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"value": "NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 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 South Africa. The consolidated financial statements of the Group for the year ended 31 December 2022 were authorised for issue by the Board of Directors on 27 April 2023. The Board of Directors confirms that the annual financial statements have been prepared pursuant to the going concern assumption, in accordance with \u00a73-3a of the Norwegian Accounting Act, and that this assumption was realistic as at the balance sheet date. The going concern assumption is based upon the financial position of the Company and the development plans currently in place. In the Board of Directors\u2019 view, the annual accounts give a true and fair view of the group\u2019s asset s and liabilities, financial position and results. Panoro Energy ASA is the parent company of the Panoro Group. Its financial statements have been prepared on the assumption that Panoro Energy will continue as a going concern. As of 31 December 2022, the Group had USD 32.7 million in cash and bank balances and debt of USD 79.5 million resulting in a net debt position of approximately USD 46.8 million. In addition to Block G and Dussafu capital expenditure, the Company is committed to progress activities on Block EG-01 and Block S in Equatorial Guinea. Although the Company is well funded to undertake upcoming capital expenditure, there is risk that additional funding may be required to conclude such activities. Should additional funding be required in the future for additional capital expenditure for new development phases or working capital requirements, the Company has various alternatives available which it can explore to fulfil such additional requirements. Options include, amongst others, offtake prepayment structures, utilisation of undrawn financing facility and the issuance of shares. As a result, these financial statements have been prepared under the assumption of going concern and realisation of assets and settlement of debt in normal operations. The Company\u2019s shares are traded on the Oslo Stock Exchange under the ticker symbol PEN. NOTE 2: BASIS OF PREPARATION The consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards (IFRS) 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. 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 2.2: 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 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. 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 as adopted by the EU requires 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 Note 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 liabiliies 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 r esults, 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 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 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: 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. 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. Note 2.4: Summary of significant accounting policies 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 Corp\u201d). Sfax Corp, 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. 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 Joint ventures A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. The Group\u2019s investment in its joint venture is accounted for using the equity method. Under the equity method, the investment in the joint venture is initially recognised at cost. The carrying amount of the investment is adjusted to recognise changes in the Group\u2019s share of net assets of the joint venture since the acquisition date. Goodwill relating to the joint venture is included in the carrying amount of the investment and is not individually tested for impairment. The statement of profit or loss reflects the Group\u2019s share of the results of operations of joint ventures. Unrealised gains and losses resulting from transactions between the Group and the joint venture are eliminated to the extent of the interest in the joint venture. The aggregate of the Group\u2019s share of profit or loss of the joint venture is shown on the face of the statement of profit or loss and other comprehensive income as part of operating profit and represents profit or loss after tax and NCI in the subsidiaries of the joint venture. The financial statements of the joint venture are prepared for the same reporting period as the Group. When necessary, adjustments are made to bring the accounting policies in line with those of the Group. At each reporting date, the Group determines whether there is objective evidence that the investment in the joint venture is impaired. If there is such evidence, the Group calculates the amount of impairment as the difference between the recoverable amount of the joint venture and its carrying value, and then recognises the loss as \u2018Share of profit of a joint venture\u2019 in the statement of profit or loss and other comprehensive income. On loss of joint control over the joint venture, the Group measures and recognises any retained investment at its fair value. Any difference between the carrying amount of the joint venture upon loss of joint control and the fair value of the retained investment and proceeds from disposal is recognised in the statement of profit or loss and other comprehensive income. 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: 2022 2021 Average rate Reporting date rate Average rate Reporting date rate Norwegian Kroner / USD 9.6149 9.8394 8.6002 8.8245 USD / British Pound Sterling 1.2367 1.2039 1.3755 1.3477 USD / Tunisian Dinar 3.0838 3.2482 2.7963 2.8865 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 non-controlling interest (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 administ rative 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. 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 i t 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 tangible and intangible 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 and intangible assets 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 esti mated 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 a re 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. 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 9.2: Impairment in Oil and Gas Interests. 2.4.5 Non-current assets held for sale or for distribution to equity holders of the parent and discontinued operations The Group classifies non-current assets and disposal groups as held for sale or for distribution to equity holders of the parent if their carrying amounts will be recovered principally through a sale or distribution rather than through continuing use. Such non- current assets and disposal groups classified as held for sale or as held for distribution are measured at the lower of their carrying amount and fair value less costs to sell or to distribute. Costs to distribute are the incremental costs directly attributable to the distribution, excluding the finance costs and income tax expense. The criteria for held for distribution classification is regarded as met only when the distribution is highly probable and the asset or disposal group is available for immediate distribution in its present condition. Actions required to complete the distribution should indicate that it is unlikely that significant changes to the distribution will be made or that the distribution with be withdrawn. Management must be committed to the distribution expected within one year from the date of the classification. Similar considerations apply to assets or a disposal group held for sale. Production assets, property, plant and equipment and intangible assets are not depreciated or amortised once classified as held for sale or as held for distribution. Assets and liabilities classified as held for sale or for distribution are presented separately as current items in the statement of financial position. A disposal group qualifies as discontinued operation if it is: \u2022 a component of the Group that is a CGU or a group of CGUs \u2022 classified as held for sale or distribution or already disposed in such a way, or \u2022 a major line of business or major geographical area. Discontinued operations are excluded from the results of continuing operations and are presented as a single amount as profit or loss after tax from discontinued operations in the statement of profit or loss. 2.4.6 Financial instruments 2.4.6.1 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. 2.4.6.2 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. Cash held for Bank guarantee - restricted Cash held for Bank guarantee relates to resources or collateral held by a bank which can only be accessed through fulfilment of conditions imposed by counter parties. Funds are only classified from restricted cash status to cash equivalents when funds are transferred to and under the control of the Group. 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 in terest 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. 2.4.6.3 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. 2.4.7 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. 2.4.8 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. 2.4.9 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. 2.4.10 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. 2.4.11 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. 2.4.12 Leases At contract inception, an assessment is made of all arrangements to determine whether they are, or contain, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Group is not a lessor in any transactions, it is only a lessee. The Group applies a single recognition and measurement approach for all leases, except for short-term leases of 12 months or less and leases of low-value assets. The Group recognises lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets. Right-of-use assets The Group recognises right-of-use assets at the commencement date of the lease (i.e., the date the underlying asset is available for use). Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. The only right-of-use asset, the London office lease, is depreciated on a straight-line basis over the lease term. If ownership of the leased asset transfers to the Group at the end of the lease term or the cost reflects the exercise of a purchase option, depreciation is calculated using the estimated useful life of the asset. 2.4.13 Property, plant and equipment Property, plant and equipment not associated with exploration and production activities are carried at cost less accumulated depreciation. These assets are also evaluated for impairment. Depreciation of other assets is calculated on a straight-line basis as follows: Computer equipment: 20 to 33.33% Furniture, Fixtures & fittings: 10 to 33.33% 2.4.14 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. 2.4.15 Defined contribution pension plan The Group pays contributions into a defined contribution plan. Obligations for contributions to defined contribution pension plans are recognised as an expense in the income statement in the periods during which services are rendered by employees. 2.4.16 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. 2.4.17 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. 2.4.18 Current versus non-current classification The Group presents assets and liabilities in the statement of financial position based on current/non-current classification. An asset is current when it is either: \u2022 Expected to be realised or intended to be sold or consumed in the normal operating cycle \u2022 Held primarily for the purpose of trading \u2022 Expected to be realised within 12 months after the reporting period \u2022 Cash or cash equivalent unless restricted from being exchanged or used to settle a liability for at least 12 months after the reporting period All other assets are classified as non-current. A liability is current when either: \u2022 It is expected to be settled in the normal operating cycle \u2022 It is held primarily for the purpose of trading \u2022 It is due to be settled within 12 months after the reporting period \u2022 There is no unconditional right to defer the settlement of the liability for at least 12 months after the reporting period The Group classifies all other liabilities as non-current. Deferred tax assets and liabilities are classified as non-current assets and liabilities. Note 2.5: New and amended standards and interpretations No standard amendments or interpretations of standards effective as of 1 January 2022 and adopted by Panoro, were material to the Group\u2019s Consolidated financial statements upon adoption. Note 2.6: Standards issued but not yet effective At the date of these Consolidated financial statements, standards amendments to standards, and interpretations of standards, issued but not yet effective, are either not expected to materially impact Panoro\u2019s Consolidated financial statements, or are not expected to be relevant to Panoro's Consolidated financial statements upon adoption. The Group has not early adopted any other standard, interpretation or amendment that was issued but is not yet effective. 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. As noted above, from December 2019, the business in Nigeria is classified as a \u201cDiscontinued Operation\u201d and as an \"Asset held for sale\u201d. Segment information has therefore been re-arranged in line with reporting requirements for such item. 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. This interest was acquired from Tullow Overseas Holdings B.V. on 31 March 2021. \u2022 The Gabon segment holds the Dussafu licence representing the Group\u2019s 17.4997% working interest in the Dussafu Marin exploration licence in Gabon. This includes an additional 10% working interest acquired from Tullow Oil Gabon SA on 9 June 2021. \u2022 The Tunisia segment holds the following assets: - Sfax Offshore Exploration Permit: Panoro Tunisia Exploration AS (Operator, 52.5%* interest net to Panoro) - The Hammamet Offshore Exploration Permit: Medco (Operator), Panoro Tunisia Exploration AS (27.6%* interest net to Panoro), under relinquishment - TPS Assets: ETAP, 51% and Panoro TPS Production GmbH, 49% (29.4%* interest net to Panoro). * Figures only represent net participation interest in proportion to Panoro\u2019s equity holding in Sfax Petroleum Corporation AS. \u2022 The \u2018South Africa\u2019 segment holds the following assets: - The Block 2B licence representing the Group\u2019s 12.5% working interest - 100% interest in the Karoo Technical Cooperation Permit 218, South Africa \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. \u2022 Discontinued Operations and Assets held for sale: - OML113-Aje represents the Group\u2019s 12.1913% revenue interest, 16.255% paying interest and 6.502% participating interest) in the OML113-Aje exploration licence in Nigeria. 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. Details of Group segments are reported below: 2022 USD 000 Equatorial Guinea Gabon Tunisia South Africa Corporate Total - continuing operations Aje-OML 113 discontinued operations Total Revenue (net) * 80,953 67,537 40,136 - - 188,626 1,181 189,807 EBITDA 66,106 37,835 28,780 (596) (4,937) 127,188 1,498 128,686 Depreciation (23,778) (7,068) (4,002) - (316) (35,164) - (35,164) Impairment (charge)/reversal - - - - - - 1,497 1,497 Profit/(loss) before tax 37,425 30,251 17,877 (10,048) (15,081) 60,424 1,258 61,682 Net Profit/(loss) 19,500 21,889 2,377 (10,048) (15,083) 18,635 1,258 19,893 Segment assets ** 240,423 219,544 60,849 17 18,512 539,345 - 539,345 Additions to licences, production, E&E and development assets *** 6,985 37,447 597 - - 45,029 - 45,029 2021 USD 000 Equatorial Guinea Gabon Tunisia South Africa Corporate Total - continuing operations Aje-OML 113 discontinued operations Total Revenue (net) * 51,563 41,734 26,360 - - 119,657 3,688 123,345 EBITDA 37,702 21,519 10,326 - (5,846) 63,701 7,455 71,156 Depreciation (18,236) (3,807) (5,271) - (236) (27,550) - (27,550) Impairment (charge)/reversal - - - - - - 8,000 8,000 Profit/(loss) before tax 15,649 63,279 (2,926) - (12,611) 63,391 7,011 70,402 Net Profit/(loss) 7,384 57,330 (9,775) - (12,627) 42,312 7,011 49,323 Segment assets 286,974 188,392 60,481 - 19,805 555,652 29,015 584,667 Additions to licences, production, E&E and development assets *** 213,315 126,261 568 - 11 340,155 298 340,453 * Revenue excludes any intercompany revenue. ** Refer to Note 14: Discontinued Operations for segment assets related to discontinued operations (OML 113, Aje). *** Excludes effect on production assets and equipment of the reasessment of decommissioning liabilities of USD 16.9 million in 2022, refer to Note 15: Asset Retirement Obligation. Includes additions from acquisitions, see Note 13: Business Combinations, but excludes reversal of impairment of USD 1.2 million (2021: USD 8 million). Revenue from major sources from continuing operations: USD 000 2022 2021 Oil revenue (net) 180,267 113,708 Other revenue 8,359 5,949 Total revenue 188,626 119,657 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 international sales of the Group in Tunisia during 2022 were to a single customer, Mercuria Energy Trading SA, through a crude marketing agreement. All sales in 2022 from the Group\u2019s production from Block G in Equatorial Guinea and Dussafu in Gabon arose from one key customer each. Under the terms of the Dussafu PSC, State profit oil is estimated and shown as other revenue with a corresponding amount as income tax, see Note 2.4.10 Income tax. There are no other items included in other revenue for both periods presented. NOTE 4: OPERATING RESULT Operating profit is stated after charging/ (crediting): USD 000 Note 2022 2021 Employee benefits expense 5,332 4,166 Depreciation 8, 9 35,164 27,550 Acquisition and project related costs (i) 1,054 1,254 (i) Acquisition and project related costs in 2022 of USD 0.6 million relate organisational restructure in Tunisia and the remaining USD 0.4 million, to business development activities. In 2021, costs of USD 1.1 million were incurred on the Equatorial Guinea and Dussafu acquisitions as described in Note 13: Business Combinations. Note 4.1: Exploration related costs The Gazania-1 exploration well located at Block 2B offshore the Northern Cape in Orange Basin, South Africa, was drilled without incident. The well did not encounter commercial hydrocarbons. As a result capitalised exploration costs of USD 9.2 million were written off during the year. In 2021 a historical non-fulfilment of a work programme related to Sfax Offshore Exploration Permit by a previous operator was settled during 2021 at a cost of USD 6.3 million. The settlement was made by way of a partial draw on the bank guarantee wih the remaining remaining USD 3.6 million cancelled and cash returned to Panoro. As part of the settlement, the license entered the second renewal period of one year which was later extended a further two years on the condition that a seismic reprocessing project would be completed. Note 4.2: Employee benefit expenses General and administrative expenses include wages, employer\u2019s contribution and other compensation as detailed below: USD 000 2022 2021 Salaries 4,283 3,423 Employers' contribution 588 555 Pension costs 235 118 Other compensation 226 70 Total 5,332 4,166 The number of employees in the Group as at year end is detailed below: 2022 2021 Number of employees 25 29 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 (2022) 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 104 of this report. Note 4.4: Management remuneration Executive management consists of the Chief Executive Officer (CEO), Chief Financial Officer (CFO) and two other Named Executives as described below. Current Executive management remuneration is summarised below: 2022 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2022 Fair value of RSUs expensed John Hamilton, CEO 472 181 11 5 669 131,772 512 Qazi Qadeer, CFO 311 119 5 5 440 64,983 195 Other Named Executives (vi) 596 227 10 12 845 127,014 382 Total 1,379 527 26 22 1,954 323,769 1,089 2021 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2021 Fair value of RSUs expensed John Hamilton, CEO 484 595 12 5 1,096 166,822 483 Qazi Qadeer, CFO 317 330 5 5 658 54,846 157 Other Named Executives (vi) 606 359 10 13 988 107,198 302 Total 1,407 1,285 27 23 2,742 328,866 942 (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. Other Named Executives have notice periods between three and six months. (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 July 2022, 487,434 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. The 2021 bonus included a one-off discretionary cash award to key management by the Board of Directors in recognition of the success of Transformational Tullow acquisitions, which increased Panoro\u2019s production and reserves by a factor of 3-4 times. (v) All bonuses were approved by the Board of Directors. (vi) Remuneration details for Other Named Executives include Mr. Richard Morton (Technical Director) and Mr. Nigel McKim (Projects Director). 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: USD 000 2022 2021 Julien Balkany (Chairman of the Board of Directors) 102 82 Torstein Sanness (Deputy Chairman of the Board of Directors) 68 57 Grace Reksten Skaugen 38 0 Alexandra Herger 62 48 Garrett Soden 61 50 Hilde \u00c5dland 58 48 Total 388 285 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 2022, the Company had no employees at parent company level and this pension plan is no longer in operation (31 December 2021: 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 for 2022 and 2021, 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 2022 2021 Ernst & Young Statutory Audit 281 280 Total Audit Services 281 280 Non-audit Services Corporate financial services including pre-acquisition due diligence - - Total non-audit services - - Total 281 175 NOTE 5: FINANCE , INTEREST AND OTHER INCOME AND EXPENSE [P- USD 000 2022 2021 Unrealised (gain) / loss on commodity hedges (Note 19) (2,622) 3,868 Realised (gain) / loss on commodity hedges (Note 19) 8,534 4,354 Interest income from placements and deposits (57) (77) Interest expense - Loans and borrowings 9,536 6,895 Interest expense - Bank guarantee - 199 Unrealised (gain) / loss on listed equity investments (Note 11) 75 - Realised (gain) / loss on listed equity investments (Note 11) 652 Other financial costs - Bank charges and ARO unwinding 4,193 2,822 Total - Net (income) / expense 20,311 18,061 --WSHYG Note 5.1: Loans and borrowings Note 5.1.1 Mercuria senior secured loan In 2018, the Group entered into an agreement with Mercuria Assets Holdings (Hong Kong) Ltd (\u201cMercuria\u201d), whereby Mercuria provided PTP (60% owned by Panoro) an acquisition loan facility comprising a Senior Secured Loan facility of USD 16.2 million (USD 27 million gross) which was fully drawn. The Senior Loan facility initially had term of 5 years with interest charged at USD 3-month LIBOR plus 6% on quarterly amounts drawn, with repayments due each quarter. Interest of USD 0.2 million (USD 0.3 million gross) was accrued up to 31 December 2022 (31 December 2021: USD 0.2 million). On 25 June 2019, the Group and Mercuria mutually agreed to make minor adjustments to the Facility terms, resulting in the Facility amount increasing by USD 2.5 million (USD 4.1 million gross) to USD 18.7 million (USD 30 million gross). As part of the security package for the enhanced facility size, shares in Panoro Energy AS (holding company for Panoro Tunisia Exploration AS) have been pledged as collateral. The amended Senior Loan facility has a term of 5 years from 30 June 2019 with interest charged at USD 3-month LIBOR plus 6% on the balance outstanding, with repayments due each quarter. Key financial covenants were unchanged as a result of the amendment and are required to be tested at the end of every 3- month period. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include the following: (i) Field life coverage ratio (FLCR): 1.50x (ii) Minimum cash balance equal to the amount of the next loan and interest repayment, varying as the loan is repaid but typically around USD 1.2 million (USD 2 million gross) to be maintained at all times in the collection account of the borrower. (iii) Debt service coverage ratio (DSCR): between 1.15x and 1.25x subject to specifications in the loan agreement. (iv) Liquidity Test: Customary to the loan instrument. Security package for the original Senior Secured loan comprised a Guarantee from Panoro Energy ASA, share pledge over shares in Panoro TPS (UK) Production Limited and Panoro TPS Production GmbH and from Sfax Petroleum Corporation AS, shareholder and intercompany loans (subordinated at all times), rights under hedging agreements, and the Account Management Agreement (for the Collection Account), negative pledge over the assets. In an event, the guarantee placed by Panoro Energy ASA is called upon, the shareholders\u2019 agreement with Beender for the ownership on Sfax Petroleum Corporation AS provides that Sfax Petroleum Corporation AS shall indemnify Panoro Energy ASA. If Sfax Petroleum Corporation AS is unable to indemnify, Panoro Energy ASA, such indemnification, pro rata to its ownership, shall be made by Beender. As part of the amendment in June 2019 as noted above, the security package for the enhanced facility size was amended to also include a pledge over the shares in Panoro Energy AS (holding company for Panoro Tunisia Exploration AS). The Mercuria loan was repaid in full on 15 March 2023 by the Group and all security held in relation to the loan was released at that date, refer to Note 25: Events subsequent to reporting date. Current and non-current portion of the outstanding balance of the Mercuria Senior Secured facility as of the date of the statement of financial position attributable to Panoro\u2019s 60% ownership is as follows: USD 000 31 December 2022 31 December 2021 Current Non-current Total Current Non-current Total Mercuria Senior Secured loan facility Principal outstanding 5,100 1,740 6,840 4,950 5,820 10,770 Accumulated interest accrued 170 - 170 169 - 169 Unamortised borrowing costs (55) (8) (63) (103) (63) (166) 5,215 1,732 6,947 5,016 5,757 10,773 Note 5.1.2 Trafigura Secured Borrowing Base facility 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, to partially finance the EG Transaction and the Dussafu Transaction as described above. The loan has been made available in two tranches, Tranche A of up to USD 55 million in respect of the EG Transaction and Tranche B of up to USD 35 million in respect of the Dussafu Acquisition. Tranche A and Tranche B can be drawn separately and are not conditional on each other. The drawn-down amount under the loan will amortise over a period of 5 years and carries an annual interest rate of USD 3-month LIBOR plus 7.5%. An accordion option for an additional USD 50 million is included alongside and in addition to the acquisition finance facilities. On 30 March 2021, Panoro drew down against Tranche A of the facility, borrowing USD 55 million which was utilised to partially pay for the purchase consideration of the EG Transaction as described above, and the balance funded from the proceeds of the equity private placement of the Company shares that completed in the first quarter of this year. On 9 June 2021, Panoro drew down against Tranche B of the facility, borrowing USD 35 million which was utilised to partially pay for the purchase consideration of the Dussafu Transaction as described above. The amended Senior Loan facility has a term of 5 years from 31 March 2021 with interest charged and paid quarterly at USD 3-month LIBOR plus 7.5% on the balance outstanding, with principal repayments due each six months. Key financial covenants are required to be tested 30 September and 31 March. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include 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) The Group was not in breach of any financial covenants as at 31 December 2022. Un-amortised borrowing costs include structuring fees and directly attributable third-party costs. During the current quarter, these costs are expensed using an effective interest rate of 11.74% per annum over the remaining term of the facility. Subsequent to year-end, the Company has increased its facility by USD 15 million in conjunction with acquisition of 40% interest in Sfax Petroleum Corporation AS. See Note 25: Events subsequent to reporting date for further details. Current and non-current portion of the outstanding balance of the Trafigura Secured Borrowing Base facility as of the date of the statement of financial position is as follows: USD 000 31 December 2022 31 December 2021 Current Non- current Total Current Non- current Total Trafigura Secured Borrowing Base facility Principal outstanding 16,200 57,600 73,800 10,800 73,800 84,600 Accumulated interest accrued - - - - - - Unamortised borrowing costs (918) (950) (1,868) (1,102) (1,868) (2,970) 15,282 56,650 71,932 9,698 71,932 81,630 Note 5.1.3 BW Energy non-recourse loan The Group has in place a non-recourse loan from BW Energy in relation to the funding of the Dussafu development. The loan bears interest at 7.5% per annum on outstanding balance, compounded annually. The balance outstanding at each balance sheet date presented is as below: USD 000 31 December 2022 31 December 2021 Current Non-current Total Current Non- Current Total BW Energy Non-Recourse loan Principal outstanding - - - 2,234 - 2,234 Accumulated interest accrued 632 - 632 2,273 - 2,273 632 - 632 4,507 - 4,507 The loan is repayable through Panoro\u2019s allocation of the cost oil in accordance with the Dussafu PSC, after paying for the proportionate field operating expenses and as such the loan is classified as current or non-current based on expected field production and lifting schedule at a reasonable oil price assumption at the time of making such classification. During the repayment phase, Panoro is still entitled to its share of profit oil, as defined in the PSC, from the Dussafu operations. The remaining balance of the BW Energy loan was repaid on 21 March 2023. 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 2022 2021 At 1 January 99,756 20,392 Cash flows: Drawdown of Secured Loans, net of fees - 90,000 Repayment of Secured Loans (14,730) (13,384) Repayment of non-recourse loan (4,065) (3,106) Realised gain/(loss) on commodity hedges (7,689) (2,668) Borrowing costs, including arrangement fees (8,141) (4,689) Lease liability payments (231) (254) Non cash changes: Unwinding of unamortised borrowing cost and finance charges 1,324 1,123 Interest accrued 8,232 5,812 Movement in unrealised hedges 5,200 6,536 Initial recognition lease under IFRS 16 - - Foreign exchange movements (32) (6) At 31 December 79,394 99,756 NOTE 6: 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 2022 2021 Income Taxes Current income tax (i) 12,834 6,541 PSC based Profit Oil allocation \u2013 current (ii) 8,359 5,949 PSC based income tax - current (iii) 27,420 10,417 Deferred tax expense / (benefit) (iv) (6,827) (1,838) Tax relating to prior years income 3 10 Tax charge / (benefit) for the period 41,789 21,079 (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 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 2022 2021 Profit/ (loss) before taxation \u2013 continuing operations 60,721 63,391 Profit / (loss) before taxation \u2013 discontinued operations 961 7,011 Profit / (loss) before taxation - total 61,682 70,402 Tax/ (tax loss) calculated at domestic tax rates applicable to profits in the respective countries 54,456 35,423 Expenses not deductible (43,919) (29,365) Expenses deductible for tax (3) (669) Deferred tax arising on taxable temporary differences (1,088) 313 PSC based Profit Oil allocation 35,779 16,366 Tax effect of prior years' losses utilised in the period (5,739) (2,151) Tax effect of losses not utilised in the period 2,300 1,152 Prior year adjustment 3 10 Tax charge / (benefit) 41,789 21,079 Tax Liabilities Tax liabilities payable of USD 35.6 million as of 31 December 2022 comprised of taxes payable in Equatorial Guinea of USD 25.8 million and Tunisia of USD 9.7 million for production from various concessions (31 December 2021: USD 17 million comprised of taxes payable in Equatorial Guinea of USD 12.3 million and Tunisia of USD 4.7 million). Advantage was taken in Tunisia of a incentives with a tax value of USD 9.2 million that require investment in government approved projects within four years. Investment plans are being considered and formalised for implementation within the allowed timeframe. Deferred tax Deferred tax benefit of USD 6.8 million recognised during the year comprises of USD 9.5 million benefit in Equatorial Guinea, offset by a USD 2.7 million expense in Tunisia arising on taxable temporary differences between accounting and tax bases of property, plant and equipment. Effective tax rate of the respective petroleum concessions has been used to calculate such liability. The deferred tax liability of USD 67.2 million as of 31 December 2022 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 and Tunisia. There are no recognised deferred tax assets in the Group financial statements as of 31 December 2022 (31 December 2021: 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 6.9 million (2021: USD 6.7 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 2022 2021 Panoro Energy ASA 12,839 21,591 Panoro Energy Limited - 486 Sfax Petroleum Corporation (at 60%) 18,530 8,802 Total 31,369 30,879 NOTE 7: 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. 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. Amounts in USD 000, unless otherwise stated 2022 2021 Net profit/(loss) attributable to equity holders - Total 19,893 49,323 Net profit/(loss) attributable to equity holders - Continuing operations 18,635 42,312 Weighted average number of shares outstanding - in thousands 113,538 105,452 Diluted weighted average number of shares outstanding - in thousands 115,890 106,611 Basic earnings/(loss) per share (USD) - Total 0.18 0.47 Diluted earnings/(loss) per share (USD) - Total 0.17 0.46 Basic earnings/(loss) per share (USD) - Continuing operations 0.16 0.40 Diluted earnings/(loss) per share (USD) - Continuing operations 0.16 0.40 NOTE 8: INTANGIBLE ASSETS Note 8.1: Licenses, Exploration and Evaluation Assets, Development Assets 2022 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2022 51,752 46,361 Additions 168 27,137 Transfer to Development Assets (49,325) 49,325 At 31 December 2022 2,595 122,823 Net carrying value at 31 December 2022 2,595 122,823 2021 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2021 21,070 14,522 Additions 2,058 24,129 Transfer to Production Assets - (12,407) Additions through Acquisition 28,624 20,117 At 31 December 2021 51,752 46,361 Net carrying value at 31 December 2021 51,752 46,361 Licence area Panoro\u2019s interest Country Expiry of current phase Block G 14.25% Equatorial Guinea December 2040 Dussafu Marin permit* 17.4997% Gabon September 2028* Sfax Offshore Exploration Permit** 52.5% (Operator) \u2013 excluding Beender\u2019s 40% Tunisia December 2024 Hammamet Offshore Exploration Permit 27.6% - excluding Beender\u2019s 40% Tunisia Under relinquishment Block S 12% Equatorial Guinea December 2024 Block EG-01 56% Equatorial Guinea February 2026 TCP 12/2/218 100% South Africa June 2023 Block 2B *** 12.5% South Africa November 2022 TPS Assets: Cercina February 2024 Cercina South November 2034 Gremda / El Ain ** 29.4% - excluding Beender\u2019s 40% Tunisia December 2018 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. Note 8.2: Production rights USD 000 2022 2021 Acquisition cost At 1 January 188,832 26,475 Depreciation charge for the year (18,307) (14,319) Additions through Acquisition - 172,676 Other additions 3,450 4,000 At 31 December 173,975 188,832 Note 8.3: Goodwill USD 000 2022 2021 Acquisition cost At 1 January 47,762 - Additions through Acquisition - 47,762 At 31 December 47,762 47,762 The Group acquired a 14.25% working interest in Block G, Equatorial Guinea during 2021, assets and liabilities were taken on at fair value and Goodwill of USD 47.8 million recognised as described in Note 13: Business Combinations. An annual impairment assessment was carried out in December 2022 at which time the total carrying value of Block G at 31 December 2022 was USD 127.4 million. 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 and using the discount rate of 12% and long-term oil price assumption of USD 80/bbl, inflated by 2% per annum after five years. 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 Block G asset to materially exceed its recoverable amount. NOTE 9: TANGIBLE ASSETS Note 9.1: Production Assets and Equipment USD 000 2022 2021 Historical cost At 1 January 141,362 40,904 Additions 15,732 10,306 Write-offs (184) (417) Adjustments to asset retirement estimates (22,163) (12,047) Transfer from Development Assets - 12,407 Additions through Acquisition (Note 12) - 90,209 At 31 December 134,747 141,362 Accumulated depreciation At 1 January 21,093 8,601 Write-offs (184) (417) Depreciation charge for the year 16,479 12,909 At 31 December 37,388 21,093 Net carrying value at 31 December 97,359 120,269 Note 9.2: 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 assumtion of USD 80/bbl with a 2% annual inflation after five years. No indication of impairment was identified and no impairment was therefore recognised during the year 2022. Dussafu, Gabon The Group has a 17.4997% interest in the Dussafu Permit, offshore Gabon. An assessment was performed using an oil price assumtion of USD 80/bbl with a 2% annual inflation after five years. No indication of impairment was identified and no impairment was therefore recognised during the year 2022. Sfax Offshore Exploration Permit, Tunisia The Group has an interest in Sfax Offshore Exploration Permit (SOEP). Qualifying directly attributable costs have been capitalised as licence and exploration assets during the year in line with Group\u2019s intention to drill an exploration well and extend the licence. TPS Assets, Tunisia The Group completed the acquisition of its share of interest in TPS Assets, comprising of Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba concessions in December 2018. The Group assesses each cash-generating unit annually to determine whether an indication of impairment exists An assessment was performed using the value of TPS assets derived from the agreed purchase of 40% of Sfax Petroleum Corporation AS by the Company as described in Note 25: Events subsequent to reporting date. . No indication of impairment was identified and no impairment was therefore recognised during the year 2022. OML 113 (Aje), Nigeria (Discontinued) In 2019, the Company entered into a sale and purchase agreement with PetroNor E&P Limited (\u201cPetroNor\u201d), an exploration & production oil and gas company listed on the Oslo Axess, to divest all outstanding shares in its fully owned subsidiaries Pan- Petroleum Services Holding BV and Pan-Petroleum Nigeria Holding BV (together referred to as \u201cDivested Subsidiaries\u201d) as described in Note 14: Discontinued Operations. Following agreement to sell the Divested Subsidiaries, the Group\u2019s interest in such subsidiaries were designated as Assets held for sale as of 31 December 2019. The transaction completed on 13 July 2022 at which time the Group derecognised the assets and liabilities of the Divested Subsidiaries at the carrying amounts. At the date of designation for held for sale during 2019, an assessment was made to determine the fair value of the assets and liabilities of the Divested Subsidiaries. As a result, based on fair value less costs to sell principle, a reversal of historical impairment charges of USD 8 million on account of Aje has been made. Further assessments were made in 2021 and 2022 resulting in a further reversal of USD 8 million and USD 1.2 million respectively of historical impairment charges to carrying value of the Divested Subsidiaries. The impairment reversals has been allocated in proportion of pre-reversal carrying value of licence and exploration assets and production assets and equipment. 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 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 (e.g., environmental taxes/fees) and estimation of future levels of environmental taxes. The Group\u2019s participation in the current licenses and concessions in various jurisdictions are not currently subject to specific carbon pricing. At the recent COP26 UN climate conference, member states explicitly acknowledged the importance of limiting global warming to less than 1.5\u00b0C, rather than the previous Paris Agreement target of \u2018well below 2\u00b0C\u2019. Despite these targets, global energy demand is projected to continue to grow rapidly, and emerging economies in Africa and other geographies are increasingly looking to their fossil resources to underpin economic growth, finance their own energy transition, and help to pay for urgently needed climate adaptation measures. Our strategy therefore aims to balance environmental, energy security and economic objectives by investing in efficient producing assets in North, West and South Africa, and working with our partners to support the transition to a low-carbon business. 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 2022 publication. The scenarios with their key features are as follows: Net Zero Emissions (NZE) NZE requires global greenhouse gas (GHG) emissions to drop by around 50% by 2030, or 7% per year for the next 9 years, implying a rapid drop in oil & gas consumption, a massive push into renewable energy, big gains in energy efficiency, and rapid development and scaling-up of new technologies, including carbon capture. Another major focus is reducing methane emissions from fossil fuel operations. It also demands no further fossil fuel exploration and no new oil and gas production from fields beyond those already approved for development. Oil demand in NZE falls to 72 MMbbls/d in 2030 and 24 mmb/d by 2050. The decline is led by road transport, where 60% of all passenger cars sold globally are electric by 2030, and no new combustion engine cars are sold anywhere after 2035. Petrochemicals are the only area where demand increases and by 2050 accounts for 55% of all oil consumed. Prices fall along with demand, to USD 36/bbl in 2030 and USD 24/bbl in 2050. Announced Pledges (APS) APS assumes full implementation of countries\u2019 pledges announced under the Paris Agreement and updated ahead of COP26 in Glasgow, and estimates an average temperature rise of 2.1\u00b0C by 2050. Oil prices decline slightly from USD 64/bbl in 2030 to USD 60/bbl in 2050. Stated Policies (STEPS) STEPS has demand continuing to rise gradually, levelling off at 104 mmb/d in the mid-2030s; then declining very slightly to 103 mmb/d by 2050. A fall in demand from power generation is offset by increased consumption for road transport (around 6 mmb/d through to 2030) and robust demand from aviation, shipping and petrochemicals. Oil prices rise, reaching USD 82/bbl in 2030 and USD 95/bbl in 2050. 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. A summary of the impact of the different future oil price scenarios on NPV and reserves are as follows: Percentage reduction Net Zero Emissions (NZE) Announced Pledges (APS) Stated Policies (STEPS) NPV12 51% 22% 0% Reserves 30% 11% 2% 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 investme nt 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 9.3: Property, Furniture, Fixtures and Equipment 2022 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2022 138 923 162 946 2,169 Additions 5 23 - - 28 At 31 December 2022 143 946 162 946 2,197 Accumulated depreciation At 1 January 2022 14 825 122 658 1,619 Depreciation charge for the year 86 63 38 191 378 At 31 December 2022 100 888 160 849 1,997 Net carrying value at 31 December 2022 43 58 2 97 200 2021 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2021 - 830 160 946 1,936 Additions 138 93 2 - 233 At 31 December 2021 138 923 162 946 2,169 Accumulated depreciation At 1 January 2021 - 783 68 445 1,296 Depreciation charge for the year 14 42 54 213 323 At 31 December 2021 14 825 122 658 1,619 Net carrying value at 31 December 2021 124 98 40 288 550 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: ACCOUNTS AND OTHER RECEIVABLES USD 000 2022 2021 Trade receivables 16,516 54,351 Other receivables and prepayments 8,273 1,278 Underlift - Block G, Equatorial Guinea 10,320 - At 31 December 35,109 55,629 Accounts receivables are non-interest bearing and generally on 30 to 120 days payment terms. At 31 December 2022 and 2021, the allowance for impairment of receivables was USD Nil. Risk information for the receivable balances is disclosed in Note 20: Financial risk management. Other non-current assets amount to joint venture account balances of USD 7 million, prepayments of USD 1.2 million (31 December 2021: USD 1.2 million) and USD 0.1 million tenancy deposit for the UK office premises for both reporting periods. NOTE 11: LISTED EQUITY INVESTMENTS On completion of the disposal of Panoro\u2019s fully owned subsidiaries Pan-Petroleum Services Holdings BV and Pan-Petroleum Nigeria Holding BV described in Note 14: Discontinued Operations below, Panoro received upfront consideration of USD 10 million in the form of 96,577,537 newly allotted and issued shares in PetroNor E&P ASA (\u201cConsideration Shares\u201d). The Board of Directors resolved on 1 August 2022 to use its authorisation to approve a dividend in the form of the Consideration Shares. Each Panoro shareholder as at the record date received 0.849 PetroNor shares for each share held in Panoro, rounded downwards to the nearest whole share. Fraction shares were not distributed. Panoro retains an investment of 4,451,249 PetroNor shares (\u201cRetained Shares\u201d), representing a holding of approximately 0.31% of PetroNor share capital. The Retained Shares were in connection with obligation to withhold tax on dividends and such taxes have since be been settled in cash by the Company. The Retained Shares are accounted for as financial assets at fair value through profit and loss and disclosed as current financial asset, valued at the published market price at the end of the reporting period, with revaluation differences disclosed as other income or expense in the statement of comprehensive income. NOTE 12: CASH AND BANK BALANCES USD 000 2022 2021 Cash and cash equivalents 32,670 24,532 At 31 December 32,670 24,532 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 2022 (31 December 2021: Nil). NOTE 13: BUSINESS COMBINATIONS Note 13.1: EG Transaction On 31 March 2021, Panoro completed the acquisition of 100% of the shares of Panoro Equatorial Guinea Limited (\u201cPEGL\u201d) from Tullow Overseas Holdings B.V. (\u201cEG Seller\u201d), a fully owned subsidiary of Tullow Oil plc, for an initial cash considerati on of USD 88.8 million that includes customary completion adjustments. PEGL holds a 14.25% non-operated working interest in Block G that contains the Ceiba and Okume Complex assets, offshore Equatorial Guinea (the \u201cEG Assets\u201d). In addition to the initial cash consideration of USD 88.8 million, the EG Seller was also paid a USD 5 million deferred consideration upon completion of the Dussafu Transaction (see Dussafu Transaction below) in June 2021. EG Seller is also entitled to a potential contingent consideration of up USD 16 million, in aggregate, payable only in years where the average annual net production of the acquired interests is in excess of 5,500 bopd. Once this initial net production threshold has been reached, in that year, and for the four consecutive subsequent annual periods, annual contingent consideration of USD 5.5 million will be payable to EG Seller provided that the production threshold is met in such annual period and the average daily Dated Brent oil prices in respect of the annual period is in excess of USD 60/bbl, subject to the aforementioned cap of USD 16 million. If the combination had taken place at the beginning of the year, total revenue from continuing operations would have been USD 178.8 million and profit before tax from continuing operations for the Group would have been USD 89.9 million. The purchase consideration, as set out above, is summarised in the following table: Shares acquired USD 000 Cash consideration 100% 87,431 Deferred consideration * 5,000 Contingent consideration ** 5,019 Net assets acquired 97,450 * Deferred consideration was paid at the time of completion of the Dussafu Transaction. ** Fair value estimate of the contingent consideration, payable only upon meeting the aforementioned criteria. This amount will be reviewed in conjunction with the criteria on an ongoing basis. The fair values of the identifiable assets and liabilities of PEGL at the date of acquisition were as follows: Purchase price allocation USD 000 Assets Concessions 132,806 Goodwill acquired 1,280 Goodwill related to step up / deferred tax 46,482 Production assets and equipment 76,367 Materials inventory 9,990 Crude oil inventory 6,904 Trade receivables 59,135 Other current receivables 245 Total Assets 333,209 Liabilities Decommissioning liability 124,646 Deferred tax liability 58,780 Corporation tax liability 15,410 Crude oil overlift 31,174 Trade payables 5,749 Total liabilities 235,759 Net assets acquired 97,450 Cash flow on acquisition 87,431 For the first quarter of 2021, the operating cashflow of PEGL was USD 10 million before taxes of USD 0.8 million and primarily relates to payments of operating costs. In addition, USD 3.4 million of cash was spent on investing activities in relation to capital expenditure. All these items are already included in the final completion payment of USD 88.8 million. Since the acquisition date, the acquired business contributed revenue of USD 51.6 million and profit before tax of USD 17.6 million to the consolidated statement of comprehensive income. Note 13.2: Dussafu Transaction On 9 February 2021, Panoro and its fully owned subsidiary Pan Petroleum Gabon BV, entered into an agreement with Tullow Oil plc and Tullow Oil Gabon SA to acquire a 10% working interest in the Dussafu Marin Permit, offshore Gabon for an initial cash consideration of USD 46 million based on an effective date of 1 July 2020 which was subject to customary working capital and other customary adjustments to be made at completion. Following completion of Dussafu Transaction in June 2021, Panoro\u2019s total working interest in Dussafu has increased to 17.4997% working interest in Dussafu. At the completion date of 9 June 2021, a total cash consideration of USD 39 million paid to Tullow Oil Gabon SA which included completion and working capital adjustments as of such date. A further contingent consideration of up to USD 24 million (the \u201cDussafu Contingent Consideration\u201d) may also be payable once commercial production commences on Hibiscus and Ruche and achieves daily production equal to or greater than 33,000 bopd gross over any 60-day continuous period. Once this milestone has been met, annual contingent consideration will apply to that year and to each of the subsequent four years where the average daily Dated Brent oil price is in excess of USD 55 per barrel, subject to the USD 24 million cap. Where the oil price threshold has been met, the Dussafu Contingent Consideration payable for that year will be based on 15% of net free cashflow after all taxes, operating and capital costs from the acquired 10% working interest. The contingent payment will be capped for any year at USD 5 million. Although the Dussafu Transaction has only been an increase in Panoro\u2019s working interest in an existing asset, under IFRS 3 the criteria is met for such transaction to be recognised as a business combination which includes recognition of fair value uplift, goodwill and the associated deferred tax under the standard which customary on recognition of such acquisitions. If the combination had taken place at the beginning of the year, total revenue from continuing operations would have been USD 129.5 million and profit before tax from continuing operations for the Group would have been USD 70.3 million. The purchase consideration, as set out above, is summarised in the following table: Working Interest acquired in Dussafu Marin Permit USD 000 Cash consideration 10% 39,028 Net assets acquired 39,028 The fair values of the identifiable assets and liabilities of PEGL at the date of acquisition were as follows: Purchase price allocation USD 000 Assets Exploration and evaluation assets 28,624 Development assets 20,117 Production reserves 39,859 Goodwill acquired (60,072) Goodwill related to step up / deferred tax 13,951 Production assets and equipment 13,843 Inventory 3,456 Other receivable 1,722 Total Assets 61,500 Liabilities Decommissioning liability 4,171 Deferred tax liability 13,951 Other current liabilities 4,350 Total liabilities 22,472 Net assets acquired 39,028 Cash flow on acquisition 39,028 Under the requirements of IFRS 3 \u201cBusiness Combinations\u201d any excess of fair value of net assets acquired over the consideration paid is recognised in the income statement as gain on acquisition of business, which was USD 48.5 million for this transaction. Such gain has arisen due to significant increase in oil prices between effective date and completion date of the Dussafu Transaction. For the first half of 2021, the operating cashflow of the 10% acquired interest under Dussafu Transaction was USD 0.2 million after excluding any value of proportional State Profit oil entitlement and primarily relates to payments of operating costs, capital expenditure and past costs dispute settlement offset by proceeds sale of crude oil entitlement. All these items are already included in the final completion payment of USD 39 million. Since the acquisition date, the acquired business contributed revenue of USD 34.4 million and profit of approximately USD 23.6 million to the consolidated statement of comprehensive income. NOTE 14: DISCONTINUED OPERATIONS On 21 October 2019, the Company entered into a sale and purchase agreement with PetroNor E&P Limited (\u201cPetroNor\u201d), an exploration & production oil and gas company listed on the Oslo Axess, to divest all outstanding shares in its fully owned subsidiaries Pan-Petroleum Services Holding BV and Pan-Petroleum Nigeria Holding BV (together referred to as \u201cDivested Subsidiaries\u201d) for an upfront consideration consisting of the allotment and issue of new PetroNor shares with a fixed value o f USD 10 million (the \u201cShare Consideration\u201d) plus a revised contingent consideration agreed in December 2020 of up to USD 16.67 million based on future gas production volumes. The transaction completed on 13 July 2022 (the \u201cCompletion Date\u201d) with the upfront consideration of USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor shares (the \u201cConsideration Shares\u201d), determined with reference to the contractually determined 30-day volume weighted average price (\u201cVWAP\u201d) of PetroNor\u2019s shares which are listed on the Oslo B\u00f8rs with the Ticker \u201cPNOR\u201d. The operations of the Group\u2019s Divested Subsidiaries were classified as discontinued operations under IFRS 5 since 2019 and the results of the Nigerian segment presented as discontinued operations up to the Completion Date are as follows: Amounts in USD 000, unless otherwise stated 2022 2021 DISCONTINUED OPERATIONS Oil revenue 1,181 3,688 Total revenues 1,181 3,688 Operating costs (1,129) (4,085) General and administrative costs (51) (148) Depreciation, depletion and amortisation - - (Impairment) / reversal of impairment for Oil and gas assets 1,497 8,000 EBIT - Operating income/(loss) 1,498 7,455 Interest costs net of income (192) (351) Net foreign exchange gain / (loss) (2) (2) Other financial costs net of income (46) (91) Net income/(loss) before tax 1,258 7,011 Income tax benefit/(expense) - - Net income/(loss) for the period from discontinued operations 1,258 7,011 EARNINGS PER SHARE Basic EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations 0.01 0.07 Diluted EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations 0.01 0.07 The Group\u2019s interest in Divested Subsidiaries designated as Assets held for sale as of the Completion Date and 31 December 2021 are summarised below: Carrying amount after allocation of impairment reversal USD 000 2022 2021 Assets held for sale Licence and exploration assets 17,632 16,904 Production assets and equipment 11,450 10,978 Crude oil inventory 317 1,088 Cash and cash equivalents 57 45 Total assets held for sale 29,456 29,015 Liabilities held for sale Decommissioning liability (3,768) (3,723) Other non-current liabilities (8,738) (8,546) Accounts payable, accruals and other liabilities (135) (134) Other current liabilities (7,112) (7,936) Total liabilities directly associated with assets classified as held for sale (19,753) (20,339) 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 2022 113,862 8,150 18,827 140,839 Unwinding of discount 2,848 204 469 3,521 Change in inflation and discount rate (14,313) (1,603) (1,804) (17,720) Change in licence term (11,390) - - (11,390) Additions - 1,457 - 1,457 Change in cost estimate 6,947 - - 6,947 Balance at 31 December 2022 97,954 8,208 17,492 123,654 At 1 January 2021 - 3,096 18,368 21,464 Unwinding of discount 1,998 148 459 2,605 Change in inflation and discount rate (estimate) (18,282) - - (18,282) Acquisitions 124,646 4,171 - 128,817 Change in cost estimate 5,500 735 - 6,235 Balance at 31 December 2021 113,862 8,150 18,827 140,839 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 2022 are a discount rate of 4% and an inflation rate of 2% (31 December 2021: 2.5% and 2% respectively). NOTE 16: SHARE CAPITAL Share capital Amounts in USD 000 unless otherwise stated Number of shares Nominal Share Capital As at 1 January 2022 113,383,690 721 Share issue under RSU Plan (Note 18) 305,682 2 As at 31 December 2022 113,689,372 723 Note 16.1 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. Note 16.2 In connection with the Company's Restricted Share Units Plan, announced on 7 July 2022, the Company issued 305,682 new shares to employees. As of 31 December 2022, the Company had a registered share capital of NOK 5,684,469 divided into 113,689,372 shares, each with a nominal value of NOK 0.05 (31 December 2021: NOK 5,669,184 divided into 113,383,690 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 represents excess of subscription value of the shares over the nominal amount. Other reserves Other reserves 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 represents 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. Currency translation reserve The translation reserve comprises all foreign exchange differences arising from the translation of the financial statements of foreign operations. NOTE 17: ACCOUNTS PAYABLE, ACCRUALS AND OTHER LIABILITIES USD 000 2022 2021 Accounts payable 9,087 12,707 Accrued and other liabilities 4,899 10,623 Other non-current liabilities 6,956 8,302 At 31 December 20,942 31,632 NOTE 18: SHARE BASED PAYMENTS Restricted Share Unit (\u201cRSU\u201d) scheme At the Annual General Meeting held on 27 May 2021, 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 2024. 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: All amounts in Number of units, unless stated otherwise 2022 2021 Outstanding RSUs as of 1 January 1,162,434 1,149,150 Add: Grants during the year 487,434 528,356 Less: Vested during the year - Settled in cash to cover taxes / settlement through purchase of shares from the market (264,819) (243,879) - Settled through issue of new shares (305,682) (271,193) Less: Terminated without vesting (29,376) - Outstanding RSUs as of 31 December 1,049,991 1,162,434 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 by delivering equity shares purchased from the market. In June 2022, 487,434 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 1.6 million (2021: USD 1.2 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 RSUs granted during the year is as follows: Key assumptions 2022 2021 Weighted average risk-free interest rate 0.75% 0.75% Dividend yield Nil 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 58% 61% Weighted average remaining contractual life of RSUs at year end 1.1 Years 1.1 Years Share price at grant date \u2013 per share NOK 32.84 NOK 24.70 The weighted average fair value of RSUs granted during the period was NOK 32.84 per unit (2021: NOK 24.70 per unit) based on 487,434 units granted (2021: 528,356 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: 2022 2021 WAEP 2022 2021 Number of Units NOK/share Exercise value in NOK Within 1 year 566,229 570,501 0.05 28,311 28,525 Between 1 and 2 years 326,533 415,814 0.05 16,327 20,791 Between 2 and 3 years 157,229 176,119 0.05 7,861 8,806 Total 1,049,991 1,162,434 52,500 58,122 As of the year ended 2022 the unvested RSUs were outstanding for 18 employees including key management personnel (2021: 16 employees). The distribution of outstanding RSUs as of 31 December 2022 amongst the employees is as follows: No of Units Exercise price NOK/share Exercise period Fair value expensed USD 000 John Hamilton, CEO 351,107 0.05 June 2023 to June 2025 512 Qazi Qadeer, CFO 136,285 0.05 June 2023 to June 2025 195 Other Named Executives (i) 267,957 0.05 June 2023 to June 2025 382 Total 755,349 1,089 (i) Other Named Executives include Richard Morton (Technical Director) and Nigel McKim (Projects Director). 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 and NOK 31.91 for the 2022 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 this grant is from 27 May 2021 to 26 May 2025, 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 were are tabled below: All amounts in Number of units, unless stated otherwise 2022 2021 Outstanding options as of 1 January 144,000 - Add: Grants during the year 24,000 144,000 Outstanding options as of 31 December 168,000 144,000 The outstanding options as of 31 December 2022 included 48,000 options that had already vested but not exercised (2021: Nil). 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 2022 2021 Weighted average risk-free interest rate 0.75% 0.75% Dividend yield Nil 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 58% 61% Weighted average remaining contractual life of RSUs at year end 1 Years 1.4 Years Share price at grant date \u2013 per share NOK 32.40 NOK 19.16 The weighted average fair value of Board Options granted during the period was NOK 32.40 per unit (2021: NOK 19.16 per unit) based on 24,000 units granted (2021: 144,000 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: 2022 2021 WAEP 2022 2021 Number of Units NOK/share Exercise value in NOK Within 1 year 104,000 48,000 19.42 2,019,829 832,320 Between 1 and 2 years 56,000 48,000 19.42 1,087,600 832,320 Between 2 and 3 years 8,000 48,000 31.91 255,280 832,320 Total 168,000 144,000 3,362,709 2,496,960 As of the year ended 2022 the unvested Board Options were outstanding for 6 members of the Board of Directors (2021: 5 members of the Board of Directors). The distribution of outstanding Board Options as of 31 December 2022 amongst the members of the Board of Directors is as follows: No of Units - unvested No of Units - vested and unexercised Exercise price NOK/share Exercise period 2022 Fair value expensed USD 000 2021 Fair value expensed USD 000 Julien Balkany 32,000 16,000 17.34 May 2023 to May 2024 19 15 Torstein Sanness 16,000 8,000 17.34 May 2023 to May 2024 9 8 Grace Skaugen 24,000 - 31.91 May 2023 to May 2024 10 - Alexandra Herger 16,000 8,000 17.34 May 2023 to May 2024 9 8 Hilde \u00c5dland 16,000 8,000 17.34 May 2023 to May 2024 9 8 Garrett Soden 16,000 8,000 17.34 May 2023 to May 2024 9 8 Total 120,000 48,000 65 47 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. The outstanding commodity hedge contracts as at the respective balance sheet dates presented were as follows: Zero cost collar instruments Remaining term Remaining contract amount Average contract price Average contract price Fair value Asset / (Liability) Fair value Asset / (Liability) Bbls Buy Put (USD/Bbl) Sell Call (USD/Bbl) Current (USD '000) Non-Current (USD '000) At 31 December 2021 Jan 21 - Dec 21 216,000 55 64 (2,489) - At 31 December 2022 Dec 22 - Mar 23 50,000 40 47 133 - The fair values of the commodity price contracts were 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 (2021: 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, liabilities 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. Commodity price risk The Group is exposed to the risk of fluctuations in prevailing market commodity prices (primarily crude oil) on the oil and gas it produces. The Group\u2019s policy is to manage these risks through the use of derivative financial instruments. The following tabl e summarises the impact on profit before tax for changes in commodity prices on the fair value of derivative financial instruments. The impact on equity is the same as the impact on profit before tax as these derivative financial instruments have not been designated as hedges and are classified as held-for-trading. The analysis is based on derivative contracts existing at the balance sheet date, the assumption that crude oil price moves 15% over all future periods, with all other variables held constant. Management believes that 15% is a reasonable sensitivity based on forward forecasts of estimated oil price volatility. Increase /(decrease) in profit before tax and equity USD 000 2022 2021 15% increase in the price of oil (20) 373 15% decrease in the price of oil 20 (373) 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), and the Pound Sterling (GBP). The Group has transactional currency exposures. Such exposure arises from sales or purchases in currencies other than the respective functional currency. The Group reports its consolidated results in USD, any change in exchange rates between its operating subsidiaries\u2019 functional currencies and the USD 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 2022 or 2021. 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 2022 2021 USD vs NOK 20% -20% 20% -20% Cash 10 (15) 9 (13) Receivables 7 (10) 7 (11) Payables (10) 15 (8) 12 Net effect 6 (9) 8 (12) USD vs TND 20% -20% 20% -20% Cash 3 (4) 182 (274) Receivables 133 (200) 1,630 (2,444) Corporation taxes payable (1,593) 2,390 (790) 1,185 Payables (765) 1,148 (593) 889 Net effect (2,223) 3,334 429 (643) USD vs EUR 20% -20% 20% -20% Cash 3 (4) 3 (5) Receivables 1 (2) (33) 50 Payables (32) 48 (33) 50 Net effect (28) 42 (63) 95 USD vs GBP 20% -20% 20% -20% Cash 61 (91) 66 (99) Receivables (49) 74 (36) 54 Payables (18) 26 (55) 83 Net effect (6) 9 (26) 38 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 2022 2021 +100bps -100bps +100bps -100bps Loans and borrowings (Secured loans) (806) 806 (954) 954 Cash equivalents 32 (32) 51 (51) Net effect (774) 774 (902) 902 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 2022 based on contractual undiscounted payments. 2022 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Secured loans) - 21,470 59,340 - 80,810 Loans and borrowings (Non-recourse loan) - 632 - - 632 Accounts payable and accrued liabilities - 9,087 - - 9,087 Non-current liabilities - - - 1,934 1,934 Corporation tax liabilities - 35,560 - - 35,560 Total - 66,749 59,340 1,934 128,023 2021 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Senior secured facility) - 15,919 79,620 - 95,539 Loans and borrowings (Non-recourse loan) - 4,507 - - 4,507 Accounts payable and accrued liabilities - 12,707 - - 12,707 Non-current liabilities - - 1,727 1,553 3,280 Corporation tax liabilities - 17,018 - - 17,018 Total - 50,151 81,347 1,553 133,051 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 2022, the Group\u2019s total debt was USD 79.5 million. The Group closed the year with a cash position of USD 32.7 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. 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 2022. 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. There is no potential claim against these performance guarantee and all license obligations are already accounted for in the statement of financial position. Other At 31 December 2022, the Company has issued a parent company guarantee in favour of Mercuria Assets Holdings (Hong Kong) Ltd. to guarantee the obligations of Panoro Tunisia Production AS as borrower. The Mercuria loan was repaid in full on 15 March 2023 and the Company was released from the parent company guarantee. Refer Note 5: Finance , interest and other income and expense. The Company has issued a parent company guarantee in favour of The Mauritius Commercial Bank Ltd. to guarantee the obligations of Panoro Energy Holding B.V. as borrower. Further details can be found in Note 5: Finance , interest and other income and expense. The Company has issued a performance guarantee on behalf of its jointly owned company Panoro Energy AS to fulfil the payment obligation of deferred consideration of up to USD 13.2 million to DNO ASA once the milestones as agreed by parties are met. As part of the farm-in transaction in Block 2B offshore South Africa, on 24 February 2020 the Company entered into deed of guarantee (the \u201cFarmee Guarantee\u201d) with Thombo Petroleum Limited whereby the Company has guaranteed all obligations of PANORO ENERGY 2022 ANNUAL REPORT | APRIL 2023 Page: 88 Panoro 2B Limited (a wholly owned subsidiary) to Thombo Petroleum Limited under the farmout agreement of the same date. In addition, on 24 February 2020 Panoro entered into deed of guarantee with Thombo Petroleum Limited, Panoro 2B Limited and African Energy Corporation whereby the Company guarantee all obligations of Panoro 2B Limited under the farm out agreement, and under the petroleum authorisation as set out in the Farmee Guarantee. 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 extended to June 2023 and the liability and the right of use asset determined using an incremental rate of return of 8.5% 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 2022, the entire USD 114 thousand was current (31 December 2021: USD 231 thousand current and USD 127 thousand non- current). USD 000 2022 2021 Lease liability recognised at 1 January 358 578 Add: lease interest 19 40 Less: gross lease payments (263) (260) Lease liability at 31 December 114 358 The following table shows the maturity profile of lease liabilities based on contractual undiscounted lease payments. USD 000 2022 2021 Within 1 year 47 187 2 to 5 years - 47 After 5 years - - Lease liability at 31 December 47 233 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 9: Tangible Assets. USD 000 2022 2021 Right of use asset recognised at 1 January 288 501 Less: depreciation and impairment (191) (213) Net book value of right of use asset at 31 December 97 288 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. NOTE 24: SUBSIDIARIES Details of the Group\u2019s subsidiaries as of 31 December 2022 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% 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% Sfax Petroleum Corporation AS Norway 60% Panoro Energy AS Norway 60% Panoro Tunisia Exploration AS Norway 60% Panoro Tunisia Production AS Norway 60% Panoro TPS Production GmbH - in liqui Austria 60% Panoro TPS (UK) Production Limited UK 60% NOTE 25: EVENTS SUBSEQUENT TO REPORTING DATE On 21 February 2023, the Board of Directors approved a cash dividend of NOK 0.2639 per share to shareholders holding shares in the Company at the end of trading on 7 March 2023. The total dividend was approximately NOK 30 million (approximately USD 3 million) and payment took place on or around 16 March 2023. Panoro was awarded a 56 percent participating interest and operatorship of Block EG-01 located offshore Equatorial Guinea. Partners in the block are Kosmos Energy (24 percent pending signature) and GEPetrol (20 percent). Block EG-01 borders both Block G where Panoro has a 14.25 percent non-operated interest (and which contains the producing Ceiba Field and Okume Complex) and Block S where Panoro has agreed to farm-in to a 12 percent non-operated interest. A 6 percent non-operated 12 percent participating interest in Block S was also acquired from Kosmos Energy and Trident Energy. Panoro\u2019s partners at Block S are Kosmos Energy (34 percent, operator), Trident Energy (34 percent) and GEPetrol (20 percent). On 15 March 2023, the Mercuria loan (refer Note 5: Finance , interest and other income and expense) was repaid in full and all security held in relation to the loan released. On 24 April 2023, the Company completed an agreement with Beender Tunisia Petroleum Limited (\u201cBeender\u201d) to acquire its 40 percent shareholding in Sfax Petroleum Corporation AS (\u201cSPC\u201d) for a total consideration of approximately USD 18.2 million in a mix of cash and shares (the \u201cAcquisition\u201d). The Acquisition increases Panoro\u2019s current ownership in SPC from 60 percent to 100 percent and SPC is now a fully owned subsidiary of Panoro. The loan facility with Trafigura was increased by USD 15 million in conjunction with the Acquisition. 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. NOTE 8: RELATED PARTY TRANSACTIONS AND BALANCES During 2020, the Company has entered into an agreement with Africa Energy Corp. (\"AEC\") in relation to farming-in of 12.5% working interest in Block 2B, offshore South Africa. Mr. Garrett Soden, the Company\u2019s non-executive director, holds the position of CEO in AEC, and is also a Director. All decisions taken by the Company in relation to the Block 2B transaction was without any involvement from Mr. Soden and as such the transaction terms were negotiated at arm\u2019s length in a competitive process undertaken by AEC to farm-out their interest in the block. As the ultimate parent company, the Company routinely provides funding to companies within the Group to support operations. The Company also receives technical and management services from its indirect subsidiary, Panoro Energy Limited. The cost of these services is then recharged to the relevant subsidiaries. In addition, the Company also has routine trading accounts and balances with other Companies in the Group. The Company had the following loans receivable from its subsidiaries at 31 December 2022: \u2022 USD 10.7 million due from its Norwegian jointly controlled entity, Sfax Petroleum Corporation AS (\u201cSfax\u201d) (60% owned) (31 December 2021: USD 10.7 million). Panoro Energy ASA (60%) and Beender Petroleum Corporation (40%) (\u201cBeender\u201d) provides loans to Sfax which are non-interest-bearing with maturity dates of 31 January 2025 to fund its operations, in proportion to their respective shareholding. \u2022 Loans of USD 8.7 million and USD 8.3 million due from its Dutch subsidiary, Panoro Energy Holding B.V., carrying interest of 2% and 4% respectively classified as current (31 December 2021: USD 10 million). These loans are classified as current and are repayable on demand. The Company had the following non-interest-bearing payable balances to companies within the Group at 31 December 2022: \u2022 Payable balances on account of intercompany recharges were USD 2.3 million (2021: USD 2.8 million) owed to Company\u2019s indirect subsidiary Panoro Energy Limited, which provides technical services to the Group. \u2022 Payable balance to the Company\u2019s subsidiary, Pan-Petroleum (Holding) Cyprus Limited was USD 0.9 million (2021: USD 0.9 million). \u2022 Payable balance to the Company\u2019s subsidiary (60% owned), Panoro Tunisia Exploration AS of USD 2.3 million. Panoro Energy ASA also provides management services to the other companies in the Group under service agreements. The total balances receivable from Group companies for services provided under service agreement and for normal operational purposes at 31 December 2022 were: \u2022 Panoro Energy Holding B.V, total USD 0.2 million (31 December 2021: USD 1.9 million) related to management and technical services provided during the year. \u2022 Pan-Petroleum Gabon B.V, total USD 0.2 million (31 December 2021: USD 0.6 million) related to management and technical services provided during the year. \u2022 Sfax Petroleum Corporation AS (60% owned); total USD 2.2 million (31 December 2021: USD 1.7 million), of which USD 0.3 million related to management and technical services provided during the year. \u2022 Panoro 2B Limited; total USD 0.8 million (31 December 2021: USD 0.2 million)., of which USD 0.5 million related to management and technical services provided during the year. \u2022 Panoro Equatorial Guinea Limited; total USD 2.2 million (31 December 2021: USD 2.9 million), of which USD 0.4 million related to management and technical services provided during the year. \u2022 USD 0.3 million (31 December 2021: USD 0.3 million) from Panoro Energy AS (60% owned), of which USD Nil related to management and technical services provided during the year \u2022 USD 0.1 million (31 December 2021: USD 1 million) from Panoro Tunisia Exploration AS (60% owned), of which USD 0.1 million related to the management and technical services provided during the year. \u2022 USD 0.1 million (31 December 2021: USD 0.7 million) from Panoro Tunisia Production AS (60% owned), of which USD 0.1 million related to the management and technical services provided during the year. \u2022 USD 0.6 million (31 December 2021: USD 0.6 million) from Panoro TPS Production GmbH (60% owned), of which USD nil related to the management and technical services provided during the year. \u2022 USD Nil (31 December 2021: USD 0.6 million) from Panoro TPS (UK) Production Limited (60% owned) Further, the Company provides funding to its Group companies to fund normal operational activity. The intercompany balances receivable from the companies within the Group at 31 December 2022 were: \u2022 USD 17 million receivable from Panoro Energy Holding B.V which interest at between 2% and 4% and is repayable on demand. \u2022 USD 9.2 million from Panoro 2B Limited. The balance bears interest at 10% and is repayable on demand. ",
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"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 South Africa. The consolidated financial statements of the Group for the year ended 31 December 2022 were authorised for issue by the Board of Directors on 27 April 2023. The Board of Directors confirms that the annual financial statements have been prepared pursuant to the going concern assumption, in accordance with \u00a73-3a of the Norwegian Accounting Act, and that this assumption was realistic as at the balance sheet date. The going concern assumption is based upon the financial position of the Company and the development plans currently in place. In the Board of Directors\u2019 view, the annual accounts give a true and fair view of the group\u2019s asset s and liabilities, financial position and results. Panoro Energy ASA is the parent company of the Panoro Group. Its financial statements have been prepared on the assumption that Panoro Energy will continue as a going concern. As of 31 December 2022, the Group had USD 32.7 million in cash and bank balances and debt of USD 79.5 million resulting in a net debt position of approximately USD 46.8 million. In addition to Block G and Dussafu capital expenditure, the Company is committed to progress activities on Block EG-01 and Block S in Equatorial Guinea. Although the Company is well funded to undertake upcoming capital expenditure, there is risk that additional funding may be required to conclude such activities. Should additional funding be required in the future for additional capital expenditure for new development phases or working capital requirements, the Company has various alternatives available which it can explore to fulfil such additional requirements. Options include, amongst others, offtake prepayment structures, utilisation of undrawn financing facility and the issuance of shares. As a result, these financial statements have been prepared under the assumption of going concern and realisation of assets and settlement of debt in normal operations. The Company\u2019s shares are traded on the Oslo Stock Exchange under the ticker symbol PEN. NOTE 2: BASIS OF PREPARATION The consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards (IFRS) 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. 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 2.2: 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 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. 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 as adopted by the EU requires 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 Note 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 liabiliies 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 r esults, 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 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 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: 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. 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 a re 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. 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 9.2: Impairment in Oil and Gas Interests. Note 2.5: New and amended standards and interpretations No standard amendments or interpretations of standards effective as of 1 January 2022 and adopted by Panoro, were material to the Group\u2019s Consolidated financial statements upon adoption. ",
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"value": "Panoro Energy ASANote 4.3: Board of Directors statement on remuneration of executives Statement for the current year (2022) 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 104 of this report. Note 4.4: Management remuneration Executive management consists of the Chief Executive Officer (CEO), Chief Financial Officer (CFO) and two other Named Executives as described below. Current Executive management remuneration is summarised below: 2022 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2022 Fair value of RSUs expensed John Hamilton, CEO 472 181 11 5 669 131,772 512 Qazi Qadeer, CFO 311 119 5 5 440 64,983 195 Other Named Executives (vi) 596 227 10 12 845 127,014 382 Total 1,379 527 26 22 1,954 323,769 1,089 2021 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2021 Fair value of RSUs expensed John Hamilton, CEO 484 595 12 5 1,096 166,822 483 Qazi Qadeer, CFO 317 330 5 5 658 54,846 157 Other Named Executives (vi) 606 359 10 13 988 107,198 302 Total 1,407 1,285 27 23 2,742 328,866 942 (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. Other Named Executives have notice periods between three and six months. (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 July 2022, 487,434 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. The 2021 bonus included a one-off discretionary cash award to key management by the Board of Directors in recognition of the success of Transformational Tullow acquisitions, which increased Panoro\u2019s production and reserves by a factor of 3-4 times. (v) All bonuses were approved by the Board of Directors. (vi) Remuneration details for Other Named Executives include Mr. Richard Morton (Technical Director) and Mr. Nigel McKim (Projects Director). 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: USD 000 2022 2021 Julien Balkany (Chairman of the Board of Directors) 102 82 Torstein Sanness (Deputy Chairman of the Board of Directors) 68 57 Grace Reksten Skaugen 38 0 Alexandra Herger 62 48 Garrett Soden 61 50 Hilde \u00c5dland 58 48 Total 388 285 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 8: RELATED PARTY TRANSACTIONS AND BALANCES During 2020, the Company has entered into an agreement with Africa Energy Corp. (\"AEC\") in relation to farming-in of 12.5% working interest in Block 2B, offshore South Africa. Mr. Garrett Soden, the Company\u2019s non-executive director, holds the position of CEO in AEC, and is also a Director. All decisions taken by the Company in relation to the Block 2B transaction was without any involvement from Mr. Soden and as such the transaction terms were negotiated at arm\u2019s length in a competitive process undertaken by AEC to farm-out their interest in the block. As the ultimate parent company, the Company routinely provides funding to companies within the Group to support operations. The Company also receives technical and management services from its indirect subsidiary, Panoro Energy Limited. The cost of these services is then recharged to the relevant subsidiaries. In addition, the Company also has routine trading accounts and balances with other Companies in the Group. The Company had the following loans receivable from its subsidiaries at 31 December 2022: \u2022 USD 10.7 million due from its Norwegian jointly controlled entity, Sfax Petroleum Corporation AS (\u201cSfax\u201d) (60% owned) (31 December 2021: USD 10.7 million). Panoro Energy ASA (60%) and Beender Petroleum Corporation (40%) (\u201cBeender\u201d) provides loans to Sfax which are non-interest-bearing with maturity dates of 31 January 2025 to fund its operations, in proportion to their respective shareholding. \u2022 Loans of USD 8.7 million and USD 8.3 million due from its Dutch subsidiary, Panoro Energy Holding B.V., carrying interest of 2% and 4% respectively classified as current (31 December 2021: USD 10 million). These loans are classified as current and are repayable on demand. The Company had the following non-interest-bearing payable balances to companies within the Group at 31 December 2022: \u2022 Payable balances on account of intercompany recharges were USD 2.3 million (2021: USD 2.8 million) owed to Company\u2019s indirect subsidiary Panoro Energy Limited, which provides technical services to the Group. \u2022 Payable balance to the Company\u2019s subsidiary, Pan-Petroleum (Holding) Cyprus Limited was USD 0.9 million (2021: USD 0.9 million). \u2022 Payable balance to the Company\u2019s subsidiary (60% owned), Panoro Tunisia Exploration AS of USD 2.3 million. Panoro Energy ASA also provides management services to the other companies in the Group under service agreements. The total balances receivable from Group companies for services provided under service agreement and for normal operational purposes at 31 December 2022 were: \u2022 Panoro Energy Holding B.V, total USD 0.2 million (31 December 2021: USD 1.9 million) related to management and technical services provided during the year. \u2022 Pan-Petroleum Gabon B.V, total USD 0.2 million (31 December 2021: USD 0.6 million) related to management and technical services provided during the year. \u2022 Sfax Petroleum Corporation AS (60% owned); total USD 2.2 million (31 December 2021: USD 1.7 million), of which USD 0.3 million related to management and technical services provided during the year. \u2022 Panoro 2B Limited; total USD 0.8 million (31 December 2021: USD 0.2 million)., of which USD 0.5 million related to management and technical services provided during the year. \u2022 Panoro Equatorial Guinea Limited; total USD 2.2 million (31 December 2021: USD 2.9 million), of which USD 0.4 million related to management and technical services provided during the year. \u2022 USD 0.3 million (31 December 2021: USD 0.3 million) from Panoro Energy AS (60% owned), of which USD Nil related to management and technical services provided during the year \u2022 USD 0.1 million (31 December 2021: USD 1 million) from Panoro Tunisia Exploration AS (60% owned), of which USD 0.1 million related to the management and technical services provided during the year. \u2022 USD 0.1 million (31 December 2021: USD 0.7 million) from Panoro Tunisia Production AS (60% owned), of which USD 0.1 million related to the management and technical services provided during the year. \u2022 USD 0.6 million (31 December 2021: USD 0.6 million) from Panoro TPS Production GmbH (60% owned), of which USD nil related to the management and technical services provided during the year. \u2022 USD Nil (31 December 2021: USD 0.6 million) from Panoro TPS (UK) Production Limited (60% owned) Further, the Company provides funding to its Group companies to fund normal operational activity. The intercompany balances receivable from the companies within the Group at 31 December 2022 were: \u2022 USD 17 million receivable from Panoro Energy Holding B.V which interest at between 2% and 4% and is repayable on demand. \u2022 USD 9.2 million from Panoro 2B Limited. The balance bears interest at 10% and is repayable on demand. ",
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"f3546": {
"value": "c/o Advokatfirmaet Schj\u00f8dt AS, Tordenskiolds gate 12, P.O. Box 2444 Solli, 0201 Oslo, Norway",
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"value": "Norway",
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"f3551": {
"value": "The Company and its subsidiaries (\u201cPanoro\u201d or the \u201cGroup\u201d) are engaged in the exploration and production of oil and gas ",
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"entity": "scheme:5967007LIEEXZXGWM030",
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"f3554": {
"value": "North, West and South Africa",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"f3555": {
"value": "The consolidated financial statements of the Group for the year ended 31 December 2022 were authorised for issue by the Board of Directors on 27 April 2023. ",
"dimensions": {
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"f3558": {
"value": "The Board of Directors confirms that the annual financial statements have been prepared pursuant to the going concern assumption, in accordance with \u00a73-3a of the Norwegian Accounting Act, and that this assumption was realistic as at the balance sheet date. The going concern assumption is based upon the financial position of the Company and the development plans currently in place. In the Board of Directors\u2019 view, the annual accounts give a true and fair view of the group\u2019s asset s and liabilities, financial position and results. Panoro Energy ASA is the parent company of the Panoro Group. Its financial statements have been prepared on the assumption that Panoro Energy will continue as a going concern. As of 31 December 2022, the Group had USD 32.7 million in cash and bank balances and debt of USD 79.5 million resulting in a net debt position of approximately USD 46.8 million. In addition to Block G and Dussafu capital expenditure, the Company is committed to progress activities on Block EG-01 and Block S in Equatorial Guinea. Although the Company is well funded to undertake upcoming capital expenditure, there is risk that additional funding may be required to conclude such activities. Should additional funding be required in the future for additional capital expenditure for new development phases or working capital requirements, the Company has various alternatives available which it can explore to fulfil such additional requirements. Options include, amongst others, offtake prepayment structures, utilisation of undrawn financing facility and the issuance of shares. As a result, these financial statements have been prepared under the assumption of going concern and realisation of assets and settlement of debt in normal operations. ",
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"f3577": {
"value": "NOTE 2: BASIS OF PREPARATION The consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards (IFRS) 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. ",
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"f3579": {
"value": "The consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union (\u201cEU\u201d).",
"dimensions": {
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"language": "en",
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"f3583": {
"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. 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. 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 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. Business combinations and goodwill Acquisitions are accounted for as described in Note 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 liabiliies and recognition of goodwill where fair values cannot reliably be measured. Note 2.4: Summary of significant accounting policies 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 Corp\u201d). Sfax Corp, 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. 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 Joint ventures A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. The Group\u2019s investment in its joint venture is accounted for using the equity method. Under the equity method, the investment in the joint venture is initially recognised at cost. The carrying amount of the investment is adjusted to recognise changes in the Group\u2019s share of net assets of the joint venture since the acquisition date. Goodwill relating to the joint venture is included in the carrying amount of the investment and is not individually tested for impairment. The statement of profit or loss reflects the Group\u2019s share of the results of operations of joint ventures. Unrealised gains and losses resulting from transactions between the Group and the joint venture are eliminated to the extent of the interest in the joint venture. The aggregate of the Group\u2019s share of profit or loss of the joint venture is shown on the face of the statement of profit or loss and other comprehensive income as part of operating profit and represents profit or loss after tax and NCI in the subsidiaries of the joint venture. The financial statements of the joint venture are prepared for the same reporting period as the Group. When necessary, adjustments are made to bring the accounting policies in line with those of the Group. At each reporting date, the Group determines whether there is objective evidence that the investment in the joint venture is impaired. If there is such evidence, the Group calculates the amount of impairment as the difference between the recoverable amount of the joint venture and its carrying value, and then recognises the loss as \u2018Share of profit of a joint venture\u2019 in the statement of profit or loss and other comprehensive income. On loss of joint control over the joint venture, the Group measures and recognises any retained investment at its fair value. Any difference between the carrying amount of the joint venture upon loss of joint control and the fair value of the retained investment and proceeds from disposal is recognised in the statement of profit or loss and other comprehensive income. 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: 2022 2021 Average rate Reporting date rate Average rate Reporting date rate Norwegian Kroner / USD 9.6149 9.8394 8.6002 8.8245 USD / British Pound Sterling 1.2367 1.2039 1.3755 1.3477 USD / Tunisian Dinar 3.0838 3.2482 2.7963 2.8865 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 non-controlling interest (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 administ rative 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. 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 i t 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 tangible and intangible 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 and intangible assets 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 esti mated 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 a re 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. 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 9.2: Impairment in Oil and Gas Interests. 2.4.5 Non-current assets held for sale or for distribution to equity holders of the parent and discontinued operations The Group classifies non-current assets and disposal groups as held for sale or for distribution to equity holders of the parent if their carrying amounts will be recovered principally through a sale or distribution rather than through continuing use. Such non- current assets and disposal groups classified as held for sale or as held for distribution are measured at the lower of their carrying amount and fair value less costs to sell or to distribute. Costs to distribute are the incremental costs directly attributable to the distribution, excluding the finance costs and income tax expense. The criteria for held for distribution classification is regarded as met only when the distribution is highly probable and the asset or disposal group is available for immediate distribution in its present condition. Actions required to complete the distribution should indicate that it is unlikely that significant changes to the distribution will be made or that the distribution with be withdrawn. Management must be committed to the distribution expected within one year from the date of the classification. Similar considerations apply to assets or a disposal group held for sale. Production assets, property, plant and equipment and intangible assets are not depreciated or amortised once classified as held for sale or as held for distribution. Assets and liabilities classified as held for sale or for distribution are presented separately as current items in the statement of financial position. A disposal group qualifies as discontinued operation if it is: \u2022 a component of the Group that is a CGU or a group of CGUs \u2022 classified as held for sale or distribution or already disposed in such a way, or \u2022 a major line of business or major geographical area. Discontinued operations are excluded from the results of continuing operations and are presented as a single amount as profit or loss after tax from discontinued operations in the statement of profit or loss. 2.4.6 Financial instruments 2.4.6.1 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. 2.4.6.2 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. Cash held for Bank guarantee - restricted Cash held for Bank guarantee relates to resources or collateral held by a bank which can only be accessed through fulfilment of conditions imposed by counter parties. Funds are only classified from restricted cash status to cash equivalents when funds are transferred to and under the control of the Group. 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 in terest 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. 2.4.6.3 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. 2.4.7 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. 2.4.8 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. 2.4.9 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. 2.4.10 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. 2.4.11 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. 2.4.12 Leases At contract inception, an assessment is made of all arrangements to determine whether they are, or contain, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Group is not a lessor in any transactions, it is only a lessee. The Group applies a single recognition and measurement approach for all leases, except for short-term leases of 12 months or less and leases of low-value assets. The Group recognises lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets. Right-of-use assets The Group recognises right-of-use assets at the commencement date of the lease (i.e., the date the underlying asset is available for use). Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. The only right-of-use asset, the London office lease, is depreciated on a straight-line basis over the lease term. If ownership of the leased asset transfers to the Group at the end of the lease term or the cost reflects the exercise of a purchase option, depreciation is calculated using the estimated useful life of the asset. 2.4.13 Property, plant and equipment Property, plant and equipment not associated with exploration and production activities are carried at cost less accumulated depreciation. These assets are also evaluated for impairment. Depreciation of other assets is calculated on a straight-line basis as follows: Computer equipment: 20 to 33.33% Furniture, Fixtures & fittings: 10 to 33.33% 2.4.14 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. 2.4.15 Defined contribution pension plan The Group pays contributions into a defined contribution plan. Obligations for contributions to defined contribution pension plans are recognised as an expense in the income statement in the periods during which services are rendered by employees. 2.4.16 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. 2.4.17 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. 2.4.18 Current versus non-current classification The Group presents assets and liabilities in the statement of financial position based on current/non-current classification. An asset is current when it is either: \u2022 Expected to be realised or intended to be sold or consumed in the normal operating cycle \u2022 Held primarily for the purpose of trading \u2022 Expected to be realised within 12 months after the reporting period \u2022 Cash or cash equivalent unless restricted from being exchanged or used to settle a liability for at least 12 months after the reporting period All other assets are classified as non-current. A liability is current when either: \u2022 It is expected to be settled in the normal operating cycle \u2022 It is held primarily for the purpose of trading \u2022 It is due to be settled within 12 months after the reporting period \u2022 There is no unconditional right to defer the settlement of the liability for at least 12 months after the reporting period The Group classifies all other liabilities as non-current. Deferred tax assets and liabilities are classified as non-current assets and liabilities. ",
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"value": "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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},
"f3590": {
"value": "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:LevelOfRoundingUsedInFinancialStatements",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3594": {
"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 2022 and adopted by Panoro, were material to the Group\u2019s Consolidated financial statements upon adoption. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesAccountingEstimatesAndErrorsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3595": {
"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 2022 and adopted by Panoro, were material to the Group\u2019s Consolidated financial statements upon adoption. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3602": {
"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 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3604": {
"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 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. 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 Corp\u201d). Sfax Corp, 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. 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 Joint ventures A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. The Group\u2019s investment in its joint venture is accounted for using the equity method. Under the equity method, the investment in the joint venture is initially recognised at cost. The carrying amount of the investment is adjusted to recognise changes in the Group\u2019s share of net assets of the joint venture since the acquisition date. Goodwill relating to the joint venture is included in the carrying amount of the investment and is not individually tested for impairment. The statement of profit or loss reflects the Group\u2019s share of the results of operations of joint ventures. Unrealised gains and losses resulting from transactions between the Group and the joint venture are eliminated to the extent of the interest in the joint venture. The aggregate of the Group\u2019s share of profit or loss of the joint venture is shown on the face of the statement of profit or loss and other comprehensive income as part of operating profit and represents profit or loss after tax and NCI in the subsidiaries of the joint venture. The financial statements of the joint venture are prepared for the same reporting period as the Group. When necessary, adjustments are made to bring the accounting policies in line with those of the Group. At each reporting date, the Group determines whether there is objective evidence that the investment in the joint venture is impaired. If there is such evidence, the Group calculates the amount of impairment as the difference between the recoverable amount of the joint venture and its carrying value, and then recognises the loss as \u2018Share of profit of a joint venture\u2019 in the statement of profit or loss and other comprehensive income. On loss of joint control over the joint venture, the Group measures and recognises any retained investment at its fair value. Any difference between the carrying amount of the joint venture upon loss of joint control and the fair value of the retained investment and proceeds from disposal is recognised in the statement of profit or loss and other comprehensive income. 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. NOTE 11: LISTED EQUITY INVESTMENTS On completion of the disposal of Panoro\u2019s fully owned subsidiaries Pan-Petroleum Services Holdings BV and Pan-Petroleum Nigeria Holding BV described in Note 14: Discontinued Operations below, Panoro received upfront consideration of USD 10 million in the form of 96,577,537 newly allotted and issued shares in PetroNor E&P ASA (\u201cConsideration Shares\u201d). The Board of Directors resolved on 1 August 2022 to use its authorisation to approve a dividend in the form of the Consideration Shares. Each Panoro shareholder as at the record date received 0.849 PetroNor shares for each share held in Panoro, rounded downwards to the nearest whole share. Fraction shares were not distributed. Panoro retains an investment of 4,451,249 PetroNor shares (\u201cRetained Shares\u201d), representing a holding of approximately 0.31% of PetroNor share capital. The Retained Shares were in connection with obligation to withhold tax on dividends and such taxes have since be been settled in cash by the Company. The Retained Shares are accounted for as financial assets at fair value through profit and loss and disclosed as current financial asset, valued at the published market price at the end of the reporting period, with revaluation differences disclosed as other income or expense in the statement of comprehensive income. NOTE 24: SUBSIDIARIES Details of the Group\u2019s subsidiaries as of 31 December 2022 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% 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% Sfax Petroleum Corporation AS Norway 60% Panoro Energy AS Norway 60% Panoro Tunisia Exploration AS Norway 60% Panoro Tunisia Production AS Norway 60% Panoro TPS Production GmbH - in liqui Austria 60% Panoro TPS (UK) Production Limited UK 60% ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInterestsInOtherEntitiesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3605": {
"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 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. NOTE 24: SUBSIDIARIES Details of the Group\u2019s subsidiaries as of 31 December 2022 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% 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% Sfax Petroleum Corporation AS Norway 60% Panoro Energy AS Norway 60% Panoro Tunisia Exploration AS Norway 60% Panoro Tunisia Production AS Norway 60% Panoro TPS Production GmbH - in liqui Austria 60% Panoro TPS (UK) Production Limited UK 60% ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3607": {
"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 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForSubsidiariesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3631": {
"value": "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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfNoncontrollingInterestsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3632": {
"value": "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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForTransactionsWithNoncontrollingInterestsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3654": {
"value": "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. Business combinations and goodwill Acquisitions are accounted for as described in Note 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 liabiliies and recognition of goodwill where fair values cannot reliably be measured. 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 non-controlling interest (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 administ rative 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. 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsAndGoodwillExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3655": {
"value": "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. Business combinations and goodwill Acquisitions are accounted for as described in Note 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 liabiliies and recognition of goodwill where fair values cannot reliably be measured. 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 non-controlling interest (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 administ rative 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. 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 13: BUSINESS COMBINATIONS Note 13.1: EG Transaction On 31 March 2021, Panoro completed the acquisition of 100% of the shares of Panoro Equatorial Guinea Limited (\u201cPEGL\u201d) from Tullow Overseas Holdings B.V. (\u201cEG Seller\u201d), a fully owned subsidiary of Tullow Oil plc, for an initial cash considerati on of USD 88.8 million that includes customary completion adjustments. PEGL holds a 14.25% non-operated working interest in Block G that contains the Ceiba and Okume Complex assets, offshore Equatorial Guinea (the \u201cEG Assets\u201d). In addition to the initial cash consideration of USD 88.8 million, the EG Seller was also paid a USD 5 million deferred consideration upon completion of the Dussafu Transaction (see Dussafu Transaction below) in June 2021. EG Seller is also entitled to a potential contingent consideration of up USD 16 million, in aggregate, payable only in years where the average annual net production of the acquired interests is in excess of 5,500 bopd. Once this initial net production threshold has been reached, in that year, and for the four consecutive subsequent annual periods, annual contingent consideration of USD 5.5 million will be payable to EG Seller provided that the production threshold is met in such annual period and the average daily Dated Brent oil prices in respect of the annual period is in excess of USD 60/bbl, subject to the aforementioned cap of USD 16 million. If the combination had taken place at the beginning of the year, total revenue from continuing operations would have been USD 178.8 million and profit before tax from continuing operations for the Group would have been USD 89.9 million. The purchase consideration, as set out above, is summarised in the following table: Shares acquired USD 000 Cash consideration 100% 87,431 Deferred consideration * 5,000 Contingent consideration ** 5,019 Net assets acquired 97,450 * Deferred consideration was paid at the time of completion of the Dussafu Transaction. ** Fair value estimate of the contingent consideration, payable only upon meeting the aforementioned criteria. This amount will be reviewed in conjunction with the criteria on an ongoing basis. The fair values of the identifiable assets and liabilities of PEGL at the date of acquisition were as follows: Purchase price allocation USD 000 Assets Concessions 132,806 Goodwill acquired 1,280 Goodwill related to step up / deferred tax 46,482 Production assets and equipment 76,367 Materials inventory 9,990 Crude oil inventory 6,904 Trade receivables 59,135 Other current receivables 245 Total Assets 333,209 Liabilities Decommissioning liability 124,646 Deferred tax liability 58,780 Corporation tax liability 15,410 Crude oil overlift 31,174 Trade payables 5,749 Total liabilities 235,759 Net assets acquired 97,450 Cash flow on acquisition 87,431 For the first quarter of 2021, the operating cashflow of PEGL was USD 10 million before taxes of USD 0.8 million and primarily relates to payments of operating costs. In addition, USD 3.4 million of cash was spent on investing activities in relation to capital expenditure. All these items are already included in the final completion payment of USD 88.8 million. Since the acquisition date, the acquired business contributed revenue of USD 51.6 million and profit before tax of USD 17.6 million to the consolidated statement of comprehensive income. Note 13.2: Dussafu Transaction On 9 February 2021, Panoro and its fully owned subsidiary Pan Petroleum Gabon BV, entered into an agreement with Tullow Oil plc and Tullow Oil Gabon SA to acquire a 10% working interest in the Dussafu Marin Permit, offshore Gabon for an initial cash consideration of USD 46 million based on an effective date of 1 July 2020 which was subject to customary working capital and other customary adjustments to be made at completion. Following completion of Dussafu Transaction in June 2021, Panoro\u2019s total working interest in Dussafu has increased to 17.4997% working interest in Dussafu. At the completion date of 9 June 2021, a total cash consideration of USD 39 million paid to Tullow Oil Gabon SA which included completion and working capital adjustments as of such date. A further contingent consideration of up to USD 24 million (the \u201cDussafu Contingent Consideration\u201d) may also be payable once commercial production commences on Hibiscus and Ruche and achieves daily production equal to or greater than 33,000 bopd gross over any 60-day continuous period. Once this milestone has been met, annual contingent consideration will apply to that year and to each of the subsequent four years where the average daily Dated Brent oil price is in excess of USD 55 per barrel, subject to the USD 24 million cap. Where the oil price threshold has been met, the Dussafu Contingent Consideration payable for that year will be based on 15% of net free cashflow after all taxes, operating and capital costs from the acquired 10% working interest. The contingent payment will be capped for any year at USD 5 million. Although the Dussafu Transaction has only been an increase in Panoro\u2019s working interest in an existing asset, under IFRS 3 the criteria is met for such transaction to be recognised as a business combination which includes recognition of fair value uplift, goodwill and the associated deferred tax under the standard which customary on recognition of such acquisitions. If the combination had taken place at the beginning of the year, total revenue from continuing operations would have been USD 129.5 million and profit before tax from continuing operations for the Group would have been USD 70.3 million. The purchase consideration, as set out above, is summarised in the following table: Working Interest acquired in Dussafu Marin Permit USD 000 Cash consideration 10% 39,028 Net assets acquired 39,028 The fair values of the identifiable assets and liabilities of PEGL at the date of acquisition were as follows: Purchase price allocation USD 000 Assets Exploration and evaluation assets 28,624 Development assets 20,117 Production reserves 39,859 Goodwill acquired (60,072) Goodwill related to step up / deferred tax 13,951 Production assets and equipment 13,843 Inventory 3,456 Other receivable 1,722 Total Assets 61,500 Liabilities Decommissioning liability 4,171 Deferred tax liability 13,951 Other current liabilities 4,350 Total liabilities 22,472 Net assets acquired 39,028 Cash flow on acquisition 39,028 Under the requirements of IFRS 3 \u201cBusiness Combinations\u201d any excess of fair value of net assets acquired over the consideration paid is recognised in the income statement as gain on acquisition of business, which was USD 48.5 million for this transaction. Such gain has arisen due to significant increase in oil prices between effective date and completion date of the Dussafu Transaction. For the first half of 2021, the operating cashflow of the 10% acquired interest under Dussafu Transaction was USD 0.2 million after excluding any value of proportional State Profit oil entitlement and primarily relates to payments of operating costs, capital expenditure and past costs dispute settlement offset by proceeds sale of crude oil entitlement. All these items are already included in the final completion payment of USD 39 million. Since the acquisition date, the acquired business contributed revenue of USD 34.4 million and profit of approximately USD 23.6 million to the consolidated statement of comprehensive income. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3656": {
"value": "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. Business combinations and goodwill Acquisitions are accounted for as described in Note 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 liabiliies and recognition of goodwill where fair values cannot reliably be measured. 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 non-controlling interest (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 administ rative 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. 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3663": {
"value": "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 as adopted by the EU requires 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 Note 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 liabiliies 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 r esults, 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 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 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: 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. 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 a re 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. 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 9.2: Impairment in Oil and Gas Interests. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3805": {
"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 Corp\u201d). Sfax Corp, 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. 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 Joint ventures A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. The Group\u2019s investment in its joint venture is accounted for using the equity method. Under the equity method, the investment in the joint venture is initially recognised at cost. The carrying amount of the investment is adjusted to recognise changes in the Group\u2019s share of net assets of the joint venture since the acquisition date. Goodwill relating to the joint venture is included in the carrying amount of the investment and is not individually tested for impairment. The statement of profit or loss reflects the Group\u2019s share of the results of operations of joint ventures. Unrealised gains and losses resulting from transactions between the Group and the joint venture are eliminated to the extent of the interest in the joint venture. The aggregate of the Group\u2019s share of profit or loss of the joint venture is shown on the face of the statement of profit or loss and other comprehensive income as part of operating profit and represents profit or loss after tax and NCI in the subsidiaries of the joint venture. The financial statements of the joint venture are prepared for the same reporting period as the Group. When necessary, adjustments are made to bring the accounting policies in line with those of the Group. At each reporting date, the Group determines whether there is objective evidence that the investment in the joint venture is impaired. If there is such evidence, the Group calculates the amount of impairment as the difference between the recoverable amount of the joint venture and its carrying value, and then recognises the loss as \u2018Share of profit of a joint venture\u2019 in the statement of profit or loss and other comprehensive income. On loss of joint control over the joint venture, the Group measures and recognises any retained investment at its fair value. Any difference between the carrying amount of the joint venture upon loss of joint control and the fair value of the retained investment and proceeds from disposal is recognised in the statement of profit or loss and other comprehensive income. 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociatesAndJointVenturesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3810": {
"value": "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 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 Joint ventures A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. The Group\u2019s investment in its joint venture is accounted for using the equity method. Under the equity method, the investment in the joint venture is initially recognised at cost. The carrying amount of the investment is adjusted to recognise changes in the Group\u2019s share of net assets of the joint venture since the acquisition date. Goodwill relating to the joint venture is included in the carrying amount of the investment and is not individually tested for impairment. The statement of profit or loss reflects the Group\u2019s share of the results of operations of joint ventures. Unrealised gains and losses resulting from transactions between the Group and the joint venture are eliminated to the extent of the interest in the joint venture. The aggregate of the Group\u2019s share of profit or loss of the joint venture is shown on the face of the statement of profit or loss and other comprehensive income as part of operating profit and represents profit or loss after tax and NCI in the subsidiaries of the joint venture. The financial statements of the joint venture are prepared for the same reporting period as the Group. When necessary, adjustments are made to bring the accounting policies in line with those of the Group. At each reporting date, the Group determines whether there is objective evidence that the investment in the joint venture is impaired. If there is such evidence, the Group calculates the amount of impairment as the difference between the recoverable amount of the joint venture and its carrying value, and then recognises the loss as \u2018Share of profit of a joint venture\u2019 in the statement of profit or loss and other comprehensive income. On loss of joint control over the joint venture, the Group measures and recognises any retained investment at its fair value. Any difference between the carrying amount of the joint venture upon loss of joint control and the fair value of the retained investment and proceeds from disposal is recognised in the statement of profit or loss and other comprehensive income. 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInvestmentsAccountedForUsingEquityMethodExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3811": {
"value": "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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSignificantInvestmentsInAssociatesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3812": {
"value": "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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociates",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3852": {
"value": "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 Joint ventures A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. The Group\u2019s investment in its joint venture is accounted for using the equity method. Under the equity method, the investment in the joint venture is initially recognised at cost. The carrying amount of the investment is adjusted to recognise changes in the Group\u2019s share of net assets of the joint venture since the acquisition date. Goodwill relating to the joint venture is included in the carrying amount of the investment and is not individually tested for impairment. The statement of profit or loss reflects the Group\u2019s share of the results of operations of joint ventures. Unrealised gains and losses resulting from transactions between the Group and the joint venture are eliminated to the extent of the interest in the joint venture. The aggregate of the Group\u2019s share of profit or loss of the joint venture is shown on the face of the statement of profit or loss and other comprehensive income as part of operating profit and represents profit or loss after tax and NCI in the subsidiaries of the joint venture. The financial statements of the joint venture are prepared for the same reporting period as the Group. When necessary, adjustments are made to bring the accounting policies in line with those of the Group. At each reporting date, the Group determines whether there is objective evidence that the investment in the joint venture is impaired. If there is such evidence, the Group calculates the amount of impairment as the difference between the recoverable amount of the joint venture and its carrying value, and then recognises the loss as \u2018Share of profit of a joint venture\u2019 in the statement of profit or loss and other comprehensive income. On loss of joint control over the joint venture, the Group measures and recognises any retained investment at its fair value. Any difference between the carrying amount of the joint venture upon loss of joint control and the fair value of the retained investment and proceeds from disposal is recognised in the statement of profit or loss and other comprehensive income. 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfJointVenturesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3855": {
"value": "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 Joint ventures A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. The Group\u2019s investment in its joint venture is accounted for using the equity method. Under the equity method, the investment in the joint venture is initially recognised at cost. The carrying amount of the investment is adjusted to recognise changes in the Group\u2019s share of net assets of the joint venture since the acquisition date. Goodwill relating to the joint venture is included in the carrying amount of the investment and is not individually tested for impairment. The statement of profit or loss reflects the Group\u2019s share of the results of operations of joint ventures. Unrealised gains and losses resulting from transactions between the Group and the joint venture are eliminated to the extent of the interest in the joint venture. The aggregate of the Group\u2019s share of profit or loss of the joint venture is shown on the face of the statement of profit or loss and other comprehensive income as part of operating profit and represents profit or loss after tax and NCI in the subsidiaries of the joint venture. The financial statements of the joint venture are prepared for the same reporting period as the Group. When necessary, adjustments are made to bring the accounting policies in line with those of the Group. At each reporting date, the Group determines whether there is objective evidence that the investment in the joint venture is impaired. If there is such evidence, the Group calculates the amount of impairment as the difference between the recoverable amount of the joint venture and its carrying value, and then recognises the loss as \u2018Share of profit of a joint venture\u2019 in the statement of profit or loss and other comprehensive income. On loss of joint control over the joint venture, the Group measures and recognises any retained investment at its fair value. Any difference between the carrying amount of the joint venture upon loss of joint control and the fair value of the retained investment and proceeds from disposal is recognised in the statement of profit or loss and other comprehensive income. 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. ",
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"concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3910": {
"value": "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: 2022 2021 Average rate Reporting date rate Average rate Reporting date rate Norwegian Kroner / USD 9.6149 9.8394 8.6002 8.8245 USD / British Pound Sterling 1.2367 1.2039 1.3755 1.3477 USD / Tunisian Dinar 3.0838 3.2482 2.7963 2.8865 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. 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), and the Pound Sterling (GBP). The Group has transactional currency exposures. Such exposure arises from sales or purchases in currencies other than the respective functional currency. The Group reports its consolidated results in USD, any change in exchange rates between its operating subsidiaries\u2019 functional currencies and the USD 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 2022 or 2021. 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 2022 2021 USD vs NOK 20% -20% 20% -20% Cash 10 (15) 9 (13) Receivables 7 (10) 7 (11) Payables (10) 15 (8) 12 Net effect 6 (9) 8 (12) USD vs TND 20% -20% 20% -20% Cash 3 (4) 182 (274) Receivables 133 (200) 1,630 (2,444) Corporation taxes payable (1,593) 2,390 (790) 1,185 Payables (765) 1,148 (593) 889 Net effect (2,223) 3,334 429 (643) USD vs EUR 20% -20% 20% -20% Cash 3 (4) 3 (5) Receivables 1 (2) (33) 50 Payables (32) 48 (33) 50 Net effect (28) 42 (63) 95 USD vs GBP 20% -20% 20% -20% Cash 61 (91) 66 (99) Receivables (49) 74 (36) 54 Payables (18) 26 (55) 83 Net effect (6) 9 (26) 38 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEffectOfChangesInForeignExchangeRatesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f3911": {
"value": "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: 2022 2021 Average rate Reporting date rate Average rate Reporting date rate Norwegian Kroner / USD 9.6149 9.8394 8.6002 8.8245 USD / British Pound Sterling 1.2367 1.2039 1.3755 1.3477 USD / Tunisian Dinar 3.0838 3.2482 2.7963 2.8865 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4014": {
"value": "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 i t 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 tangible and intangible 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 and intangible assets 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 esti mated 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 a re 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. 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 9.2: Impairment in Oil and Gas Interests. NOTE 8: INTANGIBLE ASSETS Note 8.1: Licenses, Exploration and Evaluation Assets, Development Assets 2022 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2022 51,752 46,361 Additions 168 27,137 Transfer to Development Assets (49,325) 49,325 At 31 December 2022 2,595 122,823 Net carrying value at 31 December 2022 2,595 122,823 2021 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2021 21,070 14,522 Additions 2,058 24,129 Transfer to Production Assets - (12,407) Additions through Acquisition 28,624 20,117 At 31 December 2021 51,752 46,361 Net carrying value at 31 December 2021 51,752 46,361 Licence area Panoro\u2019s interest Country Expiry of current phase Block G 14.25% Equatorial Guinea December 2040 Dussafu Marin permit* 17.4997% Gabon September 2028* Sfax Offshore Exploration Permit** 52.5% (Operator) \u2013 excluding Beender\u2019s 40% Tunisia December 2024 Hammamet Offshore Exploration Permit 27.6% - excluding Beender\u2019s 40% Tunisia Under relinquishment Block S 12% Equatorial Guinea December 2024 Block EG-01 56% Equatorial Guinea February 2026 TCP 12/2/218 100% South Africa June 2023 Block 2B *** 12.5% South Africa November 2022 TPS Assets: Cercina February 2024 Cercina South November 2034 Gremda / El Ain ** 29.4% - excluding Beender\u2019s 40% Tunisia December 2018 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. Note 8.2: Production rights USD 000 2022 2021 Acquisition cost At 1 January 188,832 26,475 Depreciation charge for the year (18,307) (14,319) Additions through Acquisition - 172,676 Other additions 3,450 4,000 At 31 December 173,975 188,832 Note 8.3: Goodwill USD 000 2022 2021 Acquisition cost At 1 January 47,762 - Additions through Acquisition - 47,762 At 31 December 47,762 47,762 The Group acquired a 14.25% working interest in Block G, Equatorial Guinea during 2021, assets and liabilities were taken on at fair value and Goodwill of USD 47.8 million recognised as described in Note 13: Business Combinations. An annual impairment assessment was carried out in December 2022 at which time the total carrying value of Block G at 31 December 2022 was USD 127.4 million. 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 and using the discount rate of 12% and long-term oil price assumption of USD 80/bbl, inflated by 2% per annum after five years. 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 Block G asset to materially exceed its recoverable amount. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4015": {
"value": "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 i t 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 tangible and intangible 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 and intangible assets 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 esti mated 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 a re 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. 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 9.2: Impairment in Oil and Gas Interests. ",
"dimensions": {
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"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4016": {
"value": "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 i t 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 tangible and intangible 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 and intangible assets 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 esti mated 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 a re 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. 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 9.2: Impairment in Oil and Gas Interests. NOTE 8: INTANGIBLE ASSETS Note 8.1: Licenses, Exploration and Evaluation Assets, Development Assets 2022 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2022 51,752 46,361 Additions 168 27,137 Transfer to Development Assets (49,325) 49,325 At 31 December 2022 2,595 122,823 Net carrying value at 31 December 2022 2,595 122,823 2021 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2021 21,070 14,522 Additions 2,058 24,129 Transfer to Production Assets - (12,407) Additions through Acquisition 28,624 20,117 At 31 December 2021 51,752 46,361 Net carrying value at 31 December 2021 51,752 46,361 Licence area Panoro\u2019s interest Country Expiry of current phase Block G 14.25% Equatorial Guinea December 2040 Dussafu Marin permit* 17.4997% Gabon September 2028* Sfax Offshore Exploration Permit** 52.5% (Operator) \u2013 excluding Beender\u2019s 40% Tunisia December 2024 Hammamet Offshore Exploration Permit 27.6% - excluding Beender\u2019s 40% Tunisia Under relinquishment Block S 12% Equatorial Guinea December 2024 Block EG-01 56% Equatorial Guinea February 2026 TCP 12/2/218 100% South Africa June 2023 Block 2B *** 12.5% South Africa November 2022 TPS Assets: Cercina February 2024 Cercina South November 2034 Gremda / El Ain ** 29.4% - excluding Beender\u2019s 40% Tunisia December 2018 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. Note 8.2: Production rights USD 000 2022 2021 Acquisition cost At 1 January 188,832 26,475 Depreciation charge for the year (18,307) (14,319) Additions through Acquisition - 172,676 Other additions 3,450 4,000 At 31 December 173,975 188,832 Note 8.3: Goodwill USD 000 2022 2021 Acquisition cost At 1 January 47,762 - Additions through Acquisition - 47,762 At 31 December 47,762 47,762 The Group acquired a 14.25% working interest in Block G, Equatorial Guinea during 2021, assets and liabilities were taken on at fair value and Goodwill of USD 47.8 million recognised as described in Note 13: Business Combinations. An annual impairment assessment was carried out in December 2022 at which time the total carrying value of Block G at 31 December 2022 was USD 127.4 million. 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 and using the discount rate of 12% and long-term oil price assumption of USD 80/bbl, inflated by 2% per annum after five years. 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 Block G asset to materially exceed its recoverable amount. ",
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"f4017": {
"value": "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 i t 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 tangible and intangible 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 and intangible assets 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 esti mated 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 a re 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. 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 9.2: Impairment in Oil and Gas Interests. ",
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"f4018": {
"value": "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 i t 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. 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. Note 4.1: Exploration related costs The Gazania-1 exploration well located at Block 2B offshore the Northern Cape in Orange Basin, South Africa, was drilled without incident. The well did not encounter commercial hydrocarbons. As a result capitalised exploration costs of USD 9.2 million were written off during the year. In 2021 a historical non-fulfilment of a work programme related to Sfax Offshore Exploration Permit by a previous operator was settled during 2021 at a cost of USD 6.3 million. The settlement was made by way of a partial draw on the bank guarantee wih the remaining remaining USD 3.6 million cancelled and cash returned to Panoro. As part of the settlement, the license entered the second renewal period of one year which was later extended a further two years on the condition that a seismic reprocessing project would be completed. Note 8.1: Licenses, Exploration and Evaluation Assets, Development Assets 2022 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2022 51,752 46,361 Additions 168 27,137 Transfer to Development Assets (49,325) 49,325 At 31 December 2022 2,595 122,823 Net carrying value at 31 December 2022 2,595 122,823 2021 USD 000 Licenses and exploration assets Development assets Historical cost At 1 January 2021 21,070 14,522 Additions 2,058 24,129 Transfer to Production Assets - (12,407) Additions through Acquisition 28,624 20,117 At 31 December 2021 51,752 46,361 Net carrying value at 31 December 2021 51,752 46,361 Licence area Panoro\u2019s interest Country Expiry of current phase Block G 14.25% Equatorial Guinea December 2040 Dussafu Marin permit* 17.4997% Gabon September 2028* Sfax Offshore Exploration Permit** 52.5% (Operator) \u2013 excluding Beender\u2019s 40% Tunisia December 2024 Hammamet Offshore Exploration Permit 27.6% - excluding Beender\u2019s 40% Tunisia Under relinquishment Block S 12% Equatorial Guinea December 2024 Block EG-01 56% Equatorial Guinea February 2026 TCP 12/2/218 100% South Africa June 2023 Block 2B *** 12.5% South Africa November 2022 TPS Assets: Cercina February 2024 Cercina South November 2034 Gremda / El Ain ** 29.4% - excluding Beender\u2019s 40% Tunisia December 2018 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. Note 8.2: Production rights USD 000 2022 2021 Acquisition cost At 1 January 188,832 26,475 Depreciation charge for the year (18,307) (14,319) Additions through Acquisition - 172,676 Other additions 3,450 4,000 At 31 December 173,975 188,832 ",
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"f4019": {
"value": "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 i t 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. 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. ",
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"f4036": {
"value": "Development tangible and intangible 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 and intangible assets 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. 2.4.13 Property, plant and equipment Property, plant and equipment not associated with exploration and production activities are carried at cost less accumulated depreciation. These assets are also evaluated for impairment. Depreciation of other assets is calculated on a straight-line basis as follows: Computer equipment: 20 to 33.33% Furniture, Fixtures & fittings: 10 to 33.33% NOTE 9: TANGIBLE ASSETS Note 9.1: Production Assets and Equipment USD 000 2022 2021 Historical cost At 1 January 141,362 40,904 Additions 15,732 10,306 Write-offs (184) (417) Adjustments to asset retirement estimates (22,163) (12,047) Transfer from Development Assets - 12,407 Additions through Acquisition (Note 12) - 90,209 At 31 December 134,747 141,362 Accumulated depreciation At 1 January 21,093 8,601 Write-offs (184) (417) Depreciation charge for the year 16,479 12,909 At 31 December 37,388 21,093 Net carrying value at 31 December 97,359 120,269 Note 9.2: 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 assumtion of USD 80/bbl with a 2% annual inflation after five years. No indication of impairment was identified and no impairment was therefore recognised during the year 2022. Dussafu, Gabon The Group has a 17.4997% interest in the Dussafu Permit, offshore Gabon. An assessment was performed using an oil price assumtion of USD 80/bbl with a 2% annual inflation after five years. No indication of impairment was identified and no impairment was therefore recognised during the year 2022. Sfax Offshore Exploration Permit, Tunisia The Group has an interest in Sfax Offshore Exploration Permit (SOEP). Qualifying directly attributable costs have been capitalised as licence and exploration assets during the year in line with Group\u2019s intention to drill an exploration well and extend the licence. TPS Assets, Tunisia The Group completed the acquisition of its share of interest in TPS Assets, comprising of Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba concessions in December 2018. The Group assesses each cash-generating unit annually to determine whether an indication of impairment exists An assessment was performed using the value of TPS assets derived from the agreed purchase of 40% of Sfax Petroleum Corporation AS by the Company as described in Note 25: Events subsequent to reporting date. . No indication of impairment was identified and no impairment was therefore recognised during the year 2022. OML 113 (Aje), Nigeria (Discontinued) In 2019, the Company entered into a sale and purchase agreement with PetroNor E&P Limited (\u201cPetroNor\u201d), an exploration & production oil and gas company listed on the Oslo Axess, to divest all outstanding shares in its fully owned subsidiaries Pan- Petroleum Services Holding BV and Pan-Petroleum Nigeria Holding BV (together referred to as \u201cDivested Subsidiaries\u201d) as described in Note 14: Discontinued Operations. Following agreement to sell the Divested Subsidiaries, the Group\u2019s interest in such subsidiaries were designated as Assets held for sale as of 31 December 2019. The transaction completed on 13 July 2022 at which time the Group derecognised the assets and liabilities of the Divested Subsidiaries at the carrying amounts. At the date of designation for held for sale during 2019, an assessment was made to determine the fair value of the assets and liabilities of the Divested Subsidiaries. As a result, based on fair value less costs to sell principle, a reversal of historical impairment charges of USD 8 million on account of Aje has been made. Further assessments were made in 2021 and 2022 resulting in a further reversal of USD 8 million and USD 1.2 million respectively of historical impairment charges to carrying value of the Divested Subsidiaries. The impairment reversals has been allocated in proportion of pre-reversal carrying value of licence and exploration assets and production assets and equipment. 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 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 (e.g., environmental taxes/fees) and estimation of future levels of environmental taxes. The Group\u2019s participation in the current licenses and concessions in various jurisdictions are not currently subject to specific carbon pricing. At the recent COP26 UN climate conference, member states explicitly acknowledged the importance of limiting global warming to less than 1.5\u00b0C, rather than the previous Paris Agreement target of \u2018well below 2\u00b0C\u2019. Despite these targets, global energy demand is projected to continue to grow rapidly, and emerging economies in Africa and other geographies are increasingly looking to their fossil resources to underpin economic growth, finance their own energy transition, and help to pay for urgently needed climate adaptation measures. Our strategy therefore aims to balance environmental, energy security and economic objectives by investing in efficient producing assets in North, West and South Africa, and working with our partners to support the transition to a low-carbon business. 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 2022 publication. The scenarios with their key features are as follows: Net Zero Emissions (NZE) NZE requires global greenhouse gas (GHG) emissions to drop by around 50% by 2030, or 7% per year for the next 9 years, implying a rapid drop in oil & gas consumption, a massive push into renewable energy, big gains in energy efficiency, and rapid development and scaling-up of new technologies, including carbon capture. Another major focus is reducing methane emissions from fossil fuel operations. It also demands no further fossil fuel exploration and no new oil and gas production from fields beyond those already approved for development. Oil demand in NZE falls to 72 MMbbls/d in 2030 and 24 mmb/d by 2050. The decline is led by road transport, where 60% of all passenger cars sold globally are electric by 2030, and no new combustion engine cars are sold anywhere after 2035. Petrochemicals are the only area where demand increases and by 2050 accounts for 55% of all oil consumed. Prices fall along with demand, to USD 36/bbl in 2030 and USD 24/bbl in 2050. Announced Pledges (APS) APS assumes full implementation of countries\u2019 pledges announced under the Paris Agreement and updated ahead of COP26 in Glasgow, and estimates an average temperature rise of 2.1\u00b0C by 2050. Oil prices decline slightly from USD 64/bbl in 2030 to USD 60/bbl in 2050. Stated Policies (STEPS) STEPS has demand continuing to rise gradually, levelling off at 104 mmb/d in the mid-2030s; then declining very slightly to 103 mmb/d by 2050. A fall in demand from power generation is offset by increased consumption for road transport (around 6 mmb/d through to 2030) and robust demand from aviation, shipping and petrochemicals. Oil prices rise, reaching USD 82/bbl in 2030 and USD 95/bbl in 2050. 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. A summary of the impact of the different future oil price scenarios on NPV and reserves are as follows: Percentage reduction Net Zero Emissions (NZE) Announced Pledges (APS) Stated Policies (STEPS) NPV12 51% 22% 0% Reserves 30% 11% 2% 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 investme nt 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 9.3: Property, Furniture, Fixtures and Equipment 2022 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2022 138 923 162 946 2,169 Additions 5 23 - - 28 At 31 December 2022 143 946 162 946 2,197 Accumulated depreciation At 1 January 2022 14 825 122 658 1,619 Depreciation charge for the year 86 63 38 191 378 At 31 December 2022 100 888 160 849 1,997 Net carrying value at 31 December 2022 43 58 2 97 200 2021 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2021 - 830 160 946 1,936 Additions 138 93 2 - 233 At 31 December 2021 138 923 162 946 2,169 Accumulated depreciation At 1 January 2021 - 783 68 445 1,296 Depreciation charge for the year 14 42 54 213 323 At 31 December 2021 14 825 122 658 1,619 Net carrying value at 31 December 2021 124 98 40 288 550 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 ",
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},
"f4037": {
"value": "Development tangible and intangible 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 and intangible assets 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. 2.4.13 Property, plant and equipment Property, plant and equipment not associated with exploration and production activities are carried at cost less accumulated depreciation. These assets are also evaluated for impairment. Depreciation of other assets is calculated on a straight-line basis as follows: Computer equipment: 20 to 33.33% Furniture, Fixtures & fittings: 10 to 33.33% ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4043": {
"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 esti mated 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4089": {
"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 a re 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. 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 9.2: Impairment in Oil and Gas Interests. 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 in terest 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. 2.4.17 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4090": {
"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 a re 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. 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 9.2: 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. An annual impairment assessment was carried out in December 2022 at which time the total carrying value of Block G at 31 December 2022 was USD 127.4 million. 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 and using the discount rate of 12% and long-term oil price assumption of USD 80/bbl, inflated by 2% per annum after five years. 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 Block G asset to materially exceed its recoverable amount. Note 9.1: Production Assets and Equipment USD 000 2022 2021 Historical cost At 1 January 141,362 40,904 Additions 15,732 10,306 Write-offs (184) (417) Adjustments to asset retirement estimates (22,163) (12,047) Transfer from Development Assets - 12,407 Additions through Acquisition (Note 12) - 90,209 At 31 December 134,747 141,362 Note 9.2: 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 assumtion of USD 80/bbl with a 2% annual inflation after five years. No indication of impairment was identified and no impairment was therefore recognised during the year 2022. Dussafu, Gabon The Group has a 17.4997% interest in the Dussafu Permit, offshore Gabon. An assessment was performed using an oil price assumtion of USD 80/bbl with a 2% annual inflation after five years. No indication of impairment was identified and no impairment was therefore recognised during the year 2022. Sfax Offshore Exploration Permit, Tunisia The Group has an interest in Sfax Offshore Exploration Permit (SOEP). Qualifying directly attributable costs have been capitalised as licence and exploration assets during the year in line with Group\u2019s intention to drill an exploration well and extend the licence. TPS Assets, Tunisia The Group completed the acquisition of its share of interest in TPS Assets, comprising of Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba concessions in December 2018. The Group assesses each cash-generating unit annually to determine whether an indication of impairment exists An assessment was performed using the value of TPS assets derived from the agreed purchase of 40% of Sfax Petroleum Corporation AS by the Company as described in Note 25: Events subsequent to reporting date. . No indication of impairment was identified and no impairment was therefore recognised during the year 2022. OML 113 (Aje), Nigeria (Discontinued) In 2019, the Company entered into a sale and purchase agreement with PetroNor E&P Limited (\u201cPetroNor\u201d), an exploration & production oil and gas company listed on the Oslo Axess, to divest all outstanding shares in its fully owned subsidiaries Pan- Petroleum Services Holding BV and Pan-Petroleum Nigeria Holding BV (together referred to as \u201cDivested Subsidiaries\u201d) as described in Note 14: Discontinued Operations. Following agreement to sell the Divested Subsidiaries, the Group\u2019s interest in such subsidiaries were designated as Assets held for sale as of 31 December 2019. The transaction completed on 13 July 2022 at which time the Group derecognised the assets and liabilities of the Divested Subsidiaries at the carrying amounts. At the date of designation for held for sale during 2019, an assessment was made to determine the fair value of the assets and liabilities of the Divested Subsidiaries. As a result, based on fair value less costs to sell principle, a reversal of historical impairment charges of USD 8 million on account of Aje has been made. Further assessments were made in 2021 and 2022 resulting in a further reversal of USD 8 million and USD 1.2 million respectively of historical impairment charges to carrying value of the Divested Subsidiaries. The impairment reversals has been allocated in proportion of pre-reversal carrying value of licence and exploration assets and production assets and equipment. 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 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 (e.g., environmental taxes/fees) and estimation of future levels of environmental taxes. The Group\u2019s participation in the current licenses and concessions in various jurisdictions are not currently subject to specific carbon pricing. At the recent COP26 UN climate conference, member states explicitly acknowledged the importance of limiting global warming to less than 1.5\u00b0C, rather than the previous Paris Agreement target of \u2018well below 2\u00b0C\u2019. Despite these targets, global energy demand is projected to continue to grow rapidly, and emerging economies in Africa and other geographies are increasingly looking to their fossil resources to underpin economic growth, finance their own energy transition, and help to pay for urgently needed climate adaptation measures. Our strategy therefore aims to balance environmental, energy security and economic objectives by investing in efficient producing assets in North, West and South Africa, and working with our partners to support the transition to a low-carbon business. 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 2022 publication. The scenarios with their key features are as follows: Net Zero Emissions (NZE) NZE requires global greenhouse gas (GHG) emissions to drop by around 50% by 2030, or 7% per year for the next 9 years, implying a rapid drop in oil & gas consumption, a massive push into renewable energy, big gains in energy efficiency, and rapid development and scaling-up of new technologies, including carbon capture. Another major focus is reducing methane emissions from fossil fuel operations. It also demands no further fossil fuel exploration and no new oil and gas production from fields beyond those already approved for development. Oil demand in NZE falls to 72 MMbbls/d in 2030 and 24 mmb/d by 2050. The decline is led by road transport, where 60% of all passenger cars sold globally are electric by 2030, and no new combustion engine cars are sold anywhere after 2035. Petrochemicals are the only area where demand increases and by 2050 accounts for 55% of all oil consumed. Prices fall along with demand, to USD 36/bbl in 2030 and USD 24/bbl in 2050. Announced Pledges (APS) APS assumes full implementation of countries\u2019 pledges announced under the Paris Agreement and updated ahead of COP26 in Glasgow, and estimates an average temperature rise of 2.1\u00b0C by 2050. Oil prices decline slightly from USD 64/bbl in 2030 to USD 60/bbl in 2050. Stated Policies (STEPS) STEPS has demand continuing to rise gradually, levelling off at 104 mmb/d in the mid-2030s; then declining very slightly to 103 mmb/d by 2050. A fall in demand from power generation is offset by increased consumption for road transport (around 6 mmb/d through to 2030) and robust demand from aviation, shipping and petrochemicals. Oil prices rise, reaching USD 82/bbl in 2030 and USD 95/bbl in 2050. 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. A summary of the impact of the different future oil price scenarios on NPV and reserves are as follows: Percentage reduction Net Zero Emissions (NZE) Announced Pledges (APS) Stated Policies (STEPS) NPV12 51% 22% 0% Reserves 30% 11% 2% 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 investme nt 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4091": {
"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 a re 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. 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 9.2: 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4161": {
"value": "2.4.5 Non-current assets held for sale or for distribution to equity holders of the parent and discontinued operations The Group classifies non-current assets and disposal groups as held for sale or for distribution to equity holders of the parent if their carrying amounts will be recovered principally through a sale or distribution rather than through continuing use. Such non- current assets and disposal groups classified as held for sale or as held for distribution are measured at the lower of their carrying amount and fair value less costs to sell or to distribute. Costs to distribute are the incremental costs directly attributable to the distribution, excluding the finance costs and income tax expense. The criteria for held for distribution classification is regarded as met only when the distribution is highly probable and the asset or disposal group is available for immediate distribution in its present condition. Actions required to complete the distribution should indicate that it is unlikely that significant changes to the distribution will be made or that the distribution with be withdrawn. Management must be committed to the distribution expected within one year from the date of the classification. Similar considerations apply to assets or a disposal group held for sale. Production assets, property, plant and equipment and intangible assets are not depreciated or amortised once classified as held for sale or as held for distribution. Assets and liabilities classified as held for sale or for distribution are presented separately as current items in the statement of financial position. A disposal group qualifies as discontinued operation if it is: \u2022 a component of the Group that is a CGU or a group of CGUs \u2022 classified as held for sale or distribution or already disposed in such a way, or \u2022 a major line of business or major geographical area. Discontinued operations are excluded from the results of continuing operations and are presented as a single amount as profit or loss after tax from discontinued operations in the statement of profit or loss. NOTE 14: DISCONTINUED OPERATIONS On 21 October 2019, the Company entered into a sale and purchase agreement with PetroNor E&P Limited (\u201cPetroNor\u201d), an exploration & production oil and gas company listed on the Oslo Axess, to divest all outstanding shares in its fully owned subsidiaries Pan-Petroleum Services Holding BV and Pan-Petroleum Nigeria Holding BV (together referred to as \u201cDivested Subsidiaries\u201d) for an upfront consideration consisting of the allotment and issue of new PetroNor shares with a fixed value o f USD 10 million (the \u201cShare Consideration\u201d) plus a revised contingent consideration agreed in December 2020 of up to USD 16.67 million based on future gas production volumes. The transaction completed on 13 July 2022 (the \u201cCompletion Date\u201d) with the upfront consideration of USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor shares (the \u201cConsideration Shares\u201d), determined with reference to the contractually determined 30-day volume weighted average price (\u201cVWAP\u201d) of PetroNor\u2019s shares which are listed on the Oslo B\u00f8rs with the Ticker \u201cPNOR\u201d. The operations of the Group\u2019s Divested Subsidiaries were classified as discontinued operations under IFRS 5 since 2019 and the results of the Nigerian segment presented as discontinued operations up to the Completion Date are as follows: Amounts in USD 000, unless otherwise stated 2022 2021 DISCONTINUED OPERATIONS Oil revenue 1,181 3,688 Total revenues 1,181 3,688 Operating costs (1,129) (4,085) General and administrative costs (51) (148) Depreciation, depletion and amortisation - - (Impairment) / reversal of impairment for Oil and gas assets 1,497 8,000 EBIT - Operating income/(loss) 1,498 7,455 Interest costs net of income (192) (351) Net foreign exchange gain / (loss) (2) (2) Other financial costs net of income (46) (91) Net income/(loss) before tax 1,258 7,011 Income tax benefit/(expense) - - Net income/(loss) for the period from discontinued operations 1,258 7,011 EARNINGS PER SHARE Basic EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations 0.01 0.07 Diluted EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations 0.01 0.07 The Group\u2019s interest in Divested Subsidiaries designated as Assets held for sale as of the Completion Date and 31 December 2021 are summarised below: Carrying amount after allocation of impairment reversal USD 000 2022 2021 Assets held for sale Licence and exploration assets 17,632 16,904 Production assets and equipment 11,450 10,978 Crude oil inventory 317 1,088 Cash and cash equivalents 57 45 Total assets held for sale 29,456 29,015 Liabilities held for sale Decommissioning liability (3,768) (3,723) Other non-current liabilities (8,738) (8,546) Accounts payable, accruals and other liabilities (135) (134) Other current liabilities (7,112) (7,936) Total liabilities directly associated with assets classified as held for sale (19,753) (20,339) ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfNoncurrentAssetsHeldForSaleAndDiscontinuedOperationsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4162": {
"value": "2.4.5 Non-current assets held for sale or for distribution to equity holders of the parent and discontinued operations The Group classifies non-current assets and disposal groups as held for sale or for distribution to equity holders of the parent if their carrying amounts will be recovered principally through a sale or distribution rather than through continuing use. Such non- current assets and disposal groups classified as held for sale or as held for distribution are measured at the lower of their carrying amount and fair value less costs to sell or to distribute. Costs to distribute are the incremental costs directly attributable to the distribution, excluding the finance costs and income tax expense. The criteria for held for distribution classification is regarded as met only when the distribution is highly probable and the asset or disposal group is available for immediate distribution in its present condition. Actions required to complete the distribution should indicate that it is unlikely that significant changes to the distribution will be made or that the distribution with be withdrawn. Management must be committed to the distribution expected within one year from the date of the classification. Similar considerations apply to assets or a disposal group held for sale. Production assets, property, plant and equipment and intangible assets are not depreciated or amortised once classified as held for sale or as held for distribution. Assets and liabilities classified as held for sale or for distribution are presented separately as current items in the statement of financial position. A disposal group qualifies as discontinued operation if it is: \u2022 a component of the Group that is a CGU or a group of CGUs \u2022 classified as held for sale or distribution or already disposed in such a way, or \u2022 a major line of business or major geographical area. Discontinued operations are excluded from the results of continuing operations and are presented as a single amount as profit or loss after tax from discontinued operations in the statement of profit or loss. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleAndDiscontinuedOperationsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4163": {
"value": "2.4.5 Non-current assets held for sale or for distribution to equity holders of the parent and discontinued operations The Group classifies non-current assets and disposal groups as held for sale or for distribution to equity holders of the parent if their carrying amounts will be recovered principally through a sale or distribution rather than through continuing use. Such non- current assets and disposal groups classified as held for sale or as held for distribution are measured at the lower of their carrying amount and fair value less costs to sell or to distribute. Costs to distribute are the incremental costs directly attributable to the distribution, excluding the finance costs and income tax expense. The criteria for held for distribution classification is regarded as met only when the distribution is highly probable and the asset or disposal group is available for immediate distribution in its present condition. Actions required to complete the distribution should indicate that it is unlikely that significant changes to the distribution will be made or that the distribution with be withdrawn. Management must be committed to the distribution expected within one year from the date of the classification. Similar considerations apply to assets or a disposal group held for sale. Production assets, property, plant and equipment and intangible assets are not depreciated or amortised once classified as held for sale or as held for distribution. Assets and liabilities classified as held for sale or for distribution are presented separately as current items in the statement of financial position. A disposal group qualifies as discontinued operation if it is: \u2022 a component of the Group that is a CGU or a group of CGUs \u2022 classified as held for sale or distribution or already disposed in such a way, or \u2022 a major line of business or major geographical area. Discontinued operations are excluded from the results of continuing operations and are presented as a single amount as profit or loss after tax from discontinued operations in the statement of profit or loss. NOTE 14: DISCONTINUED OPERATIONS On 21 October 2019, the Company entered into a sale and purchase agreement with PetroNor E&P Limited (\u201cPetroNor\u201d), an exploration & production oil and gas company listed on the Oslo Axess, to divest all outstanding shares in its fully owned subsidiaries Pan-Petroleum Services Holding BV and Pan-Petroleum Nigeria Holding BV (together referred to as \u201cDivested Subsidiaries\u201d) for an upfront consideration consisting of the allotment and issue of new PetroNor shares with a fixed value o f USD 10 million (the \u201cShare Consideration\u201d) plus a revised contingent consideration agreed in December 2020 of up to USD 16.67 million based on future gas production volumes. The transaction completed on 13 July 2022 (the \u201cCompletion Date\u201d) with the upfront consideration of USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor shares (the \u201cConsideration Shares\u201d), determined with reference to the contractually determined 30-day volume weighted average price (\u201cVWAP\u201d) of PetroNor\u2019s shares which are listed on the Oslo B\u00f8rs with the Ticker \u201cPNOR\u201d. The operations of the Group\u2019s Divested Subsidiaries were classified as discontinued operations under IFRS 5 since 2019 and the results of the Nigerian segment presented as discontinued operations up to the Completion Date are as follows: Amounts in USD 000, unless otherwise stated 2022 2021 DISCONTINUED OPERATIONS Oil revenue 1,181 3,688 Total revenues 1,181 3,688 Operating costs (1,129) (4,085) General and administrative costs (51) (148) Depreciation, depletion and amortisation - - (Impairment) / reversal of impairment for Oil and gas assets 1,497 8,000 EBIT - Operating income/(loss) 1,498 7,455 Interest costs net of income (192) (351) Net foreign exchange gain / (loss) (2) (2) Other financial costs net of income (46) (91) Net income/(loss) before tax 1,258 7,011 Income tax benefit/(expense) - - Net income/(loss) for the period from discontinued operations 1,258 7,011 EARNINGS PER SHARE Basic EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations 0.01 0.07 Diluted EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations 0.01 0.07 The Group\u2019s interest in Divested Subsidiaries designated as Assets held for sale as of the Completion Date and 31 December 2021 are summarised below: Carrying amount after allocation of impairment reversal USD 000 2022 2021 Assets held for sale Licence and exploration assets 17,632 16,904 Production assets and equipment 11,450 10,978 Crude oil inventory 317 1,088 Cash and cash equivalents 57 45 Total assets held for sale 29,456 29,015 Liabilities held for sale Decommissioning liability (3,768) (3,723) Other non-current liabilities (8,738) (8,546) Accounts payable, accruals and other liabilities (135) (134) Other current liabilities (7,112) (7,936) Total liabilities directly associated with assets classified as held for sale (19,753) (20,339) ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4164": {
"value": "2.4.5 Non-current assets held for sale or for distribution to equity holders of the parent and discontinued operations The Group classifies non-current assets and disposal groups as held for sale or for distribution to equity holders of the parent if their carrying amounts will be recovered principally through a sale or distribution rather than through continuing use. Such non- current assets and disposal groups classified as held for sale or as held for distribution are measured at the lower of their carrying amount and fair value less costs to sell or to distribute. Costs to distribute are the incremental costs directly attributable to the distribution, excluding the finance costs and income tax expense. The criteria for held for distribution classification is regarded as met only when the distribution is highly probable and the asset or disposal group is available for immediate distribution in its present condition. Actions required to complete the distribution should indicate that it is unlikely that significant changes to the distribution will be made or that the distribution with be withdrawn. Management must be committed to the distribution expected within one year from the date of the classification. Similar considerations apply to assets or a disposal group held for sale. Production assets, property, plant and equipment and intangible assets are not depreciated or amortised once classified as held for sale or as held for distribution. Assets and liabilities classified as held for sale or for distribution are presented separately as current items in the statement of financial position. A disposal group qualifies as discontinued operation if it is: \u2022 a component of the Group that is a CGU or a group of CGUs \u2022 classified as held for sale or distribution or already disposed in such a way, or \u2022 a major line of business or major geographical area. Discontinued operations are excluded from the results of continuing operations and are presented as a single amount as profit or loss after tax from discontinued operations in the statement of profit or loss. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4181": {
"value": "A disposal group qualifies as discontinued operation if it is: \u2022 a component of the Group that is a CGU or a group of CGUs \u2022 classified as held for sale or distribution or already disposed in such a way, or \u2022 a major line of business or major geographical area. Discontinued operations are excluded from the results of continuing operations and are presented as a single amount as profit or loss after tax from discontinued operations in the statement of profit or loss. NOTE 14: DISCONTINUED OPERATIONS On 21 October 2019, the Company entered into a sale and purchase agreement with PetroNor E&P Limited (\u201cPetroNor\u201d), an exploration & production oil and gas company listed on the Oslo Axess, to divest all outstanding shares in its fully owned subsidiaries Pan-Petroleum Services Holding BV and Pan-Petroleum Nigeria Holding BV (together referred to as \u201cDivested Subsidiaries\u201d) for an upfront consideration consisting of the allotment and issue of new PetroNor shares with a fixed value o f USD 10 million (the \u201cShare Consideration\u201d) plus a revised contingent consideration agreed in December 2020 of up to USD 16.67 million based on future gas production volumes. The transaction completed on 13 July 2022 (the \u201cCompletion Date\u201d) with the upfront consideration of USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor shares (the \u201cConsideration Shares\u201d), determined with reference to the contractually determined 30-day volume weighted average price (\u201cVWAP\u201d) of PetroNor\u2019s shares which are listed on the Oslo B\u00f8rs with the Ticker \u201cPNOR\u201d. The operations of the Group\u2019s Divested Subsidiaries were classified as discontinued operations under IFRS 5 since 2019 and the results of the Nigerian segment presented as discontinued operations up to the Completion Date are as follows: Amounts in USD 000, unless otherwise stated 2022 2021 DISCONTINUED OPERATIONS Oil revenue 1,181 3,688 Total revenues 1,181 3,688 Operating costs (1,129) (4,085) General and administrative costs (51) (148) Depreciation, depletion and amortisation - - (Impairment) / reversal of impairment for Oil and gas assets 1,497 8,000 EBIT - Operating income/(loss) 1,498 7,455 Interest costs net of income (192) (351) Net foreign exchange gain / (loss) (2) (2) Other financial costs net of income (46) (91) Net income/(loss) before tax 1,258 7,011 Income tax benefit/(expense) - - Net income/(loss) for the period from discontinued operations 1,258 7,011 EARNINGS PER SHARE Basic EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations 0.01 0.07 Diluted EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations 0.01 0.07 The Group\u2019s interest in Divested Subsidiaries designated as Assets held for sale as of the Completion Date and 31 December 2021 are summarised below: Carrying amount after allocation of impairment reversal USD 000 2022 2021 Assets held for sale Licence and exploration assets 17,632 16,904 Production assets and equipment 11,450 10,978 Crude oil inventory 317 1,088 Cash and cash equivalents 57 45 Total assets held for sale 29,456 29,015 Liabilities held for sale Decommissioning liability (3,768) (3,723) Other non-current liabilities (8,738) (8,546) Accounts payable, accruals and other liabilities (135) (134) Other current liabilities (7,112) (7,936) Total liabilities directly associated with assets classified as held for sale (19,753) (20,339) ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDiscontinuedOperationsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4182": {
"value": "A disposal group qualifies as discontinued operation if it is: \u2022 a component of the Group that is a CGU or a group of CGUs \u2022 classified as held for sale or distribution or already disposed in such a way, or \u2022 a major line of business or major geographical area. Discontinued operations are excluded from the results of continuing operations and are presented as a single amount as profit or loss after tax from discontinued operations in the statement of profit or loss. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDiscontinuedOperationsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4192": {
"value": "2.4.6 Financial instruments 2.4.6.1 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. 2.4.6.2 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. Cash held for Bank guarantee - restricted Cash held for Bank guarantee relates to resources or collateral held by a bank which can only be accessed through fulfilment of conditions imposed by counter parties. Funds are only classified from restricted cash status to cash equivalents when funds are transferred to and under the control of the Group. 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 in terest 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. 2.4.6.3 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. 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 5.1: Loans and borrowings Note 5.1.1 Mercuria senior secured loan In 2018, the Group entered into an agreement with Mercuria Assets Holdings (Hong Kong) Ltd (\u201cMercuria\u201d), whereby Mercuria provided PTP (60% owned by Panoro) an acquisition loan facility comprising a Senior Secured Loan facility of USD 16.2 million (USD 27 million gross) which was fully drawn. The Senior Loan facility initially had term of 5 years with interest charged at USD 3-month LIBOR plus 6% on quarterly amounts drawn, with repayments due each quarter. Interest of USD 0.2 million (USD 0.3 million gross) was accrued up to 31 December 2022 (31 December 2021: USD 0.2 million). On 25 June 2019, the Group and Mercuria mutually agreed to make minor adjustments to the Facility terms, resulting in the Facility amount increasing by USD 2.5 million (USD 4.1 million gross) to USD 18.7 million (USD 30 million gross). As part of the security package for the enhanced facility size, shares in Panoro Energy AS (holding company for Panoro Tunisia Exploration AS) have been pledged as collateral. The amended Senior Loan facility has a term of 5 years from 30 June 2019 with interest charged at USD 3-month LIBOR plus 6% on the balance outstanding, with repayments due each quarter. Key financial covenants were unchanged as a result of the amendment and are required to be tested at the end of every 3- month period. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include the following: (i) Field life coverage ratio (FLCR): 1.50x (ii) Minimum cash balance equal to the amount of the next loan and interest repayment, varying as the loan is repaid but typically around USD 1.2 million (USD 2 million gross) to be maintained at all times in the collection account of the borrower. (iii) Debt service coverage ratio (DSCR): between 1.15x and 1.25x subject to specifications in the loan agreement. (iv) Liquidity Test: Customary to the loan instrument. Security package for the original Senior Secured loan comprised a Guarantee from Panoro Energy ASA, share pledge over shares in Panoro TPS (UK) Production Limited and Panoro TPS Production GmbH and from Sfax Petroleum Corporation AS, shareholder and intercompany loans (subordinated at all times), rights under hedging agreements, and the Account Management Agreement (for the Collection Account), negative pledge over the assets. In an event, the guarantee placed by Panoro Energy ASA is called upon, the shareholders\u2019 agreement with Beender for the ownership on Sfax Petroleum Corporation AS provides that Sfax Petroleum Corporation AS shall indemnify Panoro Energy ASA. If Sfax Petroleum Corporation AS is unable to indemnify, Panoro Energy ASA, such indemnification, pro rata to its ownership, shall be made by Beender. As part of the amendment in June 2019 as noted above, the security package for the enhanced facility size was amended to also include a pledge over the shares in Panoro Energy AS (holding company for Panoro Tunisia Exploration AS). The Mercuria loan was repaid in full on 15 March 2023 by the Group and all security held in relation to the loan was released at that date, refer to Note 25: Events subsequent to reporting date. Current and non-current portion of the outstanding balance of the Mercuria Senior Secured facility as of the date of the statement of financial position attributable to Panoro\u2019s 60% ownership is as follows: USD 000 31 December 2022 31 December 2021 Current Non-current Total Current Non-current Total Mercuria Senior Secured loan facility Principal outstanding 5,100 1,740 6,840 4,950 5,820 10,770 Accumulated interest accrued 170 - 170 169 - 169 Unamortised borrowing costs (55) (8) (63) (103) (63) (166) 5,215 1,732 6,947 5,016 5,757 10,773 Note 5.1.2 Trafigura Secured Borrowing Base facility 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, to partially finance the EG Transaction and the Dussafu Transaction as described above. The loan has been made available in two tranches, Tranche A of up to USD 55 million in respect of the EG Transaction and Tranche B of up to USD 35 million in respect of the Dussafu Acquisition. Tranche A and Tranche B can be drawn separately and are not conditional on each other. The drawn-down amount under the loan will amortise over a period of 5 years and carries an annual interest rate of USD 3-month LIBOR plus 7.5%. An accordion option for an additional USD 50 million is included alongside and in addition to the acquisition finance facilities. On 30 March 2021, Panoro drew down against Tranche A of the facility, borrowing USD 55 million which was utilised to partially pay for the purchase consideration of the EG Transaction as described above, and the balance funded from the proceeds of the equity private placement of the Company shares that completed in the first quarter of this year. On 9 June 2021, Panoro drew down against Tranche B of the facility, borrowing USD 35 million which was utilised to partially pay for the purchase consideration of the Dussafu Transaction as described above. The amended Senior Loan facility has a term of 5 years from 31 March 2021 with interest charged and paid quarterly at USD 3-month LIBOR plus 7.5% on the balance outstanding, with principal repayments due each six months. Key financial covenants are required to be tested 30 September and 31 March. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include 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) The Group was not in breach of any financial covenants as at 31 December 2022. Un-amortised borrowing costs include structuring fees and directly attributable third-party costs. During the current quarter, these costs are expensed using an effective interest rate of 11.74% per annum over the remaining term of the facility. Subsequent to year-end, the Company has increased its facility by USD 15 million in conjunction with acquisition of 40% interest in Sfax Petroleum Corporation AS. See Note 25: Events subsequent to reporting date for further details. Current and non-current portion of the outstanding balance of the Trafigura Secured Borrowing Base facility as of the date of the statement of financial position is as follows: USD 000 31 December 2022 31 December 2021 Current Non- current Total Current Non- current Total Trafigura Secured Borrowing Base facility Principal outstanding 16,200 57,600 73,800 10,800 73,800 84,600 Accumulated interest accrued - - - - - - Unamortised borrowing costs (918) (950) (1,868) (1,102) (1,868) (2,970) 15,282 56,650 71,932 9,698 71,932 81,630 Note 5.1.3 BW Energy non-recourse loan The Group has in place a non-recourse loan from BW Energy in relation to the funding of the Dussafu development. The loan bears interest at 7.5% per annum on outstanding balance, compounded annually. The balance outstanding at each balance sheet date presented is as below: USD 000 31 December 2022 31 December 2021 Current Non-current Total Current Non- Current Total BW Energy Non-Recourse loan Principal outstanding - - - 2,234 - 2,234 Accumulated interest accrued 632 - 632 2,273 - 2,273 632 - 632 4,507 - 4,507 The loan is repayable through Panoro\u2019s allocation of the cost oil in accordance with the Dussafu PSC, after paying for the proportionate field operating expenses and as such the loan is classified as current or non-current based on expected field production and lifting schedule at a reasonable oil price assumption at the time of making such classification. During the repayment phase, Panoro is still entitled to its share of profit oil, as defined in the PSC, from the Dussafu operations. The remaining balance of the BW Energy loan was repaid on 21 March 2023. 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. The outstanding commodity hedge contracts as at the respective balance sheet dates presented were as follows: Zero cost collar instruments Remaining term Remaining contract amount Average contract price Average contract price Fair value Asset / (Liability) Fair value Asset / (Liability) Bbls Buy Put (USD/Bbl) Sell Call (USD/Bbl) Current (USD '000) Non-Current (USD '000) At 31 December 2021 Jan 21 - Dec 21 216,000 55 64 (2,489) - At 31 December 2022 Dec 22 - Mar 23 50,000 40 47 133 - The fair values of the commodity price contracts were 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 (2021: 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. 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, liabilities 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. Commodity price risk The Group is exposed to the risk of fluctuations in prevailing market commodity prices (primarily crude oil) on the oil and gas it produces. The Group\u2019s policy is to manage these risks through the use of derivative financial instruments. The following tabl e summarises the impact on profit before tax for changes in commodity prices on the fair value of derivative financial instruments. The impact on equity is the same as the impact on profit before tax as these derivative financial instruments have not been designated as hedges and are classified as held-for-trading. The analysis is based on derivative contracts existing at the balance sheet date, the assumption that crude oil price moves 15% over all future periods, with all other variables held constant. Management believes that 15% is a reasonable sensitivity based on forward forecasts of estimated oil price volatility. Increase /(decrease) in profit before tax and equity USD 000 2022 2021 15% increase in the price of oil (20) 373 15% decrease in the price of oil 20 (373) 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), and the Pound Sterling (GBP). The Group has transactional currency exposures. Such exposure arises from sales or purchases in currencies other than the respective functional currency. The Group reports its consolidated results in USD, any change in exchange rates between its operating subsidiaries\u2019 functional currencies and the USD 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 2022 or 2021. 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 2022 2021 USD vs NOK 20% -20% 20% -20% Cash 10 (15) 9 (13) Receivables 7 (10) 7 (11) Payables (10) 15 (8) 12 Net effect 6 (9) 8 (12) USD vs TND 20% -20% 20% -20% Cash 3 (4) 182 (274) Receivables 133 (200) 1,630 (2,444) Corporation taxes payable (1,593) 2,390 (790) 1,185 Payables (765) 1,148 (593) 889 Net effect (2,223) 3,334 429 (643) USD vs EUR 20% -20% 20% -20% Cash 3 (4) 3 (5) Receivables 1 (2) (33) 50 Payables (32) 48 (33) 50 Net effect (28) 42 (63) 95 USD vs GBP 20% -20% 20% -20% Cash 61 (91) 66 (99) Receivables (49) 74 (36) 54 Payables (18) 26 (55) 83 Net effect (6) 9 (26) 38 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 2022 2021 +100bps -100bps +100bps -100bps Loans and borrowings (Secured loans) (806) 806 (954) 954 Cash equivalents 32 (32) 51 (51) Net effect (774) 774 (902) 902 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 2022 based on contractual undiscounted payments. 2022 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Secured loans) - 21,470 59,340 - 80,810 Loans and borrowings (Non-recourse loan) - 632 - - 632 Accounts payable and accrued liabilities - 9,087 - - 9,087 Non-current liabilities - - - 1,934 1,934 Corporation tax liabilities - 35,560 - - 35,560 Total - 66,749 59,340 1,934 128,023 2021 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Senior secured facility) - 15,919 79,620 - 95,539 Loans and borrowings (Non-recourse loan) - 4,507 - - 4,507 Accounts payable and accrued liabilities - 12,707 - - 12,707 Non-current liabilities - - 1,727 1,553 3,280 Corporation tax liabilities - 17,018 - - 17,018 Total - 50,151 81,347 1,553 133,051 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 2022, the Group\u2019s total debt was USD 79.5 million. The Group closed the year with a cash position of USD 32.7 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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"f4193": {
"value": "2.4.6 Financial instruments 2.4.6.1 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. 2.4.6.2 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. Cash held for Bank guarantee - restricted Cash held for Bank guarantee relates to resources or collateral held by a bank which can only be accessed through fulfilment of conditions imposed by counter parties. Funds are only classified from restricted cash status to cash equivalents when funds are transferred to and under the control of the Group. 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 in terest 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. 2.4.6.3 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. 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. ",
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"f4195": {
"value": "2.4.6.1 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. 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. The outstanding commodity hedge contracts as at the respective balance sheet dates presented were as follows: Zero cost collar instruments Remaining term Remaining contract amount Average contract price Average contract price Fair value Asset / (Liability) Fair value Asset / (Liability) Bbls Buy Put (USD/Bbl) Sell Call (USD/Bbl) Current (USD '000) Non-Current (USD '000) At 31 December 2021 Jan 21 - Dec 21 216,000 55 64 (2,489) - At 31 December 2022 Dec 22 - Mar 23 50,000 40 47 133 - The fair values of the commodity price contracts were 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 (2021: 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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"f4196": {
"value": "2.4.6.1 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. ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4197": {
"value": "2.4.6.1 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. ",
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"concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory",
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"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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},
"f4198": {
"value": "2.4.6.1 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. ",
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"concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory",
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"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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},
"f4213": {
"value": "2.4.6.2 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. Cash held for Bank guarantee - restricted Cash held for Bank guarantee relates to resources or collateral held by a bank which can only be accessed through fulfilment of conditions imposed by counter parties. Funds are only classified from restricted cash status to cash equivalents when funds are transferred to and under the control of the Group. 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 in terest 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. ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4218": {
"value": "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. ",
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"f4243": {
"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": {
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"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
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},
"f4244": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4252": {
"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. NOTE 12: CASH AND BANK BALANCES USD 000 2022 2021 Cash and cash equivalents 32,670 24,532 At 31 December 32,670 24,532 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 2022 (31 December 2021: Nil). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4253": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4258": {
"value": "Cash held for Bank guarantee - restricted Cash held for Bank guarantee relates to resources or collateral held by a bank which can only be accessed through fulfilment of conditions imposed by counter parties. Funds are only classified from restricted cash status to cash equivalents when funds are transferred to and under the control of the Group. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRestrictedCashAndCashEquivalentsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4259": {
"value": "Cash held for Bank guarantee - restricted Cash held for Bank guarantee relates to resources or collateral held by a bank which can only be accessed through fulfilment of conditions imposed by counter parties. Funds are only classified from restricted cash status to cash equivalents when funds are transferred to and under the control of the Group. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForRestrictedCashAndCashEquivalentsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4264": {
"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 in terest 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. 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCreditRiskExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4265": {
"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 in terest 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:DisclosureOfAllowanceForCreditLossesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4266": {
"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 in terest 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4283": {
"value": "2.4.6.3 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4296": {
"value": "2.4.7 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. 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. The outstanding commodity hedge contracts as at the respective balance sheet dates presented were as follows: Zero cost collar instruments Remaining term Remaining contract amount Average contract price Average contract price Fair value Asset / (Liability) Fair value Asset / (Liability) Bbls Buy Put (USD/Bbl) Sell Call (USD/Bbl) Current (USD '000) Non-Current (USD '000) At 31 December 2021 Jan 21 - Dec 21 216,000 55 64 (2,489) - At 31 December 2022 Dec 22 - Mar 23 50,000 40 47 133 - The fair values of the commodity price contracts were 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 (2021: 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4297": {
"value": "2.4.7 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4346": {
"value": "2.4.8 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. 2.4.9 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. 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 2022 113,862 8,150 18,827 140,839 Unwinding of discount 2,848 204 469 3,521 Change in inflation and discount rate (14,313) (1,603) (1,804) (17,720) Change in licence term (11,390) - - (11,390) Additions - 1,457 - 1,457 Change in cost estimate 6,947 - - 6,947 Balance at 31 December 2022 97,954 8,208 17,492 123,654 At 1 January 2021 - 3,096 18,368 21,464 Unwinding of discount 1,998 148 459 2,605 Change in inflation and discount rate (estimate) (18,282) - - (18,282) Acquisitions 124,646 4,171 - 128,817 Change in cost estimate 5,500 735 - 6,235 Balance at 31 December 2021 113,862 8,150 18,827 140,839 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 2022 are a discount rate of 4% and an inflation rate of 2% (31 December 2021: 2.5% and 2% respectively). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfProvisionsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4347": {
"value": "2.4.8 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. 2.4.9 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:DescriptionOfAccountingPolicyForProvisionsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4359": {
"value": "2.4.9 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. 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 2022 113,862 8,150 18,827 140,839 Unwinding of discount 2,848 204 469 3,521 Change in inflation and discount rate (14,313) (1,603) (1,804) (17,720) Change in licence term (11,390) - - (11,390) Additions - 1,457 - 1,457 Change in cost estimate 6,947 - - 6,947 Balance at 31 December 2022 97,954 8,208 17,492 123,654 At 1 January 2021 - 3,096 18,368 21,464 Unwinding of discount 1,998 148 459 2,605 Change in inflation and discount rate (estimate) (18,282) - - (18,282) Acquisitions 124,646 4,171 - 128,817 Change in cost estimate 5,500 735 - 6,235 Balance at 31 December 2021 113,862 8,150 18,827 140,839 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 2022 are a discount rate of 4% and an inflation rate of 2% (31 December 2021: 2.5% and 2% respectively). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherProvisionsContingentLiabilitiesAndContingentAssetsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4360": {
"value": "2.4.9 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4380": {
"value": "2.4.10 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. NOTE 6: 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 2022 2021 Income Taxes Current income tax (i) 12,834 6,541 PSC based Profit Oil allocation \u2013 current (ii) 8,359 5,949 PSC based income tax - current (iii) 27,420 10,417 Deferred tax expense / (benefit) (iv) (6,827) (1,838) Tax relating to prior years income 3 10 Tax charge / (benefit) for the period 41,789 21,079 (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 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 2022 2021 Profit/ (loss) before taxation \u2013 continuing operations 60,721 63,391 Profit / (loss) before taxation \u2013 discontinued operations 961 7,011 Profit / (loss) before taxation - total 61,682 70,402 Tax/ (tax loss) calculated at domestic tax rates applicable to profits in the respective countries 54,456 35,423 Expenses not deductible (43,919) (29,365) Expenses deductible for tax (3) (669) Deferred tax arising on taxable temporary differences (1,088) 313 PSC based Profit Oil allocation 35,779 16,366 Tax effect of prior years' losses utilised in the period (5,739) (2,151) Tax effect of losses not utilised in the period 2,300 1,152 Prior year adjustment 3 10 Tax charge / (benefit) 41,789 21,079 Tax Liabilities Tax liabilities payable of USD 35.6 million as of 31 December 2022 comprised of taxes payable in Equatorial Guinea of USD 25.8 million and Tunisia of USD 9.7 million for production from various concessions (31 December 2021: USD 17 million comprised of taxes payable in Equatorial Guinea of USD 12.3 million and Tunisia of USD 4.7 million). Advantage was taken in Tunisia of a incentives with a tax value of USD 9.2 million that require investment in government approved projects within four years. Investment plans are being considered and formalised for implementation within the allowed timeframe. Deferred tax Deferred tax benefit of USD 6.8 million recognised during the year comprises of USD 9.5 million benefit in Equatorial Guinea, offset by a USD 2.7 million expense in Tunisia arising on taxable temporary differences between accounting and tax bases of property, plant and equipment. Effective tax rate of the respective petroleum concessions has been used to calculate such liability. The deferred tax liability of USD 67.2 million as of 31 December 2022 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 and Tunisia. There are no recognised deferred tax assets in the Group financial statements as of 31 December 2022 (31 December 2021: 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 6.9 million (2021: USD 6.7 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 2022 2021 Panoro Energy ASA 12,839 21,591 Panoro Energy Limited - 486 Sfax Petroleum Corporation (at 60%) 18,530 8,802 Total 31,369 30,879 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4381": {
"value": "2.4.10 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4392": {
"value": "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. Deferred tax Deferred tax benefit of USD 6.8 million recognised during the year comprises of USD 9.5 million benefit in Equatorial Guinea, offset by a USD 2.7 million expense in Tunisia arising on taxable temporary differences between accounting and tax bases of property, plant and equipment. Effective tax rate of the respective petroleum concessions has been used to calculate such liability. The deferred tax liability of USD 67.2 million as of 31 December 2022 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 and Tunisia. There are no recognised deferred tax assets in the Group financial statements as of 31 December 2022 (31 December 2021: 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 6.9 million (2021: USD 6.7 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 2022 2021 Panoro Energy ASA 12,839 21,591 Panoro Energy Limited - 486 Sfax Petroleum Corporation (at 60%) 18,530 8,802 Total 31,369 30,879 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4393": {
"value": "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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4448": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4458": {
"value": "2.4.11 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. Revenue from major sources from continuing operations: USD 000 2022 2021 Oil revenue (net) 180,267 113,708 Other revenue 8,359 5,949 Total revenue 188,626 119,657 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 international sales of the Group in Tunisia during 2022 were to a single customer, Mercuria Energy Trading SA, through a crude marketing agreement. All sales in 2022 from the Group\u2019s production from Block G in Equatorial Guinea and Dussafu in Gabon arose from one key customer each. Under the terms of the Dussafu PSC, State profit oil is estimated and shown as other revenue with a corresponding amount as income tax, see Note 2.4.10 Income tax. There are no other items included in other revenue for both periods presented. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRevenueExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4459": {
"value": "2.4.11 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4473": {
"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. NOTE 5: FINANCE , INTEREST AND OTHER INCOME AND EXPENSE [P- USD 000 2022 2021 Unrealised (gain) / loss on commodity hedges (Note 19) (2,622) 3,868 Realised (gain) / loss on commodity hedges (Note 19) 8,534 4,354 Interest income from placements and deposits (57) (77) Interest expense - Loans and borrowings 9,536 6,895 Interest expense - Bank guarantee - 199 Unrealised (gain) / loss on listed equity investments (Note 11) 75 - Realised (gain) / loss on listed equity investments (Note 11) 652 Other financial costs - Bank charges and ARO unwinding 4,193 2,822 Total - Net (income) / expense 20,311 18,061 --WSHYG Note 5.1: Loans and borrowings Note 5.1.1 Mercuria senior secured loan In 2018, the Group entered into an agreement with Mercuria Assets Holdings (Hong Kong) Ltd (\u201cMercuria\u201d), whereby Mercuria provided PTP (60% owned by Panoro) an acquisition loan facility comprising a Senior Secured Loan facility of USD 16.2 million (USD 27 million gross) which was fully drawn. The Senior Loan facility initially had term of 5 years with interest charged at USD 3-month LIBOR plus 6% on quarterly amounts drawn, with repayments due each quarter. Interest of USD 0.2 million (USD 0.3 million gross) was accrued up to 31 December 2022 (31 December 2021: USD 0.2 million). On 25 June 2019, the Group and Mercuria mutually agreed to make minor adjustments to the Facility terms, resulting in the Facility amount increasing by USD 2.5 million (USD 4.1 million gross) to USD 18.7 million (USD 30 million gross). As part of the security package for the enhanced facility size, shares in Panoro Energy AS (holding company for Panoro Tunisia Exploration AS) have been pledged as collateral. The amended Senior Loan facility has a term of 5 years from 30 June 2019 with interest charged at USD 3-month LIBOR plus 6% on the balance outstanding, with repayments due each quarter. Key financial covenants were unchanged as a result of the amendment and are required to be tested at the end of every 3- month period. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include the following: (i) Field life coverage ratio (FLCR): 1.50x (ii) Minimum cash balance equal to the amount of the next loan and interest repayment, varying as the loan is repaid but typically around USD 1.2 million (USD 2 million gross) to be maintained at all times in the collection account of the borrower. (iii) Debt service coverage ratio (DSCR): between 1.15x and 1.25x subject to specifications in the loan agreement. (iv) Liquidity Test: Customary to the loan instrument. Security package for the original Senior Secured loan comprised a Guarantee from Panoro Energy ASA, share pledge over shares in Panoro TPS (UK) Production Limited and Panoro TPS Production GmbH and from Sfax Petroleum Corporation AS, shareholder and intercompany loans (subordinated at all times), rights under hedging agreements, and the Account Management Agreement (for the Collection Account), negative pledge over the assets. In an event, the guarantee placed by Panoro Energy ASA is called upon, the shareholders\u2019 agreement with Beender for the ownership on Sfax Petroleum Corporation AS provides that Sfax Petroleum Corporation AS shall indemnify Panoro Energy ASA. If Sfax Petroleum Corporation AS is unable to indemnify, Panoro Energy ASA, such indemnification, pro rata to its ownership, shall be made by Beender. As part of the amendment in June 2019 as noted above, the security package for the enhanced facility size was amended to also include a pledge over the shares in Panoro Energy AS (holding company for Panoro Tunisia Exploration AS). The Mercuria loan was repaid in full on 15 March 2023 by the Group and all security held in relation to the loan was released at that date, refer to Note 25: Events subsequent to reporting date. Current and non-current portion of the outstanding balance of the Mercuria Senior Secured facility as of the date of the statement of financial position attributable to Panoro\u2019s 60% ownership is as follows: USD 000 31 December 2022 31 December 2021 Current Non-current Total Current Non-current Total Mercuria Senior Secured loan facility Principal outstanding 5,100 1,740 6,840 4,950 5,820 10,770 Accumulated interest accrued 170 - 170 169 - 169 Unamortised borrowing costs (55) (8) (63) (103) (63) (166) 5,215 1,732 6,947 5,016 5,757 10,773 Note 5.1.2 Trafigura Secured Borrowing Base facility 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, to partially finance the EG Transaction and the Dussafu Transaction as described above. The loan has been made available in two tranches, Tranche A of up to USD 55 million in respect of the EG Transaction and Tranche B of up to USD 35 million in respect of the Dussafu Acquisition. Tranche A and Tranche B can be drawn separately and are not conditional on each other. The drawn-down amount under the loan will amortise over a period of 5 years and carries an annual interest rate of USD 3-month LIBOR plus 7.5%. An accordion option for an additional USD 50 million is included alongside and in addition to the acquisition finance facilities. On 30 March 2021, Panoro drew down against Tranche A of the facility, borrowing USD 55 million which was utilised to partially pay for the purchase consideration of the EG Transaction as described above, and the balance funded from the proceeds of the equity private placement of the Company shares that completed in the first quarter of this year. On 9 June 2021, Panoro drew down against Tranche B of the facility, borrowing USD 35 million which was utilised to partially pay for the purchase consideration of the Dussafu Transaction as described above. The amended Senior Loan facility has a term of 5 years from 31 March 2021 with interest charged and paid quarterly at USD 3-month LIBOR plus 7.5% on the balance outstanding, with principal repayments due each six months. Key financial covenants are required to be tested 30 September and 31 March. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include 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) The Group was not in breach of any financial covenants as at 31 December 2022. Un-amortised borrowing costs include structuring fees and directly attributable third-party costs. During the current quarter, these costs are expensed using an effective interest rate of 11.74% per annum over the remaining term of the facility. Subsequent to year-end, the Company has increased its facility by USD 15 million in conjunction with acquisition of 40% interest in Sfax Petroleum Corporation AS. See Note 25: Events subsequent to reporting date for further details. Current and non-current portion of the outstanding balance of the Trafigura Secured Borrowing Base facility as of the date of the statement of financial position is as follows: USD 000 31 December 2022 31 December 2021 Current Non- current Total Current Non- current Total Trafigura Secured Borrowing Base facility Principal outstanding 16,200 57,600 73,800 10,800 73,800 84,600 Accumulated interest accrued - - - - - - Unamortised borrowing costs (918) (950) (1,868) (1,102) (1,868) (2,970) 15,282 56,650 71,932 9,698 71,932 81,630 Note 5.1.3 BW Energy non-recourse loan The Group has in place a non-recourse loan from BW Energy in relation to the funding of the Dussafu development. The loan bears interest at 7.5% per annum on outstanding balance, compounded annually. The balance outstanding at each balance sheet date presented is as below: USD 000 31 December 2022 31 December 2021 Current Non-current Total Current Non- Current Total BW Energy Non-Recourse loan Principal outstanding - - - 2,234 - 2,234 Accumulated interest accrued 632 - 632 2,273 - 2,273 632 - 632 4,507 - 4,507 The loan is repayable through Panoro\u2019s allocation of the cost oil in accordance with the Dussafu PSC, after paying for the proportionate field operating expenses and as such the loan is classified as current or non-current based on expected field production and lifting schedule at a reasonable oil price assumption at the time of making such classification. During the repayment phase, Panoro is still entitled to its share of profit oil, as defined in the PSC, from the Dussafu operations. The remaining balance of the BW Energy loan was repaid on 21 March 2023. 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 2022 2021 At 1 January 99,756 20,392 Cash flows: Drawdown of Secured Loans, net of fees - 90,000 Repayment of Secured Loans (14,730) (13,384) Repayment of non-recourse loan (4,065) (3,106) Realised gain/(loss) on commodity hedges (7,689) (2,668) Borrowing costs, including arrangement fees (8,141) (4,689) Lease liability payments (231) (254) Non cash changes: Unwinding of unamortised borrowing cost and finance charges 1,324 1,123 Interest accrued 8,232 5,812 Movement in unrealised hedges 5,200 6,536 Initial recognition lease under IFRS 16 - - Foreign exchange movements (32) (6) At 31 December 79,394 99,756 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4474": {
"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:DescriptionOfAccountingPolicyForFinanceIncomeAndCostsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4475": {
"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. NOTE 5: FINANCE , INTEREST AND OTHER INCOME AND EXPENSE [P- USD 000 2022 2021 Unrealised (gain) / loss on commodity hedges (Note 19) (2,622) 3,868 Realised (gain) / loss on commodity hedges (Note 19) 8,534 4,354 Interest income from placements and deposits (57) (77) Interest expense - Loans and borrowings 9,536 6,895 Interest expense - Bank guarantee - 199 Unrealised (gain) / loss on listed equity investments (Note 11) 75 - Realised (gain) / loss on listed equity investments (Note 11) 652 Other financial costs - Bank charges and ARO unwinding 4,193 2,822 Total - Net (income) / expense 20,311 18,061 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4476": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4483": {
"value": "2.4.12 Leases At contract inception, an assessment is made of all arrangements to determine whether they are, or contain, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Group is not a lessor in any transactions, it is only a lessee. The Group applies a single recognition and measurement approach for all leases, except for short-term leases of 12 months or less and leases of low-value assets. The Group recognises lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets. Right-of-use assets The Group recognises right-of-use assets at the commencement date of the lease (i.e., the date the underlying asset is available for use). Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. The only right-of-use asset, the London office lease, is depreciated on a straight-line basis over the lease term. If ownership of the leased asset transfers to the Group at the end of the lease term or the cost reflects the exercise of a purchase option, depreciation is calculated using the estimated useful life of the asset. Note 9.3: Property, Furniture, Fixtures and Equipment 2022 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2022 138 923 162 946 2,169 Additions 5 23 - - 28 At 31 December 2022 143 946 162 946 2,197 Accumulated depreciation At 1 January 2022 14 825 122 658 1,619 Depreciation charge for the year 86 63 38 191 378 At 31 December 2022 100 888 160 849 1,997 Net carrying value at 31 December 2022 43 58 2 97 200 2021 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2021 - 830 160 946 1,936 Additions 138 93 2 - 233 At 31 December 2021 138 923 162 946 2,169 Accumulated depreciation At 1 January 2021 - 783 68 445 1,296 Depreciation charge for the year 14 42 54 213 323 At 31 December 2021 14 825 122 658 1,619 Net carrying value at 31 December 2021 124 98 40 288 550 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 extended to June 2023 and the liability and the right of use asset determined using an incremental rate of return of 8.5% 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 2022, the entire USD 114 thousand was current (31 December 2021: USD 231 thousand current and USD 127 thousand non- current). USD 000 2022 2021 Lease liability recognised at 1 January 358 578 Add: lease interest 19 40 Less: gross lease payments (263) (260) Lease liability at 31 December 114 358 The following table shows the maturity profile of lease liabilities based on contractual undiscounted lease payments. USD 000 2022 2021 Within 1 year 47 187 2 to 5 years - 47 After 5 years - - Lease liability at 31 December 47 233 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 9: Tangible Assets. USD 000 2022 2021 Right of use asset recognised at 1 January 288 501 Less: depreciation and impairment (191) (213) Net book value of right of use asset at 31 December 97 288 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLeasesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4484": {
"value": "2.4.12 Leases At contract inception, an assessment is made of all arrangements to determine whether they are, or contain, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Group is not a lessor in any transactions, it is only a lessee. The Group applies a single recognition and measurement approach for all leases, except for short-term leases of 12 months or less and leases of low-value assets. The Group recognises lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets. Right-of-use assets The Group recognises right-of-use assets at the commencement date of the lease (i.e., the date the underlying asset is available for use). Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. The only right-of-use asset, the London office lease, is depreciated on a straight-line basis over the lease term. If ownership of the leased asset transfers to the Group at the end of the lease term or the cost reflects the exercise of a purchase option, depreciation is calculated using the estimated useful life of the asset. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4515": {
"value": "2.4.13 Property, plant and equipment Property, plant and equipment not associated with exploration and production activities are carried at cost less accumulated depreciation. These assets are also evaluated for impairment. Depreciation of other assets is calculated on a straight-line basis as follows: Computer equipment: 20 to 33.33% Furniture, Fixtures & fittings: 10 to 33.33% Note 8.2: Production rights USD 000 2022 2021 Acquisition cost At 1 January 188,832 26,475 Depreciation charge for the year (18,307) (14,319) Additions through Acquisition - 172,676 Other additions 3,450 4,000 At 31 December 173,975 188,832 Accumulated depreciation At 1 January 21,093 8,601 Write-offs (184) (417) Depreciation charge for the year 16,479 12,909 At 31 December 37,388 21,093 Net carrying value at 31 December 97,359 120,269 Note 9.3: Property, Furniture, Fixtures and Equipment 2022 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2022 138 923 162 946 2,169 Additions 5 23 - - 28 At 31 December 2022 143 946 162 946 2,197 Accumulated depreciation At 1 January 2022 14 825 122 658 1,619 Depreciation charge for the year 86 63 38 191 378 At 31 December 2022 100 888 160 849 1,997 Net carrying value at 31 December 2022 43 58 2 97 200 2021 USD 000 Leasehold Furniture, fixtures and fittings Computer equipment Right of use asset - London office Total Historical cost At 1 January 2021 - 830 160 946 1,936 Additions 138 93 2 - 233 At 31 December 2021 138 923 162 946 2,169 Accumulated depreciation At 1 January 2021 - 783 68 445 1,296 Depreciation charge for the year 14 42 54 213 323 At 31 December 2021 14 825 122 658 1,619 Net carrying value at 31 December 2021 124 98 40 288 550 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 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 9: Tangible Assets. USD 000 2022 2021 Right of use asset recognised at 1 January 288 501 Less: depreciation and impairment (191) (213) Net book value of right of use asset at 31 December 97 288 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4516": {
"value": "2.4.13 Property, plant and equipment Property, plant and equipment not associated with exploration and production activities are carried at cost less accumulated depreciation. These assets are also evaluated for impairment. Depreciation of other assets is calculated on a straight-line basis as follows: Computer equipment: 20 to 33.33% Furniture, Fixtures & fittings: 10 to 33.33% ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4525": {
"value": "2.4.14 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:DisclosureOfInventoriesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4526": {
"value": "2.4.14 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4531": {
"value": "2.4.15 Defined contribution pension plan The Group pays contributions into a defined contribution plan. Obligations for contributions to defined contribution pension plans are recognised as an expense in the income statement in the periods during which services are rendered by employees. 2.4.16 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. Note 4.2: Employee benefit expenses General and administrative expenses include wages, employer\u2019s contribution and other compensation as detailed below: USD 000 2022 2021 Salaries 4,283 3,423 Employers' contribution 588 555 Pension costs 235 118 Other compensation 226 70 Total 5,332 4,166 The number of employees in the Group as at year end is detailed below: 2022 2021 Number of employees 25 29 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 (2022) 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 104 of this report. Note 4.4: Management remuneration Executive management consists of the Chief Executive Officer (CEO), Chief Financial Officer (CFO) and two other Named Executives as described below. Current Executive management remuneration is summarised below: 2022 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2022 Fair value of RSUs expensed John Hamilton, CEO 472 181 11 5 669 131,772 512 Qazi Qadeer, CFO 311 119 5 5 440 64,983 195 Other Named Executives (vi) 596 227 10 12 845 127,014 382 Total 1,379 527 26 22 1,954 323,769 1,089 2021 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2021 Fair value of RSUs expensed John Hamilton, CEO 484 595 12 5 1,096 166,822 483 Qazi Qadeer, CFO 317 330 5 5 658 54,846 157 Other Named Executives (vi) 606 359 10 13 988 107,198 302 Total 1,407 1,285 27 23 2,742 328,866 942 (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. Other Named Executives have notice periods between three and six months. (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 July 2022, 487,434 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. The 2021 bonus included a one-off discretionary cash award to key management by the Board of Directors in recognition of the success of Transformational Tullow acquisitions, which increased Panoro\u2019s production and reserves by a factor of 3-4 times. (v) All bonuses were approved by the Board of Directors. (vi) Remuneration details for Other Named Executives include Mr. Richard Morton (Technical Director) and Mr. Nigel McKim (Projects Director). 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: USD 000 2022 2021 Julien Balkany (Chairman of the Board of Directors) 102 82 Torstein Sanness (Deputy Chairman of the Board of Directors) 68 57 Grace Reksten Skaugen 38 0 Alexandra Herger 62 48 Garrett Soden 61 50 Hilde \u00c5dland 58 48 Total 388 285 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 2022, the Company had no employees at parent company level and this pension plan is no longer in operation (31 December 2021: 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 for 2022 and 2021, refer to Note 4.2: Employee benefit expenses. NOTE 18: SHARE BASED PAYMENTS Restricted Share Unit (\u201cRSU\u201d) scheme At the Annual General Meeting held on 27 May 2021, 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 2024. 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: All amounts in Number of units, unless stated otherwise 2022 2021 Outstanding RSUs as of 1 January 1,162,434 1,149,150 Add: Grants during the year 487,434 528,356 Less: Vested during the year - Settled in cash to cover taxes / settlement through purchase of shares from the market (264,819) (243,879) - Settled through issue of new shares (305,682) (271,193) Less: Terminated without vesting (29,376) - Outstanding RSUs as of 31 December 1,049,991 1,162,434 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 by delivering equity shares purchased from the market. In June 2022, 487,434 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 1.6 million (2021: USD 1.2 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 RSUs granted during the year is as follows: Key assumptions 2022 2021 Weighted average risk-free interest rate 0.75% 0.75% Dividend yield Nil 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 58% 61% Weighted average remaining contractual life of RSUs at year end 1.1 Years 1.1 Years Share price at grant date \u2013 per share NOK 32.84 NOK 24.70 The weighted average fair value of RSUs granted during the period was NOK 32.84 per unit (2021: NOK 24.70 per unit) based on 487,434 units granted (2021: 528,356 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: 2022 2021 WAEP 2022 2021 Number of Units NOK/share Exercise value in NOK Within 1 year 566,229 570,501 0.05 28,311 28,525 Between 1 and 2 years 326,533 415,814 0.05 16,327 20,791 Between 2 and 3 years 157,229 176,119 0.05 7,861 8,806 Total 1,049,991 1,162,434 52,500 58,122 As of the year ended 2022 the unvested RSUs were outstanding for 18 employees including key management personnel (2021: 16 employees). The distribution of outstanding RSUs as of 31 December 2022 amongst the employees is as follows: No of Units Exercise price NOK/share Exercise period Fair value expensed USD 000 John Hamilton, CEO 351,107 0.05 June 2023 to June 2025 512 Qazi Qadeer, CFO 136,285 0.05 June 2023 to June 2025 195 Other Named Executives (i) 267,957 0.05 June 2023 to June 2025 382 Total 755,349 1,089 (i) Other Named Executives include Richard Morton (Technical Director) and Nigel McKim (Projects Director). 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 and NOK 31.91 for the 2022 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 this grant is from 27 May 2021 to 26 May 2025, 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 were are tabled below: All amounts in Number of units, unless stated otherwise 2022 2021 Outstanding options as of 1 January 144,000 - Add: Grants during the year 24,000 144,000 Outstanding options as of 31 December 168,000 144,000 The outstanding options as of 31 December 2022 included 48,000 options that had already vested but not exercised (2021: Nil). 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 2022 2021 Weighted average risk-free interest rate 0.75% 0.75% Dividend yield Nil 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 58% 61% Weighted average remaining contractual life of RSUs at year end 1 Years 1.4 Years Share price at grant date \u2013 per share NOK 32.40 NOK 19.16 The weighted average fair value of Board Options granted during the period was NOK 32.40 per unit (2021: NOK 19.16 per unit) based on 24,000 units granted (2021: 144,000 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: 2022 2021 WAEP 2022 2021 Number of Units NOK/share Exercise value in NOK Within 1 year 104,000 48,000 19.42 2,019,829 832,320 Between 1 and 2 years 56,000 48,000 19.42 1,087,600 832,320 Between 2 and 3 years 8,000 48,000 31.91 255,280 832,320 Total 168,000 144,000 3,362,709 2,496,960 As of the year ended 2022 the unvested Board Options were outstanding for 6 members of the Board of Directors (2021: 5 members of the Board of Directors). The distribution of outstanding Board Options as of 31 December 2022 amongst the members of the Board of Directors is as follows: No of Units - unvested No of Units - vested and unexercised Exercise price NOK/share Exercise period 2022 Fair value expensed USD 000 2021 Fair value expensed USD 000 Julien Balkany 32,000 16,000 17.34 May 2023 to May 2024 19 15 Torstein Sanness 16,000 8,000 17.34 May 2023 to May 2024 9 8 Grace Skaugen 24,000 - 31.91 May 2023 to May 2024 10 - Alexandra Herger 16,000 8,000 17.34 May 2023 to May 2024 9 8 Hilde \u00c5dland 16,000 8,000 17.34 May 2023 to May 2024 9 8 Garrett Soden 16,000 8,000 17.34 May 2023 to May 2024 9 8 Total 120,000 48,000 65 47 ",
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"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4532": {
"value": "2.4.15 Defined contribution pension plan The Group pays contributions into a defined contribution plan. Obligations for contributions to defined contribution pension plans are recognised as an expense in the income statement in the periods during which services are rendered by employees. 2.4.16 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. ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"f4538": {
"value": "2.4.16 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. NOTE 18: SHARE BASED PAYMENTS Restricted Share Unit (\u201cRSU\u201d) scheme At the Annual General Meeting held on 27 May 2021, 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 2024. 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: All amounts in Number of units, unless stated otherwise 2022 2021 Outstanding RSUs as of 1 January 1,162,434 1,149,150 Add: Grants during the year 487,434 528,356 Less: Vested during the year - Settled in cash to cover taxes / settlement through purchase of shares from the market (264,819) (243,879) - Settled through issue of new shares (305,682) (271,193) Less: Terminated without vesting (29,376) - Outstanding RSUs as of 31 December 1,049,991 1,162,434 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 by delivering equity shares purchased from the market. In June 2022, 487,434 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 1.6 million (2021: USD 1.2 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 RSUs granted during the year is as follows: Key assumptions 2022 2021 Weighted average risk-free interest rate 0.75% 0.75% Dividend yield Nil 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 58% 61% Weighted average remaining contractual life of RSUs at year end 1.1 Years 1.1 Years Share price at grant date \u2013 per share NOK 32.84 NOK 24.70 The weighted average fair value of RSUs granted during the period was NOK 32.84 per unit (2021: NOK 24.70 per unit) based on 487,434 units granted (2021: 528,356 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: 2022 2021 WAEP 2022 2021 Number of Units NOK/share Exercise value in NOK Within 1 year 566,229 570,501 0.05 28,311 28,525 Between 1 and 2 years 326,533 415,814 0.05 16,327 20,791 Between 2 and 3 years 157,229 176,119 0.05 7,861 8,806 Total 1,049,991 1,162,434 52,500 58,122 As of the year ended 2022 the unvested RSUs were outstanding for 18 employees including key management personnel (2021: 16 employees). The distribution of outstanding RSUs as of 31 December 2022 amongst the employees is as follows: No of Units Exercise price NOK/share Exercise period Fair value expensed USD 000 John Hamilton, CEO 351,107 0.05 June 2023 to June 2025 512 Qazi Qadeer, CFO 136,285 0.05 June 2023 to June 2025 195 Other Named Executives (i) 267,957 0.05 June 2023 to June 2025 382 Total 755,349 1,089 (i) Other Named Executives include Richard Morton (Technical Director) and Nigel McKim (Projects Director). 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 and NOK 31.91 for the 2022 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 this grant is from 27 May 2021 to 26 May 2025, 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 were are tabled below: All amounts in Number of units, unless stated otherwise 2022 2021 Outstanding options as of 1 January 144,000 - Add: Grants during the year 24,000 144,000 Outstanding options as of 31 December 168,000 144,000 The outstanding options as of 31 December 2022 included 48,000 options that had already vested but not exercised (2021: Nil). 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 2022 2021 Weighted average risk-free interest rate 0.75% 0.75% Dividend yield Nil 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 58% 61% Weighted average remaining contractual life of RSUs at year end 1 Years 1.4 Years Share price at grant date \u2013 per share NOK 32.40 NOK 19.16 The weighted average fair value of Board Options granted during the period was NOK 32.40 per unit (2021: NOK 19.16 per unit) based on 24,000 units granted (2021: 144,000 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: 2022 2021 WAEP 2022 2021 Number of Units NOK/share Exercise value in NOK Within 1 year 104,000 48,000 19.42 2,019,829 832,320 Between 1 and 2 years 56,000 48,000 19.42 1,087,600 832,320 Between 2 and 3 years 8,000 48,000 31.91 255,280 832,320 Total 168,000 144,000 3,362,709 2,496,960 As of the year ended 2022 the unvested Board Options were outstanding for 6 members of the Board of Directors (2021: 5 members of the Board of Directors). The distribution of outstanding Board Options as of 31 December 2022 amongst the members of the Board of Directors is as follows: No of Units - unvested No of Units - vested and unexercised Exercise price NOK/share Exercise period 2022 Fair value expensed USD 000 2021 Fair value expensed USD 000 Julien Balkany 32,000 16,000 17.34 May 2023 to May 2024 19 15 Torstein Sanness 16,000 8,000 17.34 May 2023 to May 2024 9 8 Grace Skaugen 24,000 - 31.91 May 2023 to May 2024 10 - Alexandra Herger 16,000 8,000 17.34 May 2023 to May 2024 9 8 Hilde \u00c5dland 16,000 8,000 17.34 May 2023 to May 2024 9 8 Garrett Soden 16,000 8,000 17.34 May 2023 to May 2024 9 8 Total 120,000 48,000 65 47 ",
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"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
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"f4539": {
"value": "2.4.16 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": {
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"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4669": {
"value": "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. As noted above, from December 2019, the business in Nigeria is classified as a \u201cDiscontinued Operation\u201d and as an \"Asset held for sale\u201d. Segment information has therefore been re-arranged in line with reporting requirements for such item. 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. This interest was acquired from Tullow Overseas Holdings B.V. on 31 March 2021. \u2022 The Gabon segment holds the Dussafu licence representing the Group\u2019s 17.4997% working interest in the Dussafu Marin exploration licence in Gabon. This includes an additional 10% working interest acquired from Tullow Oil Gabon SA on 9 June 2021. \u2022 The Tunisia segment holds the following assets: - Sfax Offshore Exploration Permit: Panoro Tunisia Exploration AS (Operator, 52.5%* interest net to Panoro) - The Hammamet Offshore Exploration Permit: Medco (Operator), Panoro Tunisia Exploration AS (27.6%* interest net to Panoro), under relinquishment - TPS Assets: ETAP, 51% and Panoro TPS Production GmbH, 49% (29.4%* interest net to Panoro). * Figures only represent net participation interest in proportion to Panoro\u2019s equity holding in Sfax Petroleum Corporation AS. \u2022 The \u2018South Africa\u2019 segment holds the following assets: - The Block 2B licence representing the Group\u2019s 12.5% working interest - 100% interest in the Karoo Technical Cooperation Permit 218, South Africa \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. \u2022 Discontinued Operations and Assets held for sale: - OML113-Aje represents the Group\u2019s 12.1913% revenue interest, 16.255% paying interest and 6.502% participating interest) in the OML113-Aje exploration licence in Nigeria. 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. Details of Group segments are reported below: 2022 USD 000 Equatorial Guinea Gabon Tunisia South Africa Corporate Total - continuing operations Aje-OML 113 discontinued operations Total Revenue (net) * 80,953 67,537 40,136 - - 188,626 1,181 189,807 EBITDA 66,106 37,835 28,780 (596) (4,937) 127,188 1,498 128,686 Depreciation (23,778) (7,068) (4,002) - (316) (35,164) - (35,164) Impairment (charge)/reversal - - - - - - 1,497 1,497 Profit/(loss) before tax 37,425 30,251 17,877 (10,048) (15,081) 60,424 1,258 61,682 Net Profit/(loss) 19,500 21,889 2,377 (10,048) (15,083) 18,635 1,258 19,893 Segment assets ** 240,423 219,544 60,849 17 18,512 539,345 - 539,345 Additions to licences, production, E&E and development assets *** 6,985 37,447 597 - - 45,029 - 45,029 2021 USD 000 Equatorial Guinea Gabon Tunisia South Africa Corporate Total - continuing operations Aje-OML 113 discontinued operations Total Revenue (net) * 51,563 41,734 26,360 - - 119,657 3,688 123,345 EBITDA 37,702 21,519 10,326 - (5,846) 63,701 7,455 71,156 Depreciation (18,236) (3,807) (5,271) - (236) (27,550) - (27,550) Impairment (charge)/reversal - - - - - - 8,000 8,000 Profit/(loss) before tax 15,649 63,279 (2,926) - (12,611) 63,391 7,011 70,402 Net Profit/(loss) 7,384 57,330 (9,775) - (12,627) 42,312 7,011 49,323 Segment assets 286,974 188,392 60,481 - 19,805 555,652 29,015 584,667 Additions to licences, production, E&E and development assets *** 213,315 126,261 568 - 11 340,155 298 340,453 * Revenue excludes any intercompany revenue. ** Refer to Note 14: Discontinued Operations for segment assets related to discontinued operations (OML 113, Aje). *** Excludes effect on production assets and equipment of the reasessment of decommissioning liabilities of USD 16.9 million in 2022, refer to Note 15: Asset Retirement Obligation. Includes additions from acquisitions, see Note 13: Business Combinations, but excludes reversal of impairment of USD 1.2 million (2021: USD 8 million). Revenue from major sources from continuing operations: USD 000 2022 2021 Oil revenue (net) 180,267 113,708 Other revenue 8,359 5,949 Total revenue 188,626 119,657 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 international sales of the Group in Tunisia during 2022 were to a single customer, Mercuria Energy Trading SA, through a crude marketing agreement. All sales in 2022 from the Group\u2019s production from Block G in Equatorial Guinea and Dussafu in Gabon arose from one key customer each. Under the terms of the Dussafu PSC, State profit oil is estimated and shown as other revenue with a corresponding amount as income tax, see Note 2.4.10 Income tax. There are no other items included in other revenue for both periods presented. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4930": {
"value": "Revenue from major sources from continuing operations: USD 000 2022 2021 Oil revenue (net) 180,267 113,708 Other revenue 8,359 5,949 Total revenue 188,626 119,657 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 international sales of the Group in Tunisia during 2022 were to a single customer, Mercuria Energy Trading SA, through a crude marketing agreement. All sales in 2022 from the Group\u2019s production from Block G in Equatorial Guinea and Dussafu in Gabon arose from one key customer each. Under the terms of the Dussafu PSC, State profit oil is estimated and shown as other revenue with a corresponding amount as income tax, see Note 2.4.10 Income tax. There are no other items included in other revenue for both periods presented. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4967": {
"value": "NOTE 4: OPERATING RESULT Operating profit is stated after charging/ (crediting): USD 000 Note 2022 2021 Employee benefits expense 5,332 4,166 Depreciation 8, 9 35,164 27,550 Acquisition and project related costs (i) 1,054 1,254 (i) Acquisition and project related costs in 2022 of USD 0.6 million relate organisational restructure in Tunisia and the remaining USD 0.4 million, to business development activities. In 2021, costs of USD 1.1 million were incurred on the Equatorial Guinea and Dussafu acquisitions as described in Note 13: Business Combinations. Note 4.1: Exploration related costs The Gazania-1 exploration well located at Block 2B offshore the Northern Cape in Orange Basin, South Africa, was drilled without incident. The well did not encounter commercial hydrocarbons. As a result capitalised exploration costs of USD 9.2 million were written off during the year. In 2021 a historical non-fulfilment of a work programme related to Sfax Offshore Exploration Permit by a previous operator was settled during 2021 at a cost of USD 6.3 million. The settlement was made by way of a partial draw on the bank guarantee wih the remaining remaining USD 3.6 million cancelled and cash returned to Panoro. As part of the settlement, the license entered the second renewal period of one year which was later extended a further two years on the condition that a seismic reprocessing project would be completed. Note 4.2: Employee benefit expenses General and administrative expenses include wages, employer\u2019s contribution and other compensation as detailed below: USD 000 2022 2021 Salaries 4,283 3,423 Employers' contribution 588 555 Pension costs 235 118 Other compensation 226 70 Total 5,332 4,166 The number of employees in the Group as at year end is detailed below: 2022 2021 Number of employees 25 29 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 (2022) 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 104 of this report. Note 4.4: Management remuneration Executive management consists of the Chief Executive Officer (CEO), Chief Financial Officer (CFO) and two other Named Executives as described below. Current Executive management remuneration is summarised below: 2022 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2022 Fair value of RSUs expensed John Hamilton, CEO 472 181 11 5 669 131,772 512 Qazi Qadeer, CFO 311 119 5 5 440 64,983 195 Other Named Executives (vi) 596 227 10 12 845 127,014 382 Total 1,379 527 26 22 1,954 323,769 1,089 2021 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2021 Fair value of RSUs expensed John Hamilton, CEO 484 595 12 5 1,096 166,822 483 Qazi Qadeer, CFO 317 330 5 5 658 54,846 157 Other Named Executives (vi) 606 359 10 13 988 107,198 302 Total 1,407 1,285 27 23 2,742 328,866 942 (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. Other Named Executives have notice periods between three and six months. (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 July 2022, 487,434 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. The 2021 bonus included a one-off discretionary cash award to key management by the Board of Directors in recognition of the success of Transformational Tullow acquisitions, which increased Panoro\u2019s production and reserves by a factor of 3-4 times. (v) All bonuses were approved by the Board of Directors. (vi) Remuneration details for Other Named Executives include Mr. Richard Morton (Technical Director) and Mr. Nigel McKim (Projects Director). Refer to Note 18: Share based payments for further information on the Restricted Share Units scheme. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfProfitLossFromOperatingActivitiesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f4970": {
"value": "Operating profit is stated after charging/ (crediting): USD 000 Note 2022 2021 Employee benefits expense 5,332 4,166 Depreciation 8, 9 35,164 27,550 Acquisition and project related costs (i) 1,054 1,254 (i) Acquisition and project related costs in 2022 of USD 0.6 million relate organisational restructure in Tunisia and the remaining USD 0.4 million, to business development activities. In 2021, costs of USD 1.1 million were incurred on the Equatorial Guinea and Dussafu acquisitions as described in Note 13: Business Combinations. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfExpensesByNatureExplanatory",
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"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f5003": {
"value": "Note 4.2: Employee benefit expenses General and administrative expenses include wages, employer\u2019s contribution and other compensation as detailed below: USD 000 2022 2021 Salaries 4,283 3,423 Employers' contribution 588 555 Pension costs 235 118 Other compensation 226 70 Total 5,332 4,166 The number of employees in the Group as at year end is detailed below: 2022 2021 Number of employees 25 29 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 (2022) 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 104 of this report. Note 4.4: Management remuneration Executive management consists of the Chief Executive Officer (CEO), Chief Financial Officer (CFO) and two other Named Executives as described below. Current Executive management remuneration is summarised below: 2022 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2022 Fair value of RSUs expensed John Hamilton, CEO 472 181 11 5 669 131,772 512 Qazi Qadeer, CFO 311 119 5 5 440 64,983 195 Other Named Executives (vi) 596 227 10 12 845 127,014 382 Total 1,379 527 26 22 1,954 323,769 1,089 2021 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2021 Fair value of RSUs expensed John Hamilton, CEO 484 595 12 5 1,096 166,822 483 Qazi Qadeer, CFO 317 330 5 5 658 54,846 157 Other Named Executives (vi) 606 359 10 13 988 107,198 302 Total 1,407 1,285 27 23 2,742 328,866 942 (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. Other Named Executives have notice periods between three and six months. (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 July 2022, 487,434 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. The 2021 bonus included a one-off discretionary cash award to key management by the Board of Directors in recognition of the success of Transformational Tullow acquisitions, which increased Panoro\u2019s production and reserves by a factor of 3-4 times. (v) All bonuses were approved by the Board of Directors. (vi) Remuneration details for Other Named Executives include Mr. Richard Morton (Technical Director) and Mr. Nigel McKim (Projects Director). 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: USD 000 2022 2021 Julien Balkany (Chairman of the Board of Directors) 102 82 Torstein Sanness (Deputy Chairman of the Board of Directors) 68 57 Grace Reksten Skaugen 38 0 Alexandra Herger 62 48 Garrett Soden 61 50 Hilde \u00c5dland 58 48 Total 388 285 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 2022, the Company had no employees at parent company level and this pension plan is no longer in operation (31 December 2021: 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 for 2022 and 2021, refer to Note 4.2: Employee benefit expenses. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInformationAboutEmployeesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f5035": {
"value": "Note 4.3: Board of Directors statement on remuneration of executives Statement for the current year (2022) 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 104 of this report. Note 4.4: Management remuneration Executive management consists of the Chief Executive Officer (CEO), Chief Financial Officer (CFO) and two other Named Executives as described below. Current Executive management remuneration is summarised below: 2022 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2022 Fair value of RSUs expensed John Hamilton, CEO 472 181 11 5 669 131,772 512 Qazi Qadeer, CFO 311 119 5 5 440 64,983 195 Other Named Executives (vi) 596 227 10 12 845 127,014 382 Total 1,379 527 26 22 1,954 323,769 1,089 2021 Short term benefits USD 000 (unless stated otherwise) Salary Bonus Benefits Pension costs Total Number of RSUs awarded in 2021 Fair value of RSUs expensed John Hamilton, CEO 484 595 12 5 1,096 166,822 483 Qazi Qadeer, CFO 317 330 5 5 658 54,846 157 Other Named Executives (vi) 606 359 10 13 988 107,198 302 Total 1,407 1,285 27 23 2,742 328,866 942 (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. Other Named Executives have notice periods between three and six months. (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 July 2022, 487,434 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. The 2021 bonus included a one-off discretionary cash award to key management by the Board of Directors in recognition of the success of Transformational Tullow acquisitions, which increased Panoro\u2019s production and reserves by a factor of 3-4 times. (v) All bonuses were approved by the Board of Directors. (vi) Remuneration details for Other Named Executives include Mr. Richard Morton (Technical Director) and Mr. Nigel McKim (Projects Director). 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: USD 000 2022 2021 Julien Balkany (Chairman of the Board of Directors) 102 82 Torstein Sanness (Deputy Chairman of the Board of Directors) 68 57 Grace Reksten Skaugen 38 0 Alexandra Herger 62 48 Garrett Soden 61 50 Hilde \u00c5dland 58 48 Total 388 285 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f5269": {
"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 2022 2021 Ernst & Young Statutory Audit 281 280 Total Audit Services 281 280 Non-audit Services Corporate financial services including pre-acquisition due diligence - - Total non-audit services - - Total 281 175 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f5296": {
"value": "NOTE 5: FINANCE , INTEREST AND OTHER INCOME AND EXPENSE [P- USD 000 2022 2021 Unrealised (gain) / loss on commodity hedges (Note 19) (2,622) 3,868 Realised (gain) / loss on commodity hedges (Note 19) 8,534 4,354 Interest income from placements and deposits (57) (77) Interest expense - Loans and borrowings 9,536 6,895 Interest expense - Bank guarantee - 199 Unrealised (gain) / loss on listed equity investments (Note 11) 75 - Realised (gain) / loss on listed equity investments (Note 11) 652 Other financial costs - Bank charges and ARO unwinding 4,193 2,822 Total - Net (income) / expense 20,311 18,061 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceCostExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f5297": {
"value": "NOTE 5: FINANCE , INTEREST AND OTHER INCOME AND EXPENSE [P- USD 000 2022 2021 Unrealised (gain) / loss on commodity hedges (Note 19) (2,622) 3,868 Realised (gain) / loss on commodity hedges (Note 19) 8,534 4,354 Interest income from placements and deposits (57) (77) Interest expense - Loans and borrowings 9,536 6,895 Interest expense - Bank guarantee - 199 Unrealised (gain) / loss on listed equity investments (Note 11) 75 - Realised (gain) / loss on listed equity investments (Note 11) 652 Other financial costs - Bank charges and ARO unwinding 4,193 2,822 Total - Net (income) / expense 20,311 18,061 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f5298": {
"value": "NOTE 5: FINANCE , INTEREST AND OTHER INCOME AND EXPENSE [P- USD 000 2022 2021 Unrealised (gain) / loss on commodity hedges (Note 19) (2,622) 3,868 Realised (gain) / loss on commodity hedges (Note 19) 8,534 4,354 Interest income from placements and deposits (57) (77) Interest expense - Loans and borrowings 9,536 6,895 Interest expense - Bank guarantee - 199 Unrealised (gain) / loss on listed equity investments (Note 11) 75 - Realised (gain) / loss on listed equity investments (Note 11) 652 Other financial costs - Bank charges and ARO unwinding 4,193 2,822 Total - Net (income) / expense 20,311 18,061 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f5299": {
"value": "NOTE 5: FINANCE , INTEREST AND OTHER INCOME AND EXPENSE [P- USD 000 2022 2021 Unrealised (gain) / loss on commodity hedges (Note 19) (2,622) 3,868 Realised (gain) / loss on commodity hedges (Note 19) 8,534 4,354 Interest income from placements and deposits (57) (77) Interest expense - Loans and borrowings 9,536 6,895 Interest expense - Bank guarantee - 199 Unrealised (gain) / loss on listed equity investments (Note 11) 75 - Realised (gain) / loss on listed equity investments (Note 11) 652 Other financial costs - Bank charges and ARO unwinding 4,193 2,822 Total - Net (income) / expense 20,311 18,061 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f5334": {
"value": "Note 5.1: Loans and borrowings Note 5.1.1 Mercuria senior secured loan In 2018, the Group entered into an agreement with Mercuria Assets Holdings (Hong Kong) Ltd (\u201cMercuria\u201d), whereby Mercuria provided PTP (60% owned by Panoro) an acquisition loan facility comprising a Senior Secured Loan facility of USD 16.2 million (USD 27 million gross) which was fully drawn. The Senior Loan facility initially had term of 5 years with interest charged at USD 3-month LIBOR plus 6% on quarterly amounts drawn, with repayments due each quarter. Interest of USD 0.2 million (USD 0.3 million gross) was accrued up to 31 December 2022 (31 December 2021: USD 0.2 million). On 25 June 2019, the Group and Mercuria mutually agreed to make minor adjustments to the Facility terms, resulting in the Facility amount increasing by USD 2.5 million (USD 4.1 million gross) to USD 18.7 million (USD 30 million gross). As part of the security package for the enhanced facility size, shares in Panoro Energy AS (holding company for Panoro Tunisia Exploration AS) have been pledged as collateral. The amended Senior Loan facility has a term of 5 years from 30 June 2019 with interest charged at USD 3-month LIBOR plus 6% on the balance outstanding, with repayments due each quarter. Key financial covenants were unchanged as a result of the amendment and are required to be tested at the end of every 3- month period. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include the following: (i) Field life coverage ratio (FLCR): 1.50x (ii) Minimum cash balance equal to the amount of the next loan and interest repayment, varying as the loan is repaid but typically around USD 1.2 million (USD 2 million gross) to be maintained at all times in the collection account of the borrower. (iii) Debt service coverage ratio (DSCR): between 1.15x and 1.25x subject to specifications in the loan agreement. (iv) Liquidity Test: Customary to the loan instrument. Security package for the original Senior Secured loan comprised a Guarantee from Panoro Energy ASA, share pledge over shares in Panoro TPS (UK) Production Limited and Panoro TPS Production GmbH and from Sfax Petroleum Corporation AS, shareholder and intercompany loans (subordinated at all times), rights under hedging agreements, and the Account Management Agreement (for the Collection Account), negative pledge over the assets. In an event, the guarantee placed by Panoro Energy ASA is called upon, the shareholders\u2019 agreement with Beender for the ownership on Sfax Petroleum Corporation AS provides that Sfax Petroleum Corporation AS shall indemnify Panoro Energy ASA. If Sfax Petroleum Corporation AS is unable to indemnify, Panoro Energy ASA, such indemnification, pro rata to its ownership, shall be made by Beender. As part of the amendment in June 2019 as noted above, the security package for the enhanced facility size was amended to also include a pledge over the shares in Panoro Energy AS (holding company for Panoro Tunisia Exploration AS). The Mercuria loan was repaid in full on 15 March 2023 by the Group and all security held in relation to the loan was released at that date, refer to Note 25: Events subsequent to reporting date. Current and non-current portion of the outstanding balance of the Mercuria Senior Secured facility as of the date of the statement of financial position attributable to Panoro\u2019s 60% ownership is as follows: USD 000 31 December 2022 31 December 2021 Current Non-current Total Current Non-current Total Mercuria Senior Secured loan facility Principal outstanding 5,100 1,740 6,840 4,950 5,820 10,770 Accumulated interest accrued 170 - 170 169 - 169 Unamortised borrowing costs (55) (8) (63) (103) (63) (166) 5,215 1,732 6,947 5,016 5,757 10,773 Note 5.1.2 Trafigura Secured Borrowing Base facility 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, to partially finance the EG Transaction and the Dussafu Transaction as described above. The loan has been made available in two tranches, Tranche A of up to USD 55 million in respect of the EG Transaction and Tranche B of up to USD 35 million in respect of the Dussafu Acquisition. Tranche A and Tranche B can be drawn separately and are not conditional on each other. The drawn-down amount under the loan will amortise over a period of 5 years and carries an annual interest rate of USD 3-month LIBOR plus 7.5%. An accordion option for an additional USD 50 million is included alongside and in addition to the acquisition finance facilities. On 30 March 2021, Panoro drew down against Tranche A of the facility, borrowing USD 55 million which was utilised to partially pay for the purchase consideration of the EG Transaction as described above, and the balance funded from the proceeds of the equity private placement of the Company shares that completed in the first quarter of this year. On 9 June 2021, Panoro drew down against Tranche B of the facility, borrowing USD 35 million which was utilised to partially pay for the purchase consideration of the Dussafu Transaction as described above. The amended Senior Loan facility has a term of 5 years from 31 March 2021 with interest charged and paid quarterly at USD 3-month LIBOR plus 7.5% on the balance outstanding, with principal repayments due each six months. Key financial covenants are required to be tested 30 September and 31 March. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include 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) The Group was not in breach of any financial covenants as at 31 December 2022. Un-amortised borrowing costs include structuring fees and directly attributable third-party costs. During the current quarter, these costs are expensed using an effective interest rate of 11.74% per annum over the remaining term of the facility. Subsequent to year-end, the Company has increased its facility by USD 15 million in conjunction with acquisition of 40% interest in Sfax Petroleum Corporation AS. See Note 25: Events subsequent to reporting date for further details. Current and non-current portion of the outstanding balance of the Trafigura Secured Borrowing Base facility as of the date of the statement of financial position is as follows: USD 000 31 December 2022 31 December 2021 Current Non- current Total Current Non- current Total Trafigura Secured Borrowing Base facility Principal outstanding 16,200 57,600 73,800 10,800 73,800 84,600 Accumulated interest accrued - - - - - - Unamortised borrowing costs (918) (950) (1,868) (1,102) (1,868) (2,970) 15,282 56,650 71,932 9,698 71,932 81,630 Note 5.1.3 BW Energy non-recourse loan The Group has in place a non-recourse loan from BW Energy in relation to the funding of the Dussafu development. The loan bears interest at 7.5% per annum on outstanding balance, compounded annually. The balance outstanding at each balance sheet date presented is as below: USD 000 31 December 2022 31 December 2021 Current Non-current Total Current Non- Current Total BW Energy Non-Recourse loan Principal outstanding - - - 2,234 - 2,234 Accumulated interest accrued 632 - 632 2,273 - 2,273 632 - 632 4,507 - 4,507 The loan is repayable through Panoro\u2019s allocation of the cost oil in accordance with the Dussafu PSC, after paying for the proportionate field operating expenses and as such the loan is classified as current or non-current based on expected field production and lifting schedule at a reasonable oil price assumption at the time of making such classification. During the repayment phase, Panoro is still entitled to its share of profit oil, as defined in the PSC, from the Dussafu operations. The remaining balance of the BW Energy loan was repaid on 21 March 2023. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBorrowingsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f5558": {
"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 2022 2021 At 1 January 99,756 20,392 Cash flows: Drawdown of Secured Loans, net of fees - 90,000 Repayment of Secured Loans (14,730) (13,384) Repayment of non-recourse loan (4,065) (3,106) Realised gain/(loss) on commodity hedges (7,689) (2,668) Borrowing costs, including arrangement fees (8,141) (4,689) Lease liability payments (231) (254) Non cash changes: Unwinding of unamortised borrowing cost and finance charges 1,324 1,123 Interest accrued 8,232 5,812 Movement in unrealised hedges 5,200 6,536 Initial recognition lease under IFRS 16 - - Foreign exchange movements (32) (6) At 31 December 79,394 99,756 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCashFlowStatementExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f5759": {
"value": "NOTE 7: 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. 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. Amounts in USD 000, unless otherwise stated 2022 2021 Net profit/(loss) attributable to equity holders - Total 19,893 49,323 Net profit/(loss) attributable to equity holders - Continuing operations 18,635 42,312 Weighted average number of shares outstanding - in thousands 113,538 105,452 Diluted weighted average number of shares outstanding - in thousands 115,890 106,611 Basic earnings/(loss) per share (USD) - Total 0.18 0.47 Diluted earnings/(loss) per share (USD) - Total 0.17 0.46 Basic earnings/(loss) per share (USD) - Continuing operations 0.16 0.40 Diluted earnings/(loss) per share (USD) - Continuing operations 0.16 0.40 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f5949": {
"value": "Note 8.3: Goodwill USD 000 2022 2021 Acquisition cost At 1 January 47,762 - Additions through Acquisition - 47,762 At 31 December 47,762 47,762 The Group acquired a 14.25% working interest in Block G, Equatorial Guinea during 2021, assets and liabilities were taken on at fair value and Goodwill of USD 47.8 million recognised as described in Note 13: Business Combinations. An annual impairment assessment was carried out in December 2022 at which time the total carrying value of Block G at 31 December 2022 was USD 127.4 million. 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 and using the discount rate of 12% and long-term oil price assumption of USD 80/bbl, inflated by 2% per annum after five years. 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 Block G asset to materially exceed its recoverable amount. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGoodwillExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6346": {
"value": "NOTE 10: ACCOUNTS AND OTHER RECEIVABLES USD 000 2022 2021 Trade receivables 16,516 54,351 Other receivables and prepayments 8,273 1,278 Underlift - Block G, Equatorial Guinea 10,320 - At 31 December 35,109 55,629 Accounts receivables are non-interest bearing and generally on 30 to 120 days payment terms. At 31 December 2022 and 2021, the allowance for impairment of receivables was USD Nil. Risk information for the receivable balances is disclosed in Note 20: Financial risk management. Other non-current assets amount to joint venture account balances of USD 7 million, prepayments of USD 1.2 million (31 December 2021: USD 1.2 million) and USD 0.1 million tenancy deposit for the UK office premises for both reporting periods. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6370": {
"value": "NOTE 11: LISTED EQUITY INVESTMENTS On completion of the disposal of Panoro\u2019s fully owned subsidiaries Pan-Petroleum Services Holdings BV and Pan-Petroleum Nigeria Holding BV described in Note 14: Discontinued Operations below, Panoro received upfront consideration of USD 10 million in the form of 96,577,537 newly allotted and issued shares in PetroNor E&P ASA (\u201cConsideration Shares\u201d). The Board of Directors resolved on 1 August 2022 to use its authorisation to approve a dividend in the form of the Consideration Shares. Each Panoro shareholder as at the record date received 0.849 PetroNor shares for each share held in Panoro, rounded downwards to the nearest whole share. Fraction shares were not distributed. Panoro retains an investment of 4,451,249 PetroNor shares (\u201cRetained Shares\u201d), representing a holding of approximately 0.31% of PetroNor share capital. The Retained Shares were in connection with obligation to withhold tax on dividends and such taxes have since be been settled in cash by the Company. The Retained Shares are accounted for as financial assets at fair value through profit and loss and disclosed as current financial asset, valued at the published market price at the end of the reporting period, with revaluation differences disclosed as other income or expense in the statement of comprehensive income. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDividendsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6372": {
"value": "NOTE 11: LISTED EQUITY INVESTMENTS On completion of the disposal of Panoro\u2019s fully owned subsidiaries Pan-Petroleum Services Holdings BV and Pan-Petroleum Nigeria Holding BV described in Note 14: Discontinued Operations below, Panoro received upfront consideration of USD 10 million in the form of 96,577,537 newly allotted and issued shares in PetroNor E&P ASA (\u201cConsideration Shares\u201d). The Board of Directors resolved on 1 August 2022 to use its authorisation to approve a dividend in the form of the Consideration Shares. Each Panoro shareholder as at the record date received 0.849 PetroNor shares for each share held in Panoro, rounded downwards to the nearest whole share. Fraction shares were not distributed. Panoro retains an investment of 4,451,249 PetroNor shares (\u201cRetained Shares\u201d), representing a holding of approximately 0.31% of PetroNor share capital. The Retained Shares were in connection with obligation to withhold tax on dividends and such taxes have since be been settled in cash by the Company. The Retained Shares are accounted for as financial assets at fair value through profit and loss and disclosed as current financial asset, valued at the published market price at the end of the reporting period, with revaluation differences disclosed as other income or expense in the statement of comprehensive income. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInvestmentsOtherThanInvestmentsAccountedForUsingEquityMethodExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6830": {
"value": "NOTE 16: SHARE CAPITAL Share capital Amounts in USD 000 unless otherwise stated Number of shares Nominal Share Capital As at 1 January 2022 113,383,690 721 Share issue under RSU Plan (Note 18) 305,682 2 As at 31 December 2022 113,689,372 723 Note 16.1 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. Note 16.2 In connection with the Company's Restricted Share Units Plan, announced on 7 July 2022, the Company issued 305,682 new shares to employees. As of 31 December 2022, the Company had a registered share capital of NOK 5,684,469 divided into 113,689,372 shares, each with a nominal value of NOK 0.05 (31 December 2021: NOK 5,669,184 divided into 113,383,690 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 represents excess of subscription value of the shares over the nominal amount. Other reserves Other reserves 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 represents 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. Currency translation reserve The translation reserve comprises all foreign exchange differences arising from the translation of the financial statements of foreign operations. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6833": {
"value": "Share capital Amounts in USD 000 unless otherwise stated Number of shares Nominal Share Capital As at 1 January 2022 113,383,690 721 Share issue under RSU Plan (Note 18) 305,682 2 As at 31 December 2022 113,689,372 723 Note 16.1 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. Note 16.2 In connection with the Company's Restricted Share Units Plan, announced on 7 July 2022, the Company issued 305,682 new shares to employees. As of 31 December 2022, the Company had a registered share capital of NOK 5,684,469 divided into 113,689,372 shares, each with a nominal value of NOK 0.05 (31 December 2021: NOK 5,669,184 divided into 113,383,690 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6864": {
"value": "Reserves Share premium Share premium reserve represents excess of subscription value of the shares over the nominal amount. Other reserves Other reserves 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 represents 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. Currency translation reserve The translation reserve comprises all foreign exchange differences arising from the translation of the financial statements of foreign operations. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6888": {
"value": "NOTE 17: ACCOUNTS PAYABLE, ACCRUALS AND OTHER LIABILITIES USD 000 2022 2021 Accounts payable 9,087 12,707 Accrued and other liabilities 4,899 10,623 Other non-current liabilities 6,956 8,302 At 31 December 20,942 31,632 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f6889": {
"value": "NOTE 17: ACCOUNTS PAYABLE, ACCRUALS AND OTHER LIABILITIES USD 000 2022 2021 Accounts payable 9,087 12,707 Accrued and other liabilities 4,899 10,623 Other non-current liabilities 6,956 8,302 At 31 December 20,942 31,632 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7260": {
"value": "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. The outstanding commodity hedge contracts as at the respective balance sheet dates presented were as follows: Zero cost collar instruments Remaining term Remaining contract amount Average contract price Average contract price Fair value Asset / (Liability) Fair value Asset / (Liability) Bbls Buy Put (USD/Bbl) Sell Call (USD/Bbl) Current (USD '000) Non-Current (USD '000) At 31 December 2021 Jan 21 - Dec 21 216,000 55 64 (2,489) - At 31 December 2022 Dec 22 - Mar 23 50,000 40 47 133 - The fair values of the commodity price contracts were 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 (2021: 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7353": {
"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, liabilities 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. Commodity price risk The Group is exposed to the risk of fluctuations in prevailing market commodity prices (primarily crude oil) on the oil and gas it produces. The Group\u2019s policy is to manage these risks through the use of derivative financial instruments. The following tabl e summarises the impact on profit before tax for changes in commodity prices on the fair value of derivative financial instruments. The impact on equity is the same as the impact on profit before tax as these derivative financial instruments have not been designated as hedges and are classified as held-for-trading. The analysis is based on derivative contracts existing at the balance sheet date, the assumption that crude oil price moves 15% over all future periods, with all other variables held constant. Management believes that 15% is a reasonable sensitivity based on forward forecasts of estimated oil price volatility. Increase /(decrease) in profit before tax and equity USD 000 2022 2021 15% increase in the price of oil (20) 373 15% decrease in the price of oil 20 (373) 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), and the Pound Sterling (GBP). The Group has transactional currency exposures. Such exposure arises from sales or purchases in currencies other than the respective functional currency. The Group reports its consolidated results in USD, any change in exchange rates between its operating subsidiaries\u2019 functional currencies and the USD 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 2022 or 2021. 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 2022 2021 USD vs NOK 20% -20% 20% -20% Cash 10 (15) 9 (13) Receivables 7 (10) 7 (11) Payables (10) 15 (8) 12 Net effect 6 (9) 8 (12) USD vs TND 20% -20% 20% -20% Cash 3 (4) 182 (274) Receivables 133 (200) 1,630 (2,444) Corporation taxes payable (1,593) 2,390 (790) 1,185 Payables (765) 1,148 (593) 889 Net effect (2,223) 3,334 429 (643) USD vs EUR 20% -20% 20% -20% Cash 3 (4) 3 (5) Receivables 1 (2) (33) 50 Payables (32) 48 (33) 50 Net effect (28) 42 (63) 95 USD vs GBP 20% -20% 20% -20% Cash 61 (91) 66 (99) Receivables (49) 74 (36) 54 Payables (18) 26 (55) 83 Net effect (6) 9 (26) 38 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 2022 2021 +100bps -100bps +100bps -100bps Loans and borrowings (Secured loans) (806) 806 (954) 954 Cash equivalents 32 (32) 51 (51) Net effect (774) 774 (902) 902 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 2022 based on contractual undiscounted payments. 2022 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Secured loans) - 21,470 59,340 - 80,810 Loans and borrowings (Non-recourse loan) - 632 - - 632 Accounts payable and accrued liabilities - 9,087 - - 9,087 Non-current liabilities - - - 1,934 1,934 Corporation tax liabilities - 35,560 - - 35,560 Total - 66,749 59,340 1,934 128,023 2021 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Senior secured facility) - 15,919 79,620 - 95,539 Loans and borrowings (Non-recourse loan) - 4,507 - - 4,507 Accounts payable and accrued liabilities - 12,707 - - 12,707 Non-current liabilities - - 1,727 1,553 3,280 Corporation tax liabilities - 17,018 - - 17,018 Total - 50,151 81,347 1,553 133,051 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 2022, the Group\u2019s total debt was USD 79.5 million. The Group closed the year with a cash position of USD 32.7 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7375": {
"value": "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, liabilities 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. Commodity price risk The Group is exposed to the risk of fluctuations in prevailing market commodity prices (primarily crude oil) on the oil and gas it produces. The Group\u2019s policy is to manage these risks through the use of derivative financial instruments. The following tabl e summarises the impact on profit before tax for changes in commodity prices on the fair value of derivative financial instruments. The impact on equity is the same as the impact on profit before tax as these derivative financial instruments have not been designated as hedges and are classified as held-for-trading. The analysis is based on derivative contracts existing at the balance sheet date, the assumption that crude oil price moves 15% over all future periods, with all other variables held constant. Management believes that 15% is a reasonable sensitivity based on forward forecasts of estimated oil price volatility. Increase /(decrease) in profit before tax and equity USD 000 2022 2021 15% increase in the price of oil (20) 373 15% decrease in the price of oil 20 (373) 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), and the Pound Sterling (GBP). The Group has transactional currency exposures. Such exposure arises from sales or purchases in currencies other than the respective functional currency. The Group reports its consolidated results in USD, any change in exchange rates between its operating subsidiaries\u2019 functional currencies and the USD 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 2022 or 2021. 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 2022 2021 USD vs NOK 20% -20% 20% -20% Cash 10 (15) 9 (13) Receivables 7 (10) 7 (11) Payables (10) 15 (8) 12 Net effect 6 (9) 8 (12) USD vs TND 20% -20% 20% -20% Cash 3 (4) 182 (274) Receivables 133 (200) 1,630 (2,444) Corporation taxes payable (1,593) 2,390 (790) 1,185 Payables (765) 1,148 (593) 889 Net effect (2,223) 3,334 429 (643) USD vs EUR 20% -20% 20% -20% Cash 3 (4) 3 (5) Receivables 1 (2) (33) 50 Payables (32) 48 (33) 50 Net effect (28) 42 (63) 95 USD vs GBP 20% -20% 20% -20% Cash 61 (91) 66 (99) Receivables (49) 74 (36) 54 Payables (18) 26 (55) 83 Net effect (6) 9 (26) 38 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 2022 2021 +100bps -100bps +100bps -100bps Loans and borrowings (Secured loans) (806) 806 (954) 954 Cash equivalents 32 (32) 51 (51) Net effect (774) 774 (902) 902 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfMarketRiskExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7601": {
"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 2022 based on contractual undiscounted payments. 2022 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Secured loans) - 21,470 59,340 - 80,810 Loans and borrowings (Non-recourse loan) - 632 - - 632 Accounts payable and accrued liabilities - 9,087 - - 9,087 Non-current liabilities - - - 1,934 1,934 Corporation tax liabilities - 35,560 - - 35,560 Total - 66,749 59,340 1,934 128,023 2021 USD 000 On demand Less than 1 year Between 2 to 5 years Over 5 years Total Loans and borrowings (Senior secured facility) - 15,919 79,620 - 95,539 Loans and borrowings (Non-recourse loan) - 4,507 - - 4,507 Accounts payable and accrued liabilities - 12,707 - - 12,707 Non-current liabilities - - 1,727 1,553 3,280 Corporation tax liabilities - 17,018 - - 17,018 Total - 50,151 81,347 1,553 133,051 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 2022, the Group\u2019s total debt was USD 79.5 million. The Group closed the year with a cash position of USD 32.7 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7717": {
"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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7730": {
"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 2022. 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. There is no potential claim against these performance guarantee and all license obligations are already accounted for in the statement of financial position. Other At 31 December 2022, the Company has issued a parent company guarantee in favour of Mercuria Assets Holdings (Hong Kong) Ltd. to guarantee the obligations of Panoro Tunisia Production AS as borrower. The Mercuria loan was repaid in full on 15 March 2023 and the Company was released from the parent company guarantee. Refer Note 5: Finance , interest and other income and expense. The Company has issued a parent company guarantee in favour of The Mauritius Commercial Bank Ltd. to guarantee the obligations of Panoro Energy Holding B.V. as borrower. Further details can be found in Note 5: Finance , interest and other income and expense. The Company has issued a performance guarantee on behalf of its jointly owned company Panoro Energy AS to fulfil the payment obligation of deferred consideration of up to USD 13.2 million to DNO ASA once the milestones as agreed by parties are met. As part of the farm-in transaction in Block 2B offshore South Africa, on 24 February 2020 the Company entered into deed of guarantee (the \u201cFarmee Guarantee\u201d) with Thombo Petroleum Limited whereby the Company has guaranteed all obligations of PANORO ENERGY 2022 ANNUAL REPORT | APRIL 2023 Page: 88 Panoro 2B Limited (a wholly owned subsidiary) to Thombo Petroleum Limited under the farmout agreement of the same date. In addition, on 24 February 2020 Panoro entered into deed of guarantee with Thombo Petroleum Limited, Panoro 2B Limited and African Energy Corporation whereby the Company guarantee all obligations of Panoro 2B Limited under the farm out agreement, and under the petroleum authorisation as set out in the Farmee Guarantee. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7731": {
"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 2022. 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. There is no potential claim against these performance guarantee and all license obligations are already accounted for in the statement of financial position. Other At 31 December 2022, the Company has issued a parent company guarantee in favour of Mercuria Assets Holdings (Hong Kong) Ltd. to guarantee the obligations of Panoro Tunisia Production AS as borrower. The Mercuria loan was repaid in full on 15 March 2023 and the Company was released from the parent company guarantee. Refer Note 5: Finance , interest and other income and expense. The Company has issued a parent company guarantee in favour of The Mauritius Commercial Bank Ltd. to guarantee the obligations of Panoro Energy Holding B.V. as borrower. Further details can be found in Note 5: Finance , interest and other income and expense. The Company has issued a performance guarantee on behalf of its jointly owned company Panoro Energy AS to fulfil the payment obligation of deferred consideration of up to USD 13.2 million to DNO ASA once the milestones as agreed by parties are met. As part of the farm-in transaction in Block 2B offshore South Africa, on 24 February 2020 the Company entered into deed of guarantee (the \u201cFarmee Guarantee\u201d) with Thombo Petroleum Limited whereby the Company has guaranteed all obligations of Panoro 2B Limited (a wholly owned subsidiary) to Thombo Petroleum Limited under the farmout agreement of the same date. In addition, on 24 February 2020 Panoro entered into deed of guarantee with Thombo Petroleum Limited, Panoro 2B Limited and African Energy Corporation whereby the Company guarantee all obligations of Panoro 2B Limited under the farm out agreement, and under the petroleum authorisation as set out in the Farmee Guarantee. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCommitmentsExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7732": {
"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 2022. 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. There is no potential claim against these performance guarantee and all license obligations are already accounted for in the statement of financial position. Other At 31 December 2022, the Company has issued a parent company guarantee in favour of Mercuria Assets Holdings (Hong Kong) Ltd. to guarantee the obligations of Panoro Tunisia Production AS as borrower. The Mercuria loan was repaid in full on 15 March 2023 and the Company was released from the parent company guarantee. Refer Note 5: Finance , interest and other income and expense. The Company has issued a parent company guarantee in favour of The Mauritius Commercial Bank Ltd. to guarantee the obligations of Panoro Energy Holding B.V. as borrower. Further details can be found in Note 5: Finance , interest and other income and expense. The Company has issued a performance guarantee on behalf of its jointly owned company Panoro Energy AS to fulfil the payment obligation of deferred consideration of up to USD 13.2 million to DNO ASA once the milestones as agreed by parties are met. As part of the farm-in transaction in Block 2B offshore South Africa, on 24 February 2020 the Company entered into deed of guarantee (the \u201cFarmee Guarantee\u201d) with Thombo Petroleum Limited whereby the Company has guaranteed all obligations of PANORO ENERGY 2022 ANNUAL REPORT | APRIL 2023 Page: 88 Panoro 2B Limited (a wholly owned subsidiary) to Thombo Petroleum Limited under the farmout agreement of the same date. In addition, on 24 February 2020 Panoro entered into deed of guarantee with Thombo Petroleum Limited, Panoro 2B Limited and African Energy Corporation whereby the Company guarantee all obligations of Panoro 2B Limited under the farm out agreement, and under the petroleum authorisation as set out in the Farmee Guarantee. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7876": {
"value": "NOTE 24: SUBSIDIARIES Details of the Group\u2019s subsidiaries as of 31 December 2022 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% 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% Sfax Petroleum Corporation AS Norway 60% Panoro Energy AS Norway 60% Panoro Tunisia Exploration AS Norway 60% Panoro Tunisia Production AS Norway 60% Panoro TPS Production GmbH - in liqui Austria 60% Panoro TPS (UK) Production Limited UK 60% ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCompositionOfGroupExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f7960": {
"value": "NOTE 25: EVENTS SUBSEQUENT TO REPORTING DATE On 21 February 2023, the Board of Directors approved a cash dividend of NOK 0.2639 per share to shareholders holding shares in the Company at the end of trading on 7 March 2023. The total dividend was approximately NOK 30 million (approximately USD 3 million) and payment took place on or around 16 March 2023. Panoro was awarded a 56 percent participating interest and operatorship of Block EG-01 located offshore Equatorial Guinea. Partners in the block are Kosmos Energy (24 percent pending signature) and GEPetrol (20 percent). Block EG-01 borders both Block G where Panoro has a 14.25 percent non-operated interest (and which contains the producing Ceiba Field and Okume Complex) and Block S where Panoro has agreed to farm-in to a 12 percent non-operated interest. A 6 percent non-operated 12 percent participating interest in Block S was also acquired from Kosmos Energy and Trident Energy. Panoro\u2019s partners at Block S are Kosmos Energy (34 percent, operator), Trident Energy (34 percent) and GEPetrol (20 percent). On 15 March 2023, the Mercuria loan (refer Note 5: Finance , interest and other income and expense) was repaid in full and all security held in relation to the loan released. On 24 April 2023, the Company completed an agreement with Beender Tunisia Petroleum Limited (\u201cBeender\u201d) to acquire its 40 percent shareholding in Sfax Petroleum Corporation AS (\u201cSPC\u201d) for a total consideration of approximately USD 18.2 million in a mix of cash and shares (the \u201cAcquisition\u201d). The Acquisition increases Panoro\u2019s current ownership in SPC from 60 percent to 100 percent and SPC is now a fully owned subsidiary of Panoro. The loan facility with Trafigura was increased by USD 15 million in conjunction with the Acquisition. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory",
"language": "en",
"entity": "scheme:5967007LIEEXZXGWM030",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
}
}
}