These are ring fenced against taxable income from the respective concessions in Equatorial Guinea, Gabon and Tunisia. There are no recognised deferred tax assets in the Group financial statements as of 31 December 2024 (31 December 2023: Nil). Deferred tax assets are recognised for tax losses carry-forwards to the extent that the realisation of the related tax benefits through future taxable profits is probable. The Group did not recognise deferred income tax assets of USD 10.1 million (2023: USD 7.3 million) in respect of losses that can be carried forward against future taxable income. The Group has provisional accumulated tax losses as of year-end that may be available to offset against future taxable income; all losses are available indefinitely and have been included in the table below. USD 000 2024 2023 Panoro Energy ASA 12,722 - Panoro Energy 2B Limited 450 922 Panoro Gabon Exploration Limited 37 11 Sfax Petroleum Corporation 32,373 32,455 Total 45,582 33,388
Deferred tax Deferred tax benefit of USD 10.6 million recognised during the year comprises USD 13.1 million charge in Equatorial Guinea and a USD 2.6 million benefit in Tunisia arising on taxable temporary differences between accounting and tax bases of property, plant and equipment. In addition, a reduction of deferred tax benefit of USD 16.7 million was recognised as a result of tax rates in Equatorial Guinea reducing from 35% to 25% effective from 1 January 2025. The deferred tax liability of USD 62.2 million as of 31 December 2024 is classified as non-current based on the current expectation of timing of such taxes. These are ring fenced against taxable income from the respective concessions in Equatorial Guinea, Gabon and Tunisia. There are no recognised deferred tax assets in the Group financial statements as of 31 December 2024 (31 December 2023: Nil). Deferred tax assets are recognised for tax losses carry-forwards to the extent that the realisation of the related tax benefits through future taxable profits is probable. The Group did not recognise deferred income tax assets of USD 10.1 million (2023: USD 7.3 million) in respect of losses that can be carried forward against future taxable income. The Group has provisional accumulated tax losses as of year-end that may be available to offset against future taxable income; all losses are available indefinitely and have been included in the table below. USD 000 2024 2023 Panoro Energy ASA 12,722 - Panoro Energy 2B Limited 450 922 Panoro Gabon Exploration Limited 37 11 Sfax Petroleum Corporation 32,373 32,455 Total 45,582 33,388
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"reg-ix-440": {
"value": "NOTE 8: BASIC AND DILUTED EARNINGS PER SHARE Basic earnings or loss per ordinary share amounts are calculated using net profit or loss for the period attributable to ordinary equity holders of the parent divided by the weighted average number of ordinary shares outstanding during the period. The weighted average number of ordinary shares exclude Treasury shares under the average market price method of calculating basic earnings per share. Diluted earnings per share amounts are calculated using the net profit attributable to ordinary equity holders of the Company divided by the weighted average number of ordinary shares outstanding during the period plus the weighted average number of ordinary shares that would be issued on the conversion of dilutive potential ordinary shares into ordinary shares. The dilution effect of 1,379 thousand shares for 2024 (2023: 1,310 thousand shares) are made up of 1,259 thousand shares related to RSUs and 120 thousand shares related to Board members\u2019 share options (2023: 1,259 thousand and 121 thousand shares respectively). Amounts in USD 000, unless otherwise stated 2024 2023 Net profit/(loss) attributable to equity holders 60,678 33,377 Weighted average number of shares outstanding - in thousands 115,813 116,142 Diluted weighted average number of shares outstanding - in thousands 117,192 117,452 Basic earnings/(loss) per share (USD) 0.52 0.29 Diluted earnings/(loss) per share (USD) 0.52 0.28
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"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
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"reg-ix-441": {
"value": "NOTE 9: LICENSES, EXPLORATION AND EVALUATION ASSETS, GOODWILL AND DEVELOPMENT ASSETS Note 9.1: Licenses, Exploration and Evaluation Assets, Development Assets 2024 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2024 10,311 83,090 Additions 9,551 7,141 Transfer to Production Assets - (4,256) At 31 December 2024 19,862 85,975 Net carrying value at 31 December 2024 19,862 85,975 2023 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2023 2,595 122,823 Additions 5,960 27,742 Transfer to Production Assets - (69,460) Additions through Acquisition (Note 14) 1,756 1,985 At 31 December 2023 10,311 83,090 Net carrying value at 31 December 2023 10,311 83,090 Note 9.2: Production rights USD 000 2024 2023 Acquisition cost At 1 January 181,559 173,975 Depreciation charge for the year (19,296) (17,602) Additions through Acquisition (Note 14) - 25,160 Other additions 9 26 At 31 December 162,272 181,559
Note 9.3: Goodwill USD 000 2024 2023 Acquisition cost At 1 January 52,124 47,762 Additions through Acquisition (Note 14) - 4,362 At 31 December 52,124 52,124 The Group acquired 40% of the shares of Sfax Petroleum Corporation AS from Beender Petroleum Tunisia Limited during 2023, assets and liabilities were taken on at fair value and Goodwill of USD 4.4 million recognised as described in Note 14: Business Combinations. Goodwill of USD 47.8 million at the beginning of the year was a result of the acquisition of the interest in Block G, Equatorial Guinea during 2021. Annual impairment assessments were carried out in December 2024 at which time the total carrying value of the Sfax Petroleum sub-group and Block G at 31 December 2023 was USD 47 million and USD 190.6 million respectively. The net recoverable value was determined on a Value in Use ('VIU') basis using a discounted cash flow model, which exceeded the carrying value. Based on a VIU analysis, performed using the profiles from third party reserves report, using the discount rate of 10% and oil price assumptions using a price deck of USD 76/bbl in 2025, increasing to USD 85/bbl in 2029 and USD 110/bbl in 2038. The resultant recoverable amounts exceed the current carrying value of the asset on the Group\u2019s balance sheet. This discount rate was derived from the Group\u2019s estimate of discount rates that might be applied by active market participants and adjusted, where applicable, to take into account any risks specific to the asset and the region where the asset is located. In determining VIU it is necessary to make a series of assumptions to estimate future cash flows including volumes, price assumption and cost estimates. Economically recoverable reserves and resources are based on NSAI and project plans based on Operator sourced information, supported by the evaluation work undertaken by appropriately qualified persons within the Joint Venture. The impairment test is most sensitive to the following assumptions: discount rates, oil and gas prices, reserve estimates and project risk. As of the date of the financial statements there is no expectation of possible changes in any of the above key assumptions that would cause the carrying value of the TPS or Block G assets to materially exceed its recoverable amount.
Note 9.1: Licenses, Exploration and Evaluation Assets, Development Assets 2024 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2024 10,311 83,090 Additions 9,551 7,141 Transfer to Production Assets - (4,256) At 31 December 2024 19,862 85,975 Net carrying value at 31 December 2024 19,862 85,975 2023 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2023 2,595 122,823 Additions 5,960 27,742 Transfer to Production Assets - (69,460) Additions through Acquisition (Note 14) 1,756 1,985 At 31 December 2023 10,311 83,090 Net carrying value at 31 December 2023 10,311 83,090 Note 9.2: Production rights USD 000 2024 2023 Acquisition cost At 1 January 181,559 173,975 Depreciation charge for the year (19,296) (17,602) Additions through Acquisition (Note 14) - 25,160 Other additions 9 26 At 31 December 162,272 181,559
Note 9.3: Goodwill USD 000 2024 2023 Acquisition cost At 1 January 52,124 47,762 Additions through Acquisition (Note 14) - 4,362 At 31 December 52,124 52,124 The Group acquired 40% of the shares of Sfax Petroleum Corporation AS from Beender Petroleum Tunisia Limited during 2023, assets and liabilities were taken on at fair value and Goodwill of USD 4.4 million recognised as described in Note 14: Business Combinations. Goodwill of USD 47.8 million at the beginning of the year was a result of the acquisition of the interest in Block G, Equatorial Guinea during 2021. Annual impairment assessments were carried out in December 2024 at which time the total carrying value of the Sfax Petroleum sub-group and Block G at 31 December 2023 was USD 47 million and USD 190.6 million respectively. The net recoverable value was determined on a Value in Use ('VIU') basis using a discounted cash flow model, which exceeded the carrying value. Based on a VIU analysis, performed using the profiles from third party reserves report, using the discount rate of 10% and oil price assumptions using a price deck of USD 76/bbl in 2025, increasing to USD 85/bbl in 2029 and USD 110/bbl in 2038. The resultant recoverable amounts exceed the current carrying value of the asset on the Group\u2019s balance sheet. This discount rate was derived from the Group\u2019s estimate of discount rates that might be applied by active market participants and adjusted, where applicable, to take into account any risks specific to the asset and the region where the asset is located. In determining VIU it is necessary to make a series of assumptions to estimate future cash flows including volumes, price assumption and cost estimates. Economically recoverable reserves and resources are based on NSAI and project plans based on Operator sourced information, supported by the evaluation work undertaken by appropriately qualified persons within the Joint Venture. The impairment test is most sensitive to the following assumptions: discount rates, oil and gas prices, reserve estimates and project risk. As of the date of the financial statements there is no expectation of possible changes in any of the above key assumptions that would cause the carrying value of the TPS or Block G assets to materially exceed its recoverable amount.
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"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
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"reg-ix-444": {
"value": "Annual impairment assessments were carried out in December 2024 at which time the total carrying value of the Sfax Petroleum sub-group and Block G at 31 December 2023 was USD 47 million and USD 190.6 million respectively. The net recoverable value was determined on a Value in Use ('VIU') basis using a discounted cash flow model, which exceeded the carrying value. Based on a VIU analysis, performed using the profiles from third party reserves report, using the discount rate of 10% and oil price assumptions using a price deck of USD 76/bbl in 2025, increasing to USD 85/bbl in 2029 and USD 110/bbl in 2038. The resultant recoverable amounts exceed the current carrying value of the asset on the Group\u2019s balance sheet. This discount rate was derived from the Group\u2019s estimate of discount rates that might be applied by active market participants and adjusted, where applicable, to take into account any risks specific to the asset and the region where the asset is located. In determining VIU it is necessary to make a series of assumptions to estimate future cash flows including volumes, price assumption and cost estimates. Economically recoverable reserves and resources are based on NSAI and project plans based on Operator sourced information, supported by the evaluation work undertaken by appropriately qualified persons within the Joint Venture. The impairment test is most sensitive to the following assumptions: discount rates, oil and gas prices, reserve estimates and project risk. As of the date of the financial statements there is no expectation of possible changes in any of the above key assumptions that would cause the carrying value of the TPS or Block G assets to materially exceed its recoverable amount.
Note 10.2: Impairment in Oil and Gas Interests Block G, Equatorial Guinea The Group has a 14.25% working interest in Block G, Equatorial Guinea. An assessment was performed using an oil price assumption price deck of USD 76/bbl in 2025, increasing each year with prices of USD 85/bbl in 2029 and USD 110/bbl in 2038. No indication of impairment was identified and no impairment was therefore recognised during the year 2024. Dussafu, Gabon The Group has a 17.4997% interest in the Dussafu Permit, offshore Gabon. An assessment was performed using an oil price assumption price deck of USD 76/bbl in 2025, increasing each year with prices of USD 85/bbl in 2029 and USD 110/bbl in 2038. No indication of impairment was identified and no impairment was therefore recognised during the year 2024. TPS Assets, Tunisia The Group has a 49% interest in the TPS Assets, comprising of Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba concessions. The Group assesses each cash-generating unit annually to determine whether an indication of impairment exists An assessment was performed using an oil price assumption price deck of USD 76/bbl in 2025, increasing each year with prices of USD 85/bbl in 2029 and USD 110/bbl in 2038. No indication of impairment was identified and no impairment was therefore recognised during the year 2024. Sensitivities to change in assumptions In general, adverse changes in key assumptions could result in recognition of impairment charges. Since there are no charges during the year, the sensitivities have not been presented in these financial statements. The Group will continue to test its assets for impairment where indications are identified and may in future recognise impairment charges or reversals. There were no net impairment (reversal)/expense for continuing operations. Climate considerations in impairment assessment Panoro incorporates certain climate considerations into its estimation of cash flows that are applied in the calculation of recoverable amount. This includes factoring in current legislation (e.g., environmental taxes/fees) and estimations of future environmental tax levels. While the Group\u2019s participation in the current licenses and concessions in various jurisdictions are not currently subject to specific carbon pricing, evolving regulatory frameworks may introduce such measures in the future.. The 2024 IEA World Energy Outlook highlights the urgency of limiting global warming to 1.5\u00b0C, with significant momentum seen in renewable energy deployment and electric vehicle adoption. However, under current policies (STEPS), global warming is projected to reach 2.4\u00b0C by 2100, emphasizing the need for accelerated emission reduction efforts. Despite these challenges, global energy demand continues to rise, driven by emerging economies leveraging fossil resources to support economic growth, fund energy transitions, and address climate adaptation needs. The Group\u2019s strategy seeks to balance environmental sustainability, energy security, and economic objectives by investing in efficient producing assets across North, West, and South Africa while collaborating with partners to transition toward a low-carbon business model. The company has run sensitivities for its West and North African oil assets in order to test the resilience of the Company\u2019s business, using three of the four scenarios examining future energy trends published by the International Energy Agency (IEA) in their World Energy Outlook 2024 publication. The scenarios with their key features are as follows: Net Zero Emissions (NZE) by 2050 Reaching net zero emissions by 2050 requires a fundamental transformation of the global energy system. Greenhouse gas emissions must fall by around 50% by 2030 \u2014 equivalent to a 7% annual reduction from 2021 \u2014 necessitating a rapid decline in oil and gas consumption. This shift is driven by a large-scale expansion of renewable energy, major improvements in energy efficiency, and the swift deployment of emerging technologies such as carbon capture, utilisation and storage (CCUS).
Cutting methane emissions from fossil fuel operations is also a critical priority. The NZE pathway assumes no further development of oil and gas fields beyond those already sanctioned, underlining the urgency of redirecting investment towards clean energy solutions. Oil demand drops sharply to 78.3 million barrels per day (mb/d) by 2030, primarily due to the electrification of road transport \u2014 the single most impactful driver of oil demand reduction. Efficiency gains and the uptake of low-emissions fuels also play an important role, particularly in sectors like aviation and shipping. By 2050, oil demand declines to 23 mb/d, with roughly 70% used as feedstock in the petrochemical industry or in non- combusted products such as paraffin waxes, asphalt and bitumen. As demand eases, oil prices fall to USD 42 per barrel by 2030, and further to USD 25 per barrel by 2050. Announced Pledges (APS) The APS scenario reflects a trajectory in which all existing climate commitments and pledges by governments \u2014 including net zero targets \u2014 are fully implemented. In this pathway, global oil demand declines markedly, reaching 92.8 mb/d by 2030 and 53.7 mb/d by 2050. Road transport continues to lead this shift. Measures to phase out single-use plastics and scale up plastics recycling contribute to slowing petrochemical demand growth. Oil use in aviation grows until the mid-2030s, then declines gradually, helped by an increasing share of sustainable aviation fuels. Oil use in shipping falls by 55% between 2022 and 2050, with 50% of marine fuels in 2050 coming from low-emissions sources. Oil prices fall from USD 72 per barrel in 2030 to USD 58 per barrel in 2050, reflecting a managed but significant transition away from fossil fuels. Stated Policies Scenario (STEPS) The STEPS scenario outlines a future based on policies and measures that are already enacted or firmly under way. In this case, global oil demand peaks just before 2030 at just under 102 mb/d, before easing back to 99 mb/d by 2035, returning to 2023 levels. The primary downward pressure on oil use comes from road transport. Electric vehicles have already displaced around 1.0 mb/d of demand since 2015, and between 2023 and 2035, they avoid a further 12 mb/d of demand growth. This results in a 2.5 mb/d net reduction in road transport oil use. Buildings-sector demand also contracts by 1.4 mb/d, thanks to fuel switching and energy efficiency measures. However, these reductions are counterbalanced by a 6.2 mb/d increase in oil demand for aviation and petrochemical production over the same period. In emerging and developing economies, oil demand growth slows \u2014 from an average of 1.8% per year (2015\u20132023) to 1% per year (2023\u20132035). India sees the largest increase, rising by 1.9 mb/d, while China adds just under 1 mb/d, mostly driven by petrochemicals. China is on course to surpass the United States as the largest oil consumer by 2030. In advanced economies, the long-term decline in oil demand accelerates. In Europe, internal combustion engine (ICE) vehicles lose ground rapidly, with over 90% of car sales expected to be electric by 2035. In North America, electric vehicle uptake grows to around 70% of car sales by 2035, largely due to recent policy measures in the United States and Canada. These transitions are even more pronounced in the APS and NZE scenarios, where electric vehicles account for almost 90% and nearly 100% of new car sales respectively by 2035. Oil prices decline modestly in this scenario, falling to USD 82 per barrel by 2030, and USD 75 per barrel by 2050, reflecting more stable but still shifting demand dynamics. Key findings Sensitivity analysis conducted show that the Company\u2019s portfolio remains resilient under each of the above-mentioned scenarios. Even under the most demanding NZE scenario, all segments remain economic, even though NPVs are negatively impacted and would result in an illustrative impairment of USD 69.2 million. A summary of the impact of the different future oil price scenarios on NPV and reserves are as follows: Percentage reduction/(increase) Net Zero Emissions (NZE) Announced Pledges (APS) Stated Policies (STEPS) NPV10 56% 18% 8% Reserves 26% 9% 5%
These illustrative impairment sensitivities assume no changes to assumptions other than oil and gas prices. However, significant reduction in the oil and gas prices, offset by foreign currency effects, would likely impact the Group\u2019s investment levels. The illustrative sensitivities on climate change are not considered to represent a best estimate of an expected impairment impact. Moreover, a significant and prolonged reduction in oil and gas prices would likely result in mitigating actions by the Group and its license partners; for example, it could have an impact on drilling plans and production profiles for new and existing assets. Quantifying such impacts is considered impracticable, as it requires detailed evaluations based on hypothetical scenarios and not based on existing business or development plans.
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"reg-ix-445": {
"value": "NOTE 10: PRODUCTION ASSETS, PROPERTY, FURNITURE, FIXTURES AND EQUIPMENT Note 10.1: Production Assets and Equipment USD 000 2024 2023 Historical cost At 1 January 234,002 134,747 Additions 86,284 33,199 Write-offs - (238) Adjustments to asset retirement estimates 10,609 (11,604) Transfer from Development Assets 4,256 69,460 Additions through Acquisition (Note 14) - 8,438 At 31 December 335,151 234,002 Accumulated depreciation At 1 January 58,935 37,388 Write-offs - (238) Depreciation charge for the year 34,801 21,785 At 31 December 93,736 58,935 Net carrying value at 31 December 241,415 175,067
Note 10.2: Impairment in Oil and Gas Interests Block G, Equatorial Guinea The Group has a 14.25% working interest in Block G, Equatorial Guinea. An assessment was performed using an oil price assumption price deck of USD 76/bbl in 2025, increasing each year with prices of USD 85/bbl in 2029 and USD 110/bbl in 2038. No indication of impairment was identified and no impairment was therefore recognised during the year 2024. Dussafu, Gabon The Group has a 17.4997% interest in the Dussafu Permit, offshore Gabon. An assessment was performed using an oil price assumption price deck of USD 76/bbl in 2025, increasing each year with prices of USD 85/bbl in 2029 and USD 110/bbl in 2038. No indication of impairment was identified and no impairment was therefore recognised during the year 2024. TPS Assets, Tunisia The Group has a 49% interest in the TPS Assets, comprising of Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba concessions. The Group assesses each cash-generating unit annually to determine whether an indication of impairment exists An assessment was performed using an oil price assumption price deck of USD 76/bbl in 2025, increasing each year with prices of USD 85/bbl in 2029 and USD 110/bbl in 2038. No indication of impairment was identified and no impairment was therefore recognised during the year 2024. Sensitivities to change in assumptions In general, adverse changes in key assumptions could result in recognition of impairment charges. Since there are no charges during the year, the sensitivities have not been presented in these financial statements. The Group will continue to test its assets for impairment where indications are identified and may in future recognise impairment charges or reversals. There were no net impairment (reversal)/expense for continuing operations. Climate considerations in impairment assessment Panoro incorporates certain climate considerations into its estimation of cash flows that are applied in the calculation of recoverable amount. This includes factoring in current legislation (e.g., environmental taxes/fees) and estimations of future environmental tax levels. While the Group\u2019s participation in the current licenses and concessions in various jurisdictions are not currently subject to specific carbon pricing, evolving regulatory frameworks may introduce such measures in the future.. The 2024 IEA World Energy Outlook highlights the urgency of limiting global warming to 1.5\u00b0C, with significant momentum seen in renewable energy deployment and electric vehicle adoption. However, under current policies (STEPS), global warming is projected to reach 2.4\u00b0C by 2100, emphasizing the need for accelerated emission reduction efforts. Despite these challenges, global energy demand continues to rise, driven by emerging economies leveraging fossil resources to support economic growth, fund energy transitions, and address climate adaptation needs. The Group\u2019s strategy seeks to balance environmental sustainability, energy security, and economic objectives by investing in efficient producing assets across North, West, and South Africa while collaborating with partners to transition toward a low-carbon business model. The company has run sensitivities for its West and North African oil assets in order to test the resilience of the Company\u2019s business, using three of the four scenarios examining future energy trends published by the International Energy Agency (IEA) in their World Energy Outlook 2024 publication. The scenarios with their key features are as follows: Net Zero Emissions (NZE) by 2050 Reaching net zero emissions by 2050 requires a fundamental transformation of the global energy system. Greenhouse gas emissions must fall by around 50% by 2030 \u2014 equivalent to a 7% annual reduction from 2021 \u2014 necessitating a rapid decline in oil and gas consumption. This shift is driven by a large-scale expansion of renewable energy, major improvements in energy efficiency, and the swift deployment of emerging technologies such as carbon capture, utilisation and storage (CCUS).
Cutting methane emissions from fossil fuel operations is also a critical priority. The NZE pathway assumes no further development of oil and gas fields beyond those already sanctioned, underlining the urgency of redirecting investment towards clean energy solutions. Oil demand drops sharply to 78.3 million barrels per day (mb/d) by 2030, primarily due to the electrification of road transport \u2014 the single most impactful driver of oil demand reduction. Efficiency gains and the uptake of low-emissions fuels also play an important role, particularly in sectors like aviation and shipping. By 2050, oil demand declines to 23 mb/d, with roughly 70% used as feedstock in the petrochemical industry or in non- combusted products such as paraffin waxes, asphalt and bitumen. As demand eases, oil prices fall to USD 42 per barrel by 2030, and further to USD 25 per barrel by 2050. Announced Pledges (APS) The APS scenario reflects a trajectory in which all existing climate commitments and pledges by governments \u2014 including net zero targets \u2014 are fully implemented. In this pathway, global oil demand declines markedly, reaching 92.8 mb/d by 2030 and 53.7 mb/d by 2050. Road transport continues to lead this shift. Measures to phase out single-use plastics and scale up plastics recycling contribute to slowing petrochemical demand growth. Oil use in aviation grows until the mid-2030s, then declines gradually, helped by an increasing share of sustainable aviation fuels. Oil use in shipping falls by 55% between 2022 and 2050, with 50% of marine fuels in 2050 coming from low-emissions sources. Oil prices fall from USD 72 per barrel in 2030 to USD 58 per barrel in 2050, reflecting a managed but significant transition away from fossil fuels. Stated Policies Scenario (STEPS) The STEPS scenario outlines a future based on policies and measures that are already enacted or firmly under way. In this case, global oil demand peaks just before 2030 at just under 102 mb/d, before easing back to 99 mb/d by 2035, returning to 2023 levels. The primary downward pressure on oil use comes from road transport. Electric vehicles have already displaced around 1.0 mb/d of demand since 2015, and between 2023 and 2035, they avoid a further 12 mb/d of demand growth. This results in a 2.5 mb/d net reduction in road transport oil use. Buildings-sector demand also contracts by 1.4 mb/d, thanks to fuel switching and energy efficiency measures. However, these reductions are counterbalanced by a 6.2 mb/d increase in oil demand for aviation and petrochemical production over the same period. In emerging and developing economies, oil demand growth slows \u2014 from an average of 1.8% per year (2015\u20132023) to 1% per year (2023\u20132035). India sees the largest increase, rising by 1.9 mb/d, while China adds just under 1 mb/d, mostly driven by petrochemicals. China is on course to surpass the United States as the largest oil consumer by 2030. In advanced economies, the long-term decline in oil demand accelerates. In Europe, internal combustion engine (ICE) vehicles lose ground rapidly, with over 90% of car sales expected to be electric by 2035. In North America, electric vehicle uptake grows to around 70% of car sales by 2035, largely due to recent policy measures in the United States and Canada. These transitions are even more pronounced in the APS and NZE scenarios, where electric vehicles account for almost 90% and nearly 100% of new car sales respectively by 2035. Oil prices decline modestly in this scenario, falling to USD 82 per barrel by 2030, and USD 75 per barrel by 2050, reflecting more stable but still shifting demand dynamics. Key findings Sensitivity analysis conducted show that the Company\u2019s portfolio remains resilient under each of the above-mentioned scenarios. Even under the most demanding NZE scenario, all segments remain economic, even though NPVs are negatively impacted and would result in an illustrative impairment of USD 69.2 million. A summary of the impact of the different future oil price scenarios on NPV and reserves are as follows: Percentage reduction/(increase) Net Zero Emissions (NZE) Announced Pledges (APS) Stated Policies (STEPS) NPV10 56% 18% 8% Reserves 26% 9% 5%
These illustrative impairment sensitivities assume no changes to assumptions other than oil and gas prices. However, significant reduction in the oil and gas prices, offset by foreign currency effects, would likely impact the Group\u2019s investment levels. The illustrative sensitivities on climate change are not considered to represent a best estimate of an expected impairment impact. Moreover, a significant and prolonged reduction in oil and gas prices would likely result in mitigating actions by the Group and its license partners; for example, it could have an impact on drilling plans and production profiles for new and existing assets. Quantifying such impacts is considered impracticable, as it requires detailed evaluations based on hypothetical scenarios and not based on existing business or development plans.
Note 10.3: Property, Furniture, Fixtures and Equipment 2024 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2024 178 958 175 1,323 2,634 Additions 48 1 54 - 103 At 31 December 2024 226 959 229 1,323 2,737 Accumulated depreciation At 1 January 2024 156 930 168 1,043 2,297 Depreciation charge for the year 10 18 5 199 232 At 31 December 2024 166 948 173 1,242 2,529 Net carrying value at 31 December 2024 60 11 56 81 208 2023 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2023 143 946 162 946 2,197 Additions 35 12 13 377 437 At 31 December 2023 178 958 175 1,323 2,634 Accumulated depreciation At 1 January 2023 100 888 160 849 1,997 Depreciation charge for the year 56 42 8 194 300 At 31 December 2023 156 930 168 1,043 2,297 Net carrying value at 31 December 2023 22 28 7 280 337 Depreciation method and rates Category Straight-line depreciation Useful life Leasehold Remaining period of lease Remaining period of lease Furniture, fixtures and fittings 10 - 33.33% 3 - 10 years Computer equipment 20 - 33.33% 3 - 5 years Right of use asset - London office Period of lease Period of lease
Accumulated depreciation At 1 January 58,935 37,388 Write-offs - (238) Depreciation charge for the year 34,801 21,785 At 31 December 93,736 58,935 Net carrying value at 31 December 241,415 175,067
Note 10.3: Property, Furniture, Fixtures and Equipment 2024 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2024 178 958 175 1,323 2,634 Additions 48 1 54 - 103 At 31 December 2024 226 959 229 1,323 2,737 Accumulated depreciation At 1 January 2024 156 930 168 1,043 2,297 Depreciation charge for the year 10 18 5 199 232 At 31 December 2024 166 948 173 1,242 2,529 Net carrying value at 31 December 2024 60 11 56 81 208 2023 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2023 143 946 162 946 2,197 Additions 35 12 13 377 437 At 31 December 2023 178 958 175 1,323 2,634 Accumulated depreciation At 1 January 2023 100 888 160 849 1,997 Depreciation charge for the year 56 42 8 194 300 At 31 December 2023 156 930 168 1,043 2,297 Net carrying value at 31 December 2023 22 28 7 280 337 Depreciation method and rates Category Straight-line depreciation Useful life Leasehold Remaining period of lease Remaining period of lease Furniture, fixtures and fittings 10 - 33.33% 3 - 10 years Computer equipment 20 - 33.33% 3 - 5 years Right of use asset - London office Period of lease Period of lease
Note 10.3: Property, Furniture, Fixtures and Equipment 2024 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2024 178 958 175 1,323 2,634 Additions 48 1 54 - 103 At 31 December 2024 226 959 229 1,323 2,737 Accumulated depreciation At 1 January 2024 156 930 168 1,043 2,297 Depreciation charge for the year 10 18 5 199 232 At 31 December 2024 166 948 173 1,242 2,529 Net carrying value at 31 December 2024 60 11 56 81 208 2023 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2023 143 946 162 946 2,197 Additions 35 12 13 377 437 At 31 December 2023 178 958 175 1,323 2,634 Accumulated depreciation At 1 January 2023 100 888 160 849 1,997 Depreciation charge for the year 56 42 8 194 300 At 31 December 2023 156 930 168 1,043 2,297 Net carrying value at 31 December 2023 22 28 7 280 337 Depreciation method and rates Category Straight-line depreciation Useful life Leasehold Remaining period of lease Remaining period of lease Furniture, fixtures and fittings 10 - 33.33% 3 - 10 years Computer equipment 20 - 33.33% 3 - 5 years Right of use asset - London office Period of lease Period of lease
NOTE 22: LEASES As noted above, Panoro leases certain assets, notably office facilities for operational activities. Panoro is mostly a lessee and the use of leases serves operational purposes rather than as a tool for financing. These lease liabilities are recognised on a gross basis in the balance sheet, income statement and statement of cash flows when Panoro is considered to have the primary responsibility for the full lease payments. In establishing Panoro\u2019s lease liabilities, the incremental borrowing rates used as discount factors in discounting payments have been established based on a consistent approach reflecting the Group\u2019s borrowing rate, the currency of the obligation, the duration of the lease term, and the credit spread for the legal entity entering into the lease contract. The London office lease contract has a reasonably certain non-cancellable period, was initially extended to June 2023, further extended to June
2025 during the year and the liability and the right of use asset determined using an incremental rate of return of 12% per annum which is deemed appropriate. Information related to lease payments and lease liabilities Lease liability is classified as current or non-current depending on maturity profile at balance sheet date. At 31 December 2024, the entire balance of USD 117 thousand was current (31 December 2023: USD 211 thousand current and USD 119 thousand non-current). USD 000 2024 2023 Lease liability recognised at 1 January 330 114 Add: new leases, including remeasurements and cancellations - 377 Add: lease interest 27 210 Less: gross lease payments (240) (371) Lease liability at 31 December 117 330 The following table shows the maturity profile of lease liabilities based on contractual undiscounted lease payments. USD 000 2024 2023 Within 1 year 117 211 2 to 5 years - 119 After 5 years - - Lease liability at 31 December 117 330 Information related to right of use assets The right of use assets are included within the line item Property, plant and equipment in the Consolidated balance sheet. See Note 10: Production Assets, Property, Furniture, Fixtures and Equipment. USD 000 2024 2023 Right of use asset recognised at 1 January 280 97 Add: new leases, including remeasurements and cancellations - 377 Less: depreciation and impairment (199) (194) Net book value of right of use asset at 31 December 81 280
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"value": "NOTE 11: INVESTMENT IN VENTURE CAPITAL FUNDS An investment was made in FCPR SWING 3 Venture Capital Trust (the \u201cVCT\u201d) via CAPSA Capital Partners as part of a Tunisian incentive plan that provides tax relief in exchange for investment in government approved projects within four years. The VCT invests in eligible activities under the incentive plan.
",
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"value": "NOTE 12: ACCOUNTS AND OTHER RECEIVABLES USD 000 2024 2023 Trade receivables 37,175 21,487 Other receivables and prepayments 1,411 6,023 Underlift - Block G, Equatorial Guinea - 3,840 At 31 December 38,586 31,350 Accounts receivables are non-interest bearing and generally on 30 to 120 days payment terms. At 31 December 2024 and 2023, the allowance for impairment of receivables was USD Nil. Risk information for the receivable balances is disclosed in Note 20: Financial risk management. Other receivables and prepayments consist entirely of prepayments at 31 December 2024 (31 December 2023: joint venture account balances of USD 4.3 million; prepayments of USD 1.6 million and USD 0.1 million tenancy deposit for the UK office premises.
NOTE 12: ACCOUNTS AND OTHER RECEIVABLES USD 000 2024 2023 Trade receivables 37,175 21,487 Other receivables and prepayments 1,411 6,023 Underlift - Block G, Equatorial Guinea - 3,840 At 31 December 38,586 31,350 Accounts receivables are non-interest bearing and generally on 30 to 120 days payment terms. At 31 December 2024 and 2023, the allowance for impairment of receivables was USD Nil. Risk information for the receivable balances is disclosed in Note 20: Financial risk management. Other receivables and prepayments consist entirely of prepayments at 31 December 2024 (31 December 2023: joint venture account balances of USD 4.3 million; prepayments of USD 1.6 million and USD 0.1 million tenancy deposit for the UK office premises.
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"reg-ix-451": {
"value": "NOTE 13: CASH AND BANK BALANCES USD 000 2024 2023 Cash and cash equivalents 72,868 27,821 At 31 December 72,868 27,821 The majority of Panoro\u2019s cash balance was denominated in USD and was held in different jurisdictions including Norway, UK, Tunisia and Mauritius. Overdraft facilities The Group had no bank overdraft facilities as at 31 December 2024 (31 December 2023: Nil).
",
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"reg-ix-452": {
"value": "NOTE 14: BUSINESS COMBINATIONS Note 14.1: Sfax Transaction On 24 April 2023, Panoro acquired the remaining 40% of the shares of Sfax Petroleum Corporation AS (\u201cSfax\u201d) from Beender Petroleum Tunisia Limited (\u201cBeender\u201d) for a total consideration of approximately USD 18.1 million in a mix of cash and shares . The acquisition was accounted for as a business combination and the additional interest acquired measured at fair value. Purchase consideration of USD 18.1 million consisted of upfront cash consideration of USD 4.9 million paid on completion and USD 5 million deferred consideration which was paid in 2024, together with interest of USD 0.4 million. Share consideration of USD 8.3 million was paid via the allotment and issue of 2,945,034 new Panoro shares on 25 April 2023 at an issue price of NOK 29.18 per share (issue value NOK 85,936,092.12). In addition, certain contingent consideration amounts are payable which are mostly linked to average annual oil prices in excess of USD 100 per barrel. The fair value of such consideration payments was recognised on the date of acquisition at USD 64 thousand. The carrying value of net assets acquired was USD 4 million, leaving excess value of USD 14.1 million to be allocated.
The fair values of the identifiable assets and liabilities and the Purchase Price Allocation (\u201cPPA\u201d) at acquisition date were as follows: Amounts in USD 000 Balance sheet of Sfax Group at acquisition pre PPA 40% portion of asset acquired / liabilities assumed pre PPA Adjustment 1 Adjustment 2 Balance sheet acquired at 40% post PPA ASSETS Production rights 34,738 13,895 11,265 - 25,160 Goodwill - - 1,618 - 1,618 Goodwill related to step up / deferred tax - - - 2,744 2,744 Intangible fixed assets 34,738 13,895 12,883 2,744 29,522 Tangible fixed assets 30,504 12,202 - - 12,202 Inventories, trade and other receivables 24,025 9,610 - - 9,610 Cash and cash equivalents 4,702 1,881 - - 1,881 Total non-current assets 59,231 23,692 - - 23,692 LIABILITIES Decommissioning liability 29,535 11,814 - - 11,814 Other non-current liabilities 13,278 5,311 (1,210) - 4,101 Deferred tax liabilities 8,460 3,384 - 2,744 6,128 Trade and other current liabilities 13,987 5,595 - - 5,595 Current and deferred taxes 18,680 7,472 - - 7,472 Total liabilities 83,940 33,576 (1,210) 2,744 35,110 Net assets (liabilities) acquired 10,029 4,012 14,093 - 18,105 Adjustment 1 relates to fair value adjustments identified and allocated to individual items in the analysis of the purchase price allocation analysis. Adjustment 2 contains deferred tax following from the previous adjustments, using a tax rate of 22% applicable to Norwegian companies.
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"reg-ix-453": {
"value": "NOTE 15: ASSET RETIREMENT OBLIGATION In accordance with the agreements and legislation, the wellheads, production assets, pipelines and other installations may have to be dismantled and removed from oil and natural gas fields when the production ceases. The following table presents amounts of the estimated obligations associated with the retirement of oil and natural gas properties: USD 000 Equatorial Guinea Gabon Tunisia Total At 1 January 2024 92,063 9,290 27,758 129,111 Unwinding of discount 4,660 451 (1,178) 3,933 Change in licence term (3,199) (1,097) - (4,296) Additions - 488 - 488 Change in cost estimate 14,417 - - 14,417 Balance at 31 December 2024 107,941 9,132 26,580 143,653 At 1 January 2023 97,954 8,208 17,492 123,654 Unwinding of discount 3,915 334 998 5,247 Change in inflation and discount rate (9,806) (869) (2,546) (13,221) Change in licence term - 259 - 259 Additions - 534 - 534 Acquisitions - - 11,814 11,814 Change in cost estimate - 824 - 824 Balance at 31 December 2023 92,063 9,290 27,758 129,111 All amounts are classified as non-current. The exact timing of the obligations is uncertain and depends on the rate the reserves of the field are depleted. However, based on the existing production profile of the assets, the following assumptions have been applied in order to calculate the liability: It is expected that expenditure on retirement is likely to be after more than five years. The current bases for the provision at 31 December 2024 are a discount rate of 4.75% and an inflation rate of 2% (31 December 2023: 4.75% and 2% respectively). Discount rate sensitivity has been calculated by assuming a reasonably possible change of 1.2 percentage points. An increase in the discount rate of 1.2 percent would reduce the ARO liability by USD 21.3 million and a corresponding reduction would increase the liability by USD 25.4 million.
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"reg-ix-454": {
"value": "NOTE 16: EQUITY Share capital Amounts in USD 000 unless otherwise stated Number of shares Nominal Share Capital As at 1 January 2024 116,944,048 738 As at 31 December 2024 116,944,048 738 Panoro Energy was formed through the merger of Norse Energy\u2019s former Brazilian business and Pan-Petroleum on 29 June 2010. The Company is incorporated in Norway and the share capital is denominated in NOK. The share capital given above is translated to USD at the foreign exchange rate in effect at the time of each share issue. All shares are fully paid-up and carry equal voting rights. As of 31 December 2024, the Company had a registered share capital of NOK 5,847,202 divided into 116,944,048 shares, each with a nominal value of NOK 0.05 (31 December 2023: NOK 5,847,202 divided into 116,944,048 shares, each with a nominal value of NOK 0.05). The Company\u2019s twenty largest shareholders and the shares owned by the CEO, Board Members and key management are referenced in the Parent Company Accounts below, please refer to Note 9: Shareholders\u2019 equity and shareholder information.
Reserves Share premium Share premium reserve of USD 415.7 million (31 December 2023: USD 434 million) represents excess of subscription value of the shares over the nominal amount. Treasury shares Treasury shares are presented as a deduction from equity represent the cost of the buy-back of the Company\u2019s own shares under a share buy-back program approved by the Board of the Company on 22 May 2024 (the \u201cProgram\u201d). Under the Program, the Company\u2019s shares are to be bought on the open market up to a maximum cost of NOK 100 million with the maximum number of shares bought back limited to 11.7 million shares. The purpose of the buy-back program is to reduce the number of common shares of the Company outstanding and to provide a return to Company shareholders. The company bought back 1,485,600 ordinary shares of its own equity during the period between 27 May 2024 and 31 December 2024, representing 1.27% of the total number of shares outstanding. The shares were acquired from the market at an average price of NOK 31.2088 per share with a total cost of NOK 46,457,612, which includes NOK 93,804 of transaction fees. The company used its retained earnings to fund the share buyback and the bought back shares are held as treasury shares and are presented as a separate equity item deduction from equity. The share buyback reduced the company's equity by USD 4.4 million and did not have an effect on its earnings per share.
Other reserves Other reserves of negative USD 43.4 million in 2024 and 2023 represent an item arising on accounting for the historical merger with Company\u2019s subsidiary Panoro Energy do Brasil Ltda. Additional paid-in capital Additional paid-in capital of USD 122.1 million (31 December 2023: USD 122 million) represent reserves created under the continuity principle on demerger. Share-based payments credit is also recorded under this reserve and so is the credit from reduction of share capital by reducing the par value of shares. Share capital Amounts in USD 000 unless otherwise stated Number of shares Nominal Share Capital As at 1 January 2024 116,944,048 738 As at 31 December 2024 116,944,048 738 Panoro Energy was formed through the merger of Norse Energy\u2019s former Brazilian business and Pan-Petroleum on 29 June 2010. The Company is incorporated in Norway and the share capital is denominated in NOK. The share capital given above is translated to USD at the foreign exchange rate in effect at the time of each share issue. All shares are fully paid-up and carry equal voting rights. As of 31 December 2024, the Company had a registered share capital of NOK 5,847,202 divided into 116,944,048 shares, each with a nominal value of NOK 0.05 (31 December 2023: NOK 5,847,202 divided into 116,944,048 shares, each with a nominal value of NOK 0.05). The Company\u2019s twenty largest shareholders and the shares owned by the CEO, Board Members and key management are referenced in the Parent Company Accounts below, please refer to Note 9: Shareholders\u2019 equity and shareholder information.
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"value": "Reserves Share premium Share premium reserve of USD 415.7 million (31 December 2023: USD 434 million) represents excess of subscription value of the shares over the nominal amount. Treasury shares Treasury shares are presented as a deduction from equity represent the cost of the buy-back of the Company\u2019s own shares under a share buy-back program approved by the Board of the Company on 22 May 2024 (the \u201cProgram\u201d). Under the Program, the Company\u2019s shares are to be bought on the open market up to a maximum cost of NOK 100 million with the maximum number of shares bought back limited to 11.7 million shares. The purpose of the buy-back program is to reduce the number of common shares of the Company outstanding and to provide a return to Company shareholders. The company bought back 1,485,600 ordinary shares of its own equity during the period between 27 May 2024 and 31 December 2024, representing 1.27% of the total number of shares outstanding. The shares were acquired from the market at an average price of NOK 31.2088 per share with a total cost of NOK 46,457,612, which includes NOK 93,804 of transaction fees. The company used its retained earnings to fund the share buyback and the bought back shares are held as treasury shares and are presented as a separate equity item deduction from equity. The share buyback reduced the company's equity by USD 4.4 million and did not have an effect on its earnings per share.
Other reserves Other reserves of negative USD 43.4 million in 2024 and 2023 represent an item arising on accounting for the historical merger with Company\u2019s subsidiary Panoro Energy do Brasil Ltda. Additional paid-in capital Additional paid-in capital of USD 122.1 million (31 December 2023: USD 122 million) represent reserves created under the continuity principle on demerger. Share-based payments credit is also recorded under this reserve and so is the credit from reduction of share capital by reducing the par value of shares. ",
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"value": "Treasury shares Treasury shares are presented as a deduction from equity represent the cost of the buy-back of the Company\u2019s own shares under a share buy-back program approved by the Board of the Company on 22 May 2024 (the \u201cProgram\u201d). Under the Program, the Company\u2019s shares are to be bought on the open market up to a maximum cost of NOK 100 million with the maximum number of shares bought back limited to 11.7 million shares. The purpose of the buy-back program is to reduce the number of common shares of the Company outstanding and to provide a return to Company shareholders. The company bought back 1,485,600 ordinary shares of its own equity during the period between 27 May 2024 and 31 December 2024, representing 1.27% of the total number of shares outstanding. The shares were acquired from the market at an average price of NOK 31.2088 per share with a total cost of NOK 46,457,612, which includes NOK 93,804 of transaction fees. The company used its retained earnings to fund the share buyback and the bought back shares are held as treasury shares and are presented as a separate equity item deduction from equity. The share buyback reduced the company's equity by USD 4.4 million and did not have an effect on its earnings per share.
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"value": "NOTE 17: ACCOUNTS PAYABLE, ACCRUALS AND OTHER LIABILITIES USD 000 2024 2023 Accounts payable 28,583 25,543 Accrued and other liabilities 5,083 3,532 Other non-current liabilities 25,939 8,852 At 31 December 59,605 37,927
NOTE 17: ACCOUNTS PAYABLE, ACCRUALS AND OTHER LIABILITIES USD 000 2024 2023 Accounts payable 28,583 25,543 Accrued and other liabilities 5,083 3,532 Other non-current liabilities 25,939 8,852 At 31 December 59,605 37,927
NOTE 18: SHARE BASED PAYMENTS Restricted Share Unit (\u201cRSU\u201d) scheme At the Annual General Meeting held on 23 May 2024, the existing RSU scheme (as originally presented and approved in the 27 May 2015 Annual General Meeting), was approved for another three years up to the general meeting to be held in the year 2027. Under this approved employee incentive scheme, the Company may issue RSUs to executive and key employees. Awards under the RSU scheme will normally be considered one time per year and grant of share-based incentives will, in
value (calculated at the time of grant), be capped levels defined in the plan. One RSU will entitle the holder to receive one share of capital stock of the Company against payment in cash of the par value for the share. Grant of RSUs will be subject to a set of performance metrics with threshold and factors reviewed annually by the Board of Directors. Such metrics will be set as objectives based on sustained performance results including mostly share price increases and achievement of specific financial performance measures related to a group of oil and gas exploration and production peers that has been defined and adopted by a committee established by the Board. The movement of RSUs during the year are tabled below: 2024 2023 All amounts in Number of units, unless stated otherwise Outstanding RSUs as of 1 January 1,203,377 1,049,991 Add: Grants during the year 640,032 719,615 Less: Vested during the year - Settled in cash to cover taxes / settlement through purchase of shares from the market (566,406) (256,587) - Settled through issue of new shares - (309,642) Outstanding RSUs as of 31 December 1,277,003 1,203,377 The cash settlement of RSUs is the Board of Directors\u2019 unilateral decision and such settlement is only to cover employee withholding taxes originating from vesting of RSUs. The Company, at its discretion, may also elect to settle the RSUs in cash or by delivering equity shares purchased from the market. RSUs vested on 13 June 2024 when the share price of the Company was NOK 32.15 per share. In June 2024, 640,032 Restricted Share Units (RSU) were awarded under the Company\u2019s RSU scheme to key employees of the Company under the long-term incentive plan approved by the shareholders. One RSU entitles the holder to receive one share of capital stock of the Company against payment in cash of the par value of the share. The par value is currently NOK 0.05 per share. Vesting of the RSUs is time based. The standard vesting period is 3 years, where 1/3 of the RSUs vest after one year, 1/3 vest after 2 years and the final 1/3 vest after 3 years from grant. The Board of Directors, at its discretion can grant a non-standard vesting period. RSUs vest automatically at the respective vesting dates, provided the unit holder continues to be an employee throughout the vesting period. The holder will be issued the applicable number of shares as soon as possible thereafter. The Company calculates the value of share-based compensation using a Black-Scholes option pricing model to estimate the fair value of the RSUs at the date of grant. The estimated fair value of RSUs is amortised to expense over the respective vesting period of USD 1.7 million (2023: USD 1.8 million) has been charged to the statement of comprehensive income for the proportion of vesting during the respective years and the same amount credited to additional paid-in capital. Upon vesting, the settlement value is reversed from the additional paid-in capital. USD 1.7 million relating to the 2024 vesting was reversed during the year (2023: USD 1.6 million). The assumptions made for the valuation of the RSUs granted during the year is as follows: Key assumptions 2024 2023 Weighted average risk-free interest rate 3.90% 3.25% Dividend yield 5.30% Nil Weighted average expected life of RSUs (vesting in Tranches) 1-3 years 1-3 years Volatility range based on Company's historical share performance 40% 41% Weighted average remaining contractual life of RSUs at year end 1.1 Years 1.2 Years Share price at grant date \u2013 per share NOK 32.20 NOK 27.18 The weighted average fair value of RSUs granted during the period was NOK 32.15 per unit (2023: NOK 27.13 per unit) based on 640,032 units granted (2023: 719,615 units granted).
The following table illustrates the maturity profile and Weighted Average Exercise Price (\"WAEP\") of the RSUs outstanding as of 31 December and vesting: 2024 2023 WAEP 2024 2023 Number of Units NOK/share Exercise value in NOK Within 1 year 598,679 566,406 0.05 29,934 28,320 Between 1 and 2 years 465,042 397,102 0.05 23,252 19,855 Between 2 and 3 years 213,282 239,869 0.05 10,664 11,993 Total 1,277,003 1,203,377 60,169 60,169 As of the year ended 2024 the unvested RSUs were outstanding for 22 employees including key management personnel (2023: 21 employees). The distribution of outstanding RSUs as of 31 December 2024 amongst the employees is as follows: No of Units Exercise price NOK/share Exercise period Fair value expensed USD 000 John Hamilton, CEO 363,818 0.05 June 2025 to June 2027 563 Qazi Qadeer, CFO 179,417 0.05 June 2025 to June 2027 273 Other Employees 733,768 0.05 June 2025 to June 2027 1,163 Total 1,277,003 1,999 Under the RSU scheme in an event where there is a change of control, all outstanding RSUs will vest immediately, and the Company will cash settle by compensating the difference between the fair market value of the RSUs and the exercise value. A change of control is defined in the RSU scheme terms and means (i) a change of control in the ownership of the Company which gives a person (individual or corporate) the right and the obligation to make a mandatory offer for all the shares in the Company pursuant to the Norwegian Securities Trading Act of 2007, (ii) if (i) is not applicable; a change of control in the ownership of the Company which gives a person (individual or corporate) ownership to or control over more than 50% of the votes in the Company, (iii) a merger in which the Company is not the surviving entity or (iv) a sale of all or substantially all of the Company\u2019s assets to another corporation, partnership or other entity that is not a wholly owned Subsidiary of the Company. In the case of (i) and (ii) above, the change of control Is deemed to occur at the time when the relevant ownership or control occurs and in the case of (iii) and (iv) above at completion of the merger or the sale. Share Options to Board of Directors Pursuant to the recommendation of the Nominations Committee and the resolutions passed in the Annual General Meeting (\u201c2021 AGM\u201d) of the Company, held on 27 May 2021, a share option plan to award share options to the Company\u2019s existing members of the Board of Directors, were approved and implemented (\u201cBoard Options\u201d). One Board Option entitles the holder to receive one share of capital stock of the Company against payment in cash of the Exercise Price of the option which has been set at NOK 17.34 each for 2021 awards, NOK 31.91 for the 2022 award and NOK 27.40 for the 2023 award, in line with the mechanism prescribed in the 2021 AGM. Vesting of the Board Options is time based and the vesting period specific to these grants is between 27 May 2021 to 26 May 2026, where 1/3 of the Board Options vest each year, starting one year after award on the date of the Company\u2019s AGM which is generally held in the last week of May each year. The movement of Board Options during the year are tabled below: All amounts in Number of units, unless stated otherwise 2024 2023 Outstanding options as of 1 January 192,000 168,000 Add: Grants during the year - 24,000 Outstanding options as of 31 December 192,000 192,000 The outstanding options as of 31 December 2024 included 168,000 options that had already vested but not exercised (2023: 112,000). The Company calculates the value of share-based compensation using a Black-Scholes option pricing model to estimate the fair value of the Board Options at the date of grant. The estimated fair value of RSUs is amortised to expense over the
respective vesting period of USD 0.1 million has been charged to the statement of comprehensive income for the proportion of vesting during the respective years and the same amount credited to additional paid-in capital. Upon vesting, the settlement value is reversed from the additional paid-in capital. The assumptions made for the valuation of the Board Options granted during the year is as follows: Key assumptions 2024 2023 Weighted average risk-free interest rate n/a 3.25% Dividend yield n/a Nil Weighted average expected life of RSUs (vesting in Tranches) n/a 1-3 years Volatility range based on Company's historical share performance n/a 41% Weighted average remaining contractual life of RSUs at year end n/a 0.8 Years Share price at grant date \u2013 per share n/a NOK 28.10 No Board Options were granted during the year. The weighted average fair value of Board Options granted during the previous period was NOK 28.10 per unit based on 24,000 units granted. The following table illustrates the maturity profile and Weighted Average Exercise Price (\"WAEP\") of the Board Options outstanding as of 31 December and vesting: 2024 2023 WAEP 2024 2023 Number of Units NOK/share Exercise value in NOK Fully vested and exercisable 168,000 112,000 19.21 3,227,280 2,058,640 Within 1 year 16,000 56,000 29.66 474,560 1,168,080 Between 1 and 2 years 8,000 16,000 27.40 219,200 474,480 Between 2 and 3 years - 8,000 0.00 0 219,200 Total 192,000 192,000 3,921,040 3,920,400 As of the year ended 2024 the unvested Board Options were outstanding for 7 current and former members of the Board of Directors (2023: 6 members of the Board of Directors) which includes two former directors who are allowed to retain their Board Options in accordance with shareholder approvals received in the 2023 Annual General Meeting. The distribution of outstanding Board Options as of 31 December 2024 amongst the members of the Board of Directors is as follows: Current directors No of Units - unvested No of Units - vested and unexercised Exercise price NOK/share Exercise period 2024 Fair value expensed USD 000 2023 Fair value expensed USD 000 Julien Balkany - 48,000 17.34 Up to May 2026 2 9 Torstein Sanness - 24,000 17.34 Up to May 2026 1 5 Alexandra Herger - 24,000 17.34 Up to May 2026 1 5 Garrett Soden - 24,000 17.34 Up to May 2026 1 5 Gunnvor Ellingsen 16,000 8,000 27.40 Up to May 2028 8 6 Total 16,000 128,000 13 47 Former directors No of Units - unvested No of Units - vested and unexercised Exercise price NOK/share Exercise period 2024 Fair value expensed USD 000 2023 Fair value expensed USD 000 Grace Skaugen 8,000 16,000 31.91 Up to May 2027 7 11 Hilde Adland - 24,000 17.34 Up to May 2026 - 6 Total 8,000 40,000 7 17
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"reg-ix-461": {
"value": "NOTE 19: FINANCIAL INSTRUMENTS Fair values of financial assets and liabilities The Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value. The Group has no material financial assets that are past due. No material financial assets are impaired at the balance sheet date. All financial assets and liabilities with the exception of derivatives are measured at amortised cost. Fair value of derivative instruments All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as a cash flow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm\u2019s length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions or using standard valuation techniques for the applicable instruments and commodities involved. The Group strategically hedges a portion of its 2P oil reserves to protect against a fall in oil prices and protect its ability to service its debt obligations and to fund operations including planned capital expenditure. The hedge instruments used include \u201czero cost collars\u201d (where Panoro is guaranteed to receive no less than the buy/put price, but no more than the sell/call price for the hedged number of bbls) and \u201ccommodity swap\u201d (where Panoro is guaranteed the contract price) contracts to protect the downside in \u2018Dated Brent\u2019 oil price. These hedge contracts are initially recognised at Nil fair value and then revalued at each balance sheet date, with changes in fair value recognised as finance income or expense in the Statement of Comprehensive Income. The hedging program continues to be closely monitored and adjusted according to the Group\u2019s risk management policies and cashflow requirements. The Group continues to monitor and optimise its hedging programme on an on-going basis. There were no outstanding commodity hedge contracts as at the respective balance sheet dates presented. The fair values of the commodity price contracts are provided by the counterparty with whom the trades have been entered into. These consist of put and call options to sell/buy crude oil. The options are valued using a Black-Scholes based methodology. The inputs to these valuations include the price of oil, its volatility. The following provides an analysis of the Group\u2019s financial instruments measured at fair value, grouped into Levels 1 to 3 based on the degree to which the fair value is observable: \u2022 Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities, \u2022 Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and \u2022 Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data. All the Group\u2019s derivatives are Level 2 (2023: Level 2). There were no transfers between fair value levels during the year. For financial instruments which are recognised on a recurring basis, the Group determines whether transfers have occurred between levels by re-assessing categorisation (based on the lowest-level input which is significant to the fair value measurement as a whole) at the end of each reporting period.
NOTE 20: FINANCIAL RISK MANAGEMENT Financial risk management objectives The Group\u2019s principal financial liabilities comprise of loans and borrowings and trade and other financial liabilities. The main purpose of these financial instruments is to finance the Group\u2019s operations, including the Group\u2019s capital expenditure programme. The Group has various financial assets such as accounts receivable and cash. The Group manages its exposure to key financial risks in accordance with its financial risk management policy. The objective of the policy is to support the Group\u2019s financial targets while protecting future financial security. The Group is exposed to the following risks: \u2022 Market risk, including commodity price, foreign currency exchange and interest rate risks \u2022 Credit risk \u2022 Liquidity risk
Management reviews and agrees policies for managing each of these risks which are summarised below. The Group\u2019s policy is that all transactions involving derivatives must be directly related to the underlying business of the Group and does not use derivative financial instruments for speculative purposes. Market risk Market risk is the risk or uncertainty arising from possible market price movements or prevailing market conditions and their impact on the future performance of a business or the ability to complete deals entered into. The primary commodity price risks that the Group is exposed to include oil prices that could adversely affect the value of the group\u2019s financial assets, liabilit ies or expected future cash flows. In accordance with the Group\u2019s financial risk management framework, the Group enters into various transactions using derivatives for risk management purposes. The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed below. Foreign currency exchange risk The Company operates internationally and is exposed to risk arising from various currency exposures, primarily with respect to the Norwegian Kroner (NOK), the Tunisian Dinar (TND), the Pound Sterling (GBP) and the Central African Franc (CFA). 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 affects its consolidated income statement and balance sheet 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. The Group evaluates on a continuous basis to use cross currency swaps if deemed appropriate by management in order to hedge the forward foreign currency risk. The group used no currency derivatives/swaps during 2024 or 2023. A 20% strengthening or weakening of the USD against the following currencies at the balance sheet dates presented would have increased / (decreased) equity and profit or loss 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 financial markets. This hypothetical analysis assumes that all other variables, including interest rates and commodity prices, remain constant. USD 000 2024 2023 USD vs NOK 20% -20% 20% -20% Cash 10 (16) 14 (21) Receivables - - 3 (5) Payables (115) 172 (20) 30 Net effect (105) 156 (3) 5 USD vs TND 20% -20% 20% -20% Cash 543 (814) 617 (925) Receivables 190 (285) 242 (363) Corporation taxes payable - - (2,112) 3,168 Payables (3,338) 5,007 (1,420) 2,130 Net effect (2,605) 3,908 (2,673) 4,010 USD vs EUR 20% -20% 20% -20% Cash 3 (5) 21 (32) Receivables - - 1 (2) Payables (45) 67 (38) 57 Net effect (42) 62 (16) 24
USD 000 2024 2023 USD vs GBP 20% -20% 20% -20% Cash 19 (29) 54 (81) Receivables 73 (109) (78) 116 Payables (252) 378 (55) 83 Net effect (160) 240 (79) 118 USD vs CFA 20% -20% 20% -20% Cash 310 (465) - - Receivables 1,652 (2,478) - - Payables (1,207) 1,811 - - Net effect 755 (1,132) - -
Interest rate risk The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to the Group\u2019s loans and borrowings and cash balances. The following table demonstrates the sensitivity of finance revenue and finance costs to a reasonably possible change in interest rates, with all other variables held constant, of the Group\u2019s profit before tax through the impact on fixed rate short-term deposits and applicable floating rate bank loans. USD 000 2024 2023 +100bps -100bps +100bps -100bps Loans and borrowings (Secured loans) (1,500) 1,500 (705) 705 Cash equivalents 16 (16) 40 (40) Net effect (1,499) 1,499 (665) 665 Credit risk The Group is exposed to credit risk that arises from cash and cash equivalents, derivative financial instruments and deposits with banks and financial institutions, as well as credit exposures to customers, including outstanding receivables and committed transactions. For banks and financial institutions, only independently rated parties with a minimum rating of \u201cA\u201d are accepted. Any change of financial institutions (except minor issues) are approved by the Group CFO. The Company may engage with counterparties of a lower rating, for commercial reason, or by taking lower exposures in such counterparties to mitigate the risks following necessary approvals. If the Group\u2019s customers are independently rated, these ratings are used. Otherwise, if there is no independent rating, risk control in the operating units assesses the credit quality of the customer, taking into account its financial position, past experience and other factors. The utilisation of credit limits is regularly monitored and kept within approved budgets.
Liquidity risk Liquidity risk is the risk that the Group will not be able to meet its obligations as they fall due. Prudent liquidity risk management includes maintaining sufficient cash and marketable securities, the availability of funding from an adequate amount of committed credit facilities and the ability to close out market positions. The table below summarises the maturity profile of the Group\u2019s financial liabilities at 31 December based on contractual undiscounted payments. 2024 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Secured loans) - 854 150,000 - 150,854 Accounts payable and accrued liabilities - 28,582 - - 28,582 Non-current liabilities - - 15,130 14,732 29,862 Corporation tax liabilities - 24,537 - - 24,537 Total - 53,973 165,130 14,732 233,835 2023 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Secured loans) - 26,420 44,033 - 70,453 Accounts payable and accrued liabilities - 25,543 - - 25,543 Non-current liabilities - - 119 3,648 3,767 Corporation tax liabilities - 34,381 - - 34,381 Total - 86,344 44,152 3,648 134,144 Management considers that the Group has adequate current assets and forecast cash from operations to manage liquidity risks arising from current and non-current liabilities. As of 31 December 2024, the Group\u2019s total debt was USD 145.9 million and oil revenue advances of nil. The Group closed the year with a cash position of USD 72.9 million. Although the Company is well funded to undertake upcoming work programmes, there is a risk that additional funding may be required to conclude such activities.
Capital Management The Group manages its capital structure to ensure that it remains sufficiently funded to support its business strategy and maximise shareholder value. 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\u2019s funding requirements are met through a combination of debt and equity and adjustments are made in light of changes in economic conditions. The Group\u2019s strategy is to maintain ratios in line with covenants associated with its Secured loans. The Group includes interest bearing loans less cash, cash equivalents and restricted cash in net debt. Capital includes share capital, share premium, other reserves and accumulated profits/losses. 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 that in the forthcoming year.
Fair values of financial assets and liabilities The Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value. The Group has no material financial assets that are past due. No material financial assets are impaired at the balance sheet date. All financial assets and liabilities with the exception of derivatives are measured at amortised cost. Fair value of derivative instruments All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as a cash flow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm\u2019s length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions or using standard valuation techniques for the applicable instruments and commodities involved. The Group strategically hedges a portion of its 2P oil reserves to protect against a fall in oil prices and protect its ability to service its debt obligations and to fund operations including planned capital expenditure. The hedge instruments used include \u201czero cost collars\u201d (where Panoro is guaranteed to receive no less than the buy/put price, but no more than the sell/call price for the hedged number of bbls) and \u201ccommodity swap\u201d (where Panoro is guaranteed the contract price) contracts to protect the downside in \u2018Dated Brent\u2019 oil price. These hedge contracts are initially recognised at Nil fair value and then revalued at each balance sheet date, with changes in fair value recognised as finance income or expense in the Statement of Comprehensive Income. The hedging program continues to be closely monitored and adjusted according to the Group\u2019s risk management policies and cashflow requirements. The Group continues to monitor and optimise its hedging programme on an on-going basis. There were no outstanding commodity hedge contracts as at the respective balance sheet dates presented. The fair values of the commodity price contracts are provided by the counterparty with whom the trades have been entered into. These consist of put and call options to sell/buy crude oil. The options are valued using a Black-Scholes based methodology. The inputs to these valuations include the price of oil, its volatility. The following provides an analysis of the Group\u2019s financial instruments measured at fair value, grouped into Levels 1 to 3 based on the degree to which the fair value is observable: \u2022 Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities, \u2022 Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and \u2022 Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data. All the Group\u2019s derivatives are Level 2 (2023: Level 2). There were no transfers between fair value levels during the year. For financial instruments which are recognised on a recurring basis, the Group determines whether transfers have occurred between levels by re-assessing categorisation (based on the lowest-level input which is significant to the fair value measurement as a whole) at the end of each reporting period.
Fair values of financial assets and liabilities The Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value. The Group has no material financial assets that are past due. No material financial assets are impaired at the balance sheet date. All financial assets and liabilities with the exception of derivatives are measured at amortised cost. Fair value of derivative instruments All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as a cash flow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm\u2019s length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions or using standard valuation techniques for the applicable instruments and commodities involved. The Group strategically hedges a portion of its 2P oil reserves to protect against a fall in oil prices and protect its ability to service its debt obligations and to fund operations including planned capital expenditure. The hedge instruments used include \u201czero cost collars\u201d (where Panoro is guaranteed to receive no less than the buy/put price, but no more than the sell/call price for the hedged number of bbls) and \u201ccommodity swap\u201d (where Panoro is guaranteed the contract price) contracts to protect the downside in \u2018Dated Brent\u2019 oil price. These hedge contracts are initially recognised at Nil fair value and then revalued at each balance sheet date, with changes in fair value recognised as finance income or expense in the Statement of Comprehensive Income. The hedging program continues to be closely monitored and adjusted according to the Group\u2019s risk management policies and cashflow requirements. The Group continues to monitor and optimise its hedging programme on an on-going basis. There were no outstanding commodity hedge contracts as at the respective balance sheet dates presented. The fair values of the commodity price contracts are provided by the counterparty with whom the trades have been entered into. These consist of put and call options to sell/buy crude oil. The options are valued using a Black-Scholes based methodology. The inputs to these valuations include the price of oil, its volatility. The following provides an analysis of the Group\u2019s financial instruments measured at fair value, grouped into Levels 1 to 3 based on the degree to which the fair value is observable: \u2022 Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities, \u2022 Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and \u2022 Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data. All the Group\u2019s derivatives are Level 2 (2023: Level 2). There were no transfers between fair value levels during the year. For financial instruments which are recognised on a recurring basis, the Group determines whether transfers have occurred between levels by re-assessing categorisation (based on the lowest-level input which is significant to the fair value measurement as a whole) at the end of each reporting period.
",
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"reg-ix-464": {
"value": "Fair value of derivative instruments All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as a cash flow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm\u2019s length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions or using standard valuation techniques for the applicable instruments and commodities involved. The Group strategically hedges a portion of its 2P oil reserves to protect against a fall in oil prices and protect its ability to service its debt obligations and to fund operations including planned capital expenditure. The hedge instruments used include \u201czero cost collars\u201d (where Panoro is guaranteed to receive no less than the buy/put price, but no more than the sell/call price for the hedged number of bbls) and \u201ccommodity swap\u201d (where Panoro is guaranteed the contract price) contracts to protect the downside in \u2018Dated Brent\u2019 oil price. These hedge contracts are initially recognised at Nil fair value and then revalued at each balance sheet date, with changes in fair value recognised as finance income or expense in the Statement of Comprehensive Income. The hedging program continues to be closely monitored and adjusted according to the Group\u2019s risk management policies and cashflow requirements. The Group continues to monitor and optimise its hedging programme on an on-going basis. There were no outstanding commodity hedge contracts as at the respective balance sheet dates presented. The fair values of the commodity price contracts are provided by the counterparty with whom the trades have been entered into. These consist of put and call options to sell/buy crude oil. The options are valued using a Black-Scholes based methodology. The inputs to these valuations include the price of oil, its volatility. The following provides an analysis of the Group\u2019s financial instruments measured at fair value, grouped into Levels 1 to 3 based on the degree to which the fair value is observable: \u2022 Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities, \u2022 Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and \u2022 Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data. All the Group\u2019s derivatives are Level 2 (2023: Level 2). There were no transfers between fair value levels during the year. For financial instruments which are recognised on a recurring basis, the Group determines whether transfers have occurred between levels by re-assessing categorisation (based on the lowest-level input which is significant to the fair value measurement as a whole) at the end of each reporting period.
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"reg-ix-465": {
"value": "NOTE 20: FINANCIAL RISK MANAGEMENT Financial risk management objectives The Group\u2019s principal financial liabilities comprise of loans and borrowings and trade and other financial liabilities. The main purpose of these financial instruments is to finance the Group\u2019s operations, including the Group\u2019s capital expenditure programme. The Group has various financial assets such as accounts receivable and cash. The Group manages its exposure to key financial risks in accordance with its financial risk management policy. The objective of the policy is to support the Group\u2019s financial targets while protecting future financial security. The Group is exposed to the following risks: \u2022 Market risk, including commodity price, foreign currency exchange and interest rate risks \u2022 Credit risk \u2022 Liquidity risk
Management reviews and agrees policies for managing each of these risks which are summarised below. The Group\u2019s policy is that all transactions involving derivatives must be directly related to the underlying business of the Group and does not use derivative financial instruments for speculative purposes. Market risk Market risk is the risk or uncertainty arising from possible market price movements or prevailing market conditions and their impact on the future performance of a business or the ability to complete deals entered into. The primary commodity price risks that the Group is exposed to include oil prices that could adversely affect the value of the group\u2019s financial assets, liabilit ies or expected future cash flows. In accordance with the Group\u2019s financial risk management framework, the Group enters into various transactions using derivatives for risk management purposes. The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed below. Foreign currency exchange risk The Company operates internationally and is exposed to risk arising from various currency exposures, primarily with respect to the Norwegian Kroner (NOK), the Tunisian Dinar (TND), the Pound Sterling (GBP) and the Central African Franc (CFA). 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 affects its consolidated income statement and balance sheet 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. The Group evaluates on a continuous basis to use cross currency swaps if deemed appropriate by management in order to hedge the forward foreign currency risk. The group used no currency derivatives/swaps during 2024 or 2023. A 20% strengthening or weakening of the USD against the following currencies at the balance sheet dates presented would have increased / (decreased) equity and profit or loss 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 financial markets. This hypothetical analysis assumes that all other variables, including interest rates and commodity prices, remain constant. USD 000 2024 2023 USD vs NOK 20% -20% 20% -20% Cash 10 (16) 14 (21) Receivables - - 3 (5) Payables (115) 172 (20) 30 Net effect (105) 156 (3) 5 USD vs TND 20% -20% 20% -20% Cash 543 (814) 617 (925) Receivables 190 (285) 242 (363) Corporation taxes payable - - (2,112) 3,168 Payables (3,338) 5,007 (1,420) 2,130 Net effect (2,605) 3,908 (2,673) 4,010 USD vs EUR 20% -20% 20% -20% Cash 3 (5) 21 (32) Receivables - - 1 (2) Payables (45) 67 (38) 57 Net effect (42) 62 (16) 24
USD 000 2024 2023 USD vs GBP 20% -20% 20% -20% Cash 19 (29) 54 (81) Receivables 73 (109) (78) 116 Payables (252) 378 (55) 83 Net effect (160) 240 (79) 118 USD vs CFA 20% -20% 20% -20% Cash 310 (465) - - Receivables 1,652 (2,478) - - Payables (1,207) 1,811 - - Net effect 755 (1,132) - -
Interest rate risk The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to the Group\u2019s loans and borrowings and cash balances. The following table demonstrates the sensitivity of finance revenue and finance costs to a reasonably possible change in interest rates, with all other variables held constant, of the Group\u2019s profit before tax through the impact on fixed rate short-term deposits and applicable floating rate bank loans. USD 000 2024 2023 +100bps -100bps +100bps -100bps Loans and borrowings (Secured loans) (1,500) 1,500 (705) 705 Cash equivalents 16 (16) 40 (40) Net effect (1,499) 1,499 (665) 665 Credit risk The Group is exposed to credit risk that arises from cash and cash equivalents, derivative financial instruments and deposits with banks and financial institutions, as well as credit exposures to customers, including outstanding receivables and committed transactions. For banks and financial institutions, only independently rated parties with a minimum rating of \u201cA\u201d are accepted. Any change of financial institutions (except minor issues) are approved by the Group CFO. The Company may engage with counterparties of a lower rating, for commercial reason, or by taking lower exposures in such counterparties to mitigate the risks following necessary approvals. If the Group\u2019s customers are independently rated, these ratings are used. Otherwise, if there is no independent rating, risk control in the operating units assesses the credit quality of the customer, taking into account its financial position, past experience and other factors. The utilisation of credit limits is regularly monitored and kept within approved budgets.
Liquidity risk Liquidity risk is the risk that the Group will not be able to meet its obligations as they fall due. Prudent liquidity risk management includes maintaining sufficient cash and marketable securities, the availability of funding from an adequate amount of committed credit facilities and the ability to close out market positions. The table below summarises the maturity profile of the Group\u2019s financial liabilities at 31 December based on contractual undiscounted payments. 2024 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Secured loans) - 854 150,000 - 150,854 Accounts payable and accrued liabilities - 28,582 - - 28,582 Non-current liabilities - - 15,130 14,732 29,862 Corporation tax liabilities - 24,537 - - 24,537 Total - 53,973 165,130 14,732 233,835 2023 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Secured loans) - 26,420 44,033 - 70,453 Accounts payable and accrued liabilities - 25,543 - - 25,543 Non-current liabilities - - 119 3,648 3,767 Corporation tax liabilities - 34,381 - - 34,381 Total - 86,344 44,152 3,648 134,144 Management considers that the Group has adequate current assets and forecast cash from operations to manage liquidity risks arising from current and non-current liabilities. As of 31 December 2024, the Group\u2019s total debt was USD 145.9 million and oil revenue advances of nil. The Group closed the year with a cash position of USD 72.9 million. Although the Company is well funded to undertake upcoming work programmes, there is a risk that additional funding may be required to conclude such activities.
Capital Management The Group manages its capital structure to ensure that it remains sufficiently funded to support its business strategy and maximise shareholder value. 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\u2019s funding requirements are met through a combination of debt and equity and adjustments are made in light of changes in economic conditions. The Group\u2019s strategy is to maintain ratios in line with covenants associated with its Secured loans. The Group includes interest bearing loans less cash, cash equivalents and restricted cash in net debt. Capital includes share capital, share premium, other reserves and accumulated profits/losses. 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 that in the forthcoming year.
Market risk Market risk is the risk or uncertainty arising from possible market price movements or prevailing market conditions and their impact on the future performance of a business or the ability to complete deals entered into. The primary commodity price risks that the Group is exposed to include oil prices that could adversely affect the value of the group\u2019s financial assets, liabilit ies or expected future cash flows. In accordance with the Group\u2019s financial risk management framework, the Group enters into various transactions using derivatives for risk management purposes. The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed below. Foreign currency exchange risk The Company operates internationally and is exposed to risk arising from various currency exposures, primarily with respect to the Norwegian Kroner (NOK), the Tunisian Dinar (TND), the Pound Sterling (GBP) and the Central African Franc (CFA). 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 affects its consolidated income statement and balance sheet 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. The Group evaluates on a continuous basis to use cross currency swaps if deemed appropriate by management in order to hedge the forward foreign currency risk. The group used no currency derivatives/swaps during 2024 or 2023. A 20% strengthening or weakening of the USD against the following currencies at the balance sheet dates presented would have increased / (decreased) equity and profit or loss 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 financial markets. This hypothetical analysis assumes that all other variables, including interest rates and commodity prices, remain constant. USD 000 2024 2023 USD vs NOK 20% -20% 20% -20% Cash 10 (16) 14 (21) Receivables - - 3 (5) Payables (115) 172 (20) 30 Net effect (105) 156 (3) 5 USD vs TND 20% -20% 20% -20% Cash 543 (814) 617 (925) Receivables 190 (285) 242 (363) Corporation taxes payable - - (2,112) 3,168 Payables (3,338) 5,007 (1,420) 2,130 Net effect (2,605) 3,908 (2,673) 4,010 USD vs EUR 20% -20% 20% -20% Cash 3 (5) 21 (32) Receivables - - 1 (2) Payables (45) 67 (38) 57 Net effect (42) 62 (16) 24
USD 000 2024 2023 USD vs GBP 20% -20% 20% -20% Cash 19 (29) 54 (81) Receivables 73 (109) (78) 116 Payables (252) 378 (55) 83 Net effect (160) 240 (79) 118 USD vs CFA 20% -20% 20% -20% Cash 310 (465) - - Receivables 1,652 (2,478) - - Payables (1,207) 1,811 - - Net effect 755 (1,132) - -
Interest rate risk The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to the Group\u2019s loans and borrowings and cash balances. The following table demonstrates the sensitivity of finance revenue and finance costs to a reasonably possible change in interest rates, with all other variables held constant, of the Group\u2019s profit before tax through the impact on fixed rate short-term deposits and applicable floating rate bank loans. USD 000 2024 2023 +100bps -100bps +100bps -100bps Loans and borrowings (Secured loans) (1,500) 1,500 (705) 705 Cash equivalents 16 (16) 40 (40) Net effect (1,499) 1,499 (665) 665 Foreign currency exchange risk The Company operates internationally and is exposed to risk arising from various currency exposures, primarily with respect to the Norwegian Kroner (NOK), the Tunisian Dinar (TND), the Pound Sterling (GBP) and the Central African Franc (CFA). 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 affects its consolidated income statement and balance sheet 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. The Group evaluates on a continuous basis to use cross currency swaps if deemed appropriate by management in order to hedge the forward foreign currency risk. The group used no currency derivatives/swaps during 2024 or 2023. A 20% strengthening or weakening of the USD against the following currencies at the balance sheet dates presented would have increased / (decreased) equity and profit or loss 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 financial markets. This hypothetical analysis assumes that all other variables, including interest rates and commodity prices, remain constant. USD 000 2024 2023 USD vs NOK 20% -20% 20% -20% Cash 10 (16) 14 (21) Receivables - - 3 (5) Payables (115) 172 (20) 30 Net effect (105) 156 (3) 5 USD vs TND 20% -20% 20% -20% Cash 543 (814) 617 (925) Receivables 190 (285) 242 (363) Corporation taxes payable - - (2,112) 3,168 Payables (3,338) 5,007 (1,420) 2,130 Net effect (2,605) 3,908 (2,673) 4,010 USD vs EUR 20% -20% 20% -20% Cash 3 (5) 21 (32) Receivables - - 1 (2) Payables (45) 67 (38) 57 Net effect (42) 62 (16) 24
USD 000 2024 2023 USD vs GBP 20% -20% 20% -20% Cash 19 (29) 54 (81) Receivables 73 (109) (78) 116 Payables (252) 378 (55) 83 Net effect (160) 240 (79) 118 USD vs CFA 20% -20% 20% -20% Cash 310 (465) - - Receivables 1,652 (2,478) - - Payables (1,207) 1,811 - - Net effect 755 (1,132) - -
",
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"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
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},
"reg-ix-468": {
"value": "Credit risk The Group is exposed to credit risk that arises from cash and cash equivalents, derivative financial instruments and deposits with banks and financial institutions, as well as credit exposures to customers, including outstanding receivables and committed transactions. For banks and financial institutions, only independently rated parties with a minimum rating of \u201cA\u201d are accepted. Any change of financial institutions (except minor issues) are approved by the Group CFO. The Company may engage with counterparties of a lower rating, for commercial reason, or by taking lower exposures in such counterparties to mitigate the risks following necessary approvals. If the Group\u2019s customers are independently rated, these ratings are used. Otherwise, if there is no independent rating, risk control in the operating units assesses the credit quality of the customer, taking into account its financial position, past experience and other factors. The utilisation of credit limits is regularly monitored and kept within approved budgets.
",
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"reg-ix-469": {
"value": "Liquidity risk Liquidity risk is the risk that the Group will not be able to meet its obligations as they fall due. Prudent liquidity risk management includes maintaining sufficient cash and marketable securities, the availability of funding from an adequate amount of committed credit facilities and the ability to close out market positions. The table below summarises the maturity profile of the Group\u2019s financial liabilities at 31 December based on contractual undiscounted payments. 2024 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Secured loans) - 854 150,000 - 150,854 Accounts payable and accrued liabilities - 28,582 - - 28,582 Non-current liabilities - - 15,130 14,732 29,862 Corporation tax liabilities - 24,537 - - 24,537 Total - 53,973 165,130 14,732 233,835 2023 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Secured loans) - 26,420 44,033 - 70,453 Accounts payable and accrued liabilities - 25,543 - - 25,543 Non-current liabilities - - 119 3,648 3,767 Corporation tax liabilities - 34,381 - - 34,381 Total - 86,344 44,152 3,648 134,144 Management considers that the Group has adequate current assets and forecast cash from operations to manage liquidity risks arising from current and non-current liabilities. As of 31 December 2024, the Group\u2019s total debt was USD 145.9 million and oil revenue advances of nil. The Group closed the year with a cash position of USD 72.9 million. Although the Company is well funded to undertake upcoming work programmes, there is a risk that additional funding may be required to conclude such activities.
",
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"reg-ix-470": {
"value": "Capital Management The Group manages its capital structure to ensure that it remains sufficiently funded to support its business strategy and maximise shareholder value. 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\u2019s funding requirements are met through a combination of debt and equity and adjustments are made in light of changes in economic conditions. The Group\u2019s strategy is to maintain ratios in line with covenants associated with its Secured loans. The Group includes interest bearing loans less cash, cash equivalents and restricted cash in net debt. Capital includes share capital, share premium, other reserves and accumulated profits/losses. 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 that in the forthcoming year.
",
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"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
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"reg-ix-471": {
"value": "NOTE 21: GUARANTEES, PLEDGES AND CONTINGENT LIABILITIES Brazil The Company has provided a performance guarantee to the Brazilian directorate Ag\u00eancia Nacional do Petr\u00f3leo,G\u00e1s Natural e Biocombust\u00edveis (the \u201cANP\u201d), in terms of which the Company is liable for the commitments of Coral. Estela do Mar and Cavalo Marinho licenses in accordance with concession agreements. The guarantee is unlimited. Further, in Brazil, termination agreements for the surrender of all licences have been signed between the JV partners and the ANP to conclude the relinquishment formalities on each licence and as such the guarantee no longer has a significant exposure to the Company. The Company\u2019s formal exit from its historical Brazilian business is still ongoing with slow progress towards the approval of abandonment by the Brazilian regulators. Management is working actively with advisers and where relevant, the operator Petrobras, to bring matters to a close and to ensure that the ongoing costs are kept to a minimum. However, the timing and eventual costs of such conclusion is uncertain at this stage. Netherlands Under section 403(1)(f) Book 2 of the Dutch Civil Code, Pan-Petroleum Gabon B.V. (Chamber of Commerce number 27166816), a subsidiary of the Company have availed exemption for audit of its statutory financial statements pursuant to guarantees issued by the Company to indemnify the subsidiary of any losses towards third parties that may arise in the financial year ended 31 December 2024. The Company can make an annual election to support such guarantee for each financial year. Gabon The Company has a guarantee issued to the State of Gabon to fulfil all obligations under the Dussafu Production Sharing Contract. Other Pursuant to the Bond Terms, certain fully owned companies in the Group classified as Guarantors, have entered into a agreement to fulfil obligations under the Bond Terms. As part of the production sharing contract (\u201cPSC\u201d) in EG-01, the Company entered into a guarantee agreement with The Republic Of Equatorial Guinea (\u201cthe EG State\u201d) whereby the Company has guaranteed the performance of the contract by Panoro EG Exploration Limited (a wholly owned subsidiary) and the payment and timely compliance with all and any debts and obligations under the PSC to the EG State. As part of the production sharing contracts (\u201cPSCs\u201d) covering the Guduma Marin G4-264 and Niosi Marin G4-265 exploration blocks, the Company entered into a guarantee agreement with The Gabonese Republic (\u201cthe Gabon State\u201d) whereby the Company has guaranteed the performance of the contracts by Panoro Gabon Exploration Limited (a wholly owned subsidiary) and the payment and timely compliance with all and any debts and obligations under the PSCs to the Gabon State. Panoro 2B Limited, a wholly owned subsidiary, provided a limited guarantee of ZAR 2.7 million (approximately USD 0.3 million) in favour of the South African government for environmental rehabilitation of planned activities to be undertaken on ER 376 once final approvals are obtained. There is no potential claim against these performance guarantee and all license obligations are already accounted for in the statement of financial position.
",
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"reg-ix-472": {
"value": "NOTE 24: SUBSIDIARIES Details of the Group\u2019s subsidiaries as of 31 December 2024 are as follows: Subsidiary Place of incorporation and ownership Ownership interest & voting power Panoro Energy do Brasil Ltda Brazil 100% Panoro Energy Limited UK 100% African Energy Equity Resources Limited UK 100% Panoro 2B Limited UK 100% Panoro EG Exploration Limited UK 100% Pan-Petroleum (Holding) Cyprus Limited Cyprus 100% Pan-Petroleum Holding B.V. Netherlands 100% Pan-Petroleum Gabon B.V. Netherlands 100% Panoro Energy Holding B.V. Netherlands 100%
Subsidiary Place of incorporation and ownership Ownership interest & voting power Panoro Equatorial Guinea Limited Isle of Man 100% Panoro Gabon Exploration Limited Isle of Man 100% Energy Equity Resources AJE Limited Nigeria 100% Energy Equity Resources Oil and Gas Limited Nigeria 100% Syntroleum Nigeria Limited Nigeria 100% PPN Services Limited Nigeria 100% Energy Equity Resources (Cayman Islands) Limited Cayman Islands 100% Energy Equity Resources (Nominees) Limited Cayman Islands 100% Panoro Energy Gabon Production SA Gabon 100% Pan-Petroleum Oil & Gas Gabon SA Gabon 100% Sfax Petroleum Corporation AS Norway 100% Panoro Energy AS Norway 100% Panoro Tunisia Exploration AS Norway 100% Panoro Tunisia Production AS Norway 100% Panoro TPS Production GmbH\u2013- in liqu Austria 100% Panoro TPS (UK) Production Limited UK 100%
NOTE 24: SUBSIDIARIES Details of the Group\u2019s subsidiaries as of 31 December 2024 are as follows: Subsidiary Place of incorporation and ownership Ownership interest & voting power Panoro Energy do Brasil Ltda Brazil 100% Panoro Energy Limited UK 100% African Energy Equity Resources Limited UK 100% Panoro 2B Limited UK 100% Panoro EG Exploration Limited UK 100% Pan-Petroleum (Holding) Cyprus Limited Cyprus 100% Pan-Petroleum Holding B.V. Netherlands 100% Pan-Petroleum Gabon B.V. Netherlands 100% Panoro Energy Holding B.V. Netherlands 100%
Subsidiary Place of incorporation and ownership Ownership interest & voting power Panoro Equatorial Guinea Limited Isle of Man 100% Panoro Gabon Exploration Limited Isle of Man 100% Energy Equity Resources AJE Limited Nigeria 100% Energy Equity Resources Oil and Gas Limited Nigeria 100% Syntroleum Nigeria Limited Nigeria 100% PPN Services Limited Nigeria 100% Energy Equity Resources (Cayman Islands) Limited Cayman Islands 100% Energy Equity Resources (Nominees) Limited Cayman Islands 100% Panoro Energy Gabon Production SA Gabon 100% Pan-Petroleum Oil & Gas Gabon SA Gabon 100% Sfax Petroleum Corporation AS Norway 100% Panoro Energy AS Norway 100% Panoro Tunisia Exploration AS Norway 100% Panoro Tunisia Production AS Norway 100% Panoro TPS Production GmbH\u2013- in liqu Austria 100% Panoro TPS (UK) Production Limited UK 100%
",
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"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2024-01-01T00:00:00/2025-01-01T00:00:00"
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"reg-ix-474": {
"value": "NOTE 25: EVENTS SUBSEQUENT TO REPORTING DATE On 24 February 2025, the Board of Directors approved a cash distribution to shareholders of NOK 80 million (approximately USD 7.7 million) in the form of repayment of capital, equating to NOK 0.684 per share to shareholders holding shares in the Company at the end of trading on 4 March 2025. Payment took place on or around 12 March 2025.
",
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}