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"value": "Notes to the accountsGENERAL INFORMATIONAker BP ASA (\u201cAker BP\u201d or \u201cthe company\u201d) is an oil and gas company involved in exploration, development and production of oil and gas on the Norwegian Continental Shelf (NCS).The company is a public limited liability company registered and domiciled in Norway. Aker BP\u2019s shares are listed on Oslo Stock Exchange (Oslo B\u00f8rs) under the ticker AKRBP. The company\u2019s registered business address is Oksen\u00f8yveien 10, 1366 Lysaker, Norway. In 2023 the Aker BP group comprised the parent company Aker BP ASA and the three subsidiaries Det norske oljeselskap AS (including its subsidiary Aker BP UK Limited), Alvheim AS and Sandvika Fjellstue AS. Except for Aker BP UK Limited, none of the subsidiaries are consolidated in the group financial statements as they are immaterial.The acquisition of the Lundin Energy's oil and gas business (\"Lundin Energy\") was completed on 30 June 2022. The activity of Lundin Energy was fully reflected in the financial statements from 30 June 2022, including effects from the fair value adjustment of Lundin Energy in line with IFRS 3, as described in note 30. At year end 2022 all legal entities acquired in the Lundin transaction were either liquidated or merged into Aker BP ASA. See note 2 for more information about subsidiaries.The financial statements were approved by the Board of Directors on 13 March 2024 and will be presented for approval at the Annual General Meeting on 10 April 2024.NOTE 1 SUMMARY OF IFRS ACCOUNTING POLICIES1.1 Basis of preparationThe group and the parent company financial statements have been prepared in accordance with IFRS\u00ae Accounting Standards as adopted by the EU and the Norwegian Accounting Act.All amounts have been rounded to the nearest million unless otherwise stated. As a result of rounding adjustments, the figures in one or more rows or columns included in the financial statements and notes may not add up to the total of that row or column.The group financial statements for Aker BP ASA include the subsidiaries as described in note 2. The accounting policies are applied consistently when consolidating ownership interests in subsidiaries and are based on the same reporting periods as those used for the parent company. When preparing the consolidated financial statements, intragroup transactions and balances, along with gains and losses on transactions between group units, are eliminated.1.2 Functional currency and presentation currencyThe presentation currency in the Group\u2019s consolidated financial statements is United States Dollars (\u201cUSD\u201d). The parent company of the Group, Aker BP ASA, has USD as its functional currency as most revenue and financing are in USD and represents the primary economic environment in which the entity operates. Balance sheet items of subsidiaries in other functional currencies are translated into the presentation currency, USD, according to the exchange rates prevailing on the balance sheet date, while profit or loss items are translated according to average quarterly exchange rates for the relevant quarters.In all material respects, the activity of Lundin Energy was conducted in the legal entity ABP Norway AS (previously Lundin Energy Norway AS), which had NOK as its functional currency. In line with accounting guidance, the related purchase price allocation (PPA) was fixed in NOK accordingly, and thus gave rise to foreign currency translation in the group accounts recognised in the statement of comprehensive income during the second half of 2022. At 31 December 2022, ABP Norway AS merged with Aker BP ASA, meaning that the mentioned impact on comprehensive impact ceased from 1 January 2023.1.3 Critical judgements and estimatesThe preparation of financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that have an effect on the application of accounting policies and the reported assets, liabilities, income and expenses.The important judgments management has made regarding the application of accounting policies are as follows:Goodwill allocation and methodology for impairment testingFor the purpose of impairment testing, goodwill is allocated to a cash-generating unit (CGU), or groups of CGUs that are expected to benefit from the synergies of the business combination from which it arose. A CGU is typically a producing field or group of producing licences for which a separate offtake facility exist that can generate separate cash flows. The allocation of goodwill requires judgment and may significantly impact any subsequent impairment charge. Although not an IFRS term, \u201ctechnical goodwill\u201d is used by Aker BP to describe the category of goodwill arising as an offsetting account to deferred tax liabilities recognised in business combinations, as described in section 1.8 below. There are no specific IFRS guidelines pertaining to the allocation of technical goodwill, and management has therefore applied the general guidelines for allocating goodwill. In general, technical goodwill is allocated at the CGU level for impairment testing purposes, while residual goodwill may be allocated across all CGUs based on the facts and circumstances of the business combination. When performing the impairment test for technical goodwill, deferred tax liabilities recognised in relation to the acquired licences reduce the net carrying value prior to any impairment charges. This methodology avoids an immediate impairment of all technical goodwill. When deferred tax liabilities from the initial recognition decreases, additional technical goodwill is \u2018exposed\u2019 to impairment. Subsequent to the initial purchase price allocation, depreciation of book values will result in decreasing deferred tax liabilities. When applicable, technical goodwill is impaired before the asset.Proven and probable oil and gas reservesProven and probable reserves and production volumes are used to calculate the depreciation of oil and gas fields by applying the unit-of-production method. Reserve estimates are also used as basis for impairment testing of licence-related assets and goodwill.Oil and gas reserves are estimated by the company\u2019s experts in accordance with industry standards. The estimates are based on Aker BP\u2019s own assessment of internal information and information received from operators. In addition, proven and probable reserves are certified by an external party. Proven and probable oil and gas reserves consist of the estimated quantities of crude oil, natural gas and condensates shown by geological and technical data to be recoverable with reasonable certainty from known reservoirs under existing economic and operational conditions, i.e. on the date that the estimates are prepared. Current market prices are used in the estimates.Changes in petroleum prices and cost estimates may change reserve estimates and accordingly economic cut-off, which may impact the timing of assumed decommissioning and removal activities. Changes to reserve estimates can also result from updated production and reservoir information. Future changes to proven and probable oil and gas reserves can have a material effect on depreciation, life of field, impair-ment of licence-related assets and goodwill, and operating results. Accounting for Exploration costs \u2013 application of the Successful Effort Method Expenses relating to the drilling of exploration wells are temporarily recognised in the Statement of financial position as capitalised exploration expenditures, pending an evaluation of potential oil and gas discoveries. If resources are not discovered, or if recovery of the resources is considered technically or commercially unviable, the costs of exploration wells are expensed. Judgments as to whether this expend-iture should remain capitalised or be expensed at the reporting date may materially affect the operating result for the period.Fair value measurementThe fair values of non-financial assets and liabilities are required to be determined, for example in a business combination, to determine the allocation of purchase price in an asset deal or when the recover-able amount of an asset or CGU is based on fair value less cost to sell. 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 of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability. 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. The fair value of oil fields in production and development phase is normally based on discounted cash flow models, where the determination of inputs to the model may require significant judgment, as described in the section below regarding impairment. Impairment/reversal of impairmentThe evaluation of impairment requires long-term assumptions concerning a number of often volatile economic factors, including future oil and gas prices, oil and gas production, currency exchange rates and discount rates. Such assumptions require the estimation of relevant factors such as long-term prices, the levels of capex and opex, production estimates and decommissioning costs. These evaluations are also necessary to determine a CGU\u2019s fair value unless information can be obtained from an actual observable market transaction. See note 13 \u2019Tangible fixed assets and intangible assets\u2019 and note 14 \u2019Impairments\u2019 for details of impairments.Decommissioning and removal obligationsThe company has obligations to decommission and remove offshore installations at the end of their production period. The estimates include costs based on expected removal concepts using existing technology and estimated costs of maritime operations, hiring of single-lift and heavy-lift barges and drilling rigs. There is significant future uncertainty in the estimate of costs for decommissioning and removal, as these estimates are based on currently applicable laws and regulations, and existing technologies. Many decommissioning and removal activities will take place many decades in the future, and the technology and related costs are expected to evolve in this time. As a result, there may be significant adjustments to the estimates of decommissioning liabilities and associated assets that can affect future financial results.. See note 22 \u2018Provision for abandonment liabilities\u2019 for further details about decommissioning and removal obligations.Income taxIncome tax expense, tax payables or receivables, and deferred taxes are based on management\u2019s interpre-tation of applicable laws and regulations, and on relevant court decisions where relevant. These estimates are dependent on management\u2019s ability to interpret and apply the requirements of tax and other relevant legislation, and requires judgment in respect of the recognition and measurement of any uncertain tax positions. See note 11 \u2018Taxes\u2019 for further details.1.4 Revenue recognition Revenue from the sale of liquids or gas is recognised at the point in time when the company\u2019s contractual performance obligations have been fulfilled and control is transferred to the customer, which will ordinarily be at the point of delivery when title passes (sales method). This is normally at the time of loading oil or NGL on vessels used for transport, or at agreed point of delivery for dry gas.There is no significant judgement applying IFRS 15 \u2018Revenue from contracts with customers\u2019 to the company\u2019s revenue generating contracts.Changes in over/underlift balances are valued at production cost including depreciation and presented as an adjustment to cost. See note 6 for further details. Gains or losses on asset disposals as described in section 1.7 are included in other operating income. Tariff revenue from processing of oil and gas is recognised as earned in line with underlying agreements.1.5 Interests in licences and partnerships The company has interests in licences on the Norwegian Continental Shelf. Under IFRS 11 Joint Arrangements, a joint operation is a 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. The company recognises investments in joint operations (oil and gas production licences) by reporting its share of related revenues, expenses, assets, liabilities and cash flows under the respective items in the company's financial statements. IFRS defines a joint arrangement as an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control 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. For those licences that are not deemed to be joint arrangements pursuant to the definition in IFRS 11 as there is no joint control, the company recognises its share of related expenses, assets, liabilities and cash flows on a line-by-line basis in the financial statements by analogy to IFRS 11 and in accordance with applicable IFRSs. 1.6 Business combinations and goodwill In a business combination, goodwill is allocated to the CGUs or groups of CGUs that are expected to benefit from synergies of the acquisition. The allocation of goodwill may vary depending on the basis for its initial recognition. The majority of the company's goodwill is related to the requirement to recognise deferred tax for the difference between the assigned fair values and the related tax base (\"technical goodwill\"). The fair value of the company\u2019s licences, all of which are located on the Norwegian Continental Shelf, are based on cash flows after tax. This is because these licences are only sold in an after-tax market based on the tax carry-over principles pursuant to the Petroleum Taxation Act section 10. The purchaser is therefore not entitled to a tax deduction for the consideration paid over and above the seller\u2019s tax values. In accordance with IAS 12 paragraphs 15 and 24, a provision is made for deferred tax corresponding to the difference between the acquisition cost and the transferred tax depreciation basis. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax. Technical goodwill is tested for impairment separately for each CGU which give rise to the technical goodwill. A CGU may be individual oil fields, or a group of oil fields that are connected to the same infrastructure/production facilities. 1.7 Acquisitions, sales and licence swaps 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 (see Item 1.8) or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Other licence purchases regarded as asset purchases are described below. Oil and gas production licencesFor licences in the development phase, the acquisition cost is allocated between capitalised exploration expenses, licence rights and production plant.When entering into agreements regarding the purchase/swap of assets, the parties agree on an effective date for the takeover of the net cash flow (usually 1 January in the calendar year which would also normally be the effective date for tax purposes). In the period between the effective date and the completion date, the seller will include its sold share of the licence in the financial statements. In accordance with the purchase agreement, there is a settlement with the seller of the net cash flow from the asset in the period from the effective date to the completion date (pro & contra settlement). The pro & contra settlement will be adjusted to the seller\u2019s losses/gains and to the assets for the purchaser, in that the settlement (after a tax reduction) is deemed to be part of the consideration in the transaction. Revenues and expenses from the relevant licence are included in the purchaser\u2019s Income statement from the acquisition date. For tax purposes, the purchaser will include the net cash flow (pro & contra) and any other income and costs as from the effective date. Deferred tax is not recognised when acquiring licences that are defined as asset acquisitions. 1.8 Tangible fixed assets and intangible assets GeneralTangible fixed assets are recognised on a historical cost basis. Gains and losses relating to the disposal of assets are determined by comparing the selling price with the book value, and are included in other operating income/expenses on a post tax basis. Operating assets related to petroleum activitiesExploration and development costs relating to oil and gas fieldsCapitalised exploration expenditures are classified as intangible assets and reclassified to tangible assets at the start of development. For accounting purposes, the field is considered to enter the development phase when the technical feasibility and commercial viability of extracting hydrocarbons from the field are demon-strable, normally at the time of concept selection. All costs relating to the development of commercial oil and/or gas fields are recognised as tangible assets. Pre-operational costs are expensed as they are incurred. The company employs the \u2019successful efforts\u2019 method to account for exploration and development costs. All exploration costs (including seismic shooting, seismic studies and 'own time\u2019), with the exception of acquisition costs of licences and drilling costs for exploration wells, are expensed as incurred. When explo-ration drilling is ongoing in a period after the reporting date and the result of the drilling is subsequently not successful, the capitalised exploration cost as of the reporting date is expensed if the evaluation of the well is completed before the date when the financial statements are authorised for issue. Drilling cost for exploration wells are temporarily capitalised pending the evaluation of potential discoveries of oil and gas resources. Such costs can remain capitalised for more than one year. The main criteria is that there must be plans for future activity in the licence area or that a development decision is expected in the near future. If no resources are discovered, or if recovery of the resources is considered technically or commercially unviable, expenses relating to the drilling of exploration wells are charged to expense.Acquired licence rights are recognised as intangible assets at the time of acquisition. Acquired licence rights related to fields in the exploration phase remain as intangible assets also when the related fields enter the development or production phase.Depreciation of oil and gas fieldsCapitalised exploration and evaluation expenditures, development expenditures from construction, installation or completion of infrastructure facilities such as platforms, pipelines and production wells, and field-dedicated transport systems for oil and gas are capitalised as production facilities and are depreciated using the unit-of-production method based on proven and probable developed reserves expected to be recovered from the area during the concession or contract period. Acquired assets used for the recovery and production of petroleum deposits, including licence rights, are also depreciated using the unit-of-pro-duction method based on proven and probable reserves. The reserve basis used for depreciation purposes is updated at least annually. Any changes in the reserves affecting unit-of-production calculations are reflected prospectively. Depreciation of assets other than oil and gas fields, including right of use assets, is calculated using the straight-line method over estimated useful lives and adjusted for any impairment or change in residual value, if applicable.1.9 Impairment Tangible fixed assets and intangible assetsThe unit of account for assessment of impairment is based on the lowest level at which it is possible to identify cash inflows that are independent of cash inflows from other groups of fixed assets. For oil and gas assets, this is typically the field or licence level. Impairment is recognised when the book value of the CGU (including any allocated goodwill) exceeds the recoverable amount. When estimating value in use and fair value less cost of disposal, expected future cash flows are discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money and the specific risk related to the asset. The discount rate is derived from the Weighted Average Cost of Capital (WACC).The lifetime of the field for the purpose of impairment testing is normally determined by the point in time when the operating cash flow from the field becomes negative.For exploration licences, impairment is based on an assessment of whether plans for further activities have been established or, if applicable, an evaluation of whether development will be decided on in the near future as described in section 1.8.A previously recognised impairment can only be reversed if changes have occurred in the estimates used for the calculation of the recoverable amount. GoodwillGoodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the value may be impaired. Impairment is recognised if the recoverable amount of the CGU (or group of CGUs) to which the goodwill is related is less than the book value, including associated goodwill and deferred tax as described in section 1.6. Losses relating to impairment of goodwill cannot be reversed in future periods. 1.10 Financial instruments The group\u2019s financial assets and liabilities comprise non-listed equity instruments, derivative financial instruments (assets and liabilities), receivables, cash and cash equivalents, payables, other short-term liabilities and non-current liabilities. The classification of financial assets and liabilities at initial recognition depends on the financial instrument\u2019s contractual cash flow characteristics and the Group\u2019s business model for managing them. The company has classified the financial instruments into the following categories of financial assets and liabilities: \u2013 Financial assets at fair value through profit or loss \u2013 Financial assets measured at amortised cost \u2013 Financial liabilities at fair value through profit or loss \u2013 Financial liabilities measured at amortised costs \u2013 The group\u2019s financial instruments at amortised cost includes trade receivables with the objective hold to collect and other short-term deposits, trade payables and other current and non-current liabilities. Receivables are initially recognised at fair value less impairment losses.All borrowings are initially recognised at transaction price, which equals the fair value of the amount received net of costs directly related to the establishment of the loan or issuance of debt. Subsequently, interest-bearing borrowings are valued at amortised cost using the effective interest method; the difference between the transaction price (after transaction costs) and the face value is recognised in the Income statement in the period until the loan falls due. Amortised costs are calculated by considering all issue costs on the settlement date, except for any discount or premium expensed immediately.Financial liabilities that do not form part of the \u201cheld for trading purposes\u201d category and which have not been designated as being at fair value with changes in value through profit or loss are classified as other financial liabilities. Further details on fair values of financial instruments are provided in note 28 \u2018Financial instruments\u2019.1.11 Presentation of payroll and administration costs The company presents its payroll and administration costs based on the functions in development, operational and exploration activities respectively, based on allocation of registered hours worked, net of amounts recharged to operated licences.1.12 Leases The lease liability is recognised at the commencement date and measured at the present value of the remaining lease payments, discounted using the company's incremental borrowing rate at the commence-ment date. The borrowing rate is derived from the terms of the company's existing credit facilities. Right-of-use (RoU) assets are depreciated over the lease term as this is ordinarily shorter than the useful life of the assets. The company applies the exemption for short term leases (12 months or less) and low value leases. As such, related lease payments are not recognised in the balance sheet, but expensed or capitalised in line with the accounting treatment for other non-lease expenses. The inclusion of non-lease components may vary across different lease categories, but for the most material class of assets (rigs), the company has excluded the non-lease components when measuring the lease liability.Lease agreements that are planned to be applied on several operated licences, are generally recognised on a gross basis as Aker BP is deemed to be the primary obligator. The company may enter into lease contracts as an operator on behalf of a licence, and may for such leases only recognise its net share of the related lease liability. Whether a contract is entered into on behalf of the licence is subject to a contract specific assessment, but the general principle is that there needs to be a direct link between the lease contract and the licence or field on which the RoU asset shall be used. For lease contracts recognised on a gross basis, the partner's share of the cost recovered by the company are presented as other income.1.13 Borrowing costs Borrowing costs that can be directly ascribed to procurement, processing or production of a qualifying asset are capitalised as part of the asset\u2019s acquisition cost. Borrowing cost is only capitalised during the development phase. Other borrowing costs are expensed in the period in which they are incurred. A qualifying asset is one that necessarily takes a substantial period of time to be made ready for its intended use or sale. Qualifying assets are generally those that are subject to major development or construction projects.1.14 Inventories Inventories mainly consist of equipment for the drilling of exploration and production wells and are valued at the lower of cost price (based on weighted average cost) and net realisable value. 1.15 Cash and cash equivalents Cash and cash equivalents include cash, bank deposits, and other short-term highly liquid investments with an original due date of three months or less. Bank overdrafts are included in the Statement of Financial Position as short-term loans.1.16 Tax GeneralTax consists of tax payable and changes in deferred tax. Deferred tax/tax benefits are calculated on the basis of the differences between book value and tax basis values of assets and liabilities, with the exception of temporary differences on acquisition of licences that are defined as asset purchases.Deferred tax is measured using the expected tax rate when the tax benefit is realised or the tax liability is met, based on tax rates and tax regulations that have been enacted or substantively enacted at the reporting date.Tax payable and deferred tax is recognised directly against equity or other comprehensive income insofar as the tax items are related to equity transactions or items of other comprehensive income.Deferred tax and tax benefits are presented net, where netting is legally permitted and the deferred tax benefit and liability are related to the same tax subject and are payable to the same tax authorities.Functional currencyThe company\u2019s functional currency is USD, while it is a statutory requirement to calculate the current tax based on NOK functional currency. This may impact the effective tax rate when the exchange rate between NOK and USD fluctuates. The revaluation of tax receivable and payable is presented as foreign exchange gain/loss, while the impact on deferred tax from revaluation of tax balances is presented as tax expense / income. Petroleum taxationAs an oil and gas company in Norway, Aker BP is subject to the special provisions of the Petroleum Taxation Act. Taxable profits from activities on the Norwegian Continental Shelf are liable to ordinary company tax and special tax. The overall tax rate for activities according to the Petroleum Taxation Act is 78 percent.The ordinary company tax is 22 percent. In addition, the company is subject to a special petroleum tax of 71.8 percent. The special petroleum tax is a cash-based tax andcompanies can make immediate deductions for expenses incurred. In addition, the corporate tax (22 percent) is deductible in the special tax base (71.8 percent) in order to maintain the overall tax rate of 78 percent. Tax depreciation and upliftInvestments in pipelines and production facilities can be depreciated by up to 16 2/3 percent annually, i.e., using the straight-line method over six years. Tax depreciation commences when the expenses are incurred. When a field stops producing, any remaining tax values may be deducted in that year. Changes to the Petroleum Taxation Act were enacted in June 2022 with effect from 1 January 2022. Under the new rules, investments are immediately deducted in the special tax base, while the ordinary depreciation rules still apply to the corporate tax base.Uplift is a special income deduction in the basis for calculation of special tax. Uplift is calculated on the basis of investments in pipelines and production facilities and can be regarded as an extra depreciation deduction in the special tax regime. The uplift rate is 12.4 percent (17.69 percent in 2022). From 2023 uplift is only applicable for investments covered by the temporary changes enacted to the Petroleum Tax Act in 2020. The changes included temporary rules for depreciation and uplift, whereby all investments incurred for income year 2020 and 2021 including uplift could be deducted for special tax in the year of investment. The tempo-rary changes are also applicable for investments up to and including year of production start in accordance with new PDOs delivered within 31 December 2022 and approved within 31 December 2023. Financial itemsInterest on debt with associated currency losses/gains is distributed between the offshore and onshore tax regimes. Offshore interest deduction is calculated as the net financial costs of interest-bearing debt multiplied by 50 percent of the ratio between net asset value for tax purposes allocated to the offshore tax regime as of 31 December in the income year and the average interest-bearing debt through the income year.Remaining financial expenses, currency losses and all interest income as well as currency gains are allocated to the onshore jurisdiction.Uncovered losses in the onshore tax jurisdictions resulting from the distribution of net financial items can be allocated to the offshore tax jurisdictions and deducted from regular income. Only 50 percent of other losses in the onshore tax jurisdictions are permitted to be reallocated to the offshore tax jurisdictions as deductions in regular income.Tax lossCorporate tax losses are carried forward without time limitations for companies subject to special tax. Special petroleum tax losses are reimbursed by the state in the following year as part of the ordinary tax assessment. The tax position can be transferred on realisation of the company or merger. 1.17 Provisions Decommissioning and removal costs: In accordance with the licence terms and conditions for the licences in which the company participates, the Norwegian State can require licence owners to remove the installation in whole or in part when production ceases or the licence period expires.In the initial recognition of the decommissioning and removal obligations, the company provides for the net present value of future costs related to decommissioning and removal based on its working interest in the respective fields. A corresponding asset is capitalised as a tangible fixed asset and depreciated using the unit-of-production method. Changes in the time value (net present value) of the obligation related to decommissioning and removal accretion are charged to income as financial expenses and increase the balance-sheet liability related to future decommissioning and removal expenses. Changes in the best estimate for expenses related to decommissioning and removal are recognised in the Statement of financial position (property, plant and equipment), except where it relates to licences with no future production or where the Company will be charged a portion of the liability as a user, i.e., based on shipped volumes. The discount rate used in the calculation of the fair value of the decommissioning and removal obligation is the risk-free rate.1.18 SegmentSince its formation, the company has conducted its entire business in one consistent segment, defined as exploration for and production of petroleum in Norway. The company conducts its activities on the Norwegian Continental Shelf, and management monitors the company at this level. The financial informa-tion relating to geographical distribution and large customers is presented in note 4.1.19 Changes to accounting standards and interpretations that: Have entered into force: The group has applied the following standards and amendment for the first time for their annual reporting period commencing 1 January 2023:Deferred Tax related to Assets and Liabilities arising from a Single Transaction (Amendments to IAS 12 Income taxes (IAS 12):The amendments to IAS 12 require companies to recognise deferred tax on particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences and will require the recognition of additional deferred tax assets and liabilities.The amendment should be applied to transactions that occur on or after the beginning of the earliest comparative period presented. In addition, entities should recognise deferred tax assets (to the extent that it is probable that they can be utilised) and deferred tax liabilities at the beginning of the earliest compara-tive period for all deductible and taxable temporary differences associated with: \u2013 right-of-use assets and lease liabilities, and \u2013 decommissioning, restoration and similar liabilities, and the corresponding amounts recognised as part of the cost of the related assets.The cumulative effect of recognising these adjustments is recognised in the opening balance of retained earnings, or another component of equity, as appropriate.IAS 12 did not previously address how to account for the tax effects of on balance sheet leases and similar transactions and various approaches were considered acceptable. Aker BP already accounted for such transactions consistent with the new requirements andthe application of the amendment did not have a material impact on the financial statements in 2023.Disclosure of Accounting Policies \u2013 Amendments to IAS 1 and IFRS Practice Statement 2:The IASB amended IAS 1 to require entities to disclose their material rather than their significant accounting policies. The amendments define what is \u2018material accounting policy information\u2019 (being infor-mation that, when considered together with other information included in an entity\u2019s financial statements, can reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements) and explain how to identify when accounting policy information is material. They further clarify that immaterial accounting policy information does not need to be disclosed. If it is disclosed, it should not obscure material accounting information.To support this amendment, the IASB also amended IFRS Practice Statement 2 Making Materiality Judgements to provide guidance on how to apply the concept of materiality to accounting policy disclo-sures. The application of the amendment did not have a material impact on the financial statements in 2023.Have been issued but have not entered into force: Certain new accounting standards and interpretations are issued, but not yet effective as of 31 December 2023. These standards are not expected to have a material impact on the group in the current or future reporting periods.Note 2 Overview of subsidiaries Aker BP UK Limited (100 percent)Aker BP UK Limited was established as a subsidiary of Det norske oljeselskap AS during 2020. The company holds two partner operated licences on the UK continental shelf, located to the borderline of the Norwegian continental shelf. The key objective within the licences is to explore the resource potential, based on the knowledge obtained in the Alvheim area.Aker BP ASA has three other subsidiaries which are not consolidated in the group accounts due to materiality considerations:Det norske oljeselskap AS (100 percent)Det norske oljeselskap AS, previously Marathon Oil Norge AS, was acquired by Aker BP in October 2014. All activity was transferred to Aker BP on 31 October 2014. During 2020, Aker BP UK Limited (see above) was established as a subsidiary of Det norske oljeselskap AS. Except for the subsidiary, the only asset in this company is cash equivalents reflecting the share capital amounting to USD 1.0 million.Alvheim AS (80 percent)The sole purpose of Alvheim AS is to act as legal owner of MST Alvheim, the floating production facility which is used to produce oil and gas from the Alvheim fields. The costs of and benefits from operating the MST Alvheim will be carried by the partners in the Alvheim field. Hence, Alvheim AS only has the formal ownership rather than the actual value of the production facilities. Following the Lundin transaction in 2022, Aker BP has a 80 percent share in Alvheim AS, which corresponds to the ownership in the Alvheim field. There were no activities in 2023.Sandvika Fjellstue AS (100 percent)Sandvika Fjellstue AS owns a conference centre used by Aker BP, located in Sandvika in Verdal.Note 3 Climate-related riskClimate-related risk assessment is generally described in the sustainability section of the annual report, and may have a significant impact on financial reporting. Climate-related risks can be divided into two major categories:- Transitional: Risks related to the transition to a lower-carbon economy- Physical: Risks related to the physical impacts of climate changeTTrraannssiittiioonnaall rriisskkssTransitional risks are deemed most relevant for financial reporting, and can be categorised as follows:Market- Demand for oil and gas can decrease significantly faster than supply can adapt, resulting in significantly lower oil and gasprices- In anticipation of the faster energy transition, key producers can shift their strategy to market share maximation, driving down pricesRegulatory and legal- The EUA price and/or Norwegian CO2 tax can increase faster and rise higher than what is anticipated- Mandatory emission abatements, including methane emission mitigation, can be enforced while being uncompetitive with other uses of capital or uneconomical- Access to new acreage can be reduced, in which case Aker BP\u2019s and the Norwegian E&P industry\u2019s longer-term growth prospects would be reduced, which would also lead to a potential increase in the cost of capital- Increased willingness to take legal actions against the Government and the E&P industry can create obstacles for ourprojects and operations Competition- Competition from new technology (e.g. batteries, renewables, hydrogen) and/or regulation can drive faster displacement of oil and gas in energy and non-energy sectors- A faster and larger scale of electrification in Europe can result in rationing and higher prices of power, thus increasing ourcostsReputational- Investors' and capital markets participants' perception of oil and gas activities in Norway can deteriorate, impactingavailability and cost of capital, as well as insurance premiums- Industry\u2019s attractiveness can deteriorate, making it difficult to attract and retain the right talent- Reputational risk related to offsetting strategySignificant mitigating actions are taken by the company to address these transitional risks, such as:- Climate risks integrated in all investment decisions- A strict financial framework for investment decisions; sanctioning projects with robust break-even price significantlylower than both current market prices and the company\u2019s long term price assumptions- Internal carbon price exceeding IEA\u2019s Net Zero scenario- Scenario analysis and sensitivity testing on both portfolio and project levels- Cost reduction initiatives- Requirement for all potential projects to be assessed for CO2 emission intensity and resilience against higher carbon taxes- Emissions reduction and efficiency initiatives- Continuous evaluation of electrification using power from shore or from offshore wind, where feasible- Efforts in place to secure financial flexibility and maintain investment grade credit ratingAlthough the above mitigating actions may limit the exposure, the company\u2019s financial reporting is significantly impacted by the transitional risks. Lower demand for oil and gas, and increased cost for Aker BP operations may have the following consequences for certain items within the financial reporting:- Decreased revenue- Higher operational cost- Shortened lifetime of the producing fields which may lead to higher present value of the abandonment provision, as wellas increased depreciation rates and impairment charges of fixed and intangible assets- Lower profitability together with investor\u2019s perception of oil and gas investments may result in higher cost of capital and lack of available capital resources. This is particularly relevant for Aker BP given the expected significant project investments over the next years - Increased tax burden as a result of unfavourable changes to the tax regimeTo illustrate the potential impact on some of the above mentioned financial reporting elements, we have included sensitivity analysis within the following areas:- Impairment (note 14): Transparency on carbon pricing and impairment sensitivity on oil and gas prices in the most recent IEA scenarios- Capitalised exploration (note 14): The impairment in a given scenario where no new project developments would be approved- Abandonment provisions (note 22): The impact on book value of abandonment provisions if cease of production of fieldswith estimated lifetime after 2040 were accelerated by 10 years - Interest expenses (note 10): Estimated increased credit spread of two percent on current loan balances. Although this isnot applicable on a short-term basis given fixed rates on all current bonds, it provides visibility on potential increased interest exposure on a longer term basis - Reserves (note 32): Impact on reserves if all production would cease from 2050 onwardsPhysical risksThe following are examples of physical risks relevant for Aker BP:AcutePotential higher frequency of extreme waves/weather may lead to operational shutdown or accelerated need for modifications of existing installations if safe design limits and structural integrity are threathened. The most significant influencing factors are rising sea levels and extreme waves challenging structural tolerance and reducing the design air gap. Mitigating actions include environmental monitoring, update of metocean data and evaluation of structural design limits. ChronicalChange in precipitation patterns and extreme variability in weather patterns over time may affect working environment conditions, for example reducing the period an offshore worker may tolerably be exposed to a certain working environment condition while performing their scope of work. Risk assessments are systematically performed by the Aker BP working environment team, including identification of improvements. Although considered less likely than transitional risks, physical risks may result in severe damage to the company\u2019s installations and may lead to significant shortened lifetime of the producing fields, as well as increased cost for mitigating actions, including preventive investments made in the field developments over the next years. As the climate changes further evolve, it is also a risk for increased probability that the physical risks will materialise. OpportunitiesThe assessment related to climate impacts will mainly be on the risk side. However, the situation may also give rise to some opportunities:- Carbon capture and storage (CCS) is expected to play an important role in the transition to a low-carbon energy future. CO2 storage has a potential to become a new profitable business opportunity for Aker BP - In an investment environment that is increasingly shaped by intensifying ESG pressure, Aker BP\u2019s industry leading GHGintensity, low production costs, and high ESG performance provide a competitive advantage and better opportunities to obtain capital in the future. This opportunity is further supported by the same actions as mitigating actions on the risk side. Net zero strategy Aker BP has a target of becoming net zero for our equity share scope 1 and 2 GHG emissions from 2030. Our strategy for emission reductions is as follows:\u2013 Avoid: We aim to avoid emissions wherever possible through electrification of new field developments and drilling rigswith power from shore (in Norway, the power mix consists mainly of hydro and wind power), portfolio management and optimisation of existing infrastructure\u2013 Reduce: We aim to reduce emissions through active energy management and brownfield electrification\u2013 Neutralise: From 2030, we aim to match every tonne of remaining equity share scope 1 and 2 GHG emissions from ouroperations, with an equal amount of high-quality carbon removalsOur emission reduction strategy emphasises that we will prioritise emission reductions from our own operations where feasible leading up to and after 2030. After 2041, we aim to have near-zero equity share scope 1 and 2 GHG emissions. In addition, from 2030, we will match every tonne of remaining equity share scope 1 and 2 GHG emissions from our operations with an equal amount of high-quality carbon removal credits. These credits are voluntary and come in addition to all carbon tax or fees we pay for our emissions. Certain emission reduction projects offshore are reflected in the business plans, and carbon removal offsets such as tree planting is not expected to incur significant cost on a long-term basis. Hence, the net zero strategy described above is deemed to be sufficiently reflected in the current business plans, which is the basis for the company's impairment testing.Note 4 Segment information The group's business is entirely related to exploration for and production of petroleum on, or to the borderline of, the Norwegian continental shelf. The group's activities are considered to have a homogeneous risk and return profile before tax, and the business is located in the geographical area Norway, except for two exploration licences in the UK. The group operates within a single operating segment which matches the internal reporting to the company's executive management. In 2023 the group had sales transactions with two customers which are under common control and represented more than 10 percent of total sales, BP Oil International Limited accounted for USD 11 591 million and BP Gas Marketing Limited accounted for USD 1 083 million. In 2022 sales transactions with BP Oil International Limited were USD 8 797 million, and sales transactions with BP Gas Marketing Limited were USD 2 820 million. In 2023 the parent company`s sales transactions with BP Oil International Limited accounted for USD 11 591 million and BP Gas Marketing Limited accounted for USD 1 083 million. In 2022 the parent company's sales transactions with BP Oil International Limited were USD 5 709 million, and sales transactions with BP Gas Marketing Limited were USD 2 820 million.Note 5 IncomeGroupParentBreakdown of petroleum revenues (USD million) 2023 2022 2023 2022Sales of liquids 11 849.8 8 986.4 11 849.8 5 834.6Sales of gas 1 714.5 3 898.9 1 714.5 3 412.5 Tariff income 15.7 10.9 15.7 10.9 Total petroleum revenues 13 580.0 12 896.2 13 580.0 9 258.0 Sales of liquids (boe million) 145.2 91.8 145.2 57.8 Sales of gas (boe million) 23.1 20.2 23.1 17.6 Other income (USD million)Realised gain (+)/loss (-) on commodity derivatives -0.0 27.0 -0.0 27.0Unrealised gain (+)/loss (-) on commodity derivatives 0.2 9.0 0.2 9.0Gain on licence transactions 0.0 11.0 0.0 11.01)Other income89.7 66.7 89.7 64.3Total other income 89.9 113.7 89.9 111.31) The figure includes partner coverage of RoU assets recognised on gross basis in the balance sheet and used in operated activity.Refer to note 23 and 28 for further details regarding commodity derivatives.Note 6 Production expensesGroup ParentProduction expenses (USD million) 2023 2022 2023 2022Cost of operations 707.6 682.7 707.6 597.6Shipping and handling 265.7 231.5 265.7 188.1Environmental taxes 62.9 63.9 62.9 54.4Production expenses based on produced volumes 1 036.3 978.1 1 036.3 840.0Adjustment for over (+)/underlift (-) 23.8 -45.3 23.8 -25.6Production expenses based on sold volumes 1 060.1 932.9 1 060.1 814.5Total produced volumes (boe million) 166.7 112.9 166.7 75.4Production expenses per boe produced (USD/boe) 6.2 8.7 6.2 11.1Note 7 Exploration expensesGroupParentBreakdown of exploration expenses (USD million) 2023 2022 2023 2022Seismic 27.2 34.4 26.7 30.0Area fees 14.4 12.3 14.4 13.3Field evaluation 13.5 10.7 13.5 8.1Dry well expenses 153.9 135.8 153.9 108.6G&G and other exploration expenses 57.5 48.9 56.0 36.2Total exploration expenses 266.3 242.2 264.3 196.2Note 8 Payroll expenses and remunerationGroup Parent Breakdown of payroll expenses (USD million) 2023 2022 2023 2022Payroll expenses 431.9 343.0 431.9 327.3Pension 41.1 34.0 41.1 32.2Social security tax 79.5 53.6 79.5 51.1Other personnel costs 19.7 20.4 19.7 19.8Total payroll expenses 572.1 451.0 572.1 430.4The payroll expenses are allocated to activities and partners based on timewriting. Aker BP's share of the total payroll expenses will depend amongst other on the ownership in the various licences. For 2023, the share of total payroll expenses to Aker BP was USD 406.1 million, equivalent to 71 percent of the gross expenses in the table above. Group Parent No. of full time equivalents employed during the year 2023 2022 2023 2022Europe 2 562 2 462 2 562 2 036Total 2 562 2 462 2 562 2 036Pension schemesThe company complies with the requirement to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension (\u201clov om obligatorisk tjenestepensjon\u201d). The company makes contributions to the pension plan for full-time employees equal to 7 percent for salary up to 7.1 G and 25.1 percent between 7.1 and 12 G. The pension premiums are charged to expenses as they are incurred.An early retirement scheme (AFP) has been introduced for all employees. The scheme is a multi-employer defined benefit plan, but is accounted for as a defined contribution pension, and premiums are expensed as incurred.Employee share programThe company has an annual share purchase program for all employees, including senior executives. The shares in the program are offered at a 25 percent discount and are subject to a three-year lock-up during which employees are not allowed to sell the shares. In connection with the share purchase program, all employees are also offered an interest free loan of 60 percent of the basic amount in the National Insurance scheme (\"G\"), to be repaid within one year. In total, employees subscribed for USD 19.3 million in 2023, compared to USD 15.5 million in 2022.Remuneration for BoD and the Executive Management Team (EMT) Information about remuneration to the BoD and EMT is provided in the Remuneration Report in the annual report. Accounting information regarding the share-based long-term incentive program (LTIP)The LTIP for members of the EMT is described in the Remuneration Report, while certain required accounting information is included below.The fair value of the grants issued in the LTIP has been measured using a Monte Carlo simulation. Service conditions were not taken into account when measuring fair value. The post-vesting lock-in condition has been incorporated into the grant date fair value by applying a discount to the valuation by estimating the probability that the employee will not comply with this condition. The LTIP agreement includes a clawback clause.The inputs used in the measurement of the 1 July 2023 grant date fair values were as follows: Fair value at grant date NOK 291.06Aker BP share price at grant date NOK 241.47Expected volatility:Aker BP39%Oslo Energy Index31%Stoxx 600 Europe Oil & Gas Index26%S&P Commodity Producers Oil & Gas E&P & Index34%Expected life3 yearsRisk free interest rate (based on government bonds)3.9%Expected volatility has been based on an evaluation of the historical volatility of the Company\u2019s share price, particularly over the historical period commensurate with the expected term. The expected term of the grants has been based on three-year vesting period.Total number of shares owned by members of EMTTotal number of shares Name2023*Karl Johnny Hersvik (Chief Executive Officer) 12 528Per Harald Kongelf (Chief Operating Officer) 5 546David Torvik T\u00f8nne (Chief Financial Officer)24 034Paula Doyle (Chief Digital Officer) 309Knut Arne Kristian Sandvik (SVP projects) 5 980Tommy Sigmundstad (SVP D&W) 10 451Per \u00d8yvind Seljebotn (SVP Exploration & Reservoir Development)619Marit Blaasmo (SVP People & Safety) 7 406Georg Olav Vidnes (SVP Operations) 2 857Ine Dolve (SVP Alvheim) 7 425Lars H\u00f8ier (SVP Yggdrasil)10 719Ole Johan Molvig (SVP Valhall) 18 140Thomas Hoff - Hansen (SVP Ula) 4 631Kari Nielsen (SVP Edvard Grieg & Ivar Aasen) 413Thomas \u00d8vretveit (SVP Skarv)743Total 111 801 *The numbers include shares held in companies where the senior executives have controlling interest. Remuneration and shares owned by the Board*The tables below include regular fees to the Board and fees for participation in the Board's subcommittees. The fees to the nomination committee are also included. To the extent applicable, fees to Board members employed in Aker ASA or BP plc groups will be paid to the companies, not to the Board member in person.20232022Fee Total number of Fee Total number of Name Comments(USD 1 000)shares(USD 1 000)shares\u00d8yvind EriksenChairman of the Board from 11.03.2016. Chair of the Organizational Development and Compensation committee. 92 - 96 -Anne Marie Cannon Deputy Chair from 17.04.2013. Member of the Audit & Risk committee and Organizational Development and Compensation committee. 66 12 078 69 12 0781)Kjell Inge R\u00f8kkeBoard member from 17.04.2013. 34 - 42 -Murray Auchincloss Board member from 16.04.2020. - - - -Trond Brandsrud Board member from 11.03.2016. Chairman of the Audit & Risk committee from 28.04.2016. 65 - 68 -Kate Thomson Board member from 30.09.2016. Member of the Audit & Risk committee from 04.10.2016. - - - -Valborg Lundegaard Board member from 05.04.2022. 40 - 28 -Charles Ashley Heppenstall Board member from 01.07.2022. 43 852 587 21 852 587Ingard Haugeberg Employee representative from 30.08.2018. 23 1 257 20 948Hilde K.Brevik Employee representative from 30.08.2018. Deputy employee rep. from 01.11.2023. 20 1 640 20 1 510Tore Vik Employee representative from 14.07.2021. 23 5 580 20 4 539Marit Karolin Hargemark D\u00f8rumEmployee representative from 01.11.2023. 3 706 N/A N/AAni Isabel Chiang Employee representative from 01.11.2023. 3 1 398 N/A N/ASarah Alexandra Berg Deputy employee representative from 14.07.2021. 3 2 572 3 2 225Rune Karstein Fauskanger Deputy employee representative from 14.07.2021. 3 9 479 3 7 888Thomas Husv\u00e6g Deputy employee representative from 07.07.2021. Employee representative from 01.11.2023. 6 441 3 132Geir Smaaskj\u00e6rDeputy employee representative from 01.11.2023. 1 2 399 N/A N/ATerje SolheimEmployee representative from 20.03.2014. Member of the Organizational Development and Compensation committee until 23 63724 63731.10.2023. Deputy employee representative from 01.11.2023.Svein Oskar Stoknes Chair of the Nomination committee from 16.04.2020. 5 - 4 -Ingebret Hisdal Member of the Nomination committee from 16.04.2020. 4 - 4 -Donna Riley Member of the Nomination committee from 16.04.2020. - - - -Ian Lundin Member og the Nomination committee from 14.04.2023. 4 - N/A N/AMember until 31.10.2023\u00d8rjan Kristensen BrakstadDeputy employee representative from 14.07.2021 until 31.10.2023. 2 374 3 420Member until 05.04.2022Paula Doyle Board member from 15.04.2021 until 05.04.2022. N/A N/A 14 -Total 463 891 148445 882 964 1) Kjell Inge R\u00f8kke owns and controls The Resource Group AS, which controls 68 percent of Aker ASA, which through a subsidiary owns 21 percent of Aker BP* Fee to board members are paid in NOK and converted to USD using a yearly average USD/NOK-rate of 10.5647 for 2023. Corresponding rate for 2022 was 9.6245.Note 9 Auditors feeGroupParent(USD 1 000) 2023 2022 2023 2022Fees for statutory audit services - PWC (excluding VAT) 341 230 310200 Fees for statutory audit services - KPMG (excluding VAT) - 132 - 132Fees for other services - PWC (excluding VAT) 598 533 598 533Fees for other services - KPMG (excluding VAT) - 202 - 202Total auditor's fees 939 1 098 907 1 068KMPG was the statutory auditor of Aker BP until April 2022, and was then replaced by PwC. Note 10 Financial itemsGroupParent(USD million) 2023 2022 2023 2022 Total interest income 133.4 26.0 133.4 23.0Realised gains on derivatives 83.4 33.5 83.4 33.5Change in fair value of derivatives 48.6 333.7 48.6 333.7Net currency gains 144.8 308.4 145.5 193.9Other financial income 44.5 98.8 44.5 98.8Total other financial income 321.2 774.3 322.0 659.8Interest expenses 212.7 154.0 212.7 147.3 Interest on lease debt 26.9 7.5 26.9 7.1 Capitalised interest cost, development projects -127.1 -85.6 -127.1 -53.3 1)Amortised loan costs49.3 31.8 49.3 19.2 Total interest expenses 161.8 107.7 161.8 120.2 Net currency loss - 269.4 - -Realised loss on derivatives 345.2 480.9 345.2 480.9Change in fair value of derivatives - - - - Accretion expenses related to abandonment provisions 166.3 119.9 166.3 107.9Other financial expenses 6.7 9.8 6.7 8.2Total other financial expenses 518.2 880.1 518.2 597.1Net financial items -225.4 -187.6 -224.7 -34.51) The figure includes amortisation of the difference between fair value and nominal value on the bonds aquired in theLundin transaction in Q2 2022.The rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalisation in 2023 is 4.34 percent. The corresponding rate for 2022 was 3.69 percent. Climate-related risk:As described in note 3 on climate-related risk, a sensitivity analysis have been performed to show the estimated impact of a two percentage points increase in credit spreads on current loan balances as of 31 December 2023 . This would result in an increased interest expenses of USD 120 million.Note 11 TaxesGroupParentTax for the period (USD million) 2023 2022 2023 2022Current year tax payable/receivable 6 136.4 7 163.0 6 136.4 4 826.1Current tax related to change in tax system - -176.4 - -176.4Prior period adjustments to current tax 58.8 -17.8 58.8 -19.0Current tax expense (+)/income (-) 6 195.2 6 968.8 6 195.2 4 630.7Change in current year deferred tax 1 200.5 -12.3 1 200.5 240.8Deferred tax related to change in tax system - 189.4 - 189.4Prior period adjustments to deferred tax 32.7 27.9 32.7 27.9Deferred tax expense (+)/ income (-) 1 233.1 205.1 1 233.1 458.2Tax expense (+)/income (-) 7 428.3 7 173.9 7 428.3 5 088.9Effective tax rate 85% 82 % 85% 82 %GroupParentReconciliation of tax expense (USD million)Tax rate2023 2022 2023 202278% tax rate on profit/loss before tax 78% 6 836.3 6 846.3 6 838.2 4 845.2Tax effect of uplift 72% -209.9 -161.7 -209.9 -148.9Permanent differences on impairment 78% 618.0 294.4 618.0 338.7FX translation of monetary items other than USD 78% -112.0 -170.6 -112.0 -170.6FX translation of monetary items other than NOK 78% -17.8 129.6 -17.8 129.6Tax effect of financial and other 22% items 56% 180.3 60.1 180.3 -33.61)Currency movements of tax balances78% 29.1 138.9 29.1 138.9Other permanent differences, prior period 78%104.436.9102.5-10.5adjustments and change in uncertain tax positionsTax expense (+)/income (-) 7 428.3 7 173.9 7 428.3 5 088.91) Tax balances are in NOK and converted to USD using the period end currency rate. When the NOK weakens againstUSD, the tax rate increases as there is less remaining tax depreciation measured in USD.From 1 January 2023 the temporary tax regime uplift rate was reduced from 17.69 to 12.40 percent.In accordance with statutory requirements, the calculation of current tax is required to be based on NOK functional currency. This may impact the effective tax rate as the company's functional currency is USD.Breakdown of tax effect of temporary GroupParentdifferences (USD million)2023 2022 2023 2022Tangible fixed assets -13 108.4 -11 057.2 -13 108.4 -11 057.2Capitalised exploration cost -253.8 -196.4 -253.8 -196.4Other intangible assets -1 301.8 -1 470.4 -1 301.8 -1 470.4Abandonment provision 3 552.8 3 249.3 3 552.8 3 249.3Lease debt 549.3 104.8 549.3 104.8Financial instruments -34.7 -26.4 -34.7 -26.4Other provisions 4.3 37.1 4.3 37.1 Net deferred tax liability (-)/deferred tax asset (+) -10 592.3 -9 359.1 -10 592.3 -9 359.1GroupParentDeferred tax liability (-)/asset (+) (USD million)2023 2022 2023 2022Deferred tax liability/asset at beginning of period -9 359.1 -3 291.3 -9 359.1 -3 291.3Change in current year deferred tax -1 200.5 12.3 -1 200.5 -240.8Deferred tax related to change in tax system - -189.4 - -189.4Deferred tax related to acquisition of Lundin Energy - -5 802.6 - -Change related to merger of group companies - - - -5 607.8Prior period adjustments -32.7 -27.9 -32.7 -29.7Deferred tax charged to OCI and equity -0.0 -60.1 -0.0 0.0Net deferred tax liability (-)/deferred tax asset (+) -10 592.3 -9 359.1 -10 592.3 -9 359.1GroupParentCalculated tax payable (-)/ tax receivable (+) (USD million) 2023 2022 2023 2022Tax payable/receivable at beginning of period -5 084.1 -1 497.3 -5 084.1 -1 497.3Current year tax payable/receivable -6 136.4 -7 163.0 -6 136.4 -4 826.1Current tax related to change in tax system - 176.4 - 176.4Net tax payment/tax refund 7 455.2 5 332.1 7 455.2 3 205.5Current tax related to acquisition of Lundin Energy - -2 181.0 - -Current tax related to merger of group companies - - - -2 427.2Change prior periods and uncertain tax positions -58.4 29.8 -58.4 31.1Currency movements of tax payable/receivable 223.9 245.8 223.9 253.4Current tax charged to OCI and equity - -27.1 - -Net tax payable (-)/receivable (+) -3 599.9 -5 084.1 -3 599.9 -5 084.1Note 12 Earnings per shareEarnings per share is calculated by dividing the year's profit attributable to ordinary equity holders of the parent entity, which was USD 1 336 million for the group (USD 1 603 million in 2022) and USD 1 338 million for the parent (USD 1 123 million in 2022) by the year's weighted average number of outstanding ordinary shares, which was 631.3 million (496.8 million in 2022). Weighted average number of diluted and ordinary shares is the same, as the company does not have any material dilutive instruments.GroupParent(USD million) 2023 2022 2023 20221)Profit for the year1 335.7 1 602.9 1 338.2 1 122.6The year's average number of ordinary shares (in million)631.3 496.8 631.3 496.8Earnings per share in USD 2.12 3.23 2.12 2.261) Attributable to ordinary equity holders of the parent entityNote 13 Tangible fixed assets and intangible assetsTANGIBLE FIXED ASSETSGGRROOUUPPPPAARREENNTTProperty, plant and equipmentProduction Fixtures and Production Fixtures and Assets under facilities including fittings, office Assets under facilities including fittings, office (USD million)developmentwellsmachinery Total groupdevelopmentwellsmachinery Total parentRestated book value 31.12.2021 1 795.4 8 332.3 86.7 10 214.4 1 795.4 8 332.3 86.7 10 214.4Restated acquisition cost 31.12.2021 1 795.4 13 403.0 256.4 15 454.9 1 795.4 13 403.0 256.4 15 454.91)Additions1 036.0 -1 203.1 18.2 -148.9 834.8 -1 181.6 18.1 -328.7Acquisition of Lundin Energy 933.2 6 726.3 3.8 7 663.3 - - - -Merger with ABP Norway AS - - - - 146.7 7 245.4 2.8 7 394.9Disposals/retirement - - 17.5 17.5 - - 17.5 17.52)Reclassification-2 132.6 2 266.6 7.3 141.3 -1 162.7 1 288.1 7.3 132.6Foreign currency translation -17.9 108.1 0.0 90.3 - - - -Acquisition cost 31.12.2022 1 614.2 21 301.0 268.3 23 183.5 1 614.2 20 754.9 267.2 22 636.3Restated accumulated depreciation and impairments 31.12.2021 - 5 070.7 169.7 5 240.5 - 5 070.7 169.7 5 240.5Depreciation - 1 635.3 39.9 1 675.2 - 1 102.2 38.8 1 141.1Impairment/reversal (-) - 385.6 - 385.6 - 385.6 - 385.6Disposals/retirement depreciation - - -17.5 -17.5 - - -17.5 -17.5Foreign currency translation - 13.0 0.0 13.0 - - - -Accumulated depreciation and impairments 31.12.2022 - 7 104.6 192.2 7 296.8 - 6 558.5 191.1 6 749.6Book value 31.12.2022 1 614.2 14 196.4 76.1 15 886.7 1 614.2 14 196.4 76.1 15 886.7Acquisition cost 31.12.2022 1 614.2 21 301.0 268.3 23 183.5 1 614.2 20 754.9 267.2 22 636.3Additions 2 671.6 990.6 10.8 3 673.0 2 671.6 990.6 10.8 3 673.0Disposals/retirement - - - - - - - -3)Reclassification-728.9 820.3 3.2 94.7 -728.9 820.3 3.2 94.7Acquisition cost 31.12.2023 3 556.9 23 111.9 282.3 26 951.2 3 556.9 22 565.8 281.2 26 404.0Accumulated depreciation and impairments 31.12.2022 - 7 104.6 192.2 7 296.8 - 6 558.5 191.1 6 749.6Depreciation - 2 135.0 35.6 2 170.6 - 2 135.0 35.6 2 170.6Impairment/reversal (-) 34.0 - - 34.0 34.0 - - 34.0Disposals/retirement depreciation - - - - - - - -Accumulated depreciation and impairments 31.12.2023 34.0 9 239.6 227.8 9 501.4 34.0 8 693.5 226.6 8 954.2Book value 31.12.2023 3 522.9 13 872.3 54.5 17 449.8 3 522.9 13 872.3 54.5 17 449.81) The negative addition is caused by decreased abandonment provision with an offseting entry on PP&E2) The reclassification is mainly related to the Johans Sverdrup phase 2 development project, which entered into production phase during 20223) The reclassification is mainly related to the Kobra East Gekko and Frosk development projects, which entered into production phase during 2023See note 14 for information regarding impairment charges.Capitalised exploration expenditures are reclassified to \"Assets under development\" when the field enters into the development phase. If development plans are subsequently re-evaluated, the associated costs remain in assets under development and are not reclassified back to exploration assets. Assets under development are reclassified to \"Production facilities\" from the start of production. Production facilities, including wells, are depreciated in accordance with the unit-of-production method. Office machinery, fixtures and fittings etc. are depreciated using the straight-line method over their useful life, i.e. 3 - 5 years. Removal and decommissioning costs are included as production facilities or assets under development.GROUPPARENTRight-of-use assetsVessels and Vessels and (USD million)Drilling Rigs Office Other Drilling Rigs BoatsTotal BoatsBook value 31.12.2021 12.3 50.7 29.3 1.8 94.2 12.3 50.7 29.3 1.8 94.2Acquisition cost 31.12.2021 18.4 57.4 52.4 2.3 130.6 18.4 57.4 52.4 2.3 130.6Additions 22.5 - 11.2 - 33.8 22.5 - 31.9 - 54.4Acquisition of Lundin Energy 11.1 - 23.7 - 34.8 - - - - -Merger with ABP Norway AS - - - - - 6.0 - - - 6.0Allocated to abandonment activity - -0.4 - - -0.4 - -0.4 - - -0.4Disposals/retirement 6.1 0.0 8.1 - 14.2 6.1 0.0 8.1 - 14.21)Reclassification-28.1 -2.3 - - -30.4 -23.0 -2.3 - - -25.4Foreign currency translation -0.0 - -2.0 - -2.0 - - - - -Acquisition cost 31.12.2022 17.9 54.7 77.3 2.3 152.2 17.9 54.7 76.2 2.3 151.1Accumulated depreciation and impairments 31.12.2021 6.1 6.7 23.1 0.5 36.4 6.1 6.7 23.1 0.5 3366..44Depreciation 2.8 3.9 11.8 0.2 18.7 2.8 3.9 10.7 0.2 17.6Impairment/reversal (-) - - - - - - - - - -Disposals/retirement depreciation -6.1 - -8.1 - -14.2 -6.1 - -8.1 - -14.2Foreign currency translation - - -0.1 - -0.1 - - - - -Accumulated depreciation and impairments 31.12.2022 2.8 10.6 26.7 0.7 40.8 2.8 10.6 25.6 0.7 39.8Book value 31.12.2022 15.1 44.1 50.6 1.6 111.3 15.1 44.1 50.6 1.6 111.3Acquisition cost 31.12.2022 17.9 54.7 77.3 2.3 152.2 17.9 54.7 76.2 2.3 151.1Additions 685.3 - 19.2 - 704.5 685.3 - 19.2 - 704.5Allocated to abandonment activity -6.4 -1.1 - - -7.5 -6.4 -1.1 - - -7.5Disposals/retirement 4.2 - - - 4.2 4.2 - - - 4.21)Reclassification-101.5 -2.4 - - -103.9 -101.5 -2.4 - - -103.9Acquisition cost 31.12.2023 591.0 51.2 96.5 2.3 741.1 591.0 51.2 95.5 2.3 740.0Accumulated depreciation and impairments 31.12.2022 2.8 10.6 26.7 0.7 40.8 2.8 10.6 25.6 0.7 39.8Depreciation 31.0 3.1 14.7 0.2 49.1 31.0 3.1 14.7 0.2 49.1Impairment/reversal (-) - - - - - - - - - -Disposals/retirement depreciation -4.2 - - - -4.2 -4.2 - - - -4.2Accumulated depreciation and impairments 31.12.2023 29.7 13.8 41.4 0.9 85.7 29.7 13.8 40.4 0.9 84.7Book value 31.12.2023 561.4 37.4 55.1 1.4 655.3 561.4 37.4 55.1 1.4 655.31) Reclassified to tangible fixed assets in line with the activity of the right-of-use assetSee note 25 for information regarding leases.Right-of-use assets are depreciated linearly over the lifetime of the related lease contract.INTANGIBLE ASSETSGROUPPARENTCapitalised Capitalised exploration Other intangible assetsexploration Other intangible assets(USD million)Goodwill Depreciated Not depreciated Total group Goodwill expendituresexpendituresBook value 31.12.2021 1 647.4 256.5 642.0 765.6 1 407.6 1 647.4 256.5 642.0 765.6 1 407.6Acquisition cost 31.12.2021 2 726.6 444.2 1 480.1 888.9 2 369.0 2 726.6 444.2 1 480.1 888.9 2 369.0Additions - 251.8 - 0.7 0.7 - 194.7 - 0.7 0.71)Acquisition of Lundin Energy12 542.9 - 25.7 1 256.6 1 282.2 - - - - -Merger with ABP Norway AS - - - - - 12 287.5 27.2 715.4 293.9 1 009.2Disposals/retirement/expensed dry wells - 135.8 - - - - 108.6 - - -2)Reclassification- -110.9 855.0 -855.0 - - -107.2 147.1 -147.1 -Foreign currency translation 135.0 1.0 0.3 12.3 12.6 - - - - -Acquisition cost 31.12.2022 15 404.4 450.3 2 361.0 1 303.6 3 664.6 15 014.1 450.3 2 342.5 1 036.4 3 379.0Accumulated depreciation and impairments 31.12.2021 1 079.1 187.7 838.1 123.3 961.4 1 079.1 187.7 838.1 123.3 961.4Depreciation - - 91.7 - 91.7 - - 73.2 - 73.2Impairment 377.4 10.9 - 258.3 258.3 - 10.9 - - -Foreign currency translation 12.9 - -0.1 8.8 8.7 - - - - -Accumulated depreciation and impairments 31.12.2022 1 469.4 198.6 929.7 390.5 1 320.2 1 079.1 198.6 911.3 123.3 1 034.6Book value 31.12.2022 13 935.0 251.7 1 431.3 913.1 2 344.4 13 935.0 251.7 1 431.3 913.1 2 344.4Acquisition cost 31.12.2022 15 404.4 450.3 2 361.0 1 303.6 3 664.6 15 014.1 450.3 2 342.5 1 036.4 3 379.0Additions - 238.6 - 9.1 9.1 - 238.6 - 9.1 9.1Disposals/retirement/expensed dry wells - 153.9 - - - - 153.9 - - -3)Reclassification- 9.2 97.9 -97.9 - - 9.2 97.9 -97.9 -Acquisition cost 31.12.2023 15 404.4 544.3 2 458.9 1 214.8 3 673.7 15 014.1 544.3 2 440.4 947.6 3 388.1Accumulated depreciation and impairments 31.12.2022 1 469.4 198.6 929.7 390.5 1 320.2 1 079.1 198.6 911.3 123.3 1 034.6Depreciation - - 187.1 - 187.1 - - 187.1 - 187.1Impairment/reversal (-) 792.2 20.4 - 42.9 42.9 792.2 20.4 - 42.9 42.9Disposals/retirement depreciation - - - - - - - - - -Accumulated depreciation and impairments 31.12.2023 2 261.6 218.9 1 116.9 433.4 1 550.3 1 871.4 218.9 1 098.4 166.3 1 264.7Book value 31.12.2023 13 142.8 325.4 1 342.0 781.4 2 123.4 13 142.8 325.4 1 342.0 781.4 2 123.41) The goodwill recognised in connection with the Lundin transaction includes the subsequent adjustment as described in note 302) The reclassification is mainly related to the Johans Sverdrup phase 2 development project, which entered into production phase during 20223) The reclassification is mainly related to the Kobra East Gekko development project, which entered into production phase during 2023Other intangible assets include both planned and producing projects on various fields. The producing projects are depreciated in line with the unit-of-production method for the applicable field. GroupParentDepreciation in the Income statement (USD million) 2023 2022 2023 2022Depreciation of tangible fixed assets 2 170.6 1 675.2 2 170.6 1 141.1Depreciation of right-of-use assets 49.1 18.7 49.1 17.6Depreciation of other intangible assets 187.1 91.7 187.1 73.2Total depreciation in the Income statement 2 406.8 1 785.7 2 406.8 1 231.8Impairment in the Income statement (USD million)Impairment/reversal of tangible fixed assets34.0 385.6 34.0 385.6Impairment/reversal of other intangible assets42.9 258.3 42.9 -Impairment/reversal of capitalised exploration 20.4 10.9 20.4 10.9Impairment of goodwill792.2 377.4 792.2 -Total impairments of tangible and intangible assets 889.5 1 032.2 889.5 396.4See note 14 for information regarding impairment charges. Note 14 ImpairmentsImpairment testingImpairment tests of individual cash-generating units are performed when impairment/reversal triggers are identified, and goodwill is tested for impairment at least annually. In 2023, two categories of impairment tests have been performed:- Impairment test of fixed assets and related intangible assets, including technical goodwill- Impairment test of residual goodwillImpairment is recognised when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. Correspondingly, a reversal of impairment is recognised when the recoverable amount exceeds the book value. Prior period impairment of goodwill is not subject to reversal. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. The impairment testing has been performed in accordance with the fair value method (level 3 in fair value hierarchy) and based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years.For producing licences and licences in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 31 December 2023.PricesFuture price level is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based on management's estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. The information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions going forward. In the impairment test, the oil and gas prices are therefore based on the forward curve from the beginning of 2024 to the end of 2026. From 2027, the oil and gas prices are based on the company's long-term price assumptions. Long-term gas price assumption is unchanged from year end 2022. Long-term oil price assumption for the period 2027 to 2035 is updated from 65.0 USD/BOE applied at year end 2022.The nominal oil and gas prices applied in the impairment test are as follows:Year USD/BOE GBP/therm202476.3 0.85202573.3 0.91202670.8 0.82From 2027 to 2035 (in real 2023 terms70.0 0.67From 2036 (in real 2023 terms)65.0 0.67Oil and gas reservesFuture cash flows are calculated on the basis of expected production profiles and estimated proven and probable reserves including potentially additional risked volumes. For more information about the determination of the reserves, reference is made to note 1, section 1.3, and to note 32.Future expenditureFuture capex, opex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost. The cost profiles include an estimated impact of the currently high cost escalation in the industry. The cash flows include a step up of CO2 tax/fees from current levels to approximately NOK 2 260 per tonn (2023 real) in 2030.Discount rateThe discount rate is derived from the company's weighted average cost of capital (\"WACC\"). The capital structure considered in the WACC calculation is derived from the capital structures of an identified peer group and market participants with consideration given to optimal structures. The cost of equity is derived from the expected return on investment by the company's investors. The cost of debt is based on the interest-bearing borrowings on debt specific to the assets acquired. The beta factors are evaluated annually based on publicly available market data about the identified peer group.The post tax nominal discount rate used at year end is 8.9 percent. This represents a change from 8.7 percent applied at year end 2022.Currency ratesYear USD/NOK202410.11202510.07202610.03From 20278.50The long-term currency rate is updated from USD/NOK 8.0 applied at year end 2022.InflationThe long-term inflation rate is assumed to be 2.0 percent, which is the same as applied at year end 2022. The currently high cost escalation in the industry is reflected in the cash flows rather than in the inflation rate.Impairment testing of assets including technical goodwillThe technical goodwill recognised in previous business combinations is allocated to each cash-generating unit for the purpose of impairment testing. Hence, the impairment test of technical goodwill is included in the impairment testing of assets, and the technical goodwill is written down before the asset. The carrying value of the assets is the sum of tangible assets, intangible assets and technical goodwill as of the assessment date. In the impairment test performed, carrying value is adjusted by the remaining part of deferred tax from which the technical goodwill arose, to avoid an immediate impairment of all technical goodwill. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable. Below is an overview of the impairment charge and the carrying value per cash-generating unit where impairment has been recognised in 2023:Group & ParentEdvard Grieg & Ivar Aasen Cash-generating unit (USD million)TroldhaugenCGUValhall CGUNet carrying value 110.5 5 944.7 4 236.9Recoverable amount - 5 762.0 3 660.8Impairment/reversal (-) 110.5 182.7 576.1Allocated as follows: Technical goodwill 33.5 182.7 576.1 Other intangible assets/licence rights 42.9 - - Tangible fixed assets 34.0 - - The main reason for the Troldhaugen impairment is related to the decision by the partership to not accede the PDO for the Troldhaugen project. The Edvard Grieg & Ivar Aasen CGU and the Valhall CGU impairment is mainly related to decrease in short-term oil and gas prices and decrease of deferred tax liabilities as described above.Exploration assetsDuring 2023, an impairment charge of USD 20.4 million has been recognised. The impairment charge is mainly related to the Ve well and has been allocated to capitalised exploration expenditures.Sensitivity analysisThe table below shows how the impairment or reversal of impairment of assets and technical goodwill would be affected by changes in the various assumptions, given that the remaining assumptions are constant. The figures in the table below are in all material respect related to goodwill impairment, which would have no impact on deferred tax. Change in impairment afterAssumption (USD million) ChangeIncrease in assumptionDecrease in assumptionOil and gas price forward period +/- 50 %-204.7 2 513.4Oil and gas price long-term +/- 20 %-5.0 1 126.2Production profile (reserves) +/- 5 %-6.2 283.4Discount rate +/- 1 % point128.0 -0.0Currency rate USD/NOK +/- 2.0 NOK-137.3 593.0Inflation +/- 1 % point-0.0 427.9Residual goodwillThe residual goodwill is tested for impairment on corporate level. The starting point for the impairment test is the difference between market value and book value of equity. At year end 2023 the market value exceeds the carrying amount of equity by a substantial margin.Climate related risksAs mentioned in the future expenditures section, the cash flows applied in the impairment testing include a step up of CO2 tax/fees from current levels to approximately NOK 2 260 per tonn (2023 real) in 2030.Further, as described in note 3, a sensitivity analysis have been performed towards various scenarios from International Energy Agency have been included in a separate sensitivity test as presented below. The price assumptions in those senarios have been provided by IEA at 2030 and 2050 in 2022 real terms. For the sensitivity calculation, a linear development between the average price for 2023 and IEA price in 2030, as well as between 2030 and 2050 have been applied. The table below summarises how the impairment charge would increase (+) or decrease (-) using the oil and gas price assumptions in the following scenarios:Change in impairmentIEA Scenario (USD million)Net ZeroAnnounced PledgesStated PoliciesValhall/Hod 2 969SkarvUla -57 -93Alvheim 132Johan Sverdrup 706Grieg/Aasen 390Yggdrasil 52Total 4 250 -57 -93 Oil USD/bblGas USD/mmbtuScenario price ranges2030 2050 2030 2050Net Zero 42 25 4.3 4.1Announced Pledges74 60 6.5 5.4Stated Policies 85 83 6.9 7.1In addition, capitalised exploration and other related balances have been reviewed as of year end 2023, in order to assess the exposure and dependancy of future government approvals. An amount of USD 516 million would have been impaired in a situation where no new project developments would be approved. Impairment testing in 2022In 2022, the impairment charge was mainly related to three CGU's and allocated to technicall goodwill, other intagible assets from acquisitions and tangible fixed assets, in addition to an impairment of exploration assets and other non-current assets. The methodology for impairment testing was the same as in 2023 as described in this note.The following assumptions were applied for the impairment testing at year end 2022:- discount rate of 8.7 percent nominal after tax for both value in use and fair value testing- a long-term inflation of 2.0 percent- a long-term exchange rate of NOK/USD 8.0 (forward curve first three years)- a long-term oil price assumption of 65 USD/barrel, using forward curve first three yearsSummary of impairment/reversal of impairmentsThe following impairments/(reversals) have been recorded:GroupParent(USD million) 2023 2022 2023 2022Impairment/reversal of tangible fixed assets 34.0 385.6 34.0 385.6Impairment/reversal of other intangible assets 42.9 258.3 42.9 -Impairment/reversal of capitalised exploration expenditures 20.4 10.9 20.4 10.9Impairment of goodwill 792.2 377.4 792.2 -Impairment of non-current assets - - - 434.2Total impairments 889.5 1 032.2 889.5 830.7Note 15 Trade receivablesTrade receivables are recognised in the Statement of Financial Position at nominal value after a deduction for the provision for credit losses. Historically there have been no significant credit losses, and the company's customers are mainly large, financially sound oil companies. Trade receivables consist of receivables related to the sale of oil and gas.GroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Receivables related to the sale of petroleum 658.8 950.9 658.9 950.9Total trade receivables 658.8 950.9 658.9 950.9Age distribution of trade receivables as of 31 December for the group and parent was as follows:Year (USD million) Total Not due <30d 30-90d >90d2023658.8 658.8 - - -2022950.9 950.1 0.8 - -Note 16 Other short-term receivablesGroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Prepayments 279.7 124.0 279.7 124.0VAT receivable 18.8 12.4 18.8 12.4Underlift of petroleum 41.7 53.6 41.7 53.6Accrued income from sale of petroleum products 216.9 335.5 216.9 335.5Other receivables, mainly balances with licence partners 185.1 160.7 185.0 161.1Total other short-term receivables 742.2 686.2 742.1 686.7Note 17 InventoriesThe inventory mainly consists of equipment for the drilling of exploration and production wells. GroupParentInventory value (USD million) 2023 2022 2023 2022Inventories - measured at cost 255.5 256.0 255.5 256.0Provision for obsolete equipment 53.1 46.5 53.1 46.5Book value of inventories 202.3 209.5 202.3 209.5Note 18 Other non-current assetsGroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Shares in Alvheim AS 0.0 0.0 0.0 0.0Shares in Det norske oljeselskap AS 1.0 1.0 1.0 1.0Shares in Aker BP UK0.0 0.0 - -Shares in Sandvika Fjellstue AS 1.8 1.8 1.8 1.81)Investment in subsidiaries2.8 2.8 2.8 2.82)Continuing involvement - Cognite AS81.4 81.4 81.4 81.4Tenancy deposit - 1.6 - 1.63)Unamortised fees - RCF15.0 11.0 15.0 11.0Other non-current assets 3.6 7.6 3.6 7.6Total other non-current assets 102.9 104.5 102.9 104.51) Alvheim AS, Det norske oljeselskap AS and Sandvika Fjellstue AS have been deemed immaterial for consolidation purposes. All companies acquired in the Lundin transaction was either liquidated or merged with Aker BP ASA in 2022. For more information regarding shares in subsidiaries, see note 2.2) In 2022 the company sold its shares in Cognite AS to Saudi Aramco Development Company for a consideration of USD118 million. As part of the transaction, Aker BP has granted the buyer an option with maturity in November 2024 which under certain conditions gives the buyer the right to sell the shares back to Aker BP for USD 81.4 million. On this basis, Aker BP is considered to have continuing involvement in Cognite AS, in accordance with guidelines in IFRS 9. Hence, both an asset and a liability of USD 81.4 million is recognised in the statement of financial position at 31 December 2023. 3) Remaining unamortised fees related to the Revolving Credit Facility (RCF). These have been reclassified from other interest-bearing debt as the RCF was undrawn as at 31 December 2023 and 31 December 2022.Note 19 Cash and cash equivalentsThe item 'Cash and cash equivalents' consists of bank accounts and time deposits that constitute parts of the group's transaction liquidity. GroupParentBreakdown of cash and cash equivalents (USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Bank deposits 3 366.9 2 756.0 3 366.9 2 756.01)Restricted bank deposits21.5 - 21.5 -Cash and cash equivalents 3 388.4 2 756.0 3 388.4 2 756.0Undrawn RCF facility 3 400.0 3 400.0 3 400.0 3 400.01) Tax deduction accountThe RCF is undrawn as at 31 December 2023 and the remaining unamortised fees of USD 15.0 million related to the facility are therefore included in other non-current assets.The senior unsecured Revolving Credit Facility (RCF) of USD 3.4 billion was established in May 2019 and consist of two tranches: (1) Working Capital Facility with a committed amount of USD 1.4 billion until 2025 and USD 1.3 billion until 2026, and(2) Liquidity Facility with a committed amount of USD 2.0 billion until 2025 and USD 1.65 billion until 2026.(3) In November 2023, Aker BP signed a new USD 1.8 billion RCF with 9 banks. The new facility will have a forward date(availability date) at the same time as the existing RCF expires in 2026 and has a maturity in 2028. The facility includes two extension options with potential final maturity in 2030. The interest rate for the Working Capital Facility is Term SOFR plus a margin of 1.00 percent and for the Liquidity Facility Term SOFR plus a margin of 0.75 percent. The new RCF with forward start in 2026 will have an interest rate of Term SOFR plus a margin of 0.85 percent. Drawing under the Liquidity Facility and new RCF will add a utilisation fee. A commitment fee of 35 percent of applicable margin is paid on the undrawn part of the facilities. The financial covenants are as follows:- Leverage Ratio: Net interest-bearing debt divided by twelve months rolling EBITDAX (excluding any impacts from IFRS 16) shall not exceed 3.5 times- Interest Coverage Ratio: Twelve months rolling EBITDA divided by Interest expenses (excluding any impacts from IFRS 16) shall be a minimum of 3.5 times The financial covenants in the group's current debt facilities exclude the effects from IFRS 16, and therefore cannot be directly derived from the group's financial statements. See reconciliations of Alternative Performance Measures for detailed information.As at 31 December 2023 the Leverage Ratio is 0.19 and Interest Coverage Ratio is 95.2 (see APM section for further details). Based on the group's current business plans and applying oil and gas price forward curves at end of 2023, the group\u2019s estimates show that the financial covenants will continue to comply with the covenants by a substantial margin.Note 20 Share capital and shareholders GroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022 Share capital 84.3 84.3 84.3 84.3Total number of shares (in 1 000) 632 022 632 022 632 022 632 022Nominal value per share in NOK 1.00 1.00 1.00 1.00There is only one single class of shares in the company and all shares carry a single voting right.The company acquires own shares in connection with the annual share purchase program for all employees, and potentially for use in relation to the LTIP program for EMT members at vesting in 2025 and onwards. During 2023 the company purchased 1 361 646 (0.2 percent of the share capital) and sold 862 255 (0.1 percent) own shares. The price per share was NOK 254.2 and 230.02 respectively. At year end 2023 the company had 728 456 own shares, equivalent to 0.1 percent of the total number of shares. The shares have a face value of NOK 1 and an average book value of NOK 259.4 per share. No. of shares Owning Overview of the 20 largest shareholders registered as of 31 December 2023(in 1 000)interestAker Capital 133 75821.16%BP Exploration Operating Company Ltd 100 30315.87%Nemesia 90 90914.38%Folketrygdfondet 33 3565.28%Capital Group 20 1973.20%BlackRock 14 7562.33%Vanguard 11 6031.84%DNB Asset Management AS 10 0081.58%MFS Investment Management 9 8291.56%KLP Kapitalforvaltning AS 5 2880.84%Avanza Bank AB 4 7740.76%Syquant Capital 4 7210.75%SAFE Investment Company Limited 4 6910.74%Janus Henderson Investors 4 5950.73%Danske Invest 4 3800.69%Storebrand Asset Management 4 3670.69%Nordea Funds 4 0620.64%State Street Global Advisors 3 2190.51%Invesco 3 1280.49%Magallanes Value Investors SGIIC 3 1140.49%Other 160 96425.47%Total 632 022100.00%Note 21 BondsOutstanding GroupParent(USD million)amount2)Senior Notes 3.000% (Jan 20/Jan 25)95.5 94.5 498.2 94.5 498.22)Senior Notes 2.875% (Sep 20/Jan 26)129.7 128.3 497.8 128.3 497.82)3)Senior Notes 2.000% (Jul 21/Jul 26)707.1 660.4 907.4 660.4 907.41)Senior Notes 5.600% (Jun 23/Jun 28)500.0 496.8 - 496.8 -Senior Notes 1.125% (May 21/May 29)750.0 824.8 795.3 824.8 795.3Senior Notes 3.750% (Jan 20/Jan 30)1 000.0 995.2 994.4 995.2 994.4Senior Notes 4.000% (Sep 20/Jan 31)750.0 745.9 745.3 745.9 745.33)Senior Notes 3.100% (Jul 21/Jul 31)1 000.0 859.3 840.8 859.3 840.81)Senior Notes 6.000% (Jun 23/Jun 33)1 000.0 993.0 - 993.0 -Long-term bonds - book value 5 798.2 5 279.2 5 798.2 5 279.2Long-term bonds - fair value 5 629.4 4 829.7 5 629.4 4 829.71) In June 2023 the company issued two new USD bonds:- USD 500 million Senior Notes 5.600% (Jun 2028)- USD 1,000 million Senior Notes 6.000% (Jun 2033)2) Parts of the proceeds from the new bonds were used to tender for our outstanding bonds maturing in 2025 and 2026.In total we repurchased the following volumes split per bond (principal amount):- USD 404.5 million on USD Senior Notes 3.000% (Jan 2025)- USD 370.3 million on USD Senior Notes 2.875% (Jan 2026)- USD 292.9 million on USD Senior Notes 2.000% (Jul 2026)The fair value of these bonds were lower than the book value at the time of repurchase. This resulted in a net gain of USD 43.7 million presented as other financial income.3) Prior to the repurchase mentioned above, these bonds had a nominal value of USD 1 billion and were recognised at fair value in connection with the Lundin Energy transaction at 30 June 2022. The difference between fair value and nominal value is linearly amortised over the lifetime of the bonds (see note 10).Interest is paid on a semi annual basis, except for the EUR Senior Notes which is paid on an annual basis. None of the bonds have financial covenants.The fair value of bonds are based on the listed prices in the active markets (level 1 in fair value hierarchy). Note 22 Provision for abandonment liabilities GroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022 Provisions as of beginning of period 4 165.6 5 172.4 4 165.6 5 172.4 Incurred removal cost -160.2 -79.2 -160.2 -78.5 Accretion expense 166.3 119.9 166.3 107.9 Abandonment liabilities from acquisition of Lundin Energy - 745.9 - - Merger with ABP Norway AS - - - 598.6 Foreign currency translation - 6.7 - - Impact of changes to discount rate -101.2 -1 876.9 -101.2 -1 747.7Change in estimates and new provisions 484.1 76.9 484.1 113.0 Total provision for abandonment liabilities 4 554.7 4 165.6 4 554.7 4 165.6 Breakdown of the provisionShort-term 250.6 115.2 250.6 115.2 Long-term 4 304.1 4 050.4 4 304.1 4 050.4 Total provision for abandonment liabilities 4 554.7 4 165.6 4 554.7 4 165.6 Estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The nominal pre tax discount rate (risk free) at end of 2023 is between 4.0 percent and 4.9 percent, depending on the timing of the expected cash flows. The corresponding range at year end 2022 was between 3.9 and 4.7. The calculations assume an inflation rate of 2.0 percent for all applicable periods.Climate-related risk:As described in note 3 on climate-related risk, a sensitivity analysis have been performed to show the impact on the book value of abandonment provisions as at 31 December 2023, if cease of production of fields with estimated lifetime from 2040 were accelerated by ten years. Such acceleration would result in an increase in the book value of abandonment provision of USD 680 million.Note 23 DerivativesGroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Unrealised gain currency contracts 38.1 2.9 38.1 2.9Long-term derivatives included in assets 38.1 2.9 38.1 2.9Unrealised gain commodity derivatives 0.2 - 0.2 -Unrealised gain currency contracts 147.9 153.1 147.9 153.1Short-term derivatives included in assets 148.1 153.1 148.1 153.1Total derivatives included in assets 186.2 156.0 186.2 156.0Fair value of option related to sale of Cognite - 16.0 - 16.0Unrealised losses currency contracts 0.5 1.0 0.5 1.0Long-term derivatives included in liabilities 0.5 17.0 0.5 17.0Fair value of option related to sale of Cognite 4.8 - 4.8 -Unrealised losses currency contracts 28.0 34.9 28.0 34.9Short-term derivatives included in liabilities 32.8 34.9 32.8 34.9Total derivatives included in liabilities 33.3 51.9 33.3 51.9The company has various types of economic hedging instruments, but no hedge accounting is applied. Commodity derivatives are used to hedge the risk of oil price reduction. The company currently has limited exposure towards fluctuations in interest rate, but generally manages such exposure by using interest rate derivatives. Foreign currency exchange derivatives are used to manage the company's exposure to currency risks, mainly costs in NOK, EUR and GBP. These derivatives are mark to market with changes in market value recognised in the income statement. In the income statement, impacts from commodity derivatives are presented as other income, while impacts from other derivatives are presented as financial items.As of year end 2023 the company has used currency derivatives to secure approximately NOK 35 billion in 2024 by selling USD at an average exchange rate of USD/NOK 10.51 and NOK 9 billion in 2025 at an average rate of USD/NOK 10.38. In addition, NOK 1.3 billion has been secured in 2026 using options, with an average strike price of USD/NOK 10.53. Note 24 Other current liabilitiesGroupParentBreakdown of other current liabilities (USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Balances with licence partners 30.9 43.1 30.9 43.1Share of other current liabilities in licences 692.5 460.8 692.3 460.8Overlift of petroleum 42.8 30.9 42.8 30.9Accrued interest 85.8 95.8 85.8 95.8Payroll liabilities and other provisions 219.2 176.5 218.5 176.3Total other current liabilities 1 071.0 807.1 1 070.2 806.9Note 25 Lease agreementsThe group has entered into leases for rig contracts, other licence related commitments and office premises. The leases do not contain any restrictions on the company's dividend policy or financing. Lease agreements that are planned to be applied on several operated licences, are generally recogised on a gross basis as Aker BP is deemed to be the primary obligator. A sublease is recognised upon commencement to the extent the related RoU asset will be subleased for more than 12 months.Significant lease agreementsFor 2023, the group had four operated rig commitments recognised as lease debt. This included the two jack-up rigs Noble Invincible and Noble Integrator. Noble Invincible commenced on a new contract in the beginning of April 2023, expected to expire in November 2027, including options to suspend the commitment for parts of the period. Noble Integrator was contracted by Valhall/Hod from 2022 until September 2023.In addition, we had the semi-submersible rig Deepsea Nordkapp contract with Odfjell Drilling during 2023. After exercising an extension option, committing the Deepsea Nordkapp for the completion of the Kobra East Gekko (KEG) scope, the rig contract was recognised in the statement of financial position when the KEG scope commenced in early 2023. After finalising the KEG scope, the Deepsea Nordkapp commenced on a new contract in October 2023 with a firm contract scope until end of 2026, with possible optionality to extend the contract period further. The new contract has thus been recognised as lease liability in 2023 for the firm period.Aker BP has further entered into a rig agreement with Saipem for the semi-submersible drilling rig Scarabeo 8. The contract duration is for three years with two one-year options and a mechanism of rate adjustment to market rates from the third year and onwards. The rig commenced with Aker BP in beginning of January 2023 and was recognised in the statement of financial position as a lease liability, including the two one-year option periods.In addition, Aker BP has a lease liability related to the semi-submersible rig Deepsea Atlantic, operated by Equinor on Johan Sverdrup expected to end around mid-2024.Other significant lease agreements Under the drilling and well construction alliance agreements, Aker BP entered into a five-year rig commitment for the jack-up rig Noble Integrator in 2022. Different rate structures will apply during the period reflecting different operating modes, agreed incentive schemes, and market developments. There will be different work scopes, with varying durations in the period from 2024 to 2027, including options to suspend the commitment for parts of the period. Noble Integrator is expected to commence operations in Q2 2024. The semi-submersible rig Deepsea Stavanger is expected to join the Aker BP rig fleet in the first half of 2025 for a five-year contract.The minimum commitments from the lease contracts described above that has not commenced within year end 2023, have been included as other commitments in note 26. Other lease informationNon-lease components such as the service element of rig commitments are not included as part of the lease debt. As at 31 December 2023 this amounts to USD 451 million.The total expenditure relating to short-term leases which are not recognised as part of lease liabilities was USD 4 million in 2023 (USD 71 million in 2022). The group does not have any residual value guarantees or variable lease payments. Extension options are included in the lease liability when, based on management's judgement, it is reasonably certain that an extension will be exercised. No sublease of right-of-use assets has been recognised as of year end 2023.The incremental borrowing rate applied in discounting of the nominal lease debt is between 2.40 percent and 6.90 percent, dependent on the duration of the lease and when it was intially recognised.GroupParent(USD million) 2023 2022 2023 2022Lease debt as of beginning of period 134.4 136.2 134.4 136.2New lease debt recognised in the period 704.5 33.8 704.5 54.41)Payments of lease debt-160.4 -74.1 -160.4 -67.6Interest expense on lease debt 26.9 7.5 26.9 7.1Lease debt from acquisition of Lundin Energy - 34.8 - 6.0Currency exchange differences -1.2 -3.8 -1.2 -1.8Total lease debt 704.2 134.4 704.2 134.4Break down of the lease debt to short-term and long-term liabilitiesShort-term 148.7 36.3 148.7 36.3Long-term 555.5 98.1 555.5 98.1Total lease debt 704.2 134.4 704.2 134.41) Payments of lease debt split by activities (USD million): 2023 2022 2023 2022Investments in fixed assets 95.7 46.9 95.7 41.7Abandonment activity 8.3 0.8 8.3 0.8Operating expenditures 11.3 13.9 11.3 13.9Exploration expenditures 12.0 6.2 12.0 6.2Other income 33.1 6.3 33.1 5.0Total 160.4 74.1 160.4 67.6Nominal lease debt maturity breakdown (USD million):Within one year 220.2 42.6 220.2 42.6Two to five years 528.4 87.2 528.4 87.2After five years 11.8 26.4 11.8 26.4Total 760.4 156.2 760.4 156.2See note 13 for disclosures relating to the right-of-use assets.Note 26 CommitmentsCapital commitments and other contractual obligationsAker BP`s net share of capital commitments and other contractual obligations in the table below are mainly related to unavoidable costs related to development projects, non-rig commitments not recognised as lease liabilities, rig leases not yet commenced and booked future gas transportation capacity. Parts of the rig leases have been entered into in the company\u2019s name at the initial signing, and subsequently partly allocated to licences. The figures have been calculated based on the assumed net share for the company based on the planned use of the related leased assets as at 31 December 2023. The numbers below exclude any liabilities disclosed in note 25 in relation to right-of-use assets. GroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Within one year1 191.91 572.11 191.91 572.1One to five years753.8714.7753.8714.7After five years76.0284.076.0284.0Total 2 021.8 2 570.7 2 021.8 2 570.7The main part of the commitments within one year in the table above relates to non-cancellable expenditures on contracts entered into in connection with the PDO's delivered in 2022.Contingent liabilities During the normal course of its business, the company will be involved in disputes, including tax disputes. Potential tax claims related to previous taxable income of acquired companies can to some extent be reimbursed from the sellers. The company has made accruals for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS 37 and IAS 12. As for other licences on the NCS, the company has unlimited liability for damage, including pollution damage. The company has insured its pro rata liability on the NCS on a par with other oil companies. Facilities and liabilities towards third parties are covered by an operational insurance policy.Note 27 Transactions with related partiesThe three main shareholders in Aker BP is Aker Capital AS, BP Exploration Operating Company and Nemesia S.a.r.l, which are all considered to have significant influence over Aker BP. Aker BP has no transactions with entities controlled by Nemesia. Entities controlled by either of the Aker Group or BP Group are considered to be related parties under IFRS and are listed in the table below. The figures listed represent net charges to Aker BP. GroupParentRelated party (USD million) Revenues (-) / expenses (+) 31.12.2023 31.12.2022 31.12.2023 31.12.2022ABP Norway AS Interest cost - - - 9.2ABP Norway AS Interest income - - - -7.4ABP Norway ASOperating expenses - - - 18.51)ABP Norway ASRecharges- - - -52.5ABP Energy Holding BV Interest cost - - - 1.2aiZe AS Purchases of consultant and technology services13.1 5.1 13.1 5.1Aker ASA Board remuneration etc 0.5 0.9 0.5 0.92)Cognite ASPurchases of consultant and IT services 11.9 7.0 11.9 7.0Lily Akerkvartalet AS Office cost 0.7 0.5 0.7 0.5BP Oil International Ltd Sales of Oil and NGL -11 591.4 -8 796.6 -11 591.4 -5 707.5BP Gas Marketing Ltd Sales of Gas -1 083.1 -2 819.7 -1 083.1 -2 956.5GroupParentRelated party (USD million)Receivables (+) / liabilities (-) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Aker BP UK LtdOther receivables - - 8.5 6.2BP Oil International Ltd Trade receivables 637.7 838.5 637.7 400.41) The figure represents total gross charges related to personnel employed by Aker BP ASA working for ABP Norway AS. These charges have been allocated to various licences and corporate activity based on timewriting.2) As described in note 18 Aker BP sold its share in Cognite during 2022. Due to the continuing involvement arising from the put option arrangement, the transactions with Cognite are still considered to be within related parties.Note 28 Financial instrumentsCapital structure and equity The company's financial position has been developed and improved over time and has clear capital allocation principles. The main priority is a robust balance sheet with financial flexibility and investment grade credit rating. Maintaining our rating is particularly central as it gives us effective access to capital markets and serves as a foundation for future investments. The company has an investment grade rating by S&P Global, Fitch and Moody's. The company's production level, financial position and resource and reserve levels are important parameters in relation to the assigned rating. The company continues to optimise its capital structure by balancing the return on equity against liquidity requirements.The company monitors changes in financing needs, risk, assets and cash flows, and evaluates the capital structure continuously. To maintain the desired capital structure, the company considers various types of capital transactions, including refinancing of its debt, purchase or issue new shares or debt instruments, sell assets or pay back capital to the owners.Unless specified otherwise, the numbers below apply both to the group and the parent. Categories of financial assets and liabilities The company has the following financial assets and liabilities: financial assets and liabilities recognised at fair value through profit or loss, cash and receivables, and other liabilities. The latter two are recognised in the accounts at amortised cost, while the first item is recognised at fair value.Categories of financial assets and financial liabilities - Group and ParentFinancial Financial Financial Financial assets at fair assets liabilities at fair liabilities value through measured at value through measured at 31.12.2023profit and lossamortised costprofit and lossamortised costTotalAssetsTrade receivables - 658.8 - - 658.81)Other short-term receivable- 462.4 - - 462.4Cash and cash equivalents - 3 388.4 - - 3 388.4Long-term receivables 7.0 62.2 - - 69.1Derivatives 186.2 - - - 186.2Total financial assets 193.2 4 571.8 - - 4 764.9LiabilitiesDerivatives - - 33.3 - 33.3Trade creditors - - - 291.0 291.0Bonds - - - 5 798.2 5 798.2Other short-term liabilities - - - 1 071.0 1 071.0Total financial liabilities - - 33.3 7 160.2 7 193.41) Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.Financial Financial Financial Financial assets at fair assets liabilities at fair liabilities value through measured at value through measured at profit and lossamortised costprofit and lossamortised costTotal31.12.2022AssetsTrade receivables - 950.9 - - 950.91)Other short-term receivables- 562.3 - - 562.3Cash and cash equivalents - 2 756.0 - - 2 756.0Long-term receivables 11.0 158.6 - - 169.5Derivatives 156.0 - - - 156.0Total financial assets 167.0 4 427.8 - - 4 594.7LiabilitiesDerivatives - - 51.9 - 51.9Trade creditors - - - 133.9 133.9Bonds - - - 5 279.2 5 279.2Other short-term liabilities - - - 807.1 807.1Total financial liabilities - - 51.9 6 220.2 6 272.11) Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.Financial risk The company has financed its activities with bonds (see note 21) and has an undrawn revolving credit facility with a syndication of banks (see note 19). In addition, the company has financial instruments such as trade receivable, trade creditors, cash balances etc., directly related to its day-to-day operations. For hedging purposes, the company has different types of economic hedging instruments, but no hedge accounting is applied. Commodity derivatives are used to hedge the risk for lower oil prices. Foreign currency exchange derivatives are used to reduce currency risk related to cash flows. For the year 2023 all outstanding debt hold fixed rate coupons. The group currently has limited exposure towards fluctuations in interest rates, but generally manages such exposure by using interest rate derivatives.The most important financial risks which the company is exposed to relate to lower oil and gas prices, change in foreign exchange rates and access to cost efficient funding.The company's risk management, including financial risk management, is designed to ensure identification, analysis and systematic and cost-efficient handling of risk. Established management procedures provide a sound basis for reporting and monitoring of the company's financial risk exposure. (i) Commodity price riskAker BP's revenues are derived from the sale of petroleum products, and the revenue flow is therefore exposed to oil and gas price fluctuations. The company is continuously evaluating and assessing opportunities for hedging as part of a prudent financial risk management process. The company had no material commodity derivatives exposure per 31 December 2023.(ii) Currency riskRevenues from sale of petroleum products are mainly in USD, EUR and GBP, while expenditures are mainly in NOK, USD, EUR and GBP. Sales and expenses in the same currency contribute to mitigating some of the currency risk. Currency derivatives may be used to further reduce this risk.The table below shows the company's exposure in NOK as of 31 December:Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 229.3 260.0 Trade creditors, tax payable, leasing liability and other short-term liabilities -4 515.7 -5 397.3 Net exposure to NOK -4 286.4 -5 137.3The amounts above does not include tax balances in NOK, as they are not deemed to be financial instruments. The company's management of currency risk takes into account the USD values of non-USD assets, liabilities, opex and investments over time, including those exposures arising from the requirement to perform the tax calculation in NOK while the company's functional currency is USD.The table below shows the impact on profit/loss from changes in NOK/USD exchange rate, including the impact from currency derivatives. For further information about currency derivatives, see note 23.(USD million) Change in exchange rate 31.12.2023 31.12.2022Effect on pre-tax profit/loss: + 10% -5.6 56.2- 10% 30.8 -68.7In 2023 the company had EUR/USD exposure related to bond, cash and cash equivalents and receivables from gassales. As the Senior Notes bond is EUR denominated, there is currency risk associated with the translation to the company\u2019s USD functional currency and the cash payments of interest and principle amounts, though EUR denominated gas sales and EUR Time Deposit mitigate the risks associated with payments.Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 750.8 1 407.5Bond, trade creditors and other short-term liabilities -936.7 -861.1Net exposure to EUR -185.9 546.5The table below shows the impact on profit/loss from changes in EUR/USD exchange rate for the EUR bond, cash and cash equivalents and receivables. (USD million)Change in exchange rate 31.12.2023 31.12.2022Effect on pre-tax profit/loss: + 10% 16.9 -49.7- 10% -20.7 60.7In 2023 the company had GBP/USD exposure related cash and cash equivalents and receivables from gas sales.The table below shows the company's exposure in GBP as of 31 December:Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 75.1 402.1Trade creditors and other short-term liabilities -52.2 -22.5Net exposure to GBP 22.9 379.6The table below shows the impact on profit/loss from changes in GBP/USD exchange rate for cash and cash equivalents and receivables.(USD million) Change in exchange rate Effect on pre-tax profit/loss: + 10% -2.1 -34.5- 10% 2.6 42.2The company is also exposed to changes in other exchange rates, but the amounts are deemed immaterial. (iii) Interest-rate riskIn 2023, the company had no outstanding debt liabilities exposed to floating interest rate risk, which is unchanged from 2022. The company is relatively limited exposed to interest-rate risk related to cash and cash equivalents. The terms of the company's debt instruments are described in notes 19 and 21. For all the relevant material financial agreements, Aker BP has in place new benchmark rates or a fallback clause to cater for the discontinuation of IBOR rates. The IBOR reform did not have any current impact on Aker BP and is not expected to significantly affect future periods. All our bonds are at fixed interest rate, and the RCF is linked to Term SOFR, as described in note 19.(iv) Liquidity risk/liquidity managementThe company's liquidity risk is the risk that it will not be able to meet its financial obligations as they fall due.Short-term (12 months) and long-term (five years) forecasts are prepared on a regular basis to plan the company's liquidity requirements. These plans are updated regularly for various scenarios and form part of the decision basis for the company's management and Board of Directors.Excess liquidity is defined as the sum of bank account balances, short-term bank deposits and unused credit facilities. For excess liquidity, the requirement for low liquidity risk (i.e. the risk of realisation on short notice) is generally more important than maximising the return.The company deems its maximum risk exposure to correspond with the book value of cash and cash equivalents, accounts receivable and other short-term receivables, see notes 15, 16 and 19. The company's objective for the placement and management of excess capital is to maintain a low risk profile and good liquidity.The company's liquid assets as of 31 December 2023 are deposited in bank accounts and on short term time deposits with banks. As of 31 December 2023, the group had cash reserves of USD 3 388 million (2022: USD 2 756 million). Revenues and expenses are managed on a day-to-day basis for liquidity risk management purposes.The table below shows the payment structure for the company's financial commitments, based on undiscounted contractual payments. For corresponding information on lease debt and capital commitments and other contractual obligations, reference is made to note 25 and 26.Contract related cash flowLess than 1 31.12.2023 Book value yearNon-derivative financial liabilities:Bonds5 798.2 216.1 311.2 1 928.2 5 136.5 7 592.0Trade creditors and other liabilities1 362.0 1 362.0 - - - 1 362.0Derivative financial liabilitiesDerivatives33.3 32.8 0.5 - - 33.3Total as of 31.12.20237 193.4 1 610.9 311.7 1 928.2 5 136.5 8 987.3Contract related cash flowLess than 1 31.12.2022 Book value yearNon-derivative financial liabilities:Bonds5 279.2 157.0 157.0 2 391.9 3 890.9 6 596.9Trade creditors and other liabilities941.0 941.0 - - - 941.0Derivative financial liabilitiesDerivatives51.9 34.9 17.0 - - 51.9Total as of 31.12.20226 272.1 1 132.9 174.0 2 391.9 3 890.9 7 589.8(v) Credit risk The risk of counterparties being financially incapable of fulfilling their obligations is regarded as minor as there have nothistorically been any losses on trade receivable. The company's customers and licence partners are generally large and credit worthy oil companies, and it has thus not been necessary to make any provision for credit losses.In the management of the company's liquid assets, low credit risk is prioritised. Liquid assets are generally placed in bank deposits that represent a low credit risk. All investments are subject to internal policy that requires a rating equivalent to A-2 from S&P and limits investment with a single counterparty.The maximum credit risk exposure corresponds to the book value of financial assets. The company deems its maximum risk exposure to correspond with the book value of cash and cash equivalents, accounts receivable and other short-term receivables, see notes 15, 16 and 19. Determination of fair value The fair value of forward exchange contracts is determined using the forward exchange rate at the end of the reporting period. The fair value of commodity derivatives is determined using the forward Brent blend curve at the end of the reporting period. The fair value of interest rate swaps and cross currency interest rate swaps is determined by using the expected floating interest rates at the end of the period and is confirmed by external market sources. See note 23 for detailed information about the derivatives.The following of the company's financial instruments have not been valued at fair value: trade debtors, other short-term receivables, long-term receivables, and other short-term liabilities and bonds. The carrying amount of cash and cash equivalents is approximately equal to fair value, since these instruments have a short term to maturity. Similarly, the carrying amount of trade receivable, other receivables, trade creditors and other short-term liabilities is materially the same as their fair value as they are entered into on ordinary terms and conditions.The Senior Notes are all listed on The Luxembourg Stock Exchange. The fair values for disclosure purposes are determined using the quoted value as of 31 December 2023.The following is a comparison between the book value and fair value of the company's financial instruments, except those where the carrying amount is a reasonable approximation of fair value (such as short-term trade receivables and payables in addition to instruments measured to fair value).31.12.202331.12.2022Fair value of financial instruments (USD million)Book value Fair value Book value Fair valueFinancial liabilities measured at amortised cost: Bonds 5 798.2 5 629.4 5 279.2 4 829.7Total financial liabilities 5 798.2 5 629.4 5 279.2 4 829.7Fair value hierarchyThe company classifies fair value measurements by employing a value hierarchy that reflects the significance of the input used in preparing the measurements. The fair value hierarchy consists of the following levels:Level 1 - input in the form of listed (unadjusted) prices in active markets for identical assets or liabilities.Level 2 - input other than listed prices of assets and liabilities included in Level 1 that is observable for assets or liabilities,either directly (i.e. as prices) or indirectly (i.e. derived from prices).Level 3 - input for assets or liabilities for which there is no observable market data (non-observable input). 31.12.2023Financial instruments recognised at fair value (USD million) Level 1 Level 2 Level 3Financial assets or liabilities measured at fair value with changes in value recognised through profit or loss:1)Long-term receivables- - 7.02)Derivatives- 157.7 -4.831.12.2022Financial instruments recognised at fair value (USD million) Level 1 Level 2 Level 3Financial assets or liabilities measured at fair value with changes in value recognised through profit or loss:1)Long-term receivables- - 11.02)Derivatives- 120.1 -16.01) The sale of 2.6 percent of Johan Sverdrup during 2019 (made by Lundin) included a contingent consideration based on future reserve reclassifications and is due in 2026, The valuation is considered level 3 in the fair value hierarchy.2) The level 3 figure relates to the put option granted to the buyer of the shares in Cognite AS, as described in note 18.The valuation is considered level 3 in the fair value hierarchy due to the significance of unobservable market data in the valuation.In the course of the reporting period, there were no changes in the fair value measurements that involved any transfers between levels. Reconciliation of cash flows from financing activitiesThe table below shows a reconciliation between the opening and the closing balances in the statement of financial position for liabilities arising from financing activities.Non-cash changesAmortisation and interest 1)31.12.2022 Cash flows Currency Otherexpense31.12.2023Bonds 5 279.2 486.1 45.0 28.8 -40.9 5 798.2Other interest-bearing debt (RCF) - -8.3 - - 8.3 -Accrued interest, classified under other current liabilities 98.1 -251.8 239.5 - - 85.8Lease debt 134.4 -133.5 - -1.2 704.5 704.2Paid dividends - -1 390.4 - - - -Treasury shares -7.1 -10.5 - - - -17.6Totals5 504.6 -1 308.5 284.5 27.6 671.9 6 570.5Non-cash changesAmortisation and interest 2)3)31.12.2021 Cash flows Currency Otherexpense31.12.2022Bonds 3 576.7 - 25.9 -49.4 1 726.0 5 279.2Other interest-bearing debt (RCF) - -601.1 - - 601.1 -Accrued interest, classified under other current liabilities 77.3 -156.5 177.3 - - 98.1Lease debt 136.2 -66.6 - -3.8 68.5 134.4Paid dividends - -1 005.7 - - -Treasury shares -8.6 1.5 - - - -7.1Totals3 781.6 -1 828.3 203.1 -53.2 2 395.5 5 504.61) Other includes gain related to repurchase of bonds, as described in note 21 and new lease debt, as described in note 252) Other includes transfer of bonds and other interest bearing debt to Aker BP in connection with the Lundin transaction3) Amortisation of Bonds in Parent was USD 14.7 millionNote 29 Investments in joint operationsFields operated: 31.12.2023 31.12.2022 Fields operated: 31.12.2023 31.12.2022Alvheim80.000 %80.000 % Tambar55.000 %55.000 %B\u00f8yla80.000 %80.000 %Tambar \u00d8st46.200 %46.200 %Edvard Grieg65.000 %65.000 % Ula80.000 %80.000 %Hod90.000 %90.000 % Valhall90.000 %90.000 %Ivar Aasen Unit36.171 %36.171 % Vilje46.904 %46.904 %Skogul65.000 %65.000 % Volund100.000 %100.000 %Skarv23.835 %23.835 % Volve50.000 %50.000 %Solveig65.000 %65.000 %\u00c6rfugl Nord30.000 %30.000 %Production licences in which Aker BP is the operator:Licence: 31.12.2023 31.12.2022 Licence: 31.12.2023 31.12.2022PL 001B35.000 %35.000 % PL 16750.000 %50.000 %PL 006B90.000 %90.000 % PL 167B50.000 %50.000 %PL 01980.000 %80.000 % PL 167C50.000 %50.000 %PL 019E80.000 %80.000 % PL 20380.000 %80.000 %PL 019F55.000 %55.000 % PL 21230.000 %30.000 %PL 02687.700 %87.700 % PL 212B30.000 %30.000 %PL 026B87.700 %87.700 % PL 212E30.000 %30.000 %PL 028B35.000 %35.000 % PL 24235.000 %35.000 %PL 03390.000 %90.000 % PL 26170.000 %70.000 %PL 033B90.000 %90.000 % PL 261C23.835 %23.835 %PL 03550.000 %50.000 % PL 26230.000 %30.000 %PL 035C50.000 %50.000 % PL 27250.000 %50.000 %PL 035D50.000 %0.000 % PL 272B50.000 %50.000 %PL 036C80.000 %80.000 % PL 272C50.000 %50.000 %PL 036D46.904 %46.904 % PL 272D50.000 %0.000 %PL 036E64.000 %64.000 % PL 30055.000 %55.000 %PL 036F64.000 %64.000 % PL 33377.800 %77.800 %PL 036G80.000 %0.000 % PL 33865.000 %65.000 %PL 06555.000 %55.000 % PL 338BS50.000 %50.000 %PL 065B55.000 %55.000 % PL 338C80.000 %80.000 %PL 088BS80.000 %80.000 % PL 338DS65.000 %65.000 %PL 102D50.000 %50.000 % PL 338E80.000 %80.000 %PL 102F60.000 %60.000 % PL 34080.000 %80.000 %PL 102G60.000 %60.000 % PL 340BS80.000 %80.000 %PL 102H50.000 %50.000 % PL 35965.000 %65.000 %PL 127C68.083 %68.083 % PL 36487.700 %87.700 %PL 127DS88.083 %88.083 % PL 44287.700 %87.700 %PL 14677.800 %77.800 % PL 442B87.700 %87.700 %PL 146B77.800 %77.800 % PL 442C87.700 %87.700 %PL 150100.000 %100.000 % PL 457BS40.000 %40.000 %PL 159D23.835 %23.835 % PL 46065.000 %65.000 %PL 159H23.835 %0.000 % PL 492100.000 %100.000 %Production licences in which Aker BP is the operator:Licence: 31.12.2023 31.12.2022 Licence: 31.12.2023 31.12.2022PL 50137.384 %37.384 % PL 10570.000 %60.000 %PL 501B37.384 %37.384 % PL 106650.000 %50.000 %PL 60955.000 %55.000 % PL 1066B50.000 %0.000 %PL 609B55.000 %55.000 %PL 10820.000 %50.000 %PL 609D55.000 %55.000 %PL 108340.000 %40.000 %PL 782SB60.000 %0.000 % PL 108460.000 %60.000 %PL 782SC60.000 %0.000 % PL 108555.000 %55.000 %PL 78440.000 %40.000 % PL 108877.800 %77.800 %PL 81560.000 %60.000 % PL 108950.000 %50.000 %PL 8180.000 %40.000 % PL 109140.000 %40.000 %PL 818B0.000 %40.000 % PL 109250.000 %50.000 %PL 822S87.700 %87.700 % PL 10940.000 %60.000 %PL 8300.000 %40.000 % PL 10950.000 %50.000 %PL 83835.000 %35.000 % PL 109770.000 %70.000 %PL 86780.000 %80.000 % PL 10990.000 %40.000 %PL 867B80.000 %80.000 % PL 110255.000 %55.000 %PL 86980.000 %80.000 % PL 111055.000 %40.000 %PL 87347.700 %47.700 % PL 11240.000 %23.835 %PL 87487.700 %87.700 % PL 113335.000 %35.000 %PL 88660.000 %60.000 % PL 113435.000 %35.000 %PL 886B60.000 %60.000 % PL 113940.000 %40.000 %PL 9060.000 %50.000 % PL 114170.000 %70.000 %PL 91980.000 %80.000 % PL 1141B70.000 %0.000 %PL 93240.000 %60.000 % PL 114282.060 %82.060 %PL 94170.000 %70.000 % PL 114382.060 %82.060 %PL 941B70.000 %70.000 % PL 114440.000 %40.000 %PL 94230.000 %30.000 % PL 115340.000 %40.000 %PL 97670.000 %40.000 % PL 11570.000 %60.000 %PL 97960.000 %60.000 % PL 115840.000 %40.000 %PL 100540.000 %40.000 % PL 116250.000 %50.000 %PL 100880.000 %90.000 % PL 116440.000 %40.000 %PL 103240.000 %40.000 % PL 117035.000 %35.000 %PL 104180.000 %70.000 % PL 117150.000 %0.000 %PL 104240.000 %40.000 % PL 117240.000 %0.000 %PL 104580.000 %80.000 % PL 117550.000 %0.000 %PL 1045B80.000 %80.000 % PL 117660.000 %0.000 %PL 10480.000 %50.000 %PL 119380.000 %0.000 %PL 10510.000 %60.000 %Number of licences in which Aker BP is the operator 126 126 Fields non-operated: 31.12.2023 31.12.2022Atla10.000 %10.000 %Enoch2.000 %2.000 %Johan Sverdrup31.573 %31.573 %Oda15.000 %15.000 %Production licences in which Aker BP is a partner:Licence: 31.12.2023 31.12.2022 Licence: 31.12.2023 31.12.2022PL 006C35.000 %35.000 % PL 95620.000 %20.000 %PL 048D10.000 %10.000 % PL 9680.000 %30.000 %PL 102C10.000 %10.000 % PL 98410.000 %0.000 %PL 12750.000 %50.000 % PL 98530.000 %30.000 %PL 211CS15.000 %15.000 % PL 9890.000 %30.000 %PL 22015.000 %15.000 % PL 104030.000 %30.000 %PL 229E50.000 %50.000 % PL 10640.000 %20.000 %PL 229G50.000 %50.000 % PL 108750.000 %50.000 %PL 26527.384 %27.384 % PL 109030.000 %30.000 %PL 40515.000 %15.000 % PL 110440.000 %40.000 %PL 50222.222 %22.222 % PL 110620.000 %20.000 %PL 53735.000 %35.000 % PL 1122 0.000 %20.000 %PL 537B35.000 %35.000 % PL 112330.000 %30.000 %PL 55430.000 %30.000 % PL 112630.000 %30.000 %PL 554B30.000 %30.000 % PL 112930.000 %30.000 %PL 554C30.000 %30.000 % PL 113120.000 %20.000 %PL 554D30.000 %30.000 % PL 113830.000 %30.000 %PL 554E30.000 %0.000 % PL 114040.000 %40.000 %PL 782S20.000 %20.000 % PL 114540.000 %40.000 %PL 782SB0.000 %20.000 % PL 114720.000 %20.000 %PL 782SC0.000 %20.000 % PL 1148B10.000 %0.000 %PL 782SD0.000 %20.000 % PL 114930.000 %30.000 %PL 820S26.000 %26.000 % PL 1149B30.000 %0.000 %PL 820SB26.000 %26.000 % PL 115120.000 %20.000 %PL 838B30.000 %30.000 % PL 115250.000 %50.000 %PL 89410.000 %10.000 % PL 115430.000 %30.000 %PL 8960.000 %30.000 % PL 116320.000 %20.000 %PL 91740.000 %40.000 % PL 116540.000 %40.000 %PL 917B0.000 %40.000 % PL 1182S30.000 %0.000 %PL 92910.000 %10.000 % PL 118520.000 %0.000 %PL 93520.000 %20.000 % PL 119130.000 %0.000 %PL 9430.000 %20.000 %Number of licences in which Aker BP is a partner 53 56 Note 30 Business combinationThe acquisition of the Lundin Energy's oil and gas business was completed on 30 June 2022, Due to the significance of the transaction, the related business combination note is also included in these 2023 Financial Stataments, and this note is similar to the note provided in the 2022 Financial Statements. The transaction was announced on 21 December 2021, and Aker BP issued 271.91 million new shares to the owners of Lundin Energy as compensation. In addition, the group paid a cash consideration of USD 2.22 billion. The purpose of the transaction is to create the E&P company of the future which will offer low CO2 emmisions, low cost and an attractive growth pipeline in the industry. The acquisition included three Dutch and one Swiss legal entity, in addition to Lundin Energy Norway AS (renamed to ABP Norway AS at completion of the transaction). All oil and gas assets included in the transaction are located on the Norwegian Continental Shelf. The acquisition date for accounting purposes corresponds to the finalisation of the transaction on 30 June 2022. The acquisition is regarded as a business combination and has been accounted for using the acquisition method of accounting in accordance with IFRS 3. A purchase price allocation (PPA) has been performed to allocate the consideration to fair value of assets and liabilities in Lundin Energy. The PPA is performed as of the acquisition date, 30 June 2022. The 30 June closing share price at Oslo Stock Exchange (NOK 342.1) and the closing currency exchange rate (USD/NOK 9.9629) were used as a basis for measuring the value of the shares consideration, as set forth below. The value of the cash consideration is adjusted for certain settlement arrangements and currency impacts as the cash was transferred in Swedish Kronor. (USD million) 30.06.2022Value of cash consideration 2 221.8 Value of share consideration 9 336.6Total value of consideration 11 558.4 Estimated transaction cost incurred in Aker BP is approximately USD 8 million, and is included in the income statement as other operating expenses.Each identifiable asset and liability is measured at its acquisition date fair value based on guidance in IFRS 13. The standard defines fair value as 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. This definition emphasises that fair value is a market-based measurement, not an entity-specific measurement. When measuring fair value, the group uses the assumptions that market participants would use when pricing the asset or liability under current market conditions, including assumptions about risk. Acquired property, plant and equipment have been valued using the cost approach (replacement cost), while intangible assets (value of licences) have been valued using the income approach. Accounts receivable are recognised at gross contractual amounts due, as they relate to large and credit-worthy customers. Historically, there has been no significant uncollectible accounts receivable in Lundin Energy.Purchase price allocation(USD million) 30.06.2022Goodwill 12 542.91)Other intangible assets1 282.2Property, plant and equipment 7 663.3Right-of-use assets 34.8Long-term receivables 12.5Other non-current assets 0.2Inventories 40.2Trade receivables 389.8Other short-term receivables 217.5Intercompany 57.0Cash and cash equivalents 937.6Total assets 23 178.0(USD million) 30.06.2022Deferred taxes 5 802.6Long-term abandonment provision 724.3Long-term bonds 1 726.0Long-term derivatives 4.3Long-term lease debt 20.3Other interest-bearing debt 600.0Trade creditors 17.9Accrued public charges and indirect taxes 33.1Tax payable 2 181.0Short-term derivatives 199.4Short-term abandonment provision 21.6Short-term lease debt 14.5Other current liabilities 274.7Total liabilities 11 619.5Net assets and liabilities recognised 11 558.4Fair value of consideration paid on acquisition 11 558.41) Mainly related to undeveloped oil and gas assetsThe goodwill of USD 12.5 billion arises principally because of the following factors:1. The ability to capture synergies that can be realised from managing a larger portfolio of both acquired and existing fields on the Norwegian Continental Shelf, including workforce (\"residual goodwill\").2. The requirement to recognise deferred tax assets and liabilities for the difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. Licences under development and licences in production can only be sold in a market after tax, based on a decision made by the Norwegian Ministry of Finance pursuant to the Petroleum Taxation Act Section 10. The assessment of fair value of such licences is therefore based on cash flows after tax. Nevertheless, in accordance with IAS 12 Sections 15 and 19, a provision is made for deferred tax corresponding to the tax rate multiplied by the difference between the acquisition cost and the tax base. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax (\"technical goodwill\"). None of the goodwill recognised will be deductable for tax purposes.Reconciliation of goodwill from the acquisition of Lundin Energy (USD 1 000) 30.06.2022Goodwill related to synergies - residual goodwill 6 291.7Goodwill as a result of deferred tax - technical goodwill 6 251.2Net goodwill from the acquisition of Lundin Energy 12 542.9If the acquisition had taken place at the beginning of 2022, revenue would have increased by USD 3.7 billion and net income would have increased by USD 422 million. Parent company - accounting effect of mergers:As of 13 October 2022, the wholly owned subsidiary ABP Energy Holding BV was merged with the parent company Aker BP ASA. The merger was carried out in accordance with the Public Limited Liability Companies Act section 13-25, and the merger was carried out based on group continuity for accounting purposes. Upon completion of the merger, all assets, rights and obligations of ABP Energy Holding BV was transferred to Aker BP ASA without any consideration being rendered. At the same time, ABP Energy Holding BV was liquidated. The merger is considered a transaction for tax purposes. As of 31 December 2022, the wholly owned subsidiary ABP Norway AS was merged with the parent company Aker BP ASA. The merger was carried out in accordance with the Public Limited Liability Companies Act section 13-24, and the merger was carried out based on group continuity for accounting purposes. Upon completion of the merger, all assets, rights and obligations of ABP Norway AS was transferred to Aker BP ASA without any consideration being rendered. At the same time, ABP Norway AS was liquidated. The merger is based on company continuity from 1 January 2022 for tax purposes.Note 31 Events after the balance sheet dateOn 18 January 2024, the Oslo District Court ruled that the Ministry of Energy's approvals for the plans for development and operation (PDO) for the Breidablikk, Tyrving, and Yggdrasil fields were invalid due to procedural errors. The court concluded that the state had failed to consider the effects of combustion emissions as part of the final PDO. In addition, the court issued a temporary injunction, preventing the state from making decisions that assume valid PDO approval for the projects. Currently, the ruling is non-binding in relation to the procedural errors. The state has filed an appeal against both the main ruling and the temporary injunction to the Borgarting Court of Appeal. Aker BP, which has participating interests and operates the Yggdrasil and Tyrving development projects, is not a party to the court case. The PDO approvals granted for Yggdrasil and Tyrving remain valid in relation to Aker BP. Aker BP continues executing the Yggdrasil and Tyrving projects in accordance with the permissions granted. In response to the current situation, a dedicated task force has been established to identify potential risks and coordinate the company\u2019s activities and risk-mitigating actions. The court case is deemed to have no material impact on the 2023 financial statements.Note 32 Classification of reserves and contingent resources (unaudited) Classification of reserves and contingent resourcesAker BP ASA's reserve and contingent resource volumes have been classified in accordance with the Society of Petroleum Engineer\u2019s (SPE\u2019s) \u201cPetroleum Resources Management System\u201d. This classification system is consistent with Oslo B\u00f8rs requirements for the disclosure of hydrocarbon reserves and contingent resources. The framework of the classification system is illustrated in Figure 1.PPrroojjeeccttMMaattuurriittyyPRODUCTIONssuubb--ccllaasssseessOn ProductionApproved forRESERVESDevelopmentJustified for DevelopmentDevelopment PendingCONTINGENTDevelopment Unclarified or On HoldRESOURCESDevelopment Not ViableUNRECOVERABLEProspectPROSPECTIVELeadRESOURCESPlayUNRECOVERABLENot to scaleRange of uncertaintyReserves, developed and non-developedAll reserve estimates are based on all available data including seismic, well logs, core data, drill stem tests and production history. Industry standards are used to establish 1P and 2P. This includes decline analysis for mature fields in which reliable trends are established. For undeveloped fields and less mature producing fields reservoir simulation models or simulations models in combination with decline analysis have been used for profiles generation. Note that an independent third party, AGR Petroleum Services AS, has certified 1P and 2P reserves for all Aker BP assets except for the minor assets Atla and Enoch, representing 0.0003 percent of total 2P reserves.Aker BP ASA has a working interest in 54 fields/projects containing reserves, see Table 1 and 2. Out of these fields/projects, 26 are in the sub-class \u201cOn Production\u201d/Developed, 26 are in the sub-class \u201cApproved for Development\u201d/Undeveloped and 2 are in the sub-class \u201cJustified for Development\u201d/Undeveloped. Note that several fields have reserves in more than one reserve sub-class. Table 1 - Aker BP fields - Developed reserves Field/projectInvestment shareOperatorResource classAlvheim Base80.0 % Aker BP On ProductionBoa Base70.9 % Aker BP On ProductionB\u00f8yla Base80.0 % Aker BP On ProductionFrosk80.0 % Aker BP On ProductionKobra East/Gekko80.0 % Aker BP On ProductionSkogul Base65.0 % Aker BP On ProductionVilje Base46.9 % Aker BP On ProductionVolund Base100.0 % Aker BP On ProductionEdvard Grieg Base65.0 % Aker BP On ProductionSolveig Ph165.0 % Aker BP On ProductionTroldhaugen EWT extension80.0 % Aker BP On ProductionIvar Aasen Base36.2 % Aker BP On ProductionPL212E \u00c6rfugl Nord Base30.0 % Aker BP On ProductionSkarv Base23.8 % Aker BP On ProductionSkarv Gr\u00e5sel23.8 % Aker BP On ProductionSkarv Idun Tunge23.8 % Aker BP On ProductionSkarv \u00c6rfugl23.8 % Aker BP On ProductionTambar Base55.0 % Aker BP On ProductionTambar East Base46.2 % Aker BP On ProductionUla Base80.0 % Aker BP On ProductionHod Base90.0 % Aker BP On ProductionValhall Base90.0 % Aker BP On ProductionJohan Sverdrup Base31.6 % Equinor On ProductionOda Base15.0 % Sval Energi AS On ProductionAtla10.0 % TotalEnergies On ProductionEnoch2.0 % Repsol Sinopec On ProductionTable 2 - Aker BP fields - Undeveloped reservesField/projectInvestment shareOperatorResource classAlvheim East KAM L580.0 % Aker BPApproved for DevelopmentKameleon Gas Cap Blow Down80.0 % Aker BPApproved for DevelopmentTyrving61.3 % Aker BPApproved for DevelopmentSolveig Ph265.0 % Aker BPApproved for DevelopmentSymra50.0 % Aker BPApproved for DevelopmentHanz35.0 % Aker BPApproved for DevelopmentSkarv \u00c6rfugl Infill A0223.8 % Aker BPApproved for DevelopmentPL127C Alve Nord Development 68.1 % Aker BPApproved for DevelopmentPL159D Idun Nord Development 23.8 % Aker BPApproved for DevelopmentPL942 \u00d8rn Development30.0 % Aker BPApproved for DevelopmentTambar East K5 Sidetrack46.2 % Aker BPApproved for DevelopmentUla WAG from K-5B80.0 % Aker BPApproved for DevelopmentFenris77.8 % Aker BPApproved for DevelopmentValhall IP Workover90.0 % Aker BPApproved for DevelopmentValhall PWP90.0 % Aker BPApproved for DevelopmentFrigg Gamma Delta Development87.7 % Aker BPApproved for DevelopmentFr\u00f8y Development87.7 % Aker BPApproved for DevelopmentFulla Development47.7 % Aker BPApproved for DevelopmentKrafla/Askja Development50.0 % Aker BPApproved for DevelopmentLangfjellet Development87.7 % Aker BPApproved for DevelopmentLille Frigg Development47.7 % Aker BPApproved for DevelopmentRind Development87.7 % Aker BPApproved for DevelopmentJohan Sverdrup IOR D-21 (G-P6)31.6 % EquinorApproved for DevelopmentJohan Sverdrup IOR D-7 WO & D-2T4S31.6 % EquinorApproved for DevelopmentJohan Sverdrup WAG31.6 % EquinorApproved for DevelopmentVerdande Development7.0 % EquinorApproved for DevelopmentKobra East/Gekko Gas blowdown80.0 % Aker BP Justified for DevelopmentSkarv Tilje Infill A0523.8 % Aker BP Justified for DevelopmentTotal net proven reserves (1P/P90) as of 31 December 2023 to Aker BP ASA are estimated at 1 127 million barrels of oil equivalents. Total net proven plus probable reserves (2P/P50) are estimated at 1 716 million barrels of oil equivalents. The split between liquid and gas and between the different subcategories are given in tables 3 and 4.Table 3 - Reserves by field, area and reserve class1P / P90 (low estimate)2P / P50 (best estimate)Gross oil Gross NGL Gross gas Gross oil equiv. Net oil equiv. Gross oil/cond. Gross NGL Gross gas Gross oil equiv. Net oil equiv.31.12.2023 (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe)Alvheim 41 - 14 55 43 53 - 30 84 66B\u00f8yla1 - 0 1 1 2 - 0 3 2Frosk 4 - 0 4 3 8 - 0 8 6Skogul 1 - 0 1 1 5 - 0 5 3Vilje 4 - - 4 2 7 - - 7 3Volund 2 - 0 2 2 4 - 0 4 4Kobra East/Gekko 17 - 25 42 34 19 - 30 49 39Tyrving 15 - 0 15 9 24 - 0 24 15Alvheim Area 86 - 38 125 95 122 - 61 183 138Ivar Aasen 32 2 6 40 14 39 3 9 51 18Edvard Grieg 49 3 6 58 38 92 6 11 108 70Solveig 42 7 10 58 38 71 10 14 96 62Troldhaugen EWT - - - - - 0 0 0 0 0Symra 19 2 4 25 13 34 3 6 43 22Hanz 9 1 2 12 4 16 1 3 20 7Edvard Grieg Area 151 15 28 193 107 252 23 43 318 180Skarv (incl Gr\u00e5sel and Idun Tunge)7 11 59 78 18 10 13 69 92 22\u00c6rfugl (Incl. \u00c6rfugl Nord)10 13 68 90 22 13 17 89 119 29Alve Nord 2 2 7 11 7 9 6 19 33 23Idun Nord 0 0 6 6 2 0 1 8 9 2\u00d8rn1 1 21 24 7 2 3 48 54 16Skarv Area 20 28 160 209 56 34 40 234 307 92Tambar 0 0 0 1 0 1 0 0 2 1Tambar East 2 0 0 3 1 4 0 1 5 2Ula 3 0 - 3 3 5 0 - 5 4Ula Area 6 0 0 7 4 10 1 1 12 7Hod 24 1 4 30 27 30 2 5 37 33Fenris 28 4 42 73 57 62 7 84 154 120Valhall 151 11 28 189 170 194 14 36 244 220Valhall Area 203 16 73 292 254 286 23 125 434 372Johan Sverdrup 1 224 14 29 1 268 400 1 720 26 50 1 797 567Hugin 108 6 22 136 119 174 12 37 223 196Fulla 4 6 30 40 19 8 11 54 72 34Munin 65 21 55 141 70 105 40 108 253 126Yggdrasil 177 33 107 317 209 286 63 198 547 356Oda 1 0 0 1 0 2 0 0 2 0Verdande Development 20 0 2 23 2 28 1 5 34 2Atla - - - - - - - - - -Enoch - - - - - 0 - - 0 0Other (Atla, Enoch, Verdande and Oda) 21 0 2 24 2 31 1 5 37 3Total 1 888 106 439 2 433 1 127 2 742 176 718 3 636 1 716Table 4 - Reserves by project and reserve classInterest1P / P90 (low estimate)2P / P50 (best estimate)On production Gross oil/cond. Gross NGL Gross gas Gross oil equiv. Net oil equiv. Gross oil Gross NGL Gross gas Gross oil equiv. Net oil equiv.31.12.2023 % (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe)Alvheim Base80.0 %30 - 6 37 29 38 - 10 48 38Boa Base70.9 %7 - 1 8 6 10 - 1 11 8B\u00f8yla Base80.0 %1 - 0 1 1 2 - 0 3 2Frosk80.0 %4 - 0 4 3 8 - 0 8 6Kobra East/Gekko80.0 %14 - 7 20 16 18 - 6 24 19Skogul Base65.0 %1 - 0 1 1 5 - 0 5 3Vilje Base46.9 %4 - - 4 2 7 - - 7 3Volund Base100.0 %2 - -0 2 2 4 - 0 4 4Edvard Grieg Base65.0 %49 3 6 58 38 92 6 11 108 70Solveig Ph165.0 %23 4 6 34 22 42 6 9 57 37Troldhaugen EWT extension80.0 %- - - - - 0 0 0 0 0Ivar Aasen Base36.2 %32 2 6 40 14 39 3 9 51 18PL212E \u00c6rfugl Nord Base30.0 %0 1 4 6 2 1 1 6 8 2Skarv Base23.8 %5 10 52 67 16 5 11 59 76 18Skarv Gr\u00e5sel23.8 %2 1 3 6 1 2 1 4 7 2Skarv Idun Tunge23.8 %0 0 0 0 0 0 0 1 1 0Skarv \u00c6rfugl23.8 %9 11 60 80 19 11 15 76 102 24Tambar Base55.0 %0 0 0 1 0 1 0 0 2 1Tambar East Base46.2 %0 0 0 0 0 0 0 0 0 0Ula Base80.0 %3 0 - 3 3 5 0 - 5 4Hod Base90.0 %24 1 4 30 27 30 2 5 37 33Valhall Base90.0 %110 7 19 136 123 131 9 23 162 146Johan Sverdrup Base31.6 %1 161 19 39 1 219 385 1 626 33 62 1 721 543Oda Base15.0 %1 0 0 1 0 2 0 0 2 0Atla10.0 %- - - - - - - - - -Enoch2.0 %- - - - - 0 - - 0 0Total 1 485 60 214 1 759 710 2 081 86 282 2 448 985Interest1P / P90 (low estimate)2P / P50 (best estimate)Approved for development Gross oil Gross NGL Gross gas Gross oil equiv. Net oil equiv. Gross oil/cond. Gross NGL Gross gas Gross oil equiv. Net oil equiv.31.12.2023 % (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe)Alvheim East KAM L580.0 %3 - 2 5 4 4 - 3 7 6Kameleon Gas Cap Blow Down80.0 %0 - 5 5 4 0 - 16 17 14Tyrving61.3 %15 - -0 15 9 24 - 0 24 15Solveig Ph265.0 %18 2 4 24 16 29 4 6 39 25Symra50.0 %19 2 4 25 13 34 3 6 43 22Hanz35.0 %9 1 2 12 4 16 1 3 20 7Skarv \u00c6rfugl Infill A0223.8 %0 1 3 4 1 1 1 8 10 2PL127C Alve Nord Development 68.1 %2 2 7 11 7 9 6 19 33 23PL159D Idun Nord Development 23.8 %0 0 6 6 2 0 1 8 9 2PL942 \u00d8rn Development30.0 %1 1 21 24 7 2 3 48 54 16Tambar East K5 Sidetrack46.2 %2 0 0 2 1 4 0 1 5 2Ula WAG from K-5B80.0 %0 0 - 0 0 0 0 - 0 0Fenris77.8 %28 4 42 73 57 62 7 84 154 120Valhall IP Workover90.0 %7 0 1 9 8 10 1 2 12 11Valhall PWP90.0 %34 3 8 44 40 53 5 12 70 63Frigg Gamma Delta Development87.7 %46 1 4 51 45 79 1 8 88 77Fr\u00f8y Development87.7 %21 1 3 25 22 30 1 7 38 34Fulla Development47.7 %3 3 23 29 14 5 6 41 52 25Krafla/Askja Development50.0 %65 21 55 141 70 105 40 108 253 126Langfjellet Development87.7 %12 3 3 18 16 25 7 6 39 34Lille Frigg Development47.7 %2 2 6 10 5 3 5 12 19 9Rind Development87.7 %29 2 12 43 37 40 2 16 58 51Johan Sverdrup IOR D-21 (G-P6)31.6 %2 0 0 2 1 4 0 0 4 1Johan Sverdrup IOR D-7 WO & D-2T4ST31.6 %0 0 0 0 0 3 0 0 3 1Johan Sverdrup WAG31.6 %61 -5 -10 46 15 87 -6 -12 68 22Verdande Development7.0 %20 0 2 23 2 28 1 5 34 2Total 399 45 204 648 398 657 89 407 1 153 709Interest1P / P90 (low estimate)2P / P50 (best estimate)Justified for development Gross oil/cond. Gross NGL Gross gas Gross oil equiv. Net oil equiv. Gross oil/cond. Gross NGL Gross gas Gross oil equiv. Net oil equiv.31.12.2023 % (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe)Kobra East/Gekko Gas blowdown80.0 %4 - 18 22 17 1 - 24 25 20Skarv Tilje Infill A0523.8 %1 1 3 5 1 3 1 5 9 2Total 5 1 21 26 19 4 1 29 34 22Total reserves 31.12.2023 1 127 1 716Total reserves 31.12.2022 1 251 1 859Changes from the 2022 reserve report are summarised in Table 5. During 2023, Aker BP 2P reserves were decreased by 143 mmboe from 1 859 to 1 716 mmboe. The production was 166 mmboe, thus net reserves increases were 23 mmboe. The main reasons for increased net reserve estimate (i.e. disregarding the produced volumes) are IOR-activities in Alvheim-, Grieg/Aasen-, Ula- and Skarv-areas. On the negative side, reserves were reduced on Valhall primarily due to well difficulties and thinner reservoirs on flanks, and on Johan Sverdrup due to a reduced field-life expectancy.An oil price of 75 USD/bbl (2024), 70 USD/bbl (2025) and 65 USD/bbl (following years) has been used for reserves estimation. Low- and high case sensitivities with oil prices of 40 USD/bbl and 90 USD/bbl, respectively, have been performed by AGR. The low price resulted in a reduction in total net proven (1P/P90) reserves of ~47 % and net proven plus probable (2P/P50) reserves of ~46 %. The high oil price scenario resulted in a marginal increase in reserves of less than 1% to the proven (1P/P90) estimates and no change to the proven plus probable (2P/P50) estimates. Table 5 - Aggregated reserves, production, developments, and adjustmentsNet attributed million barrels of oil equivalent On productionApproved for devlop.Justified for devlop.Total(mmboe) 1P/P90 2P/P50 1P/P90 2P/P50 1P/P90 2P/P50 1P/P90 2P/P50Balance as of 31.12.2022 816 1 103 71 114 364 642 1 251 1 859Production -166 -166 - - - - -166-166Transfer 21 33 325 589 -347 -622 - -Revisions 36 8 -2 -2 - - 34 6IOR 3 7 3 8 1 2 817Discovery and extensions - - - - - - - -Acquisition and sale - - - - - - - -Balance as of 31.12.2023 710 985 398 709 19 22 1 127 1 716Delta -106 -119 327 595 -346 -620 -124 -143Note also that production numbers are preliminary pr October 2023, leaving numbers for the last two months of 2023 as estimates. The final numbers may be slightly different.CClliimmaattee--rreellaatteeddrriisskk::As described in note 3 on climate-related risk, a sensitivity analysis have been performed to show the impact on reserves as at 31 December 2023, if all production would cease from 2050 onwards. Such acceleration of cease of production would result in an decrease in the reserves of approximately 17 million boe.End of financial statement",
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"value": "oil and gas company involved in exploration, development and production of oil and gas on the Norwegian Continental Shelf (NCS).",
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"value": "Norway",
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"value": "Norway",
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"value": "Oksen\u00f8yveien 10, 1366 Lysaker, Norway",
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"value": "Oksen\u00f8yveien 10, 1366 Lysaker, Norway",
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"value": "In 2023 the Aker BP group comprised the parent company Aker BP ASA and the three subsidiaries Det norske oljeselskap AS (including its subsidiary Aker BP UK Limited), Alvheim AS and Sandvika Fjellstue AS. Except for Aker BP UK Limited, none of the subsidiaries are consolidated in the group financial statements as they are immaterial.The acquisition of the Lundin Energy's oil and gas business (\"Lundin Energy\") was completed on 30 June 2022. The activity of Lundin Energy was fully reflected in the financial statements from 30 June 2022, including effects from the fair value adjustment of Lundin Energy in line with IFRS 3, as described in note 30. At year end 2022 all legal entities acquired in the Lundin transaction were either liquidated or merged into Aker BP ASA. See note 2 for more information about subsidiaries.The financial statements were approved by the Board of Directors on 13 March 2024 and will be presented for approval at the Annual General Meeting on 10 April 2024.",
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"value": "The financial statements were approved by the Board of Directors on 13 March 2024 and will be presented for approval at the Annual General Meeting on 10 April 2024.",
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"value": "NOTE 1 SUMMARY OF IFRS ACCOUNTING POLICIES1.1 Basis of preparationThe group and the parent company financial statements have been prepared in accordance with IFRS\u00ae Accounting Standards as adopted by the EU and the Norwegian Accounting Act.All amounts have been rounded to the nearest million unless otherwise stated. As a result of rounding adjustments, the figures in one or more rows or columns included in the financial statements and notes may not add up to the total of that row or column.The group financial statements for Aker BP ASA include the subsidiaries as described in note 2. The accounting policies are applied consistently when consolidating ownership interests in subsidiaries and are based on the same reporting periods as those used for the parent company. When preparing the consolidated financial statements, intragroup transactions and balances, along with gains and losses on transactions between group units, are eliminated.1.2 Functional currency and presentation currencyThe presentation currency in the Group\u2019s consolidated financial statements is United States Dollars (\u201cUSD\u201d). The parent company of the Group, Aker BP ASA, has USD as its functional currency as most revenue and financing are in USD and represents the primary economic environment in which the entity operates. Balance sheet items of subsidiaries in other functional currencies are translated into the presentation currency, USD, according to the exchange rates prevailing on the balance sheet date, while profit or loss items are translated according to average quarterly exchange rates for the relevant quarters.In all material respects, the activity of Lundin Energy was conducted in the legal entity ABP Norway AS (previously Lundin Energy Norway AS), which had NOK as its functional currency. In line with accounting guidance, the related purchase price allocation (PPA) was fixed in NOK accordingly, and thus gave rise to foreign currency translation in the group accounts recognised in the statement of comprehensive income during the second half of 2022. At 31 December 2022, ABP Norway AS merged with Aker BP ASA, meaning that the mentioned impact on comprehensive impact ceased from 1 January 2023.1.3 Critical judgements and estimatesThe preparation of financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that have an effect on the application of accounting policies and the reported assets, liabilities, income and expenses.The important judgments management has made regarding the application of accounting policies are as follows:Goodwill allocation and methodology for impairment testingFor the purpose of impairment testing, goodwill is allocated to a cash-generating unit (CGU), or groups of CGUs that are expected to benefit from the synergies of the business combination from which it arose. A CGU is typically a producing field or group of producing licences for which a separate offtake facility exist that can generate separate cash flows. The allocation of goodwill requires judgment and may significantly impact any subsequent impairment charge. Although not an IFRS term, \u201ctechnical goodwill\u201d is used by Aker BP to describe the category of goodwill arising as an offsetting account to deferred tax liabilities recognised in business combinations, as described in section 1.8 below. There are no specific IFRS guidelines pertaining to the allocation of technical goodwill, and management has therefore applied the general guidelines for allocating goodwill. In general, technical goodwill is allocated at the CGU level for impairment testing purposes, while residual goodwill may be allocated across all CGUs based on the facts and circumstances of the business combination. When performing the impairment test for technical goodwill, deferred tax liabilities recognised in relation to the acquired licences reduce the net carrying value prior to any impairment charges. This methodology avoids an immediate impairment of all technical goodwill. When deferred tax liabilities from the initial recognition decreases, additional technical goodwill is \u2018exposed\u2019 to impairment. Subsequent to the initial purchase price allocation, depreciation of book values will result in decreasing deferred tax liabilities. When applicable, technical goodwill is impaired before the asset.Proven and probable oil and gas reservesProven and probable reserves and production volumes are used to calculate the depreciation of oil and gas fields by applying the unit-of-production method. Reserve estimates are also used as basis for impairment testing of licence-related assets and goodwill.Oil and gas reserves are estimated by the company\u2019s experts in accordance with industry standards. The estimates are based on Aker BP\u2019s own assessment of internal information and information received from operators. In addition, proven and probable reserves are certified by an external party. Proven and probable oil and gas reserves consist of the estimated quantities of crude oil, natural gas and condensates shown by geological and technical data to be recoverable with reasonable certainty from known reservoirs under existing economic and operational conditions, i.e. on the date that the estimates are prepared. Current market prices are used in the estimates.Changes in petroleum prices and cost estimates may change reserve estimates and accordingly economic cut-off, which may impact the timing of assumed decommissioning and removal activities. Changes to reserve estimates can also result from updated production and reservoir information. Future changes to proven and probable oil and gas reserves can have a material effect on depreciation, life of field, impair-ment of licence-related assets and goodwill, and operating results. Accounting for Exploration costs \u2013 application of the Successful Effort Method Expenses relating to the drilling of exploration wells are temporarily recognised in the Statement of financial position as capitalised exploration expenditures, pending an evaluation of potential oil and gas discoveries. If resources are not discovered, or if recovery of the resources is considered technically or commercially unviable, the costs of exploration wells are expensed. Judgments as to whether this expend-iture should remain capitalised or be expensed at the reporting date may materially affect the operating result for the period.Fair value measurementThe fair values of non-financial assets and liabilities are required to be determined, for example in a business combination, to determine the allocation of purchase price in an asset deal or when the recover-able amount of an asset or CGU is based on fair value less cost to sell. 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 of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability. 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. The fair value of oil fields in production and development phase is normally based on discounted cash flow models, where the determination of inputs to the model may require significant judgment, as described in the section below regarding impairment. Impairment/reversal of impairmentThe evaluation of impairment requires long-term assumptions concerning a number of often volatile economic factors, including future oil and gas prices, oil and gas production, currency exchange rates and discount rates. Such assumptions require the estimation of relevant factors such as long-term prices, the levels of capex and opex, production estimates and decommissioning costs. These evaluations are also necessary to determine a CGU\u2019s fair value unless information can be obtained from an actual observable market transaction. See note 13 \u2019Tangible fixed assets and intangible assets\u2019 and note 14 \u2019Impairments\u2019 for details of impairments.Decommissioning and removal obligationsThe company has obligations to decommission and remove offshore installations at the end of their production period. The estimates include costs based on expected removal concepts using existing technology and estimated costs of maritime operations, hiring of single-lift and heavy-lift barges and drilling rigs. There is significant future uncertainty in the estimate of costs for decommissioning and removal, as these estimates are based on currently applicable laws and regulations, and existing technologies. Many decommissioning and removal activities will take place many decades in the future, and the technology and related costs are expected to evolve in this time. As a result, there may be significant adjustments to the estimates of decommissioning liabilities and associated assets that can affect future financial results.. See note 22 \u2018Provision for abandonment liabilities\u2019 for further details about decommissioning and removal obligations.Income taxIncome tax expense, tax payables or receivables, and deferred taxes are based on management\u2019s interpre-tation of applicable laws and regulations, and on relevant court decisions where relevant. These estimates are dependent on management\u2019s ability to interpret and apply the requirements of tax and other relevant legislation, and requires judgment in respect of the recognition and measurement of any uncertain tax positions. See note 11 \u2018Taxes\u2019 for further details.1.4 Revenue recognition Revenue from the sale of liquids or gas is recognised at the point in time when the company\u2019s contractual performance obligations have been fulfilled and control is transferred to the customer, which will ordinarily be at the point of delivery when title passes (sales method). This is normally at the time of loading oil or NGL on vessels used for transport, or at agreed point of delivery for dry gas.There is no significant judgement applying IFRS 15 \u2018Revenue from contracts with customers\u2019 to the company\u2019s revenue generating contracts.Changes in over/underlift balances are valued at production cost including depreciation and presented as an adjustment to cost. See note 6 for further details. Gains or losses on asset disposals as described in section 1.7 are included in other operating income. Tariff revenue from processing of oil and gas is recognised as earned in line with underlying agreements.1.5 Interests in licences and partnerships The company has interests in licences on the Norwegian Continental Shelf. Under IFRS 11 Joint Arrangements, a joint operation is a 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. The company recognises investments in joint operations (oil and gas production licences) by reporting its share of related revenues, expenses, assets, liabilities and cash flows under the respective items in the company's financial statements. IFRS defines a joint arrangement as an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control 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. For those licences that are not deemed to be joint arrangements pursuant to the definition in IFRS 11 as there is no joint control, the company recognises its share of related expenses, assets, liabilities and cash flows on a line-by-line basis in the financial statements by analogy to IFRS 11 and in accordance with applicable IFRSs. 1.6 Business combinations and goodwill In a business combination, goodwill is allocated to the CGUs or groups of CGUs that are expected to benefit from synergies of the acquisition. The allocation of goodwill may vary depending on the basis for its initial recognition. The majority of the company's goodwill is related to the requirement to recognise deferred tax for the difference between the assigned fair values and the related tax base (\"technical goodwill\"). The fair value of the company\u2019s licences, all of which are located on the Norwegian Continental Shelf, are based on cash flows after tax. This is because these licences are only sold in an after-tax market based on the tax carry-over principles pursuant to the Petroleum Taxation Act section 10. The purchaser is therefore not entitled to a tax deduction for the consideration paid over and above the seller\u2019s tax values. In accordance with IAS 12 paragraphs 15 and 24, a provision is made for deferred tax corresponding to the difference between the acquisition cost and the transferred tax depreciation basis. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax. Technical goodwill is tested for impairment separately for each CGU which give rise to the technical goodwill. A CGU may be individual oil fields, or a group of oil fields that are connected to the same infrastructure/production facilities. 1.7 Acquisitions, sales and licence swaps 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 (see Item 1.8) or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Other licence purchases regarded as asset purchases are described below. Oil and gas production licencesFor licences in the development phase, the acquisition cost is allocated between capitalised exploration expenses, licence rights and production plant.When entering into agreements regarding the purchase/swap of assets, the parties agree on an effective date for the takeover of the net cash flow (usually 1 January in the calendar year which would also normally be the effective date for tax purposes). In the period between the effective date and the completion date, the seller will include its sold share of the licence in the financial statements. In accordance with the purchase agreement, there is a settlement with the seller of the net cash flow from the asset in the period from the effective date to the completion date (pro & contra settlement). The pro & contra settlement will be adjusted to the seller\u2019s losses/gains and to the assets for the purchaser, in that the settlement (after a tax reduction) is deemed to be part of the consideration in the transaction. Revenues and expenses from the relevant licence are included in the purchaser\u2019s Income statement from the acquisition date. For tax purposes, the purchaser will include the net cash flow (pro & contra) and any other income and costs as from the effective date. Deferred tax is not recognised when acquiring licences that are defined as asset acquisitions. 1.8 Tangible fixed assets and intangible assets GeneralTangible fixed assets are recognised on a historical cost basis. Gains and losses relating to the disposal of assets are determined by comparing the selling price with the book value, and are included in other operating income/expenses on a post tax basis. Operating assets related to petroleum activitiesExploration and development costs relating to oil and gas fieldsCapitalised exploration expenditures are classified as intangible assets and reclassified to tangible assets at the start of development. For accounting purposes, the field is considered to enter the development phase when the technical feasibility and commercial viability of extracting hydrocarbons from the field are demon-strable, normally at the time of concept selection. All costs relating to the development of commercial oil and/or gas fields are recognised as tangible assets. Pre-operational costs are expensed as they are incurred. The company employs the \u2019successful efforts\u2019 method to account for exploration and development costs. All exploration costs (including seismic shooting, seismic studies and 'own time\u2019), with the exception of acquisition costs of licences and drilling costs for exploration wells, are expensed as incurred. When explo-ration drilling is ongoing in a period after the reporting date and the result of the drilling is subsequently not successful, the capitalised exploration cost as of the reporting date is expensed if the evaluation of the well is completed before the date when the financial statements are authorised for issue. Drilling cost for exploration wells are temporarily capitalised pending the evaluation of potential discoveries of oil and gas resources. Such costs can remain capitalised for more than one year. The main criteria is that there must be plans for future activity in the licence area or that a development decision is expected in the near future. If no resources are discovered, or if recovery of the resources is considered technically or commercially unviable, expenses relating to the drilling of exploration wells are charged to expense.Acquired licence rights are recognised as intangible assets at the time of acquisition. Acquired licence rights related to fields in the exploration phase remain as intangible assets also when the related fields enter the development or production phase.Depreciation of oil and gas fieldsCapitalised exploration and evaluation expenditures, development expenditures from construction, installation or completion of infrastructure facilities such as platforms, pipelines and production wells, and field-dedicated transport systems for oil and gas are capitalised as production facilities and are depreciated using the unit-of-production method based on proven and probable developed reserves expected to be recovered from the area during the concession or contract period. Acquired assets used for the recovery and production of petroleum deposits, including licence rights, are also depreciated using the unit-of-pro-duction method based on proven and probable reserves. The reserve basis used for depreciation purposes is updated at least annually. Any changes in the reserves affecting unit-of-production calculations are reflected prospectively. Depreciation of assets other than oil and gas fields, including right of use assets, is calculated using the straight-line method over estimated useful lives and adjusted for any impairment or change in residual value, if applicable.1.9 Impairment Tangible fixed assets and intangible assetsThe unit of account for assessment of impairment is based on the lowest level at which it is possible to identify cash inflows that are independent of cash inflows from other groups of fixed assets. For oil and gas assets, this is typically the field or licence level. Impairment is recognised when the book value of the CGU (including any allocated goodwill) exceeds the recoverable amount. When estimating value in use and fair value less cost of disposal, expected future cash flows are discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money and the specific risk related to the asset. The discount rate is derived from the Weighted Average Cost of Capital (WACC).The lifetime of the field for the purpose of impairment testing is normally determined by the point in time when the operating cash flow from the field becomes negative.For exploration licences, impairment is based on an assessment of whether plans for further activities have been established or, if applicable, an evaluation of whether development will be decided on in the near future as described in section 1.8.A previously recognised impairment can only be reversed if changes have occurred in the estimates used for the calculation of the recoverable amount. GoodwillGoodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the value may be impaired. Impairment is recognised if the recoverable amount of the CGU (or group of CGUs) to which the goodwill is related is less than the book value, including associated goodwill and deferred tax as described in section 1.6. Losses relating to impairment of goodwill cannot be reversed in future periods. 1.10 Financial instruments The group\u2019s financial assets and liabilities comprise non-listed equity instruments, derivative financial instruments (assets and liabilities), receivables, cash and cash equivalents, payables, other short-term liabilities and non-current liabilities. The classification of financial assets and liabilities at initial recognition depends on the financial instrument\u2019s contractual cash flow characteristics and the Group\u2019s business model for managing them. The company has classified the financial instruments into the following categories of financial assets and liabilities: \u2013 Financial assets at fair value through profit or loss \u2013 Financial assets measured at amortised cost \u2013 Financial liabilities at fair value through profit or loss \u2013 Financial liabilities measured at amortised costs \u2013 The group\u2019s financial instruments at amortised cost includes trade receivables with the objective hold to collect and other short-term deposits, trade payables and other current and non-current liabilities. Receivables are initially recognised at fair value less impairment losses.All borrowings are initially recognised at transaction price, which equals the fair value of the amount received net of costs directly related to the establishment of the loan or issuance of debt. Subsequently, interest-bearing borrowings are valued at amortised cost using the effective interest method; the difference between the transaction price (after transaction costs) and the face value is recognised in the Income statement in the period until the loan falls due. Amortised costs are calculated by considering all issue costs on the settlement date, except for any discount or premium expensed immediately.Financial liabilities that do not form part of the \u201cheld for trading purposes\u201d category and which have not been designated as being at fair value with changes in value through profit or loss are classified as other financial liabilities. Further details on fair values of financial instruments are provided in note 28 \u2018Financial instruments\u2019.1.11 Presentation of payroll and administration costs The company presents its payroll and administration costs based on the functions in development, operational and exploration activities respectively, based on allocation of registered hours worked, net of amounts recharged to operated licences.1.12 Leases The lease liability is recognised at the commencement date and measured at the present value of the remaining lease payments, discounted using the company's incremental borrowing rate at the commence-ment date. The borrowing rate is derived from the terms of the company's existing credit facilities. Right-of-use (RoU) assets are depreciated over the lease term as this is ordinarily shorter than the useful life of the assets. The company applies the exemption for short term leases (12 months or less) and low value leases. As such, related lease payments are not recognised in the balance sheet, but expensed or capitalised in line with the accounting treatment for other non-lease expenses. The inclusion of non-lease components may vary across different lease categories, but for the most material class of assets (rigs), the company has excluded the non-lease components when measuring the lease liability.Lease agreements that are planned to be applied on several operated licences, are generally recognised on a gross basis as Aker BP is deemed to be the primary obligator. The company may enter into lease contracts as an operator on behalf of a licence, and may for such leases only recognise its net share of the related lease liability. Whether a contract is entered into on behalf of the licence is subject to a contract specific assessment, but the general principle is that there needs to be a direct link between the lease contract and the licence or field on which the RoU asset shall be used. For lease contracts recognised on a gross basis, the partner's share of the cost recovered by the company are presented as other income.1.13 Borrowing costs Borrowing costs that can be directly ascribed to procurement, processing or production of a qualifying asset are capitalised as part of the asset\u2019s acquisition cost. Borrowing cost is only capitalised during the development phase. Other borrowing costs are expensed in the period in which they are incurred. A qualifying asset is one that necessarily takes a substantial period of time to be made ready for its intended use or sale. Qualifying assets are generally those that are subject to major development or construction projects.1.14 Inventories Inventories mainly consist of equipment for the drilling of exploration and production wells and are valued at the lower of cost price (based on weighted average cost) and net realisable value. 1.15 Cash and cash equivalents Cash and cash equivalents include cash, bank deposits, and other short-term highly liquid investments with an original due date of three months or less. Bank overdrafts are included in the Statement of Financial Position as short-term loans.1.16 Tax GeneralTax consists of tax payable and changes in deferred tax. Deferred tax/tax benefits are calculated on the basis of the differences between book value and tax basis values of assets and liabilities, with the exception of temporary differences on acquisition of licences that are defined as asset purchases.Deferred tax is measured using the expected tax rate when the tax benefit is realised or the tax liability is met, based on tax rates and tax regulations that have been enacted or substantively enacted at the reporting date.Tax payable and deferred tax is recognised directly against equity or other comprehensive income insofar as the tax items are related to equity transactions or items of other comprehensive income.Deferred tax and tax benefits are presented net, where netting is legally permitted and the deferred tax benefit and liability are related to the same tax subject and are payable to the same tax authorities.Functional currencyThe company\u2019s functional currency is USD, while it is a statutory requirement to calculate the current tax based on NOK functional currency. This may impact the effective tax rate when the exchange rate between NOK and USD fluctuates. The revaluation of tax receivable and payable is presented as foreign exchange gain/loss, while the impact on deferred tax from revaluation of tax balances is presented as tax expense / income. Petroleum taxationAs an oil and gas company in Norway, Aker BP is subject to the special provisions of the Petroleum Taxation Act. Taxable profits from activities on the Norwegian Continental Shelf are liable to ordinary company tax and special tax. The overall tax rate for activities according to the Petroleum Taxation Act is 78 percent.The ordinary company tax is 22 percent. In addition, the company is subject to a special petroleum tax of 71.8 percent. The special petroleum tax is a cash-based tax andcompanies can make immediate deductions for expenses incurred. In addition, the corporate tax (22 percent) is deductible in the special tax base (71.8 percent) in order to maintain the overall tax rate of 78 percent. Tax depreciation and upliftInvestments in pipelines and production facilities can be depreciated by up to 16 2/3 percent annually, i.e., using the straight-line method over six years. Tax depreciation commences when the expenses are incurred. When a field stops producing, any remaining tax values may be deducted in that year. Changes to the Petroleum Taxation Act were enacted in June 2022 with effect from 1 January 2022. Under the new rules, investments are immediately deducted in the special tax base, while the ordinary depreciation rules still apply to the corporate tax base.Uplift is a special income deduction in the basis for calculation of special tax. Uplift is calculated on the basis of investments in pipelines and production facilities and can be regarded as an extra depreciation deduction in the special tax regime. The uplift rate is 12.4 percent (17.69 percent in 2022). From 2023 uplift is only applicable for investments covered by the temporary changes enacted to the Petroleum Tax Act in 2020. The changes included temporary rules for depreciation and uplift, whereby all investments incurred for income year 2020 and 2021 including uplift could be deducted for special tax in the year of investment. The tempo-rary changes are also applicable for investments up to and including year of production start in accordance with new PDOs delivered within 31 December 2022 and approved within 31 December 2023. Financial itemsInterest on debt with associated currency losses/gains is distributed between the offshore and onshore tax regimes. Offshore interest deduction is calculated as the net financial costs of interest-bearing debt multiplied by 50 percent of the ratio between net asset value for tax purposes allocated to the offshore tax regime as of 31 December in the income year and the average interest-bearing debt through the income year.Remaining financial expenses, currency losses and all interest income as well as currency gains are allocated to the onshore jurisdiction.Uncovered losses in the onshore tax jurisdictions resulting from the distribution of net financial items can be allocated to the offshore tax jurisdictions and deducted from regular income. Only 50 percent of other losses in the onshore tax jurisdictions are permitted to be reallocated to the offshore tax jurisdictions as deductions in regular income.Tax lossCorporate tax losses are carried forward without time limitations for companies subject to special tax. Special petroleum tax losses are reimbursed by the state in the following year as part of the ordinary tax assessment. The tax position can be transferred on realisation of the company or merger. 1.17 Provisions Decommissioning and removal costs: In accordance with the licence terms and conditions for the licences in which the company participates, the Norwegian State can require licence owners to remove the installation in whole or in part when production ceases or the licence period expires.In the initial recognition of the decommissioning and removal obligations, the company provides for the net present value of future costs related to decommissioning and removal based on its working interest in the respective fields. A corresponding asset is capitalised as a tangible fixed asset and depreciated using the unit-of-production method. Changes in the time value (net present value) of the obligation related to decommissioning and removal accretion are charged to income as financial expenses and increase the balance-sheet liability related to future decommissioning and removal expenses. Changes in the best estimate for expenses related to decommissioning and removal are recognised in the Statement of financial position (property, plant and equipment), except where it relates to licences with no future production or where the Company will be charged a portion of the liability as a user, i.e., based on shipped volumes. The discount rate used in the calculation of the fair value of the decommissioning and removal obligation is the risk-free rate.1.18 SegmentSince its formation, the company has conducted its entire business in one consistent segment, defined as exploration for and production of petroleum in Norway. The company conducts its activities on the Norwegian Continental Shelf, and management monitors the company at this level. The financial informa-tion relating to geographical distribution and large customers is presented in note 4.1.19 Changes to accounting standards and interpretations that: Have entered into force: The group has applied the following standards and amendment for the first time for their annual reporting period commencing 1 January 2023:Deferred Tax related to Assets and Liabilities arising from a Single Transaction (Amendments to IAS 12 Income taxes (IAS 12):The amendments to IAS 12 require companies to recognise deferred tax on particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences and will require the recognition of additional deferred tax assets and liabilities.The amendment should be applied to transactions that occur on or after the beginning of the earliest comparative period presented. In addition, entities should recognise deferred tax assets (to the extent that it is probable that they can be utilised) and deferred tax liabilities at the beginning of the earliest compara-tive period for all deductible and taxable temporary differences associated with: \u2013 right-of-use assets and lease liabilities, and \u2013 decommissioning, restoration and similar liabilities, and the corresponding amounts recognised as part of the cost of the related assets.The cumulative effect of recognising these adjustments is recognised in the opening balance of retained earnings, or another component of equity, as appropriate.IAS 12 did not previously address how to account for the tax effects of on balance sheet leases and similar transactions and various approaches were considered acceptable. Aker BP already accounted for such transactions consistent with the new requirements andthe application of the amendment did not have a material impact on the financial statements in 2023.Disclosure of Accounting Policies \u2013 Amendments to IAS 1 and IFRS Practice Statement 2:The IASB amended IAS 1 to require entities to disclose their material rather than their significant accounting policies. The amendments define what is \u2018material accounting policy information\u2019 (being infor-mation that, when considered together with other information included in an entity\u2019s financial statements, can reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements) and explain how to identify when accounting policy information is material. They further clarify that immaterial accounting policy information does not need to be disclosed. If it is disclosed, it should not obscure material accounting information.To support this amendment, the IASB also amended IFRS Practice Statement 2 Making Materiality Judgements to provide guidance on how to apply the concept of materiality to accounting policy disclo-sures. The application of the amendment did not have a material impact on the financial statements in 2023.Have been issued but have not entered into force: Certain new accounting standards and interpretations are issued, but not yet effective as of 31 December 2023. These standards are not expected to have a material impact on the group in the current or future reporting periods.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSummaryOfSignificantAccountingPoliciesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__19": {
"value": "1.1 Basis of preparationThe group and the parent company financial statements have been prepared in accordance with IFRS\u00ae Accounting Standards as adopted by the EU and the Norwegian Accounting Act.All amounts have been rounded to the nearest million unless otherwise stated. As a result of rounding adjustments, the figures in one or more rows or columns included in the financial statements and notes may not add up to the total of that row or column.The group financial statements for Aker BP ASA include the subsidiaries as described in note 2. The accounting policies are applied consistently when consolidating ownership interests in subsidiaries and are based on the same reporting periods as those used for the parent company. When preparing the consolidated financial statements, intragroup transactions and balances, along with gains and losses on transactions between group units, are eliminated.",
"dimensions": {
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"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__18": {
"value": "The group and the parent company financial statements have been prepared in accordance with IFRS\u00ae Accounting Standards as adopted by the EU and the Norwegian Accounting Act.",
"dimensions": {
"concept": "ifrs-full:StatementOfIFRSCompliance",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__20": {
"value": "1.2 Functional currency and presentation currencyThe presentation currency in the Group\u2019s consolidated financial statements is United States Dollars (\u201cUSD\u201d). The parent company of the Group, Aker BP ASA, has USD as its functional currency as most revenue and financing are in USD and represents the primary economic environment in which the entity operates. Balance sheet items of subsidiaries in other functional currencies are translated into the presentation currency, USD, according to the exchange rates prevailing on the balance sheet date, while profit or loss items are translated according to average quarterly exchange rates for the relevant quarters.In all material respects, the activity of Lundin Energy was conducted in the legal entity ABP Norway AS (previously Lundin Energy Norway AS), which had NOK as its functional currency. In line with accounting guidance, the related purchase price allocation (PPA) was fixed in NOK accordingly, and thus gave rise to foreign currency translation in the group accounts recognised in the statement of comprehensive income during the second half of 2022. At 31 December 2022, ABP Norway AS merged with Aker BP ASA, meaning that the mentioned impact on comprehensive impact ceased from 1 January 2023.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__21": {
"value": "1.3 Critical judgements and estimatesThe preparation of financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that have an effect on the application of accounting policies and the reported assets, liabilities, income and expenses.The important judgments management has made regarding the application of accounting policies are as follows:Goodwill allocation and methodology for impairment testingFor the purpose of impairment testing, goodwill is allocated to a cash-generating unit (CGU), or groups of CGUs that are expected to benefit from the synergies of the business combination from which it arose. A CGU is typically a producing field or group of producing licences for which a separate offtake facility exist that can generate separate cash flows. The allocation of goodwill requires judgment and may significantly impact any subsequent impairment charge. Although not an IFRS term, \u201ctechnical goodwill\u201d is used by Aker BP to describe the category of goodwill arising as an offsetting account to deferred tax liabilities recognised in business combinations, as described in section 1.8 below. There are no specific IFRS guidelines pertaining to the allocation of technical goodwill, and management has therefore applied the general guidelines for allocating goodwill. In general, technical goodwill is allocated at the CGU level for impairment testing purposes, while residual goodwill may be allocated across all CGUs based on the facts and circumstances of the business combination. When performing the impairment test for technical goodwill, deferred tax liabilities recognised in relation to the acquired licences reduce the net carrying value prior to any impairment charges. This methodology avoids an immediate impairment of all technical goodwill. When deferred tax liabilities from the initial recognition decreases, additional technical goodwill is \u2018exposed\u2019 to impairment. Subsequent to the initial purchase price allocation, depreciation of book values will result in decreasing deferred tax liabilities. When applicable, technical goodwill is impaired before the asset.Proven and probable oil and gas reservesProven and probable reserves and production volumes are used to calculate the depreciation of oil and gas fields by applying the unit-of-production method. Reserve estimates are also used as basis for impairment testing of licence-related assets and goodwill.Oil and gas reserves are estimated by the company\u2019s experts in accordance with industry standards. The estimates are based on Aker BP\u2019s own assessment of internal information and information received from operators. In addition, proven and probable reserves are certified by an external party. Proven and probable oil and gas reserves consist of the estimated quantities of crude oil, natural gas and condensates shown by geological and technical data to be recoverable with reasonable certainty from known reservoirs under existing economic and operational conditions, i.e. on the date that the estimates are prepared. Current market prices are used in the estimates.Changes in petroleum prices and cost estimates may change reserve estimates and accordingly economic cut-off, which may impact the timing of assumed decommissioning and removal activities. Changes to reserve estimates can also result from updated production and reservoir information. Future changes to proven and probable oil and gas reserves can have a material effect on depreciation, life of field, impair-ment of licence-related assets and goodwill, and operating results. Accounting for Exploration costs \u2013 application of the Successful Effort Method Expenses relating to the drilling of exploration wells are temporarily recognised in the Statement of financial position as capitalised exploration expenditures, pending an evaluation of potential oil and gas discoveries. If resources are not discovered, or if recovery of the resources is considered technically or commercially unviable, the costs of exploration wells are expensed. Judgments as to whether this expend-iture should remain capitalised or be expensed at the reporting date may materially affect the operating result for the period.Fair value measurementThe fair values of non-financial assets and liabilities are required to be determined, for example in a business combination, to determine the allocation of purchase price in an asset deal or when the recover-able amount of an asset or CGU is based on fair value less cost to sell. 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 of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability. 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. The fair value of oil fields in production and development phase is normally based on discounted cash flow models, where the determination of inputs to the model may require significant judgment, as described in the section below regarding impairment. Impairment/reversal of impairmentThe evaluation of impairment requires long-term assumptions concerning a number of often volatile economic factors, including future oil and gas prices, oil and gas production, currency exchange rates and discount rates. Such assumptions require the estimation of relevant factors such as long-term prices, the levels of capex and opex, production estimates and decommissioning costs. These evaluations are also necessary to determine a CGU\u2019s fair value unless information can be obtained from an actual observable market transaction. See note 13 \u2019Tangible fixed assets and intangible assets\u2019 and note 14 \u2019Impairments\u2019 for details of impairments.Decommissioning and removal obligationsThe company has obligations to decommission and remove offshore installations at the end of their production period. The estimates include costs based on expected removal concepts using existing technology and estimated costs of maritime operations, hiring of single-lift and heavy-lift barges and drilling rigs. There is significant future uncertainty in the estimate of costs for decommissioning and removal, as these estimates are based on currently applicable laws and regulations, and existing technologies. Many decommissioning and removal activities will take place many decades in the future, and the technology and related costs are expected to evolve in this time. As a result, there may be significant adjustments to the estimates of decommissioning liabilities and associated assets that can affect future financial results.. See note 22 \u2018Provision for abandonment liabilities\u2019 for further details about decommissioning and removal obligations.Income taxIncome tax expense, tax payables or receivables, and deferred taxes are based on management\u2019s interpre-tation of applicable laws and regulations, and on relevant court decisions where relevant. These estimates are dependent on management\u2019s ability to interpret and apply the requirements of tax and other relevant legislation, and requires judgment in respect of the recognition and measurement of any uncertain tax positions. See note 11 \u2018Taxes\u2019 for further details.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__22-1": {
"value": "Goodwill allocation and methodology for impairment testingFor the purpose of impairment testing, goodwill is allocated to a cash-generating unit (CGU), or groups of CGUs that are expected to benefit from the synergies of the business combination from which it arose. A CGU is typically a producing field or group of producing licences for which a separate offtake facility exist that can generate separate cash flows. The allocation of goodwill requires judgment and may significantly impact any subsequent impairment charge. Although not an IFRS term, \u201ctechnical goodwill\u201d is used by Aker BP to describe the category of goodwill arising as an offsetting account to deferred tax liabilities recognised in business combinations, as described in section 1.8 below. There are no specific IFRS guidelines pertaining to the allocation of technical goodwill, and management has therefore applied the general guidelines for allocating goodwill. In general, technical goodwill is allocated at the CGU level for impairment testing purposes, while residual goodwill may be allocated across all CGUs based on the facts and circumstances of the business combination. When performing the impairment test for technical goodwill, deferred tax liabilities recognised in relation to the acquired licences reduce the net carrying value prior to any impairment charges. This methodology avoids an immediate impairment of all technical goodwill. When deferred tax liabilities from the initial recognition decreases, additional technical goodwill is \u2018exposed\u2019 to impairment. Subsequent to the initial purchase price allocation, depreciation of book values will result in decreasing deferred tax liabilities. When applicable, technical goodwill is impaired before the asset.Impairment/reversal of impairmentThe evaluation of impairment requires long-term assumptions concerning a number of often volatile economic factors, including future oil and gas prices, oil and gas production, currency exchange rates and discount rates. Such assumptions require the estimation of relevant factors such as long-term prices, the levels of capex and opex, production estimates and decommissioning costs. These evaluations are also necessary to determine a CGU\u2019s fair value unless information can be obtained from an actual observable market transaction. See note 13 \u2019Tangible fixed assets and intangible assets\u2019 and note 14 \u2019Impairments\u2019 for details of impairments.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfFinancialAssetsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__23": {
"value": "Proven and probable oil and gas reservesProven and probable reserves and production volumes are used to calculate the depreciation of oil and gas fields by applying the unit-of-production method. Reserve estimates are also used as basis for impairment testing of licence-related assets and goodwill.Oil and gas reserves are estimated by the company\u2019s experts in accordance with industry standards. The estimates are based on Aker BP\u2019s own assessment of internal information and information received from operators. In addition, proven and probable reserves are certified by an external party. Proven and probable oil and gas reserves consist of the estimated quantities of crude oil, natural gas and condensates shown by geological and technical data to be recoverable with reasonable certainty from known reservoirs under existing economic and operational conditions, i.e. on the date that the estimates are prepared. Current market prices are used in the estimates.Changes in petroleum prices and cost estimates may change reserve estimates and accordingly economic cut-off, which may impact the timing of assumed decommissioning and removal activities. Changes to reserve estimates can also result from updated production and reservoir information. Future changes to proven and probable oil and gas reserves can have a material effect on depreciation, life of field, impair-ment of licence-related assets and goodwill, and operating results.",
"dimensions": {
"concept": "ifrs-full:ExplanationOfAssumptionAboutFutureWithSignificantRiskOfResultingInMaterialAdjustments",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__24-1": {
"value": "Accounting for Exploration costs \u2013 application of the Successful Effort Method Expenses relating to the drilling of exploration wells are temporarily recognised in the Statement of financial position as capitalised exploration expenditures, pending an evaluation of potential oil and gas discoveries. If resources are not discovered, or if recovery of the resources is considered technically or commercially unviable, the costs of exploration wells are expensed. Judgments as to whether this expend-iture should remain capitalised or be expensed at the reporting date may materially affect the operating result for the period.1.11 Presentation of payroll and administration costs The company presents its payroll and administration costs based on the functions in development, operational and exploration activities respectively, based on allocation of registered hours worked, net of amounts recharged to operated licences.1.13 Borrowing costs Borrowing costs that can be directly ascribed to procurement, processing or production of a qualifying asset are capitalised as part of the asset\u2019s acquisition cost. Borrowing cost is only capitalised during the development phase. Other borrowing costs are expensed in the period in which they are incurred. A qualifying asset is one that necessarily takes a substantial period of time to be made ready for its intended use or sale. Qualifying assets are generally those that are subject to major development or construction projects.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForExpensesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__25": {
"value": "Fair value measurementThe fair values of non-financial assets and liabilities are required to be determined, for example in a business combination, to determine the allocation of purchase price in an asset deal or when the recover-able amount of an asset or CGU is based on fair value less cost to sell. 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 of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability. 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. The fair value of oil fields in production and development phase is normally based on discounted cash flow models, where the determination of inputs to the model may require significant judgment, as described in the section below regarding impairment.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFairValueMeasurementExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__27-1": {
"value": "Decommissioning and removal obligationsThe company has obligations to decommission and remove offshore installations at the end of their production period. The estimates include costs based on expected removal concepts using existing technology and estimated costs of maritime operations, hiring of single-lift and heavy-lift barges and drilling rigs. There is significant future uncertainty in the estimate of costs for decommissioning and removal, as these estimates are based on currently applicable laws and regulations, and existing technologies. Many decommissioning and removal activities will take place many decades in the future, and the technology and related costs are expected to evolve in this time. As a result, there may be significant adjustments to the estimates of decommissioning liabilities and associated assets that can affect future financial results.. See note 22 \u2018Provision for abandonment liabilities\u2019 for further details about decommissioning and removal obligations.Decommissioning and removal costs: In accordance with the licence terms and conditions for the licences in which the company participates, the Norwegian State can require licence owners to remove the installation in whole or in part when production ceases or the licence period expires.In the initial recognition of the decommissioning and removal obligations, the company provides for the net present value of future costs related to decommissioning and removal based on its working interest in the respective fields. A corresponding asset is capitalised as a tangible fixed asset and depreciated using the unit-of-production method. Changes in the time value (net present value) of the obligation related to decommissioning and removal accretion are charged to income as financial expenses and increase the balance-sheet liability related to future decommissioning and removal expenses. Changes in the best estimate for expenses related to decommissioning and removal are recognised in the Statement of financial position (property, plant and equipment), except where it relates to licences with no future production or where the Company will be charged a portion of the liability as a user, i.e., based on shipped volumes. The discount rate used in the calculation of the fair value of the decommissioning and removal obligation is the risk-free rate.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__28-1": {
"value": "Income taxIncome tax expense, tax payables or receivables, and deferred taxes are based on management\u2019s interpre-tation of applicable laws and regulations, and on relevant court decisions where relevant. These estimates are dependent on management\u2019s ability to interpret and apply the requirements of tax and other relevant legislation, and requires judgment in respect of the recognition and measurement of any uncertain tax positions. See note 11 \u2018Taxes\u2019 for further details.1.16 Tax GeneralTax consists of tax payable and changes in deferred tax. Deferred tax/tax benefits are calculated on the basis of the differences between book value and tax basis values of assets and liabilities, with the exception of temporary differences on acquisition of licences that are defined as asset purchases.Deferred tax is measured using the expected tax rate when the tax benefit is realised or the tax liability is met, based on tax rates and tax regulations that have been enacted or substantively enacted at the reporting date.Tax payable and deferred tax is recognised directly against equity or other comprehensive income insofar as the tax items are related to equity transactions or items of other comprehensive income.Deferred tax and tax benefits are presented net, where netting is legally permitted and the deferred tax benefit and liability are related to the same tax subject and are payable to the same tax authorities.Functional currencyThe company\u2019s functional currency is USD, while it is a statutory requirement to calculate the current tax based on NOK functional currency. This may impact the effective tax rate when the exchange rate between NOK and USD fluctuates. The revaluation of tax receivable and payable is presented as foreign exchange gain/loss, while the impact on deferred tax from revaluation of tax balances is presented as tax expense / income.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__29": {
"value": "1.4 Revenue recognition Revenue from the sale of liquids or gas is recognised at the point in time when the company\u2019s contractual performance obligations have been fulfilled and control is transferred to the customer, which will ordinarily be at the point of delivery when title passes (sales method). This is normally at the time of loading oil or NGL on vessels used for transport, or at agreed point of delivery for dry gas.There is no significant judgement applying IFRS 15 \u2018Revenue from contracts with customers\u2019 to the company\u2019s revenue generating contracts.Changes in over/underlift balances are valued at production cost including depreciation and presented as an adjustment to cost. See note 6 for further details. Gains or losses on asset disposals as described in section 1.7 are included in other operating income. Tariff revenue from processing of oil and gas is recognised as earned in line with underlying agreements.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__31": {
"value": "1.5 Interests in licences and partnerships The company has interests in licences on the Norwegian Continental Shelf. Under IFRS 11 Joint Arrangements, a joint operation is a 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. The company recognises investments in joint operations (oil and gas production licences) by reporting its share of related revenues, expenses, assets, liabilities and cash flows under the respective items in the company's financial statements. IFRS defines a joint arrangement as an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control 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. For those licences that are not deemed to be joint arrangements pursuant to the definition in IFRS 11 as there is no joint control, the company recognises its share of related expenses, assets, liabilities and cash flows on a line-by-line basis in the financial statements by analogy to IFRS 11 and in accordance with applicable IFRSs.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__30": {
"value": "1.5 Interests in licences and partnerships The company has interests in licences on the Norwegian Continental Shelf. Under IFRS 11 Joint Arrangements, a joint operation is a 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. The company recognises investments in joint operations (oil and gas production licences) by reporting its share of related revenues, expenses, assets, liabilities and cash flows under the respective items in the company's financial statements. IFRS defines a joint arrangement as an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control 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. For those licences that are not deemed to be joint arrangements pursuant to the definition in IFRS 11 as there is no joint control, the company recognises its share of related expenses, assets, liabilities and cash flows on a line-by-line basis in the financial statements by analogy to IFRS 11 and in accordance with applicable IFRSs.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociatesAndJointVenturesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__34": {
"value": "1.6 Business combinations and goodwill In a business combination, goodwill is allocated to the CGUs or groups of CGUs that are expected to benefit from synergies of the acquisition. The allocation of goodwill may vary depending on the basis for its initial recognition. The majority of the company's goodwill is related to the requirement to recognise deferred tax for the difference between the assigned fair values and the related tax base (\"technical goodwill\"). The fair value of the company\u2019s licences, all of which are located on the Norwegian Continental Shelf, are based on cash flows after tax. This is because these licences are only sold in an after-tax market based on the tax carry-over principles pursuant to the Petroleum Taxation Act section 10. The purchaser is therefore not entitled to a tax deduction for the consideration paid over and above the seller\u2019s tax values. In accordance with IAS 12 paragraphs 15 and 24, a provision is made for deferred tax corresponding to the difference between the acquisition cost and the transferred tax depreciation basis. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax. Technical goodwill is tested for impairment separately for each CGU which give rise to the technical goodwill. A CGU may be individual oil fields, or a group of oil fields that are connected to the same infrastructure/production facilities.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__33": {
"value": "1.6 Business combinations and goodwill In a business combination, goodwill is allocated to the CGUs or groups of CGUs that are expected to benefit from synergies of the acquisition. The allocation of goodwill may vary depending on the basis for its initial recognition. The majority of the company's goodwill is related to the requirement to recognise deferred tax for the difference between the assigned fair values and the related tax base (\"technical goodwill\"). The fair value of the company\u2019s licences, all of which are located on the Norwegian Continental Shelf, are based on cash flows after tax. This is because these licences are only sold in an after-tax market based on the tax carry-over principles pursuant to the Petroleum Taxation Act section 10. The purchaser is therefore not entitled to a tax deduction for the consideration paid over and above the seller\u2019s tax values. In accordance with IAS 12 paragraphs 15 and 24, a provision is made for deferred tax corresponding to the difference between the acquisition cost and the transferred tax depreciation basis. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax. Technical goodwill is tested for impairment separately for each CGU which give rise to the technical goodwill. A CGU may be individual oil fields, or a group of oil fields that are connected to the same infrastructure/production facilities.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__32": {
"value": "1.6 Business combinations and goodwill In a business combination, goodwill is allocated to the CGUs or groups of CGUs that are expected to benefit from synergies of the acquisition. The allocation of goodwill may vary depending on the basis for its initial recognition. The majority of the company's goodwill is related to the requirement to recognise deferred tax for the difference between the assigned fair values and the related tax base (\"technical goodwill\"). The fair value of the company\u2019s licences, all of which are located on the Norwegian Continental Shelf, are based on cash flows after tax. This is because these licences are only sold in an after-tax market based on the tax carry-over principles pursuant to the Petroleum Taxation Act section 10. The purchaser is therefore not entitled to a tax deduction for the consideration paid over and above the seller\u2019s tax values. In accordance with IAS 12 paragraphs 15 and 24, a provision is made for deferred tax corresponding to the difference between the acquisition cost and the transferred tax depreciation basis. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax. Technical goodwill is tested for impairment separately for each CGU which give rise to the technical goodwill. A CGU may be individual oil fields, or a group of oil fields that are connected to the same infrastructure/production facilities.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsAndGoodwillExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__35-1": {
"value": "1.7 Acquisitions, sales and licence swaps 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 (see Item 1.8) or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Other licence purchases regarded as asset purchases are described below. Oil and gas production licencesFor licences in the development phase, the acquisition cost is allocated between capitalised exploration expenses, licence rights and production plant.When entering into agreements regarding the purchase/swap of assets, the parties agree on an effective date for the takeover of the net cash flow (usually 1 January in the calendar year which would also normally be the effective date for tax purposes). In the period between the effective date and the completion date, the seller will include its sold share of the licence in the financial statements. In accordance with the purchase agreement, there is a settlement with the seller of the net cash flow from the asset in the period from the effective date to the completion date (pro & contra settlement). The pro & contra settlement will be adjusted to the seller\u2019s losses/gains and to the assets for the purchaser, in that the settlement (after a tax reduction) is deemed to be part of the consideration in the transaction. Revenues and expenses from the relevant licence are included in the purchaser\u2019s Income statement from the acquisition date. For tax purposes, the purchaser will include the net cash flow (pro & contra) and any other income and costs as from the effective date. Deferred tax is not recognised when acquiring licences that are defined as asset acquisitions.Exploration and development costs relating to oil and gas fieldsCapitalised exploration expenditures are classified as intangible assets and reclassified to tangible assets at the start of development. For accounting purposes, the field is considered to enter the development phase when the technical feasibility and commercial viability of extracting hydrocarbons from the field are demon-strable, normally at the time of concept selection. All costs relating to the development of commercial oil and/or gas fields are recognised as tangible assets. Pre-operational costs are expensed as they are incurred. The company employs the \u2019successful efforts\u2019 method to account for exploration and development costs. All exploration costs (including seismic shooting, seismic studies and 'own time\u2019), with the exception of acquisition costs of licences and drilling costs for exploration wells, are expensed as incurred. When explo-ration drilling is ongoing in a period after the reporting date and the result of the drilling is subsequently not successful, the capitalised exploration cost as of the reporting date is expensed if the evaluation of the well is completed before the date when the financial statements are authorised for issue. Drilling cost for exploration wells are temporarily capitalised pending the evaluation of potential discoveries of oil and gas resources. Such costs can remain capitalised for more than one year. The main criteria is that there must be plans for future activity in the licence area or that a development decision is expected in the near future. If no resources are discovered, or if recovery of the resources is considered technically or commercially unviable, expenses relating to the drilling of exploration wells are charged to expense.Acquired licence rights are recognised as intangible assets at the time of acquisition. Acquired licence rights related to fields in the exploration phase remain as intangible assets also when the related fields enter the development or production phase.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForOilAndGasAssetsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__37": {
"value": "1.8 Tangible fixed assets and intangible assets GeneralTangible fixed assets are recognised on a historical cost basis. Gains and losses relating to the disposal of assets are determined by comparing the selling price with the book value, and are included in other operating income/expenses on a post tax basis. Operating assets related to petroleum activitiesExploration and development costs relating to oil and gas fieldsCapitalised exploration expenditures are classified as intangible assets and reclassified to tangible assets at the start of development. For accounting purposes, the field is considered to enter the development phase when the technical feasibility and commercial viability of extracting hydrocarbons from the field are demon-strable, normally at the time of concept selection. All costs relating to the development of commercial oil and/or gas fields are recognised as tangible assets. Pre-operational costs are expensed as they are incurred. The company employs the \u2019successful efforts\u2019 method to account for exploration and development costs. All exploration costs (including seismic shooting, seismic studies and 'own time\u2019), with the exception of acquisition costs of licences and drilling costs for exploration wells, are expensed as incurred. When explo-ration drilling is ongoing in a period after the reporting date and the result of the drilling is subsequently not successful, the capitalised exploration cost as of the reporting date is expensed if the evaluation of the well is completed before the date when the financial statements are authorised for issue. Drilling cost for exploration wells are temporarily capitalised pending the evaluation of potential discoveries of oil and gas resources. Such costs can remain capitalised for more than one year. The main criteria is that there must be plans for future activity in the licence area or that a development decision is expected in the near future. If no resources are discovered, or if recovery of the resources is considered technically or commercially unviable, expenses relating to the drilling of exploration wells are charged to expense.Acquired licence rights are recognised as intangible assets at the time of acquisition. Acquired licence rights related to fields in the exploration phase remain as intangible assets also when the related fields enter the development or production phase.Depreciation of oil and gas fieldsCapitalised exploration and evaluation expenditures, development expenditures from construction, installation or completion of infrastructure facilities such as platforms, pipelines and production wells, and field-dedicated transport systems for oil and gas are capitalised as production facilities and are depreciated using the unit-of-production method based on proven and probable developed reserves expected to be recovered from the area during the concession or contract period. Acquired assets used for the recovery and production of petroleum deposits, including licence rights, are also depreciated using the unit-of-pro-duction method based on proven and probable reserves. The reserve basis used for depreciation purposes is updated at least annually. Any changes in the reserves affecting unit-of-production calculations are reflected prospectively. Depreciation of assets other than oil and gas fields, including right of use assets, is calculated using the straight-line method over estimated useful lives and adjusted for any impairment or change in residual value, if applicable.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsOtherThanGoodwillExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__36": {
"value": "1.8 Tangible fixed assets and intangible assets GeneralTangible fixed assets are recognised on a historical cost basis. Gains and losses relating to the disposal of assets are determined by comparing the selling price with the book value, and are included in other operating income/expenses on a post tax basis. Operating assets related to petroleum activitiesExploration and development costs relating to oil and gas fieldsCapitalised exploration expenditures are classified as intangible assets and reclassified to tangible assets at the start of development. For accounting purposes, the field is considered to enter the development phase when the technical feasibility and commercial viability of extracting hydrocarbons from the field are demon-strable, normally at the time of concept selection. All costs relating to the development of commercial oil and/or gas fields are recognised as tangible assets. Pre-operational costs are expensed as they are incurred. The company employs the \u2019successful efforts\u2019 method to account for exploration and development costs. All exploration costs (including seismic shooting, seismic studies and 'own time\u2019), with the exception of acquisition costs of licences and drilling costs for exploration wells, are expensed as incurred. When explo-ration drilling is ongoing in a period after the reporting date and the result of the drilling is subsequently not successful, the capitalised exploration cost as of the reporting date is expensed if the evaluation of the well is completed before the date when the financial statements are authorised for issue. Drilling cost for exploration wells are temporarily capitalised pending the evaluation of potential discoveries of oil and gas resources. Such costs can remain capitalised for more than one year. The main criteria is that there must be plans for future activity in the licence area or that a development decision is expected in the near future. If no resources are discovered, or if recovery of the resources is considered technically or commercially unviable, expenses relating to the drilling of exploration wells are charged to expense.Acquired licence rights are recognised as intangible assets at the time of acquisition. Acquired licence rights related to fields in the exploration phase remain as intangible assets also when the related fields enter the development or production phase.Depreciation of oil and gas fieldsCapitalised exploration and evaluation expenditures, development expenditures from construction, installation or completion of infrastructure facilities such as platforms, pipelines and production wells, and field-dedicated transport systems for oil and gas are capitalised as production facilities and are depreciated using the unit-of-production method based on proven and probable developed reserves expected to be recovered from the area during the concession or contract period. Acquired assets used for the recovery and production of petroleum deposits, including licence rights, are also depreciated using the unit-of-pro-duction method based on proven and probable reserves. The reserve basis used for depreciation purposes is updated at least annually. Any changes in the reserves affecting unit-of-production calculations are reflected prospectively. Depreciation of assets other than oil and gas fields, including right of use assets, is calculated using the straight-line method over estimated useful lives and adjusted for any impairment or change in residual value, if applicable.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__39": {
"value": "Exploration and development costs relating to oil and gas fieldsCapitalised exploration expenditures are classified as intangible assets and reclassified to tangible assets at the start of development. For accounting purposes, the field is considered to enter the development phase when the technical feasibility and commercial viability of extracting hydrocarbons from the field are demon-strable, normally at the time of concept selection. All costs relating to the development of commercial oil and/or gas fields are recognised as tangible assets. Pre-operational costs are expensed as they are incurred. The company employs the \u2019successful efforts\u2019 method to account for exploration and development costs. All exploration costs (including seismic shooting, seismic studies and 'own time\u2019), with the exception of acquisition costs of licences and drilling costs for exploration wells, are expensed as incurred. When explo-ration drilling is ongoing in a period after the reporting date and the result of the drilling is subsequently not successful, the capitalised exploration cost as of the reporting date is expensed if the evaluation of the well is completed before the date when the financial statements are authorised for issue. Drilling cost for exploration wells are temporarily capitalised pending the evaluation of potential discoveries of oil and gas resources. Such costs can remain capitalised for more than one year. The main criteria is that there must be plans for future activity in the licence area or that a development decision is expected in the near future. If no resources are discovered, or if recovery of the resources is considered technically or commercially unviable, expenses relating to the drilling of exploration wells are charged to expense.Acquired licence rights are recognised as intangible assets at the time of acquisition. Acquired licence rights related to fields in the exploration phase remain as intangible assets also when the related fields enter the development or production phase.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForExplorationAndEvaluationExpenditures",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__40": {
"value": "Depreciation of oil and gas fieldsCapitalised exploration and evaluation expenditures, development expenditures from construction, installation or completion of infrastructure facilities such as platforms, pipelines and production wells, and field-dedicated transport systems for oil and gas are capitalised as production facilities and are depreciated using the unit-of-production method based on proven and probable developed reserves expected to be recovered from the area during the concession or contract period. Acquired assets used for the recovery and production of petroleum deposits, including licence rights, are also depreciated using the unit-of-pro-duction method based on proven and probable reserves. The reserve basis used for depreciation purposes is updated at least annually. Any changes in the reserves affecting unit-of-production calculations are reflected prospectively. Depreciation of assets other than oil and gas fields, including right of use assets, is calculated using the straight-line method over estimated useful lives and adjusted for any impairment or change in residual value, if applicable.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__42": {
"value": "1.9 Impairment Tangible fixed assets and intangible assetsThe unit of account for assessment of impairment is based on the lowest level at which it is possible to identify cash inflows that are independent of cash inflows from other groups of fixed assets. For oil and gas assets, this is typically the field or licence level. Impairment is recognised when the book value of the CGU (including any allocated goodwill) exceeds the recoverable amount. When estimating value in use and fair value less cost of disposal, expected future cash flows are discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money and the specific risk related to the asset. The discount rate is derived from the Weighted Average Cost of Capital (WACC).The lifetime of the field for the purpose of impairment testing is normally determined by the point in time when the operating cash flow from the field becomes negative.For exploration licences, impairment is based on an assessment of whether plans for further activities have been established or, if applicable, an evaluation of whether development will be decided on in the near future as described in section 1.8.A previously recognised impairment can only be reversed if changes have occurred in the estimates used for the calculation of the recoverable amount. GoodwillGoodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the value may be impaired. Impairment is recognised if the recoverable amount of the CGU (or group of CGUs) to which the goodwill is related is less than the book value, including associated goodwill and deferred tax as described in section 1.6. Losses relating to impairment of goodwill cannot be reversed in future periods.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfNonfinancialAssetsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__41": {
"value": "1.9 Impairment Tangible fixed assets and intangible assetsThe unit of account for assessment of impairment is based on the lowest level at which it is possible to identify cash inflows that are independent of cash inflows from other groups of fixed assets. For oil and gas assets, this is typically the field or licence level. Impairment is recognised when the book value of the CGU (including any allocated goodwill) exceeds the recoverable amount. When estimating value in use and fair value less cost of disposal, expected future cash flows are discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money and the specific risk related to the asset. The discount rate is derived from the Weighted Average Cost of Capital (WACC).The lifetime of the field for the purpose of impairment testing is normally determined by the point in time when the operating cash flow from the field becomes negative.For exploration licences, impairment is based on an assessment of whether plans for further activities have been established or, if applicable, an evaluation of whether development will be decided on in the near future as described in section 1.8.A previously recognised impairment can only be reversed if changes have occurred in the estimates used for the calculation of the recoverable amount. GoodwillGoodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the value may be impaired. Impairment is recognised if the recoverable amount of the CGU (or group of CGUs) to which the goodwill is related is less than the book value, including associated goodwill and deferred tax as described in section 1.6. Losses relating to impairment of goodwill cannot be reversed in future periods.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__43": {
"value": "1.10 Financial instruments The group\u2019s financial assets and liabilities comprise non-listed equity instruments, derivative financial instruments (assets and liabilities), receivables, cash and cash equivalents, payables, other short-term liabilities and non-current liabilities. The classification of financial assets and liabilities at initial recognition depends on the financial instrument\u2019s contractual cash flow characteristics and the Group\u2019s business model for managing them. The company has classified the financial instruments into the following categories of financial assets and liabilities: \u2013 Financial assets at fair value through profit or loss \u2013 Financial assets measured at amortised cost \u2013 Financial liabilities at fair value through profit or loss \u2013 Financial liabilities measured at amortised costs \u2013 The group\u2019s financial instruments at amortised cost includes trade receivables with the objective hold to collect and other short-term deposits, trade payables and other current and non-current liabilities. Receivables are initially recognised at fair value less impairment losses.All borrowings are initially recognised at transaction price, which equals the fair value of the amount received net of costs directly related to the establishment of the loan or issuance of debt. Subsequently, interest-bearing borrowings are valued at amortised cost using the effective interest method; the difference between the transaction price (after transaction costs) and the face value is recognised in the Income statement in the period until the loan falls due. Amortised costs are calculated by considering all issue costs on the settlement date, except for any discount or premium expensed immediately.Financial liabilities that do not form part of the \u201cheld for trading purposes\u201d category and which have not been designated as being at fair value with changes in value through profit or loss are classified as other financial liabilities. Further details on fair values of financial instruments are provided in note 28 \u2018Financial instruments\u2019.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__45": {
"value": "1.12 Leases The lease liability is recognised at the commencement date and measured at the present value of the remaining lease payments, discounted using the company's incremental borrowing rate at the commence-ment date. The borrowing rate is derived from the terms of the company's existing credit facilities. Right-of-use (RoU) assets are depreciated over the lease term as this is ordinarily shorter than the useful life of the assets. The company applies the exemption for short term leases (12 months or less) and low value leases. As such, related lease payments are not recognised in the balance sheet, but expensed or capitalised in line with the accounting treatment for other non-lease expenses. The inclusion of non-lease components may vary across different lease categories, but for the most material class of assets (rigs), the company has excluded the non-lease components when measuring the lease liability.Lease agreements that are planned to be applied on several operated licences, are generally recognised on a gross basis as Aker BP is deemed to be the primary obligator. The company may enter into lease contracts as an operator on behalf of a licence, and may for such leases only recognise its net share of the related lease liability. Whether a contract is entered into on behalf of the licence is subject to a contract specific assessment, but the general principle is that there needs to be a direct link between the lease contract and the licence or field on which the RoU asset shall be used. For lease contracts recognised on a gross basis, the partner's share of the cost recovered by the company are presented as other income.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__47": {
"value": "1.13 Borrowing costs Borrowing costs that can be directly ascribed to procurement, processing or production of a qualifying asset are capitalised as part of the asset\u2019s acquisition cost. Borrowing cost is only capitalised during the development phase. Other borrowing costs are expensed in the period in which they are incurred. A qualifying asset is one that necessarily takes a substantial period of time to be made ready for its intended use or sale. Qualifying assets are generally those that are subject to major development or construction projects.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingCostsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__48": {
"value": "1.14 Inventories Inventories mainly consist of equipment for the drilling of exploration and production wells and are valued at the lower of cost price (based on weighted average cost) and net realisable value.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForMeasuringInventories",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__49": {
"value": "1.15 Cash and cash equivalents Cash and cash equivalents include cash, bank deposits, and other short-term highly liquid investments with an original due date of three months or less. Bank overdrafts are included in the Statement of Financial Position as short-term loans.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__50": {
"value": "1.16 Tax GeneralTax consists of tax payable and changes in deferred tax. Deferred tax/tax benefits are calculated on the basis of the differences between book value and tax basis values of assets and liabilities, with the exception of temporary differences on acquisition of licences that are defined as asset purchases.Deferred tax is measured using the expected tax rate when the tax benefit is realised or the tax liability is met, based on tax rates and tax regulations that have been enacted or substantively enacted at the reporting date.Tax payable and deferred tax is recognised directly against equity or other comprehensive income insofar as the tax items are related to equity transactions or items of other comprehensive income.Deferred tax and tax benefits are presented net, where netting is legally permitted and the deferred tax benefit and liability are related to the same tax subject and are payable to the same tax authorities.Functional currencyThe company\u2019s functional currency is USD, while it is a statutory requirement to calculate the current tax based on NOK functional currency. This may impact the effective tax rate when the exchange rate between NOK and USD fluctuates. The revaluation of tax receivable and payable is presented as foreign exchange gain/loss, while the impact on deferred tax from revaluation of tax balances is presented as tax expense / income.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__52": {
"value": "1.17 Provisions Decommissioning and removal costs: In accordance with the licence terms and conditions for the licences in which the company participates, the Norwegian State can require licence owners to remove the installation in whole or in part when production ceases or the licence period expires.In the initial recognition of the decommissioning and removal obligations, the company provides for the net present value of future costs related to decommissioning and removal based on its working interest in the respective fields. A corresponding asset is capitalised as a tangible fixed asset and depreciated using the unit-of-production method. Changes in the time value (net present value) of the obligation related to decommissioning and removal accretion are charged to income as financial expenses and increase the balance-sheet liability related to future decommissioning and removal expenses. Changes in the best estimate for expenses related to decommissioning and removal are recognised in the Statement of financial position (property, plant and equipment), except where it relates to licences with no future production or where the Company will be charged a portion of the liability as a user, i.e., based on shipped volumes. The discount rate used in the calculation of the fair value of the decommissioning and removal obligation is the risk-free rate.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__54": {
"value": "1.18 SegmentSince its formation, the company has conducted its entire business in one consistent segment, defined as exploration for and production of petroleum in Norway. The company conducts its activities on the Norwegian Continental Shelf, and management monitors the company at this level. The financial informa-tion relating to geographical distribution and large customers is presented in note 4.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForSegmentReportingExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__56": {
"value": "1.19 Changes to accounting standards and interpretations that: Have entered into force: The group has applied the following standards and amendment for the first time for their annual reporting period commencing 1 January 2023:Deferred Tax related to Assets and Liabilities arising from a Single Transaction (Amendments to IAS 12 Income taxes (IAS 12):The amendments to IAS 12 require companies to recognise deferred tax on particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences and will require the recognition of additional deferred tax assets and liabilities.The amendment should be applied to transactions that occur on or after the beginning of the earliest comparative period presented. In addition, entities should recognise deferred tax assets (to the extent that it is probable that they can be utilised) and deferred tax liabilities at the beginning of the earliest compara-tive period for all deductible and taxable temporary differences associated with: \u2013 right-of-use assets and lease liabilities, and \u2013 decommissioning, restoration and similar liabilities, and the corresponding amounts recognised as part of the cost of the related assets.The cumulative effect of recognising these adjustments is recognised in the opening balance of retained earnings, or another component of equity, as appropriate.IAS 12 did not previously address how to account for the tax effects of on balance sheet leases and similar transactions and various approaches were considered acceptable. Aker BP already accounted for such transactions consistent with the new requirements andthe application of the amendment did not have a material impact on the financial statements in 2023.Disclosure of Accounting Policies \u2013 Amendments to IAS 1 and IFRS Practice Statement 2:The IASB amended IAS 1 to require entities to disclose their material rather than their significant accounting policies. The amendments define what is \u2018material accounting policy information\u2019 (being infor-mation that, when considered together with other information included in an entity\u2019s financial statements, can reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements) and explain how to identify when accounting policy information is material. They further clarify that immaterial accounting policy information does not need to be disclosed. If it is disclosed, it should not obscure material accounting information.To support this amendment, the IASB also amended IFRS Practice Statement 2 Making Materiality Judgements to provide guidance on how to apply the concept of materiality to accounting policy disclo-sures. The application of the amendment did not have a material impact on the financial statements in 2023.Have been issued but have not entered into force: Certain new accounting standards and interpretations are issued, but not yet effective as of 31 December 2023. These standards are not expected to have a material impact on the group in the current or future reporting periods.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__55": {
"value": "1.19 Changes to accounting standards and interpretations that: Have entered into force: The group has applied the following standards and amendment for the first time for their annual reporting period commencing 1 January 2023:Deferred Tax related to Assets and Liabilities arising from a Single Transaction (Amendments to IAS 12 Income taxes (IAS 12):The amendments to IAS 12 require companies to recognise deferred tax on particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences and will require the recognition of additional deferred tax assets and liabilities.The amendment should be applied to transactions that occur on or after the beginning of the earliest comparative period presented. In addition, entities should recognise deferred tax assets (to the extent that it is probable that they can be utilised) and deferred tax liabilities at the beginning of the earliest compara-tive period for all deductible and taxable temporary differences associated with: \u2013 right-of-use assets and lease liabilities, and \u2013 decommissioning, restoration and similar liabilities, and the corresponding amounts recognised as part of the cost of the related assets.The cumulative effect of recognising these adjustments is recognised in the opening balance of retained earnings, or another component of equity, as appropriate.IAS 12 did not previously address how to account for the tax effects of on balance sheet leases and similar transactions and various approaches were considered acceptable. Aker BP already accounted for such transactions consistent with the new requirements andthe application of the amendment did not have a material impact on the financial statements in 2023.Disclosure of Accounting Policies \u2013 Amendments to IAS 1 and IFRS Practice Statement 2:The IASB amended IAS 1 to require entities to disclose their material rather than their significant accounting policies. The amendments define what is \u2018material accounting policy information\u2019 (being infor-mation that, when considered together with other information included in an entity\u2019s financial statements, can reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements) and explain how to identify when accounting policy information is material. They further clarify that immaterial accounting policy information does not need to be disclosed. If it is disclosed, it should not obscure material accounting information.To support this amendment, the IASB also amended IFRS Practice Statement 2 Making Materiality Judgements to provide guidance on how to apply the concept of materiality to accounting policy disclo-sures. The application of the amendment did not have a material impact on the financial statements in 2023.Have been issued but have not entered into force: Certain new accounting standards and interpretations are issued, but not yet effective as of 31 December 2023. These standards are not expected to have a material impact on the group in the current or future reporting periods.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesAccountingEstimatesAndErrorsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__57-1": {
"value": "Note 2 Overview of subsidiaries Aker BP UK Limited (100 percent)Aker BP UK Limited was established as a subsidiary of Det norske oljeselskap AS during 2020. The company holds two partner operated licences on the UK continental shelf, located to the borderline of the Norwegian continental shelf. The key objective within the licences is to explore the resource potential, based on the knowledge obtained in the Alvheim area.Aker BP ASA has three other subsidiaries which are not consolidated in the group accounts due to materiality considerations:Det norske oljeselskap AS (100 percent)Det norske oljeselskap AS, previously Marathon Oil Norge AS, was acquired by Aker BP in October 2014. All activity was transferred to Aker BP on 31 October 2014. During 2020, Aker BP UK Limited (see above) was established as a subsidiary of Det norske oljeselskap AS. Except for the subsidiary, the only asset in this company is cash equivalents reflecting the share capital amounting to USD 1.0 million.Alvheim AS (80 percent)The sole purpose of Alvheim AS is to act as legal owner of MST Alvheim, the floating production facility which is used to produce oil and gas from the Alvheim fields. The costs of and benefits from operating the MST Alvheim will be carried by the partners in the Alvheim field. Hence, Alvheim AS only has the formal ownership rather than the actual value of the production facilities. Following the Lundin transaction in 2022, Aker BP has a 80 percent share in Alvheim AS, which corresponds to the ownership in the Alvheim field. There were no activities in 2023.Sandvika Fjellstue AS (100 percent)Sandvika Fjellstue AS owns a conference centre used by Aker BP, located in Sandvika in Verdal.Note 18 Other non-current assetsGroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Shares in Alvheim AS 0.0 0.0 0.0 0.0Shares in Det norske oljeselskap AS 1.0 1.0 1.0 1.0Shares in Aker BP UK0.0 0.0 - -Shares in Sandvika Fjellstue AS 1.8 1.8 1.8 1.81)Investment in subsidiaries2.8 2.8 2.8 2.82)Continuing involvement - Cognite AS81.4 81.4 81.4 81.4Tenancy deposit - 1.6 - 1.63)Unamortised fees - RCF15.0 11.0 15.0 11.0Other non-current assets 3.6 7.6 3.6 7.6Total other non-current assets 102.9 104.5 102.9 104.51) Alvheim AS, Det norske oljeselskap AS and Sandvika Fjellstue AS have been deemed immaterial for consolidation purposes. All companies acquired in the Lundin transaction was either liquidated or merged with Aker BP ASA in 2022. For more information regarding shares in subsidiaries, see note 2.2) In 2022 the company sold its shares in Cognite AS to Saudi Aramco Development Company for a consideration of USD118 million. As part of the transaction, Aker BP has granted the buyer an option with maturity in November 2024 which under certain conditions gives the buyer the right to sell the shares back to Aker BP for USD 81.4 million. On this basis, Aker BP is considered to have continuing involvement in Cognite AS, in accordance with guidelines in IFRS 9. Hence, both an asset and a liability of USD 81.4 million is recognised in the statement of financial position at 31 December 2023. 3) Remaining unamortised fees related to the Revolving Credit Facility (RCF). These have been reclassified from other interest-bearing debt as the RCF was undrawn as at 31 December 2023 and 31 December 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__58": {
"value": "Note 4 Segment information The group's business is entirely related to exploration for and production of petroleum on, or to the borderline of, the Norwegian continental shelf. The group's activities are considered to have a homogeneous risk and return profile before tax, and the business is located in the geographical area Norway, except for two exploration licences in the UK. The group operates within a single operating segment which matches the internal reporting to the company's executive management. In 2023 the group had sales transactions with two customers which are under common control and represented more than 10 percent of total sales, BP Oil International Limited accounted for USD 11 591 million and BP Gas Marketing Limited accounted for USD 1 083 million. In 2022 sales transactions with BP Oil International Limited were USD 8 797 million, and sales transactions with BP Gas Marketing Limited were USD 2 820 million. In 2023 the parent company`s sales transactions with BP Oil International Limited accounted for USD 11 591 million and BP Gas Marketing Limited accounted for USD 1 083 million. In 2022 the parent company's sales transactions with BP Oil International Limited were USD 5 709 million, and sales transactions with BP Gas Marketing Limited were USD 2 820 million.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__64-1": {
"value": "Note 6 Production expensesGroup ParentProduction expenses (USD million) 2023 2022 2023 2022Cost of operations 707.6 682.7 707.6 597.6Shipping and handling 265.7 231.5 265.7 188.1Environmental taxes 62.9 63.9 62.9 54.4Production expenses based on produced volumes 1 036.3 978.1 1 036.3 840.0Adjustment for over (+)/underlift (-) 23.8 -45.3 23.8 -25.6Production expenses based on sold volumes 1 060.1 932.9 1 060.1 814.5Total produced volumes (boe million) 166.7 112.9 166.7 75.4Production expenses per boe produced (USD/boe) 6.2 8.7 6.2 11.1Note 7 Exploration expensesGroupParentBreakdown of exploration expenses (USD million) 2023 2022 2023 2022Seismic 27.2 34.4 26.7 30.0Area fees 14.4 12.3 14.4 13.3Field evaluation 13.5 10.7 13.5 8.1Dry well expenses 153.9 135.8 153.9 108.6G&G and other exploration expenses 57.5 48.9 56.0 36.2Total exploration expenses 266.3 242.2 264.3 196.2Note 8 Payroll expenses and remunerationGroup Parent Breakdown of payroll expenses (USD million) 2023 2022 2023 2022Payroll expenses 431.9 343.0 431.9 327.3Pension 41.1 34.0 41.1 32.2Social security tax 79.5 53.6 79.5 51.1Other personnel costs 19.7 20.4 19.7 19.8Total payroll expenses 572.1 451.0 572.1 430.4The payroll expenses are allocated to activities and partners based on timewriting. Aker BP's share of the total payroll expenses will depend amongst other on the ownership in the various licences. For 2023, the share of total payroll expenses to Aker BP was USD 406.1 million, equivalent to 71 percent of the gross expenses in the table above.GroupParentDepreciation in the Income statement (USD million) 2023 2022 2023 2022Depreciation of tangible fixed assets 2 170.6 1 675.2 2 170.6 1 141.1Depreciation of right-of-use assets 49.1 18.7 49.1 17.6Depreciation of other intangible assets 187.1 91.7 187.1 73.2Total depreciation in the Income statement 2 406.8 1 785.7 2 406.8 1 231.8Impairment in the Income statement (USD million)Impairment/reversal of tangible fixed assets34.0 385.6 34.0 385.6Impairment/reversal of other intangible assets42.9 258.3 42.9 -Impairment/reversal of capitalised exploration 20.4 10.9 20.4 10.9Impairment of goodwill792.2 377.4 792.2 -Total impairments of tangible and intangible assets 889.5 1 032.2 889.5 396.4See note 14 for information regarding impairment charges.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfExpensesByNatureExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__63-1": {
"value": "Note 6 Production expensesGroup ParentProduction expenses (USD million) 2023 2022 2023 2022Cost of operations 707.6 682.7 707.6 597.6Shipping and handling 265.7 231.5 265.7 188.1Environmental taxes 62.9 63.9 62.9 54.4Production expenses based on produced volumes 1 036.3 978.1 1 036.3 840.0Adjustment for over (+)/underlift (-) 23.8 -45.3 23.8 -25.6Production expenses based on sold volumes 1 060.1 932.9 1 060.1 814.5Total produced volumes (boe million) 166.7 112.9 166.7 75.4Production expenses per boe produced (USD/boe) 6.2 8.7 6.2 11.1Note 7 Exploration expensesGroupParentBreakdown of exploration expenses (USD million) 2023 2022 2023 2022Seismic 27.2 34.4 26.7 30.0Area fees 14.4 12.3 14.4 13.3Field evaluation 13.5 10.7 13.5 8.1Dry well expenses 153.9 135.8 153.9 108.6G&G and other exploration expenses 57.5 48.9 56.0 36.2Total exploration expenses 266.3 242.2 264.3 196.2Note 8 Payroll expenses and remunerationGroup Parent Breakdown of payroll expenses (USD million) 2023 2022 2023 2022Payroll expenses 431.9 343.0 431.9 327.3Pension 41.1 34.0 41.1 32.2Social security tax 79.5 53.6 79.5 51.1Other personnel costs 19.7 20.4 19.7 19.8Total payroll expenses 572.1 451.0 572.1 430.4The payroll expenses are allocated to activities and partners based on timewriting. Aker BP's share of the total payroll expenses will depend amongst other on the ownership in the various licences. For 2023, the share of total payroll expenses to Aker BP was USD 406.1 million, equivalent to 71 percent of the gross expenses in the table above.GroupParentDepreciation in the Income statement (USD million) 2023 2022 2023 2022Depreciation of tangible fixed assets 2 170.6 1 675.2 2 170.6 1 141.1Depreciation of right-of-use assets 49.1 18.7 49.1 17.6Depreciation of other intangible assets 187.1 91.7 187.1 73.2Total depreciation in the Income statement 2 406.8 1 785.7 2 406.8 1 231.8Impairment in the Income statement (USD million)Impairment/reversal of tangible fixed assets34.0 385.6 34.0 385.6Impairment/reversal of other intangible assets42.9 258.3 42.9 -Impairment/reversal of capitalised exploration 20.4 10.9 20.4 10.9Impairment of goodwill792.2 377.4 792.2 -Total impairments of tangible and intangible assets 889.5 1 032.2 889.5 396.4See note 14 for information regarding impairment charges.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfExpensesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__59": {
"value": "Note 5 IncomeGroupParentBreakdown of petroleum revenues (USD million) 2023 2022 2023 2022Sales of liquids 11 849.8 8 986.4 11 849.8 5 834.6Sales of gas 1 714.5 3 898.9 1 714.5 3 412.5 Tariff income 15.7 10.9 15.7 10.9 Total petroleum revenues 13 580.0 12 896.2 13 580.0 9 258.0 Sales of liquids (boe million) 145.2 91.8 145.2 57.8 Sales of gas (boe million) 23.1 20.2 23.1 17.6 Other income (USD million)Realised gain (+)/loss (-) on commodity derivatives -0.0 27.0 -0.0 27.0Unrealised gain (+)/loss (-) on commodity derivatives 0.2 9.0 0.2 9.0Gain on licence transactions 0.0 11.0 0.0 11.01)Other income89.7 66.7 89.7 64.3Total other income 89.9 113.7 89.9 111.31) The figure includes partner coverage of RoU assets recognised on gross basis in the balance sheet and used in operated activity.Refer to note 23 and 28 for further details regarding commodity derivatives.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRevenueExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__62": {
"value": "Other income (USD million)Realised gain (+)/loss (-) on commodity derivatives -0.0 27.0 -0.0 27.0Unrealised gain (+)/loss (-) on commodity derivatives 0.2 9.0 0.2 9.0Gain on licence transactions 0.0 11.0 0.0 11.01)Other income89.7 66.7 89.7 64.3Total other income 89.9 113.7 89.9 111.31) The figure includes partner coverage of RoU assets recognised on gross basis in the balance sheet and used in operated activity.Refer to note 23 and 28 for further details regarding commodity derivatives.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__61": {
"value": "Other income (USD million)Realised gain (+)/loss (-) on commodity derivatives -0.0 27.0 -0.0 27.0Unrealised gain (+)/loss (-) on commodity derivatives 0.2 9.0 0.2 9.0Gain on licence transactions 0.0 11.0 0.0 11.01)Other income89.7 66.7 89.7 64.3Total other income 89.9 113.7 89.9 111.31) The figure includes partner coverage of RoU assets recognised on gross basis in the balance sheet and used in operated activity.Refer to note 23 and 28 for further details regarding commodity derivatives.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExpenseExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__60": {
"value": "GroupParentBreakdown of petroleum revenues (USD million) 2023 2022 2023 2022Sales of liquids 11 849.8 8 986.4 11 849.8 5 834.6Sales of gas 1 714.5 3 898.9 1 714.5 3 412.5 Tariff income 15.7 10.9 15.7 10.9 Total petroleum revenues 13 580.0 12 896.2 13 580.0 9 258.0 Sales of liquids (boe million) 145.2 91.8 145.2 57.8 Sales of gas (boe million) 23.1 20.2 23.1 17.6",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__70": {
"value": "Pension schemesThe company complies with the requirement to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension (\u201clov om obligatorisk tjenestepensjon\u201d). The company makes contributions to the pension plan for full-time employees equal to 7 percent for salary up to 7.1 G and 25.1 percent between 7.1 and 12 G. The pension premiums are charged to expenses as they are incurred.An early retirement scheme (AFP) has been introduced for all employees. The scheme is a multi-employer defined benefit plan, but is accounted for as a defined contribution pension, and premiums are expensed as incurred.Employee share programThe company has an annual share purchase program for all employees, including senior executives. The shares in the program are offered at a 25 percent discount and are subject to a three-year lock-up during which employees are not allowed to sell the shares. In connection with the share purchase program, all employees are also offered an interest free loan of 60 percent of the basic amount in the National Insurance scheme (\"G\"), to be repaid within one year. In total, employees subscribed for USD 19.3 million in 2023, compared to USD 15.5 million in 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__72": {
"value": "Remuneration for BoD and the Executive Management Team (EMT) Information about remuneration to the BoD and EMT is provided in the Remuneration Report in the annual report. Accounting information regarding the share-based long-term incentive program (LTIP)The LTIP for members of the EMT is described in the Remuneration Report, while certain required accounting information is included below.The fair value of the grants issued in the LTIP has been measured using a Monte Carlo simulation. Service conditions were not taken into account when measuring fair value. The post-vesting lock-in condition has been incorporated into the grant date fair value by applying a discount to the valuation by estimating the probability that the employee will not comply with this condition. The LTIP agreement includes a clawback clause.The inputs used in the measurement of the 1 July 2023 grant date fair values were as follows: Fair value at grant date NOK 291.06Aker BP share price at grant date NOK 241.47Expected volatility:Aker BP39%Oslo Energy Index31%Stoxx 600 Europe Oil & Gas Index26%S&P Commodity Producers Oil & Gas E&P & Index34%Expected life3 yearsRisk free interest rate (based on government bonds)3.9%Expected volatility has been based on an evaluation of the historical volatility of the Company\u2019s share price, particularly over the historical period commensurate with the expected term. The expected term of the grants has been based on three-year vesting period.Total number of shares owned by members of EMTTotal number of shares Name2023*Karl Johnny Hersvik (Chief Executive Officer) 12 528Per Harald Kongelf (Chief Operating Officer) 5 546David Torvik T\u00f8nne (Chief Financial Officer)24 034Paula Doyle (Chief Digital Officer) 309Knut Arne Kristian Sandvik (SVP projects) 5 980Tommy Sigmundstad (SVP D&W) 10 451Per \u00d8yvind Seljebotn (SVP Exploration & Reservoir Development)619Marit Blaasmo (SVP People & Safety) 7 406Georg Olav Vidnes (SVP Operations) 2 857Ine Dolve (SVP Alvheim) 7 425Lars H\u00f8ier (SVP Yggdrasil)10 719Ole Johan Molvig (SVP Valhall) 18 140Thomas Hoff - Hansen (SVP Ula) 4 631Kari Nielsen (SVP Edvard Grieg & Ivar Aasen) 413Thomas \u00d8vretveit (SVP Skarv)743Total 111 801 *The numbers include shares held in companies where the senior executives have controlling interest. Remuneration and shares owned by the Board*The tables below include regular fees to the Board and fees for participation in the Board's subcommittees. The fees to the nomination committee are also included. To the extent applicable, fees to Board members employed in Aker ASA or BP plc groups will be paid to the companies, not to the Board member in person.20232022Fee Total number of Fee Total number of Name Comments(USD 1 000)shares(USD 1 000)shares\u00d8yvind EriksenChairman of the Board from 11.03.2016. Chair of the Organizational Development and Compensation committee. 92 - 96 -Anne Marie Cannon Deputy Chair from 17.04.2013. Member of the Audit & Risk committee and Organizational Development and Compensation committee. 66 12 078 69 12 0781)Kjell Inge R\u00f8kkeBoard member from 17.04.2013. 34 - 42 -Murray Auchincloss Board member from 16.04.2020. - - - -Trond Brandsrud Board member from 11.03.2016. Chairman of the Audit & Risk committee from 28.04.2016. 65 - 68 -Kate Thomson Board member from 30.09.2016. Member of the Audit & Risk committee from 04.10.2016. - - - -Valborg Lundegaard Board member from 05.04.2022. 40 - 28 -Charles Ashley Heppenstall Board member from 01.07.2022. 43 852 587 21 852 587Ingard Haugeberg Employee representative from 30.08.2018. 23 1 257 20 948Hilde K.Brevik Employee representative from 30.08.2018. Deputy employee rep. from 01.11.2023. 20 1 640 20 1 510Tore Vik Employee representative from 14.07.2021. 23 5 580 20 4 539Marit Karolin Hargemark D\u00f8rumEmployee representative from 01.11.2023. 3 706 N/A N/AAni Isabel Chiang Employee representative from 01.11.2023. 3 1 398 N/A N/ASarah Alexandra Berg Deputy employee representative from 14.07.2021. 3 2 572 3 2 225Rune Karstein Fauskanger Deputy employee representative from 14.07.2021. 3 9 479 3 7 888Thomas Husv\u00e6g Deputy employee representative from 07.07.2021. Employee representative from 01.11.2023. 6 441 3 132Geir Smaaskj\u00e6rDeputy employee representative from 01.11.2023. 1 2 399 N/A N/ATerje SolheimEmployee representative from 20.03.2014. Member of the Organizational Development and Compensation committee until 23 63724 63731.10.2023. Deputy employee representative from 01.11.2023.Svein Oskar Stoknes Chair of the Nomination committee from 16.04.2020. 5 - 4 -Ingebret Hisdal Member of the Nomination committee from 16.04.2020. 4 - 4 -Donna Riley Member of the Nomination committee from 16.04.2020. - - - -Ian Lundin Member og the Nomination committee from 14.04.2023. 4 - N/A N/AMember until 31.10.2023\u00d8rjan Kristensen BrakstadDeputy employee representative from 14.07.2021 until 31.10.2023. 2 374 3 420Member until 05.04.2022Paula Doyle Board member from 15.04.2021 until 05.04.2022. N/A N/A 14 -Total 463 891 148445 882 964 1) Kjell Inge R\u00f8kke owns and controls The Resource Group AS, which controls 68 percent of Aker ASA, which through a subsidiary owns 21 percent of Aker BP* Fee to board members are paid in NOK and converted to USD using a yearly average USD/NOK-rate of 10.5647 for 2023. Corresponding rate for 2022 was 9.6245.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__69": {
"value": "Remuneration for BoD and the Executive Management Team (EMT) Information about remuneration to the BoD and EMT is provided in the Remuneration Report in the annual report. Accounting information regarding the share-based long-term incentive program (LTIP)The LTIP for members of the EMT is described in the Remuneration Report, while certain required accounting information is included below.The fair value of the grants issued in the LTIP has been measured using a Monte Carlo simulation. Service conditions were not taken into account when measuring fair value. The post-vesting lock-in condition has been incorporated into the grant date fair value by applying a discount to the valuation by estimating the probability that the employee will not comply with this condition. The LTIP agreement includes a clawback clause.The inputs used in the measurement of the 1 July 2023 grant date fair values were as follows: Fair value at grant date NOK 291.06Aker BP share price at grant date NOK 241.47Expected volatility:Aker BP39%Oslo Energy Index31%Stoxx 600 Europe Oil & Gas Index26%S&P Commodity Producers Oil & Gas E&P & Index34%Expected life3 yearsRisk free interest rate (based on government bonds)3.9%Expected volatility has been based on an evaluation of the historical volatility of the Company\u2019s share price, particularly over the historical period commensurate with the expected term. The expected term of the grants has been based on three-year vesting period.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__71": {
"value": "Group Parent No. of full time equivalents employed during the year 2023 2022 2023 2022Europe 2 562 2 462 2 562 2 036Total 2 562 2 462 2 562 2 036",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInformationAboutEmployeesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__73": {
"value": "Note 9 Auditors feeGroupParent(USD 1 000) 2023 2022 2023 2022Fees for statutory audit services - PWC (excluding VAT) 341 230 310200 Fees for statutory audit services - KPMG (excluding VAT) - 132 - 132Fees for other services - PWC (excluding VAT) 598 533 598 533Fees for other services - KPMG (excluding VAT) - 202 - 202Total auditor's fees 939 1 098 907 1 068KMPG was the statutory auditor of Aker BP until April 2022, and was then replaced by PwC.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__82": {
"value": "Note 11 TaxesGroupParentTax for the period (USD million) 2023 2022 2023 2022Current year tax payable/receivable 6 136.4 7 163.0 6 136.4 4 826.1Current tax related to change in tax system - -176.4 - -176.4Prior period adjustments to current tax 58.8 -17.8 58.8 -19.0Current tax expense (+)/income (-) 6 195.2 6 968.8 6 195.2 4 630.7Change in current year deferred tax 1 200.5 -12.3 1 200.5 240.8Deferred tax related to change in tax system - 189.4 - 189.4Prior period adjustments to deferred tax 32.7 27.9 32.7 27.9Deferred tax expense (+)/ income (-) 1 233.1 205.1 1 233.1 458.2Tax expense (+)/income (-) 7 428.3 7 173.9 7 428.3 5 088.9Effective tax rate 85% 82 % 85% 82 %GroupParentReconciliation of tax expense (USD million)Tax rate2023 2022 2023 202278% tax rate on profit/loss before tax 78% 6 836.3 6 846.3 6 838.2 4 845.2Tax effect of uplift 72% -209.9 -161.7 -209.9 -148.9Permanent differences on impairment 78% 618.0 294.4 618.0 338.7FX translation of monetary items other than USD 78% -112.0 -170.6 -112.0 -170.6FX translation of monetary items other than NOK 78% -17.8 129.6 -17.8 129.6Tax effect of financial and other 22% items 56% 180.3 60.1 180.3 -33.61)Currency movements of tax balances78% 29.1 138.9 29.1 138.9Other permanent differences, prior period 78%104.436.9102.5-10.5adjustments and change in uncertain tax positionsTax expense (+)/income (-) 7 428.3 7 173.9 7 428.3 5 088.91) Tax balances are in NOK and converted to USD using the period end currency rate. When the NOK weakens againstUSD, the tax rate increases as there is less remaining tax depreciation measured in USD.From 1 January 2023 the temporary tax regime uplift rate was reduced from 17.69 to 12.40 percent.In accordance with statutory requirements, the calculation of current tax is required to be based on NOK functional currency. This may impact the effective tax rate as the company's functional currency is USD.Breakdown of tax effect of temporary GroupParentdifferences (USD million)2023 2022 2023 2022Tangible fixed assets -13 108.4 -11 057.2 -13 108.4 -11 057.2Capitalised exploration cost -253.8 -196.4 -253.8 -196.4Other intangible assets -1 301.8 -1 470.4 -1 301.8 -1 470.4Abandonment provision 3 552.8 3 249.3 3 552.8 3 249.3Lease debt 549.3 104.8 549.3 104.8Financial instruments -34.7 -26.4 -34.7 -26.4Other provisions 4.3 37.1 4.3 37.1 Net deferred tax liability (-)/deferred tax asset (+) -10 592.3 -9 359.1 -10 592.3 -9 359.1GroupParentDeferred tax liability (-)/asset (+) (USD million)2023 2022 2023 2022Deferred tax liability/asset at beginning of period -9 359.1 -3 291.3 -9 359.1 -3 291.3Change in current year deferred tax -1 200.5 12.3 -1 200.5 -240.8Deferred tax related to change in tax system - -189.4 - -189.4Deferred tax related to acquisition of Lundin Energy - -5 802.6 - -Change related to merger of group companies - - - -5 607.8Prior period adjustments -32.7 -27.9 -32.7 -29.7Deferred tax charged to OCI and equity -0.0 -60.1 -0.0 0.0Net deferred tax liability (-)/deferred tax asset (+) -10 592.3 -9 359.1 -10 592.3 -9 359.1GroupParentCalculated tax payable (-)/ tax receivable (+) (USD million) 2023 2022 2023 2022Tax payable/receivable at beginning of period -5 084.1 -1 497.3 -5 084.1 -1 497.3Current year tax payable/receivable -6 136.4 -7 163.0 -6 136.4 -4 826.1Current tax related to change in tax system - 176.4 - 176.4Net tax payment/tax refund 7 455.2 5 332.1 7 455.2 3 205.5Current tax related to acquisition of Lundin Energy - -2 181.0 - -Current tax related to merger of group companies - - - -2 427.2Change prior periods and uncertain tax positions -58.4 29.8 -58.4 31.1Currency movements of tax payable/receivable 223.9 245.8 223.9 253.4Current tax charged to OCI and equity - -27.1 - -Net tax payable (-)/receivable (+) -3 599.9 -5 084.1 -3 599.9 -5 084.1",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__80-1": {
"value": "Note 11 TaxesGroupParentTax for the period (USD million) 2023 2022 2023 2022Current year tax payable/receivable 6 136.4 7 163.0 6 136.4 4 826.1Current tax related to change in tax system - -176.4 - -176.4Prior period adjustments to current tax 58.8 -17.8 58.8 -19.0Current tax expense (+)/income (-) 6 195.2 6 968.8 6 195.2 4 630.7Change in current year deferred tax 1 200.5 -12.3 1 200.5 240.8Deferred tax related to change in tax system - 189.4 - 189.4Prior period adjustments to deferred tax 32.7 27.9 32.7 27.9Deferred tax expense (+)/ income (-) 1 233.1 205.1 1 233.1 458.2Tax expense (+)/income (-) 7 428.3 7 173.9 7 428.3 5 088.9Effective tax rate 85% 82 % 85% 82 %Breakdown of tax effect of temporary GroupParentdifferences (USD million)2023 2022 2023 2022Tangible fixed assets -13 108.4 -11 057.2 -13 108.4 -11 057.2Capitalised exploration cost -253.8 -196.4 -253.8 -196.4Other intangible assets -1 301.8 -1 470.4 -1 301.8 -1 470.4Abandonment provision 3 552.8 3 249.3 3 552.8 3 249.3Lease debt 549.3 104.8 549.3 104.8Financial instruments -34.7 -26.4 -34.7 -26.4Other provisions 4.3 37.1 4.3 37.1 Net deferred tax liability (-)/deferred tax asset (+) -10 592.3 -9 359.1 -10 592.3 -9 359.1GroupParentDeferred tax liability (-)/asset (+) (USD million)2023 2022 2023 2022Deferred tax liability/asset at beginning of period -9 359.1 -3 291.3 -9 359.1 -3 291.3Change in current year deferred tax -1 200.5 12.3 -1 200.5 -240.8Deferred tax related to change in tax system - -189.4 - -189.4Deferred tax related to acquisition of Lundin Energy - -5 802.6 - -Change related to merger of group companies - - - -5 607.8Prior period adjustments -32.7 -27.9 -32.7 -29.7Deferred tax charged to OCI and equity -0.0 -60.1 -0.0 0.0Net deferred tax liability (-)/deferred tax asset (+) -10 592.3 -9 359.1 -10 592.3 -9 359.1",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__79": {
"value": "Note 10 Financial itemsGroupParent(USD million) 2023 2022 2023 2022 Total interest income 133.4 26.0 133.4 23.0Realised gains on derivatives 83.4 33.5 83.4 33.5Change in fair value of derivatives 48.6 333.7 48.6 333.7Net currency gains 144.8 308.4 145.5 193.9Other financial income 44.5 98.8 44.5 98.8Total other financial income 321.2 774.3 322.0 659.8Interest expenses 212.7 154.0 212.7 147.3 Interest on lease debt 26.9 7.5 26.9 7.1 Capitalised interest cost, development projects -127.1 -85.6 -127.1 -53.3 1)Amortised loan costs49.3 31.8 49.3 19.2 Total interest expenses 161.8 107.7 161.8 120.2 Net currency loss - 269.4 - -Realised loss on derivatives 345.2 480.9 345.2 480.9Change in fair value of derivatives - - - - Accretion expenses related to abandonment provisions 166.3 119.9 166.3 107.9Other financial expenses 6.7 9.8 6.7 8.2Total other financial expenses 518.2 880.1 518.2 597.1Net financial items -225.4 -187.6 -224.7 -34.51) The figure includes amortisation of the difference between fair value and nominal value on the bonds aquired in theLundin transaction in Q2 2022.The rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalisation in 2023 is 4.34 percent. The corresponding rate for 2022 was 3.69 percent. Climate-related risk:As described in note 3 on climate-related risk, a sensitivity analysis have been performed to show the estimated impact of a two percentage points increase in credit spreads on current loan balances as of 31 December 2023 . This would result in an increased interest expenses of USD 120 million.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__78": {
"value": "Note 10 Financial itemsGroupParent(USD million) 2023 2022 2023 2022 Total interest income 133.4 26.0 133.4 23.0Realised gains on derivatives 83.4 33.5 83.4 33.5Change in fair value of derivatives 48.6 333.7 48.6 333.7Net currency gains 144.8 308.4 145.5 193.9Other financial income 44.5 98.8 44.5 98.8Total other financial income 321.2 774.3 322.0 659.8Interest expenses 212.7 154.0 212.7 147.3 Interest on lease debt 26.9 7.5 26.9 7.1 Capitalised interest cost, development projects -127.1 -85.6 -127.1 -53.3 1)Amortised loan costs49.3 31.8 49.3 19.2 Total interest expenses 161.8 107.7 161.8 120.2 Net currency loss - 269.4 - -Realised loss on derivatives 345.2 480.9 345.2 480.9Change in fair value of derivatives - - - - Accretion expenses related to abandonment provisions 166.3 119.9 166.3 107.9Other financial expenses 6.7 9.8 6.7 8.2Total other financial expenses 518.2 880.1 518.2 597.1Net financial items -225.4 -187.6 -224.7 -34.51) The figure includes amortisation of the difference between fair value and nominal value on the bonds aquired in theLundin transaction in Q2 2022.The rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalisation in 2023 is 4.34 percent. The corresponding rate for 2022 was 3.69 percent. Climate-related risk:As described in note 3 on climate-related risk, a sensitivity analysis have been performed to show the estimated impact of a two percentage points increase in credit spreads on current loan balances as of 31 December 2023 . This would result in an increased interest expenses of USD 120 million.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__77": {
"value": "Note 10 Financial itemsGroupParent(USD million) 2023 2022 2023 2022 Total interest income 133.4 26.0 133.4 23.0Realised gains on derivatives 83.4 33.5 83.4 33.5Change in fair value of derivatives 48.6 333.7 48.6 333.7Net currency gains 144.8 308.4 145.5 193.9Other financial income 44.5 98.8 44.5 98.8Total other financial income 321.2 774.3 322.0 659.8Interest expenses 212.7 154.0 212.7 147.3 Interest on lease debt 26.9 7.5 26.9 7.1 Capitalised interest cost, development projects -127.1 -85.6 -127.1 -53.3 1)Amortised loan costs49.3 31.8 49.3 19.2 Total interest expenses 161.8 107.7 161.8 120.2 Net currency loss - 269.4 - -Realised loss on derivatives 345.2 480.9 345.2 480.9Change in fair value of derivatives - - - - Accretion expenses related to abandonment provisions 166.3 119.9 166.3 107.9Other financial expenses 6.7 9.8 6.7 8.2Total other financial expenses 518.2 880.1 518.2 597.1Net financial items -225.4 -187.6 -224.7 -34.51) The figure includes amortisation of the difference between fair value and nominal value on the bonds aquired in theLundin transaction in Q2 2022.The rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalisation in 2023 is 4.34 percent. The corresponding rate for 2022 was 3.69 percent. Climate-related risk:As described in note 3 on climate-related risk, a sensitivity analysis have been performed to show the estimated impact of a two percentage points increase in credit spreads on current loan balances as of 31 December 2023 . This would result in an increased interest expenses of USD 120 million.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__76": {
"value": "Note 10 Financial itemsGroupParent(USD million) 2023 2022 2023 2022 Total interest income 133.4 26.0 133.4 23.0Realised gains on derivatives 83.4 33.5 83.4 33.5Change in fair value of derivatives 48.6 333.7 48.6 333.7Net currency gains 144.8 308.4 145.5 193.9Other financial income 44.5 98.8 44.5 98.8Total other financial income 321.2 774.3 322.0 659.8Interest expenses 212.7 154.0 212.7 147.3 Interest on lease debt 26.9 7.5 26.9 7.1 Capitalised interest cost, development projects -127.1 -85.6 -127.1 -53.3 1)Amortised loan costs49.3 31.8 49.3 19.2 Total interest expenses 161.8 107.7 161.8 120.2 Net currency loss - 269.4 - -Realised loss on derivatives 345.2 480.9 345.2 480.9Change in fair value of derivatives - - - - Accretion expenses related to abandonment provisions 166.3 119.9 166.3 107.9Other financial expenses 6.7 9.8 6.7 8.2Total other financial expenses 518.2 880.1 518.2 597.1Net financial items -225.4 -187.6 -224.7 -34.51) The figure includes amortisation of the difference between fair value and nominal value on the bonds aquired in theLundin transaction in Q2 2022.The rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalisation in 2023 is 4.34 percent. The corresponding rate for 2022 was 3.69 percent. Climate-related risk:As described in note 3 on climate-related risk, a sensitivity analysis have been performed to show the estimated impact of a two percentage points increase in credit spreads on current loan balances as of 31 December 2023 . This would result in an increased interest expenses of USD 120 million.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceCostExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__75": {
"value": "Note 10 Financial itemsGroupParent(USD million) 2023 2022 2023 2022 Total interest income 133.4 26.0 133.4 23.0Realised gains on derivatives 83.4 33.5 83.4 33.5Change in fair value of derivatives 48.6 333.7 48.6 333.7Net currency gains 144.8 308.4 145.5 193.9Other financial income 44.5 98.8 44.5 98.8Total other financial income 321.2 774.3 322.0 659.8Interest expenses 212.7 154.0 212.7 147.3 Interest on lease debt 26.9 7.5 26.9 7.1 Capitalised interest cost, development projects -127.1 -85.6 -127.1 -53.3 1)Amortised loan costs49.3 31.8 49.3 19.2 Total interest expenses 161.8 107.7 161.8 120.2 Net currency loss - 269.4 - -Realised loss on derivatives 345.2 480.9 345.2 480.9Change in fair value of derivatives - - - - Accretion expenses related to abandonment provisions 166.3 119.9 166.3 107.9Other financial expenses 6.7 9.8 6.7 8.2Total other financial expenses 518.2 880.1 518.2 597.1Net financial items -225.4 -187.6 -224.7 -34.51) The figure includes amortisation of the difference between fair value and nominal value on the bonds aquired in theLundin transaction in Q2 2022.The rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalisation in 2023 is 4.34 percent. The corresponding rate for 2022 was 3.69 percent. Climate-related risk:As described in note 3 on climate-related risk, a sensitivity analysis have been performed to show the estimated impact of a two percentage points increase in credit spreads on current loan balances as of 31 December 2023 . This would result in an increased interest expenses of USD 120 million.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__74": {
"value": "Note 10 Financial itemsGroupParent(USD million) 2023 2022 2023 2022 Total interest income 133.4 26.0 133.4 23.0Realised gains on derivatives 83.4 33.5 83.4 33.5Change in fair value of derivatives 48.6 333.7 48.6 333.7Net currency gains 144.8 308.4 145.5 193.9Other financial income 44.5 98.8 44.5 98.8Total other financial income 321.2 774.3 322.0 659.8Interest expenses 212.7 154.0 212.7 147.3 Interest on lease debt 26.9 7.5 26.9 7.1 Capitalised interest cost, development projects -127.1 -85.6 -127.1 -53.3 1)Amortised loan costs49.3 31.8 49.3 19.2 Total interest expenses 161.8 107.7 161.8 120.2 Net currency loss - 269.4 - -Realised loss on derivatives 345.2 480.9 345.2 480.9Change in fair value of derivatives - - - - Accretion expenses related to abandonment provisions 166.3 119.9 166.3 107.9Other financial expenses 6.7 9.8 6.7 8.2Total other financial expenses 518.2 880.1 518.2 597.1Net financial items -225.4 -187.6 -224.7 -34.51) The figure includes amortisation of the difference between fair value and nominal value on the bonds aquired in theLundin transaction in Q2 2022.The rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalisation in 2023 is 4.34 percent. The corresponding rate for 2022 was 3.69 percent. Climate-related risk:As described in note 3 on climate-related risk, a sensitivity analysis have been performed to show the estimated impact of a two percentage points increase in credit spreads on current loan balances as of 31 December 2023 . This would result in an increased interest expenses of USD 120 million.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__84": {
"value": "Note 12 Earnings per shareEarnings per share is calculated by dividing the year's profit attributable to ordinary equity holders of the parent entity, which was USD 1 336 million for the group (USD 1 603 million in 2022) and USD 1 338 million for the parent (USD 1 123 million in 2022) by the year's weighted average number of outstanding ordinary shares, which was 631.3 million (496.8 million in 2022). Weighted average number of diluted and ordinary shares is the same, as the company does not have any material dilutive instruments.GroupParent(USD million) 2023 2022 2023 20221)Profit for the year1 335.7 1 602.9 1 338.2 1 122.6The year's average number of ordinary shares (in million)631.3 496.8 631.3 496.8Earnings per share in USD 2.12 3.23 2.12 2.261) Attributable to ordinary equity holders of the parent entity",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__83": {
"value": "GroupParentDeferred tax liability (-)/asset (+) (USD million)2023 2022 2023 2022Deferred tax liability/asset at beginning of period -9 359.1 -3 291.3 -9 359.1 -3 291.3Change in current year deferred tax -1 200.5 12.3 -1 200.5 -240.8Deferred tax related to change in tax system - -189.4 - -189.4Deferred tax related to acquisition of Lundin Energy - -5 802.6 - -Change related to merger of group companies - - - -5 607.8Prior period adjustments -32.7 -27.9 -32.7 -29.7Deferred tax charged to OCI and equity -0.0 -60.1 -0.0 0.0Net deferred tax liability (-)/deferred tax asset (+) -10 592.3 -9 359.1 -10 592.3 -9 359.1GroupParentCalculated tax payable (-)/ tax receivable (+) (USD million) 2023 2022 2023 2022Tax payable/receivable at beginning of period -5 084.1 -1 497.3 -5 084.1 -1 497.3Current year tax payable/receivable -6 136.4 -7 163.0 -6 136.4 -4 826.1Current tax related to change in tax system - 176.4 - 176.4Net tax payment/tax refund 7 455.2 5 332.1 7 455.2 3 205.5Current tax related to acquisition of Lundin Energy - -2 181.0 - -Current tax related to merger of group companies - - - -2 427.2Change prior periods and uncertain tax positions -58.4 29.8 -58.4 31.1Currency movements of tax payable/receivable 223.9 245.8 223.9 253.4Current tax charged to OCI and equity - -27.1 - -Net tax payable (-)/receivable (+) -3 599.9 -5 084.1 -3 599.9 -5 084.1",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTaxReceivablesAndPayablesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__86-1": {
"value": "Note 13 Tangible fixed assets and intangible assetsTANGIBLE FIXED ASSETSGGRROOUUPPPPAARREENNTTProperty, plant and equipmentProduction Fixtures and Production Fixtures and Assets under facilities including fittings, office Assets under facilities including fittings, office (USD million)developmentwellsmachinery Total groupdevelopmentwellsmachinery Total parentRestated book value 31.12.2021 1 795.4 8 332.3 86.7 10 214.4 1 795.4 8 332.3 86.7 10 214.4Restated acquisition cost 31.12.2021 1 795.4 13 403.0 256.4 15 454.9 1 795.4 13 403.0 256.4 15 454.91)Additions1 036.0 -1 203.1 18.2 -148.9 834.8 -1 181.6 18.1 -328.7Acquisition of Lundin Energy 933.2 6 726.3 3.8 7 663.3 - - - -Merger with ABP Norway AS - - - - 146.7 7 245.4 2.8 7 394.9Disposals/retirement - - 17.5 17.5 - - 17.5 17.52)Reclassification-2 132.6 2 266.6 7.3 141.3 -1 162.7 1 288.1 7.3 132.6Foreign currency translation -17.9 108.1 0.0 90.3 - - - -Acquisition cost 31.12.2022 1 614.2 21 301.0 268.3 23 183.5 1 614.2 20 754.9 267.2 22 636.3Restated accumulated depreciation and impairments 31.12.2021 - 5 070.7 169.7 5 240.5 - 5 070.7 169.7 5 240.5Depreciation - 1 635.3 39.9 1 675.2 - 1 102.2 38.8 1 141.1Impairment/reversal (-) - 385.6 - 385.6 - 385.6 - 385.6Disposals/retirement depreciation - - -17.5 -17.5 - - -17.5 -17.5Foreign currency translation - 13.0 0.0 13.0 - - - -Accumulated depreciation and impairments 31.12.2022 - 7 104.6 192.2 7 296.8 - 6 558.5 191.1 6 749.6Book value 31.12.2022 1 614.2 14 196.4 76.1 15 886.7 1 614.2 14 196.4 76.1 15 886.7Acquisition cost 31.12.2022 1 614.2 21 301.0 268.3 23 183.5 1 614.2 20 754.9 267.2 22 636.3Additions 2 671.6 990.6 10.8 3 673.0 2 671.6 990.6 10.8 3 673.0Disposals/retirement - - - - - - - -3)Reclassification-728.9 820.3 3.2 94.7 -728.9 820.3 3.2 94.7Acquisition cost 31.12.2023 3 556.9 23 111.9 282.3 26 951.2 3 556.9 22 565.8 281.2 26 404.0Accumulated depreciation and impairments 31.12.2022 - 7 104.6 192.2 7 296.8 - 6 558.5 191.1 6 749.6Depreciation - 2 135.0 35.6 2 170.6 - 2 135.0 35.6 2 170.6Impairment/reversal (-) 34.0 - - 34.0 34.0 - - 34.0Disposals/retirement depreciation - - - - - - - -Accumulated depreciation and impairments 31.12.2023 34.0 9 239.6 227.8 9 501.4 34.0 8 693.5 226.6 8 954.2Book value 31.12.2023 3 522.9 13 872.3 54.5 17 449.8 3 522.9 13 872.3 54.5 17 449.81) The negative addition is caused by decreased abandonment provision with an offseting entry on PP&E2) The reclassification is mainly related to the Johans Sverdrup phase 2 development project, which entered into production phase during 20223) The reclassification is mainly related to the Kobra East Gekko and Frosk development projects, which entered into production phase during 2023See note 14 for information regarding impairment charges.Capitalised exploration expenditures are reclassified to \"Assets under development\" when the field enters into the development phase. If development plans are subsequently re-evaluated, the associated costs remain in assets under development and are not reclassified back to exploration assets. Assets under development are reclassified to \"Production facilities\" from the start of production. Production facilities, including wells, are depreciated in accordance with the unit-of-production method. Office machinery, fixtures and fittings etc. are depreciated using the straight-line method over their useful life, i.e. 3 - 5 years. Removal and decommissioning costs are included as production facilities or assets under development.GROUPPARENTRight-of-use assetsVessels and Vessels and (USD million)Drilling Rigs Office Other Drilling Rigs BoatsTotal BoatsBook value 31.12.2021 12.3 50.7 29.3 1.8 94.2 12.3 50.7 29.3 1.8 94.2Acquisition cost 31.12.2021 18.4 57.4 52.4 2.3 130.6 18.4 57.4 52.4 2.3 130.6Additions 22.5 - 11.2 - 33.8 22.5 - 31.9 - 54.4Acquisition of Lundin Energy 11.1 - 23.7 - 34.8 - - - - -Merger with ABP Norway AS - - - - - 6.0 - - - 6.0Allocated to abandonment activity - -0.4 - - -0.4 - -0.4 - - -0.4Disposals/retirement 6.1 0.0 8.1 - 14.2 6.1 0.0 8.1 - 14.21)Reclassification-28.1 -2.3 - - -30.4 -23.0 -2.3 - - -25.4Foreign currency translation -0.0 - -2.0 - -2.0 - - - - -Acquisition cost 31.12.2022 17.9 54.7 77.3 2.3 152.2 17.9 54.7 76.2 2.3 151.1Accumulated depreciation and impairments 31.12.2021 6.1 6.7 23.1 0.5 36.4 6.1 6.7 23.1 0.5 3366..44Depreciation 2.8 3.9 11.8 0.2 18.7 2.8 3.9 10.7 0.2 17.6Impairment/reversal (-) - - - - - - - - - -Disposals/retirement depreciation -6.1 - -8.1 - -14.2 -6.1 - -8.1 - -14.2Foreign currency translation - - -0.1 - -0.1 - - - - -Accumulated depreciation and impairments 31.12.2022 2.8 10.6 26.7 0.7 40.8 2.8 10.6 25.6 0.7 39.8Book value 31.12.2022 15.1 44.1 50.6 1.6 111.3 15.1 44.1 50.6 1.6 111.3Acquisition cost 31.12.2022 17.9 54.7 77.3 2.3 152.2 17.9 54.7 76.2 2.3 151.1Additions 685.3 - 19.2 - 704.5 685.3 - 19.2 - 704.5Allocated to abandonment activity -6.4 -1.1 - - -7.5 -6.4 -1.1 - - -7.5Disposals/retirement 4.2 - - - 4.2 4.2 - - - 4.21)Reclassification-101.5 -2.4 - - -103.9 -101.5 -2.4 - - -103.9Acquisition cost 31.12.2023 591.0 51.2 96.5 2.3 741.1 591.0 51.2 95.5 2.3 740.0Accumulated depreciation and impairments 31.12.2022 2.8 10.6 26.7 0.7 40.8 2.8 10.6 25.6 0.7 39.8Depreciation 31.0 3.1 14.7 0.2 49.1 31.0 3.1 14.7 0.2 49.1Impairment/reversal (-) - - - - - - - - - -Disposals/retirement depreciation -4.2 - - - -4.2 -4.2 - - - -4.2Accumulated depreciation and impairments 31.12.2023 29.7 13.8 41.4 0.9 85.7 29.7 13.8 40.4 0.9 84.7Book value 31.12.2023 561.4 37.4 55.1 1.4 655.3 561.4 37.4 55.1 1.4 655.31) Reclassified to tangible fixed assets in line with the activity of the right-of-use assetSee note 25 for information regarding leases.Right-of-use assets are depreciated linearly over the lifetime of the related lease contract.Note 22 Provision for abandonment liabilities GroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022 Provisions as of beginning of period 4 165.6 5 172.4 4 165.6 5 172.4 Incurred removal cost -160.2 -79.2 -160.2 -78.5 Accretion expense 166.3 119.9 166.3 107.9 Abandonment liabilities from acquisition of Lundin Energy - 745.9 - - Merger with ABP Norway AS - - - 598.6 Foreign currency translation - 6.7 - - Impact of changes to discount rate -101.2 -1 876.9 -101.2 -1 747.7Change in estimates and new provisions 484.1 76.9 484.1 113.0 Total provision for abandonment liabilities 4 554.7 4 165.6 4 554.7 4 165.6 Breakdown of the provisionShort-term 250.6 115.2 250.6 115.2 Long-term 4 304.1 4 050.4 4 304.1 4 050.4 Total provision for abandonment liabilities 4 554.7 4 165.6 4 554.7 4 165.6 Estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The nominal pre tax discount rate (risk free) at end of 2023 is between 4.0 percent and 4.9 percent, depending on the timing of the expected cash flows. The corresponding range at year end 2022 was between 3.9 and 4.7. The calculations assume an inflation rate of 2.0 percent for all applicable periods.Climate-related risk:As described in note 3 on climate-related risk, a sensitivity analysis have been performed to show the impact on the book value of abandonment provisions as at 31 December 2023, if cease of production of fields with estimated lifetime from 2040 were accelerated by ten years. Such acceleration would result in an increase in the book value of abandonment provision of USD 680 million.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAssetsAndLiabilitiesWithSignificantRiskOfMaterialAdjustmentExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__85": {
"value": "Note 13 Tangible fixed assets and intangible assetsTANGIBLE FIXED ASSETSGGRROOUUPPPPAARREENNTTProperty, plant and equipmentProduction Fixtures and Production Fixtures and Assets under facilities including fittings, office Assets under facilities including fittings, office (USD million)developmentwellsmachinery Total groupdevelopmentwellsmachinery Total parentRestated book value 31.12.2021 1 795.4 8 332.3 86.7 10 214.4 1 795.4 8 332.3 86.7 10 214.4Restated acquisition cost 31.12.2021 1 795.4 13 403.0 256.4 15 454.9 1 795.4 13 403.0 256.4 15 454.91)Additions1 036.0 -1 203.1 18.2 -148.9 834.8 -1 181.6 18.1 -328.7Acquisition of Lundin Energy 933.2 6 726.3 3.8 7 663.3 - - - -Merger with ABP Norway AS - - - - 146.7 7 245.4 2.8 7 394.9Disposals/retirement - - 17.5 17.5 - - 17.5 17.52)Reclassification-2 132.6 2 266.6 7.3 141.3 -1 162.7 1 288.1 7.3 132.6Foreign currency translation -17.9 108.1 0.0 90.3 - - - -Acquisition cost 31.12.2022 1 614.2 21 301.0 268.3 23 183.5 1 614.2 20 754.9 267.2 22 636.3Restated accumulated depreciation and impairments 31.12.2021 - 5 070.7 169.7 5 240.5 - 5 070.7 169.7 5 240.5Depreciation - 1 635.3 39.9 1 675.2 - 1 102.2 38.8 1 141.1Impairment/reversal (-) - 385.6 - 385.6 - 385.6 - 385.6Disposals/retirement depreciation - - -17.5 -17.5 - - -17.5 -17.5Foreign currency translation - 13.0 0.0 13.0 - - - -Accumulated depreciation and impairments 31.12.2022 - 7 104.6 192.2 7 296.8 - 6 558.5 191.1 6 749.6Book value 31.12.2022 1 614.2 14 196.4 76.1 15 886.7 1 614.2 14 196.4 76.1 15 886.7Acquisition cost 31.12.2022 1 614.2 21 301.0 268.3 23 183.5 1 614.2 20 754.9 267.2 22 636.3Additions 2 671.6 990.6 10.8 3 673.0 2 671.6 990.6 10.8 3 673.0Disposals/retirement - - - - - - - -3)Reclassification-728.9 820.3 3.2 94.7 -728.9 820.3 3.2 94.7Acquisition cost 31.12.2023 3 556.9 23 111.9 282.3 26 951.2 3 556.9 22 565.8 281.2 26 404.0Accumulated depreciation and impairments 31.12.2022 - 7 104.6 192.2 7 296.8 - 6 558.5 191.1 6 749.6Depreciation - 2 135.0 35.6 2 170.6 - 2 135.0 35.6 2 170.6Impairment/reversal (-) 34.0 - - 34.0 34.0 - - 34.0Disposals/retirement depreciation - - - - - - - -Accumulated depreciation and impairments 31.12.2023 34.0 9 239.6 227.8 9 501.4 34.0 8 693.5 226.6 8 954.2Book value 31.12.2023 3 522.9 13 872.3 54.5 17 449.8 3 522.9 13 872.3 54.5 17 449.81) The negative addition is caused by decreased abandonment provision with an offseting entry on PP&E2) The reclassification is mainly related to the Johans Sverdrup phase 2 development project, which entered into production phase during 20223) The reclassification is mainly related to the Kobra East Gekko and Frosk development projects, which entered into production phase during 2023See note 14 for information regarding impairment charges.Capitalised exploration expenditures are reclassified to \"Assets under development\" when the field enters into the development phase. If development plans are subsequently re-evaluated, the associated costs remain in assets under development and are not reclassified back to exploration assets. Assets under development are reclassified to \"Production facilities\" from the start of production. Production facilities, including wells, are depreciated in accordance with the unit-of-production method. Office machinery, fixtures and fittings etc. are depreciated using the straight-line method over their useful life, i.e. 3 - 5 years. Removal and decommissioning costs are included as production facilities or assets under development.GROUPPARENTRight-of-use assetsVessels and Vessels and (USD million)Drilling Rigs Office Other Drilling Rigs BoatsTotal BoatsBook value 31.12.2021 12.3 50.7 29.3 1.8 94.2 12.3 50.7 29.3 1.8 94.2Acquisition cost 31.12.2021 18.4 57.4 52.4 2.3 130.6 18.4 57.4 52.4 2.3 130.6Additions 22.5 - 11.2 - 33.8 22.5 - 31.9 - 54.4Acquisition of Lundin Energy 11.1 - 23.7 - 34.8 - - - - -Merger with ABP Norway AS - - - - - 6.0 - - - 6.0Allocated to abandonment activity - -0.4 - - -0.4 - -0.4 - - -0.4Disposals/retirement 6.1 0.0 8.1 - 14.2 6.1 0.0 8.1 - 14.21)Reclassification-28.1 -2.3 - - -30.4 -23.0 -2.3 - - -25.4Foreign currency translation -0.0 - -2.0 - -2.0 - - - - -Acquisition cost 31.12.2022 17.9 54.7 77.3 2.3 152.2 17.9 54.7 76.2 2.3 151.1Accumulated depreciation and impairments 31.12.2021 6.1 6.7 23.1 0.5 36.4 6.1 6.7 23.1 0.5 3366..44Depreciation 2.8 3.9 11.8 0.2 18.7 2.8 3.9 10.7 0.2 17.6Impairment/reversal (-) - - - - - - - - - -Disposals/retirement depreciation -6.1 - -8.1 - -14.2 -6.1 - -8.1 - -14.2Foreign currency translation - - -0.1 - -0.1 - - - - -Accumulated depreciation and impairments 31.12.2022 2.8 10.6 26.7 0.7 40.8 2.8 10.6 25.6 0.7 39.8Book value 31.12.2022 15.1 44.1 50.6 1.6 111.3 15.1 44.1 50.6 1.6 111.3Acquisition cost 31.12.2022 17.9 54.7 77.3 2.3 152.2 17.9 54.7 76.2 2.3 151.1Additions 685.3 - 19.2 - 704.5 685.3 - 19.2 - 704.5Allocated to abandonment activity -6.4 -1.1 - - -7.5 -6.4 -1.1 - - -7.5Disposals/retirement 4.2 - - - 4.2 4.2 - - - 4.21)Reclassification-101.5 -2.4 - - -103.9 -101.5 -2.4 - - -103.9Acquisition cost 31.12.2023 591.0 51.2 96.5 2.3 741.1 591.0 51.2 95.5 2.3 740.0Accumulated depreciation and impairments 31.12.2022 2.8 10.6 26.7 0.7 40.8 2.8 10.6 25.6 0.7 39.8Depreciation 31.0 3.1 14.7 0.2 49.1 31.0 3.1 14.7 0.2 49.1Impairment/reversal (-) - - - - - - - - - -Disposals/retirement depreciation -4.2 - - - -4.2 -4.2 - - - -4.2Accumulated depreciation and impairments 31.12.2023 29.7 13.8 41.4 0.9 85.7 29.7 13.8 40.4 0.9 84.7Book value 31.12.2023 561.4 37.4 55.1 1.4 655.3 561.4 37.4 55.1 1.4 655.31) Reclassified to tangible fixed assets in line with the activity of the right-of-use assetSee note 25 for information regarding leases.Right-of-use assets are depreciated linearly over the lifetime of the related lease contract.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__90": {
"value": "INTANGIBLE ASSETSGROUPPARENTCapitalised Capitalised exploration Other intangible assetsexploration Other intangible assets(USD million)Goodwill Depreciated Not depreciated Total group Goodwill expendituresexpendituresBook value 31.12.2021 1 647.4 256.5 642.0 765.6 1 407.6 1 647.4 256.5 642.0 765.6 1 407.6Acquisition cost 31.12.2021 2 726.6 444.2 1 480.1 888.9 2 369.0 2 726.6 444.2 1 480.1 888.9 2 369.0Additions - 251.8 - 0.7 0.7 - 194.7 - 0.7 0.71)Acquisition of Lundin Energy12 542.9 - 25.7 1 256.6 1 282.2 - - - - -Merger with ABP Norway AS - - - - - 12 287.5 27.2 715.4 293.9 1 009.2Disposals/retirement/expensed dry wells - 135.8 - - - - 108.6 - - -2)Reclassification- -110.9 855.0 -855.0 - - -107.2 147.1 -147.1 -Foreign currency translation 135.0 1.0 0.3 12.3 12.6 - - - - -Acquisition cost 31.12.2022 15 404.4 450.3 2 361.0 1 303.6 3 664.6 15 014.1 450.3 2 342.5 1 036.4 3 379.0Accumulated depreciation and impairments 31.12.2021 1 079.1 187.7 838.1 123.3 961.4 1 079.1 187.7 838.1 123.3 961.4Depreciation - - 91.7 - 91.7 - - 73.2 - 73.2Impairment 377.4 10.9 - 258.3 258.3 - 10.9 - - -Foreign currency translation 12.9 - -0.1 8.8 8.7 - - - - -Accumulated depreciation and impairments 31.12.2022 1 469.4 198.6 929.7 390.5 1 320.2 1 079.1 198.6 911.3 123.3 1 034.6Book value 31.12.2022 13 935.0 251.7 1 431.3 913.1 2 344.4 13 935.0 251.7 1 431.3 913.1 2 344.4Acquisition cost 31.12.2022 15 404.4 450.3 2 361.0 1 303.6 3 664.6 15 014.1 450.3 2 342.5 1 036.4 3 379.0Additions - 238.6 - 9.1 9.1 - 238.6 - 9.1 9.1Disposals/retirement/expensed dry wells - 153.9 - - - - 153.9 - - -3)Reclassification- 9.2 97.9 -97.9 - - 9.2 97.9 -97.9 -Acquisition cost 31.12.2023 15 404.4 544.3 2 458.9 1 214.8 3 673.7 15 014.1 544.3 2 440.4 947.6 3 388.1Accumulated depreciation and impairments 31.12.2022 1 469.4 198.6 929.7 390.5 1 320.2 1 079.1 198.6 911.3 123.3 1 034.6Depreciation - - 187.1 - 187.1 - - 187.1 - 187.1Impairment/reversal (-) 792.2 20.4 - 42.9 42.9 792.2 20.4 - 42.9 42.9Disposals/retirement depreciation - - - - - - - - - -Accumulated depreciation and impairments 31.12.2023 2 261.6 218.9 1 116.9 433.4 1 550.3 1 871.4 218.9 1 098.4 166.3 1 264.7Book value 31.12.2023 13 142.8 325.4 1 342.0 781.4 2 123.4 13 142.8 325.4 1 342.0 781.4 2 123.41) The goodwill recognised in connection with the Lundin transaction includes the subsequent adjustment as described in note 302) The reclassification is mainly related to the Johans Sverdrup phase 2 development project, which entered into production phase during 20223) The reclassification is mainly related to the Kobra East Gekko development project, which entered into production phase during 2023Other intangible assets include both planned and producing projects on various fields. The producing projects are depreciated in line with the unit-of-production method for the applicable field.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__89": {
"value": "INTANGIBLE ASSETSGROUPPARENTCapitalised Capitalised exploration Other intangible assetsexploration Other intangible assets(USD million)Goodwill Depreciated Not depreciated Total group Goodwill expendituresexpendituresBook value 31.12.2021 1 647.4 256.5 642.0 765.6 1 407.6 1 647.4 256.5 642.0 765.6 1 407.6Acquisition cost 31.12.2021 2 726.6 444.2 1 480.1 888.9 2 369.0 2 726.6 444.2 1 480.1 888.9 2 369.0Additions - 251.8 - 0.7 0.7 - 194.7 - 0.7 0.71)Acquisition of Lundin Energy12 542.9 - 25.7 1 256.6 1 282.2 - - - - -Merger with ABP Norway AS - - - - - 12 287.5 27.2 715.4 293.9 1 009.2Disposals/retirement/expensed dry wells - 135.8 - - - - 108.6 - - -2)Reclassification- -110.9 855.0 -855.0 - - -107.2 147.1 -147.1 -Foreign currency translation 135.0 1.0 0.3 12.3 12.6 - - - - -Acquisition cost 31.12.2022 15 404.4 450.3 2 361.0 1 303.6 3 664.6 15 014.1 450.3 2 342.5 1 036.4 3 379.0Accumulated depreciation and impairments 31.12.2021 1 079.1 187.7 838.1 123.3 961.4 1 079.1 187.7 838.1 123.3 961.4Depreciation - - 91.7 - 91.7 - - 73.2 - 73.2Impairment 377.4 10.9 - 258.3 258.3 - 10.9 - - -Foreign currency translation 12.9 - -0.1 8.8 8.7 - - - - -Accumulated depreciation and impairments 31.12.2022 1 469.4 198.6 929.7 390.5 1 320.2 1 079.1 198.6 911.3 123.3 1 034.6Book value 31.12.2022 13 935.0 251.7 1 431.3 913.1 2 344.4 13 935.0 251.7 1 431.3 913.1 2 344.4Acquisition cost 31.12.2022 15 404.4 450.3 2 361.0 1 303.6 3 664.6 15 014.1 450.3 2 342.5 1 036.4 3 379.0Additions - 238.6 - 9.1 9.1 - 238.6 - 9.1 9.1Disposals/retirement/expensed dry wells - 153.9 - - - - 153.9 - - -3)Reclassification- 9.2 97.9 -97.9 - - 9.2 97.9 -97.9 -Acquisition cost 31.12.2023 15 404.4 544.3 2 458.9 1 214.8 3 673.7 15 014.1 544.3 2 440.4 947.6 3 388.1Accumulated depreciation and impairments 31.12.2022 1 469.4 198.6 929.7 390.5 1 320.2 1 079.1 198.6 911.3 123.3 1 034.6Depreciation - - 187.1 - 187.1 - - 187.1 - 187.1Impairment/reversal (-) 792.2 20.4 - 42.9 42.9 792.2 20.4 - 42.9 42.9Disposals/retirement depreciation - - - - - - - - - -Accumulated depreciation and impairments 31.12.2023 2 261.6 218.9 1 116.9 433.4 1 550.3 1 871.4 218.9 1 098.4 166.3 1 264.7Book value 31.12.2023 13 142.8 325.4 1 342.0 781.4 2 123.4 13 142.8 325.4 1 342.0 781.4 2 123.41) The goodwill recognised in connection with the Lundin transaction includes the subsequent adjustment as described in note 302) The reclassification is mainly related to the Johans Sverdrup phase 2 development project, which entered into production phase during 20223) The reclassification is mainly related to the Kobra East Gekko development project, which entered into production phase during 2023Other intangible assets include both planned and producing projects on various fields. The producing projects are depreciated in line with the unit-of-production method for the applicable field.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGoodwillExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__88": {
"value": "INTANGIBLE ASSETSGROUPPARENTCapitalised Capitalised exploration Other intangible assetsexploration Other intangible assets(USD million)Goodwill Depreciated Not depreciated Total group Goodwill expendituresexpendituresBook value 31.12.2021 1 647.4 256.5 642.0 765.6 1 407.6 1 647.4 256.5 642.0 765.6 1 407.6Acquisition cost 31.12.2021 2 726.6 444.2 1 480.1 888.9 2 369.0 2 726.6 444.2 1 480.1 888.9 2 369.0Additions - 251.8 - 0.7 0.7 - 194.7 - 0.7 0.71)Acquisition of Lundin Energy12 542.9 - 25.7 1 256.6 1 282.2 - - - - -Merger with ABP Norway AS - - - - - 12 287.5 27.2 715.4 293.9 1 009.2Disposals/retirement/expensed dry wells - 135.8 - - - - 108.6 - - -2)Reclassification- -110.9 855.0 -855.0 - - -107.2 147.1 -147.1 -Foreign currency translation 135.0 1.0 0.3 12.3 12.6 - - - - -Acquisition cost 31.12.2022 15 404.4 450.3 2 361.0 1 303.6 3 664.6 15 014.1 450.3 2 342.5 1 036.4 3 379.0Accumulated depreciation and impairments 31.12.2021 1 079.1 187.7 838.1 123.3 961.4 1 079.1 187.7 838.1 123.3 961.4Depreciation - - 91.7 - 91.7 - - 73.2 - 73.2Impairment 377.4 10.9 - 258.3 258.3 - 10.9 - - -Foreign currency translation 12.9 - -0.1 8.8 8.7 - - - - -Accumulated depreciation and impairments 31.12.2022 1 469.4 198.6 929.7 390.5 1 320.2 1 079.1 198.6 911.3 123.3 1 034.6Book value 31.12.2022 13 935.0 251.7 1 431.3 913.1 2 344.4 13 935.0 251.7 1 431.3 913.1 2 344.4Acquisition cost 31.12.2022 15 404.4 450.3 2 361.0 1 303.6 3 664.6 15 014.1 450.3 2 342.5 1 036.4 3 379.0Additions - 238.6 - 9.1 9.1 - 238.6 - 9.1 9.1Disposals/retirement/expensed dry wells - 153.9 - - - - 153.9 - - -3)Reclassification- 9.2 97.9 -97.9 - - 9.2 97.9 -97.9 -Acquisition cost 31.12.2023 15 404.4 544.3 2 458.9 1 214.8 3 673.7 15 014.1 544.3 2 440.4 947.6 3 388.1Accumulated depreciation and impairments 31.12.2022 1 469.4 198.6 929.7 390.5 1 320.2 1 079.1 198.6 911.3 123.3 1 034.6Depreciation - - 187.1 - 187.1 - - 187.1 - 187.1Impairment/reversal (-) 792.2 20.4 - 42.9 42.9 792.2 20.4 - 42.9 42.9Disposals/retirement depreciation - - - - - - - - - -Accumulated depreciation and impairments 31.12.2023 2 261.6 218.9 1 116.9 433.4 1 550.3 1 871.4 218.9 1 098.4 166.3 1 264.7Book value 31.12.2023 13 142.8 325.4 1 342.0 781.4 2 123.4 13 142.8 325.4 1 342.0 781.4 2 123.41) The goodwill recognised in connection with the Lundin transaction includes the subsequent adjustment as described in note 302) The reclassification is mainly related to the Johans Sverdrup phase 2 development project, which entered into production phase during 20223) The reclassification is mainly related to the Kobra East Gekko development project, which entered into production phase during 2023Other intangible assets include both planned and producing projects on various fields. The producing projects are depreciated in line with the unit-of-production method for the applicable field.",
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"language": "en",
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"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
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"s8_notes__6__87": {
"value": "INTANGIBLE ASSETSGROUPPARENTCapitalised Capitalised exploration Other intangible assetsexploration Other intangible assets(USD million)Goodwill Depreciated Not depreciated Total group Goodwill expendituresexpendituresBook value 31.12.2021 1 647.4 256.5 642.0 765.6 1 407.6 1 647.4 256.5 642.0 765.6 1 407.6Acquisition cost 31.12.2021 2 726.6 444.2 1 480.1 888.9 2 369.0 2 726.6 444.2 1 480.1 888.9 2 369.0Additions - 251.8 - 0.7 0.7 - 194.7 - 0.7 0.71)Acquisition of Lundin Energy12 542.9 - 25.7 1 256.6 1 282.2 - - - - -Merger with ABP Norway AS - - - - - 12 287.5 27.2 715.4 293.9 1 009.2Disposals/retirement/expensed dry wells - 135.8 - - - - 108.6 - - -2)Reclassification- -110.9 855.0 -855.0 - - -107.2 147.1 -147.1 -Foreign currency translation 135.0 1.0 0.3 12.3 12.6 - - - - -Acquisition cost 31.12.2022 15 404.4 450.3 2 361.0 1 303.6 3 664.6 15 014.1 450.3 2 342.5 1 036.4 3 379.0Accumulated depreciation and impairments 31.12.2021 1 079.1 187.7 838.1 123.3 961.4 1 079.1 187.7 838.1 123.3 961.4Depreciation - - 91.7 - 91.7 - - 73.2 - 73.2Impairment 377.4 10.9 - 258.3 258.3 - 10.9 - - -Foreign currency translation 12.9 - -0.1 8.8 8.7 - - - - -Accumulated depreciation and impairments 31.12.2022 1 469.4 198.6 929.7 390.5 1 320.2 1 079.1 198.6 911.3 123.3 1 034.6Book value 31.12.2022 13 935.0 251.7 1 431.3 913.1 2 344.4 13 935.0 251.7 1 431.3 913.1 2 344.4Acquisition cost 31.12.2022 15 404.4 450.3 2 361.0 1 303.6 3 664.6 15 014.1 450.3 2 342.5 1 036.4 3 379.0Additions - 238.6 - 9.1 9.1 - 238.6 - 9.1 9.1Disposals/retirement/expensed dry wells - 153.9 - - - - 153.9 - - -3)Reclassification- 9.2 97.9 -97.9 - - 9.2 97.9 -97.9 -Acquisition cost 31.12.2023 15 404.4 544.3 2 458.9 1 214.8 3 673.7 15 014.1 544.3 2 440.4 947.6 3 388.1Accumulated depreciation and impairments 31.12.2022 1 469.4 198.6 929.7 390.5 1 320.2 1 079.1 198.6 911.3 123.3 1 034.6Depreciation - - 187.1 - 187.1 - - 187.1 - 187.1Impairment/reversal (-) 792.2 20.4 - 42.9 42.9 792.2 20.4 - 42.9 42.9Disposals/retirement depreciation - - - - - - - - - -Accumulated depreciation and impairments 31.12.2023 2 261.6 218.9 1 116.9 433.4 1 550.3 1 871.4 218.9 1 098.4 166.3 1 264.7Book value 31.12.2023 13 142.8 325.4 1 342.0 781.4 2 123.4 13 142.8 325.4 1 342.0 781.4 2 123.41) The goodwill recognised in connection with the Lundin transaction includes the subsequent adjustment as described in note 302) The reclassification is mainly related to the Johans Sverdrup phase 2 development project, which entered into production phase during 20223) The reclassification is mainly related to the Kobra East Gekko development project, which entered into production phase during 2023Other intangible assets include both planned and producing projects on various fields. The producing projects are depreciated in line with the unit-of-production method for the applicable field.",
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"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
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"s8_notes__6__95": {
"value": "Note 14 ImpairmentsImpairment testingImpairment tests of individual cash-generating units are performed when impairment/reversal triggers are identified, and goodwill is tested for impairment at least annually. In 2023, two categories of impairment tests have been performed:- Impairment test of fixed assets and related intangible assets, including technical goodwill- Impairment test of residual goodwillImpairment is recognised when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. Correspondingly, a reversal of impairment is recognised when the recoverable amount exceeds the book value. Prior period impairment of goodwill is not subject to reversal. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. The impairment testing has been performed in accordance with the fair value method (level 3 in fair value hierarchy) and based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years.For producing licences and licences in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 31 December 2023.PricesFuture price level is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based on management's estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. The information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions going forward. In the impairment test, the oil and gas prices are therefore based on the forward curve from the beginning of 2024 to the end of 2026. From 2027, the oil and gas prices are based on the company's long-term price assumptions. Long-term gas price assumption is unchanged from year end 2022. Long-term oil price assumption for the period 2027 to 2035 is updated from 65.0 USD/BOE applied at year end 2022.The nominal oil and gas prices applied in the impairment test are as follows:Year USD/BOE GBP/therm202476.3 0.85202573.3 0.91202670.8 0.82From 2027 to 2035 (in real 2023 terms70.0 0.67From 2036 (in real 2023 terms)65.0 0.67Oil and gas reservesFuture cash flows are calculated on the basis of expected production profiles and estimated proven and probable reserves including potentially additional risked volumes. For more information about the determination of the reserves, reference is made to note 1, section 1.3, and to note 32.Future expenditureFuture capex, opex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost. The cost profiles include an estimated impact of the currently high cost escalation in the industry. The cash flows include a step up of CO2 tax/fees from current levels to approximately NOK 2 260 per tonn (2023 real) in 2030.Discount rateThe discount rate is derived from the company's weighted average cost of capital (\"WACC\"). The capital structure considered in the WACC calculation is derived from the capital structures of an identified peer group and market participants with consideration given to optimal structures. The cost of equity is derived from the expected return on investment by the company's investors. The cost of debt is based on the interest-bearing borrowings on debt specific to the assets acquired. The beta factors are evaluated annually based on publicly available market data about the identified peer group.The post tax nominal discount rate used at year end is 8.9 percent. This represents a change from 8.7 percent applied at year end 2022.Currency ratesYear USD/NOK202410.11202510.07202610.03From 20278.50The long-term currency rate is updated from USD/NOK 8.0 applied at year end 2022.InflationThe long-term inflation rate is assumed to be 2.0 percent, which is the same as applied at year end 2022. The currently high cost escalation in the industry is reflected in the cash flows rather than in the inflation rate.Impairment testing of assets including technical goodwillThe technical goodwill recognised in previous business combinations is allocated to each cash-generating unit for the purpose of impairment testing. Hence, the impairment test of technical goodwill is included in the impairment testing of assets, and the technical goodwill is written down before the asset. The carrying value of the assets is the sum of tangible assets, intangible assets and technical goodwill as of the assessment date. In the impairment test performed, carrying value is adjusted by the remaining part of deferred tax from which the technical goodwill arose, to avoid an immediate impairment of all technical goodwill. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable. Below is an overview of the impairment charge and the carrying value per cash-generating unit where impairment has been recognised in 2023:Group & ParentEdvard Grieg & Ivar Aasen Cash-generating unit (USD million)TroldhaugenCGUValhall CGUNet carrying value 110.5 5 944.7 4 236.9Recoverable amount - 5 762.0 3 660.8Impairment/reversal (-) 110.5 182.7 576.1Allocated as follows: Technical goodwill 33.5 182.7 576.1 Other intangible assets/licence rights 42.9 - - Tangible fixed assets 34.0 - - The main reason for the Troldhaugen impairment is related to the decision by the partership to not accede the PDO for the Troldhaugen project. The Edvard Grieg & Ivar Aasen CGU and the Valhall CGU impairment is mainly related to decrease in short-term oil and gas prices and decrease of deferred tax liabilities as described above.Exploration assetsDuring 2023, an impairment charge of USD 20.4 million has been recognised. The impairment charge is mainly related to the Ve well and has been allocated to capitalised exploration expenditures.Sensitivity analysisThe table below shows how the impairment or reversal of impairment of assets and technical goodwill would be affected by changes in the various assumptions, given that the remaining assumptions are constant. The figures in the table below are in all material respect related to goodwill impairment, which would have no impact on deferred tax. Change in impairment afterAssumption (USD million) ChangeIncrease in assumptionDecrease in assumptionOil and gas price forward period +/- 50 %-204.7 2 513.4Oil and gas price long-term +/- 20 %-5.0 1 126.2Production profile (reserves) +/- 5 %-6.2 283.4Discount rate +/- 1 % point128.0 -0.0Currency rate USD/NOK +/- 2.0 NOK-137.3 593.0Inflation +/- 1 % point-0.0 427.9Residual goodwillThe residual goodwill is tested for impairment on corporate level. The starting point for the impairment test is the difference between market value and book value of equity. At year end 2023 the market value exceeds the carrying amount of equity by a substantial margin.Climate related risksAs mentioned in the future expenditures section, the cash flows applied in the impairment testing include a step up of CO2 tax/fees from current levels to approximately NOK 2 260 per tonn (2023 real) in 2030.Further, as described in note 3, a sensitivity analysis have been performed towards various scenarios from International Energy Agency have been included in a separate sensitivity test as presented below. The price assumptions in those senarios have been provided by IEA at 2030 and 2050 in 2022 real terms. For the sensitivity calculation, a linear development between the average price for 2023 and IEA price in 2030, as well as between 2030 and 2050 have been applied. The table below summarises how the impairment charge would increase (+) or decrease (-) using the oil and gas price assumptions in the following scenarios:Change in impairmentIEA Scenario (USD million)Net ZeroAnnounced PledgesStated PoliciesValhall/Hod 2 969SkarvUla -57 -93Alvheim 132Johan Sverdrup 706Grieg/Aasen 390Yggdrasil 52Total 4 250 -57 -93 Oil USD/bblGas USD/mmbtuScenario price ranges2030 2050 2030 2050Net Zero 42 25 4.3 4.1Announced Pledges74 60 6.5 5.4Stated Policies 85 83 6.9 7.1In addition, capitalised exploration and other related balances have been reviewed as of year end 2023, in order to assess the exposure and dependancy of future government approvals. An amount of USD 516 million would have been impaired in a situation where no new project developments would be approved. Impairment testing in 2022In 2022, the impairment charge was mainly related to three CGU's and allocated to technicall goodwill, other intagible assets from acquisitions and tangible fixed assets, in addition to an impairment of exploration assets and other non-current assets. The methodology for impairment testing was the same as in 2023 as described in this note.The following assumptions were applied for the impairment testing at year end 2022:- discount rate of 8.7 percent nominal after tax for both value in use and fair value testing- a long-term inflation of 2.0 percent- a long-term exchange rate of NOK/USD 8.0 (forward curve first three years)- a long-term oil price assumption of 65 USD/barrel, using forward curve first three yearsSummary of impairment/reversal of impairmentsThe following impairments/(reversals) have been recorded:GroupParent(USD million) 2023 2022 2023 2022Impairment/reversal of tangible fixed assets 34.0 385.6 34.0 385.6Impairment/reversal of other intangible assets 42.9 258.3 42.9 -Impairment/reversal of capitalised exploration expenditures 20.4 10.9 20.4 10.9Impairment of goodwill 792.2 377.4 792.2 -Impairment of non-current assets - - - 434.2Total impairments 889.5 1 032.2 889.5 830.7",
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"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
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"s8_notes__6__92": {
"value": "GroupParentDepreciation in the Income statement (USD million) 2023 2022 2023 2022Depreciation of tangible fixed assets 2 170.6 1 675.2 2 170.6 1 141.1Depreciation of right-of-use assets 49.1 18.7 49.1 17.6Depreciation of other intangible assets 187.1 91.7 187.1 73.2Total depreciation in the Income statement 2 406.8 1 785.7 2 406.8 1 231.8Impairment in the Income statement (USD million)Impairment/reversal of tangible fixed assets34.0 385.6 34.0 385.6Impairment/reversal of other intangible assets42.9 258.3 42.9 -Impairment/reversal of capitalised exploration 20.4 10.9 20.4 10.9Impairment of goodwill792.2 377.4 792.2 -Total impairments of tangible and intangible assets 889.5 1 032.2 889.5 396.4See note 14 for information regarding impairment charges.",
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"language": "en",
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"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
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"s8_notes__6__91": {
"value": "GroupParentDepreciation in the Income statement (USD million) 2023 2022 2023 2022Depreciation of tangible fixed assets 2 170.6 1 675.2 2 170.6 1 141.1Depreciation of right-of-use assets 49.1 18.7 49.1 17.6Depreciation of other intangible assets 187.1 91.7 187.1 73.2Total depreciation in the Income statement 2 406.8 1 785.7 2 406.8 1 231.8Impairment in the Income statement (USD million)Impairment/reversal of tangible fixed assets34.0 385.6 34.0 385.6Impairment/reversal of other intangible assets42.9 258.3 42.9 -Impairment/reversal of capitalised exploration 20.4 10.9 20.4 10.9Impairment of goodwill792.2 377.4 792.2 -Total impairments of tangible and intangible assets 889.5 1 032.2 889.5 396.4See note 14 for information regarding impairment charges.",
"dimensions": {
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"language": "en",
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"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
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"s8_notes__6__96-1": {
"value": "Note 15 Trade receivablesTrade receivables are recognised in the Statement of Financial Position at nominal value after a deduction for the provision for credit losses. Historically there have been no significant credit losses, and the company's customers are mainly large, financially sound oil companies. Trade receivables consist of receivables related to the sale of oil and gas.GroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Receivables related to the sale of petroleum 658.8 950.9 658.9 950.9Total trade receivables 658.8 950.9 658.9 950.9Age distribution of trade receivables as of 31 December for the group and parent was as follows:Year (USD million) Total Not due <30d 30-90d >90d2023658.8 658.8 - - -2022950.9 950.1 0.8 - -Note 16 Other short-term receivablesGroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Prepayments 279.7 124.0 279.7 124.0VAT receivable 18.8 12.4 18.8 12.4Underlift of petroleum 41.7 53.6 41.7 53.6Accrued income from sale of petroleum products 216.9 335.5 216.9 335.5Other receivables, mainly balances with licence partners 185.1 160.7 185.0 161.1Total other short-term receivables 742.2 686.2 742.1 686.7Related party (USD million) Revenues (-) / expenses (+) 31.12.2023 31.12.2022 31.12.2023 31.12.2022ABP Norway AS Interest cost - - - 9.2ABP Norway AS Interest income - - - -7.4ABP Norway ASOperating expenses - - - 18.51)ABP Norway ASRecharges- - - -52.5ABP Energy Holding BV Interest cost - - - 1.2aiZe AS Purchases of consultant and technology services13.1 5.1 13.1 5.1Aker ASA Board remuneration etc 0.5 0.9 0.5 0.92)Cognite ASPurchases of consultant and IT services 11.9 7.0 11.9 7.0Lily Akerkvartalet AS Office cost 0.7 0.5 0.7 0.5BP Oil International Ltd Sales of Oil and NGL -11 591.4 -8 796.6 -11 591.4 -5 707.5BP Gas Marketing Ltd Sales of Gas -1 083.1 -2 819.7 -1 083.1 -2 956.5GroupParentRelated party (USD million)Receivables (+) / liabilities (-) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Aker BP UK LtdOther receivables - - 8.5 6.2BP Oil International Ltd Trade receivables 637.7 838.5 637.7 400.41) The figure represents total gross charges related to personnel employed by Aker BP ASA working for ABP Norway AS. These charges have been allocated to various licences and corporate activity based on timewriting.2) As described in note 18 Aker BP sold its share in Cognite during 2022. Due to the continuing involvement arising from the put option arrangement, the transactions with Cognite are still considered to be within related parties.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
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"s8_notes__6__98": {
"value": "Note 16 Other short-term receivablesGroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Prepayments 279.7 124.0 279.7 124.0VAT receivable 18.8 12.4 18.8 12.4Underlift of petroleum 41.7 53.6 41.7 53.6Accrued income from sale of petroleum products 216.9 335.5 216.9 335.5Other receivables, mainly balances with licence partners 185.1 160.7 185.0 161.1Total other short-term receivables 742.2 686.2 742.1 686.7",
"dimensions": {
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"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
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"s8_notes__6__99": {
"value": "Note 17 InventoriesThe inventory mainly consists of equipment for the drilling of exploration and production wells. GroupParentInventory value (USD million) 2023 2022 2023 2022Inventories - measured at cost 255.5 256.0 255.5 256.0Provision for obsolete equipment 53.1 46.5 53.1 46.5Book value of inventories 202.3 209.5 202.3 209.5",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInventoriesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
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"s8_notes__6__101": {
"value": "Note 18 Other non-current assetsGroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Shares in Alvheim AS 0.0 0.0 0.0 0.0Shares in Det norske oljeselskap AS 1.0 1.0 1.0 1.0Shares in Aker BP UK0.0 0.0 - -Shares in Sandvika Fjellstue AS 1.8 1.8 1.8 1.81)Investment in subsidiaries2.8 2.8 2.8 2.82)Continuing involvement - Cognite AS81.4 81.4 81.4 81.4Tenancy deposit - 1.6 - 1.63)Unamortised fees - RCF15.0 11.0 15.0 11.0Other non-current assets 3.6 7.6 3.6 7.6Total other non-current assets 102.9 104.5 102.9 104.51) Alvheim AS, Det norske oljeselskap AS and Sandvika Fjellstue AS have been deemed immaterial for consolidation purposes. All companies acquired in the Lundin transaction was either liquidated or merged with Aker BP ASA in 2022. For more information regarding shares in subsidiaries, see note 2.2) In 2022 the company sold its shares in Cognite AS to Saudi Aramco Development Company for a consideration of USD118 million. As part of the transaction, Aker BP has granted the buyer an option with maturity in November 2024 which under certain conditions gives the buyer the right to sell the shares back to Aker BP for USD 81.4 million. On this basis, Aker BP is considered to have continuing involvement in Cognite AS, in accordance with guidelines in IFRS 9. Hence, both an asset and a liability of USD 81.4 million is recognised in the statement of financial position at 31 December 2023. 3) Remaining unamortised fees related to the Revolving Credit Facility (RCF). These have been reclassified from other interest-bearing debt as the RCF was undrawn as at 31 December 2023 and 31 December 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherNoncurrentAssetsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
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"s8_notes__6__100": {
"value": "Note 18 Other non-current assetsGroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Shares in Alvheim AS 0.0 0.0 0.0 0.0Shares in Det norske oljeselskap AS 1.0 1.0 1.0 1.0Shares in Aker BP UK0.0 0.0 - -Shares in Sandvika Fjellstue AS 1.8 1.8 1.8 1.81)Investment in subsidiaries2.8 2.8 2.8 2.82)Continuing involvement - Cognite AS81.4 81.4 81.4 81.4Tenancy deposit - 1.6 - 1.63)Unamortised fees - RCF15.0 11.0 15.0 11.0Other non-current assets 3.6 7.6 3.6 7.6Total other non-current assets 102.9 104.5 102.9 104.51) Alvheim AS, Det norske oljeselskap AS and Sandvika Fjellstue AS have been deemed immaterial for consolidation purposes. All companies acquired in the Lundin transaction was either liquidated or merged with Aker BP ASA in 2022. For more information regarding shares in subsidiaries, see note 2.2) In 2022 the company sold its shares in Cognite AS to Saudi Aramco Development Company for a consideration of USD118 million. As part of the transaction, Aker BP has granted the buyer an option with maturity in November 2024 which under certain conditions gives the buyer the right to sell the shares back to Aker BP for USD 81.4 million. On this basis, Aker BP is considered to have continuing involvement in Cognite AS, in accordance with guidelines in IFRS 9. Hence, both an asset and a liability of USD 81.4 million is recognised in the statement of financial position at 31 December 2023. 3) Remaining unamortised fees related to the Revolving Credit Facility (RCF). These have been reclassified from other interest-bearing debt as the RCF was undrawn as at 31 December 2023 and 31 December 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherAssetsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__105-1": {
"value": "Note 19 Cash and cash equivalentsThe item 'Cash and cash equivalents' consists of bank accounts and time deposits that constitute parts of the group's transaction liquidity. GroupParentBreakdown of cash and cash equivalents (USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Bank deposits 3 366.9 2 756.0 3 366.9 2 756.01)Restricted bank deposits21.5 - 21.5 -Cash and cash equivalents 3 388.4 2 756.0 3 388.4 2 756.0Undrawn RCF facility 3 400.0 3 400.0 3 400.0 3 400.01) Tax deduction accountThe RCF is undrawn as at 31 December 2023 and the remaining unamortised fees of USD 15.0 million related to the facility are therefore included in other non-current assets.The senior unsecured Revolving Credit Facility (RCF) of USD 3.4 billion was established in May 2019 and consist of two tranches: (1) Working Capital Facility with a committed amount of USD 1.4 billion until 2025 and USD 1.3 billion until 2026, and(2) Liquidity Facility with a committed amount of USD 2.0 billion until 2025 and USD 1.65 billion until 2026.(3) In November 2023, Aker BP signed a new USD 1.8 billion RCF with 9 banks. The new facility will have a forward date(availability date) at the same time as the existing RCF expires in 2026 and has a maturity in 2028. The facility includes two extension options with potential final maturity in 2030. The interest rate for the Working Capital Facility is Term SOFR plus a margin of 1.00 percent and for the Liquidity Facility Term SOFR plus a margin of 0.75 percent. The new RCF with forward start in 2026 will have an interest rate of Term SOFR plus a margin of 0.85 percent. Drawing under the Liquidity Facility and new RCF will add a utilisation fee. A commitment fee of 35 percent of applicable margin is paid on the undrawn part of the facilities. The financial covenants are as follows:- Leverage Ratio: Net interest-bearing debt divided by twelve months rolling EBITDAX (excluding any impacts from IFRS 16) shall not exceed 3.5 times- Interest Coverage Ratio: Twelve months rolling EBITDA divided by Interest expenses (excluding any impacts from IFRS 16) shall be a minimum of 3.5 times The financial covenants in the group's current debt facilities exclude the effects from IFRS 16, and therefore cannot be directly derived from the group's financial statements. See reconciliations of Alternative Performance Measures for detailed information.As at 31 December 2023 the Leverage Ratio is 0.19 and Interest Coverage Ratio is 95.2 (see APM section for further details). Based on the group's current business plans and applying oil and gas price forward curves at end of 2023, the group\u2019s estimates show that the financial covenants will continue to comply with the covenants by a substantial margin.Note 21 BondsOutstanding GroupParent(USD million)amount2)Senior Notes 3.000% (Jan 20/Jan 25)95.5 94.5 498.2 94.5 498.22)Senior Notes 2.875% (Sep 20/Jan 26)129.7 128.3 497.8 128.3 497.82)3)Senior Notes 2.000% (Jul 21/Jul 26)707.1 660.4 907.4 660.4 907.41)Senior Notes 5.600% (Jun 23/Jun 28)500.0 496.8 - 496.8 -Senior Notes 1.125% (May 21/May 29)750.0 824.8 795.3 824.8 795.3Senior Notes 3.750% (Jan 20/Jan 30)1 000.0 995.2 994.4 995.2 994.4Senior Notes 4.000% (Sep 20/Jan 31)750.0 745.9 745.3 745.9 745.33)Senior Notes 3.100% (Jul 21/Jul 31)1 000.0 859.3 840.8 859.3 840.81)Senior Notes 6.000% (Jun 23/Jun 33)1 000.0 993.0 - 993.0 -Long-term bonds - book value 5 798.2 5 279.2 5 798.2 5 279.2Long-term bonds - fair value 5 629.4 4 829.7 5 629.4 4 829.71) In June 2023 the company issued two new USD bonds:- USD 500 million Senior Notes 5.600% (Jun 2028)- USD 1,000 million Senior Notes 6.000% (Jun 2033)2) Parts of the proceeds from the new bonds were used to tender for our outstanding bonds maturing in 2025 and 2026.In total we repurchased the following volumes split per bond (principal amount):- USD 404.5 million on USD Senior Notes 3.000% (Jan 2025)- USD 370.3 million on USD Senior Notes 2.875% (Jan 2026)- USD 292.9 million on USD Senior Notes 2.000% (Jul 2026)The fair value of these bonds were lower than the book value at the time of repurchase. This resulted in a net gain of USD 43.7 million presented as other financial income.3) Prior to the repurchase mentioned above, these bonds had a nominal value of USD 1 billion and were recognised at fair value in connection with the Lundin Energy transaction at 30 June 2022. The difference between fair value and nominal value is linearly amortised over the lifetime of the bonds (see note 10).Interest is paid on a semi annual basis, except for the EUR Senior Notes which is paid on an annual basis. None of the bonds have financial covenants.The fair value of bonds are based on the listed prices in the active markets (level 1 in fair value hierarchy).",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBorrowingsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__104": {
"value": "Note 19 Cash and cash equivalentsThe item 'Cash and cash equivalents' consists of bank accounts and time deposits that constitute parts of the group's transaction liquidity. GroupParentBreakdown of cash and cash equivalents (USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Bank deposits 3 366.9 2 756.0 3 366.9 2 756.01)Restricted bank deposits21.5 - 21.5 -Cash and cash equivalents 3 388.4 2 756.0 3 388.4 2 756.0Undrawn RCF facility 3 400.0 3 400.0 3 400.0 3 400.01) Tax deduction accountThe RCF is undrawn as at 31 December 2023 and the remaining unamortised fees of USD 15.0 million related to the facility are therefore included in other non-current assets.The senior unsecured Revolving Credit Facility (RCF) of USD 3.4 billion was established in May 2019 and consist of two tranches: (1) Working Capital Facility with a committed amount of USD 1.4 billion until 2025 and USD 1.3 billion until 2026, and(2) Liquidity Facility with a committed amount of USD 2.0 billion until 2025 and USD 1.65 billion until 2026.(3) In November 2023, Aker BP signed a new USD 1.8 billion RCF with 9 banks. The new facility will have a forward date(availability date) at the same time as the existing RCF expires in 2026 and has a maturity in 2028. The facility includes two extension options with potential final maturity in 2030. The interest rate for the Working Capital Facility is Term SOFR plus a margin of 1.00 percent and for the Liquidity Facility Term SOFR plus a margin of 0.75 percent. The new RCF with forward start in 2026 will have an interest rate of Term SOFR plus a margin of 0.85 percent. Drawing under the Liquidity Facility and new RCF will add a utilisation fee. A commitment fee of 35 percent of applicable margin is paid on the undrawn part of the facilities. The financial covenants are as follows:- Leverage Ratio: Net interest-bearing debt divided by twelve months rolling EBITDAX (excluding any impacts from IFRS 16) shall not exceed 3.5 times- Interest Coverage Ratio: Twelve months rolling EBITDA divided by Interest expenses (excluding any impacts from IFRS 16) shall be a minimum of 3.5 times The financial covenants in the group's current debt facilities exclude the effects from IFRS 16, and therefore cannot be directly derived from the group's financial statements. See reconciliations of Alternative Performance Measures for detailed information.As at 31 December 2023 the Leverage Ratio is 0.19 and Interest Coverage Ratio is 95.2 (see APM section for further details). Based on the group's current business plans and applying oil and gas price forward curves at end of 2023, the group\u2019s estimates show that the financial covenants will continue to comply with the covenants by a substantial margin.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__103": {
"value": "Note 19 Cash and cash equivalentsThe item 'Cash and cash equivalents' consists of bank accounts and time deposits that constitute parts of the group's transaction liquidity. GroupParentBreakdown of cash and cash equivalents (USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Bank deposits 3 366.9 2 756.0 3 366.9 2 756.01)Restricted bank deposits21.5 - 21.5 -Cash and cash equivalents 3 388.4 2 756.0 3 388.4 2 756.0Undrawn RCF facility 3 400.0 3 400.0 3 400.0 3 400.01) Tax deduction accountThe RCF is undrawn as at 31 December 2023 and the remaining unamortised fees of USD 15.0 million related to the facility are therefore included in other non-current assets.The senior unsecured Revolving Credit Facility (RCF) of USD 3.4 billion was established in May 2019 and consist of two tranches: (1) Working Capital Facility with a committed amount of USD 1.4 billion until 2025 and USD 1.3 billion until 2026, and(2) Liquidity Facility with a committed amount of USD 2.0 billion until 2025 and USD 1.65 billion until 2026.(3) In November 2023, Aker BP signed a new USD 1.8 billion RCF with 9 banks. The new facility will have a forward date(availability date) at the same time as the existing RCF expires in 2026 and has a maturity in 2028. The facility includes two extension options with potential final maturity in 2030. The interest rate for the Working Capital Facility is Term SOFR plus a margin of 1.00 percent and for the Liquidity Facility Term SOFR plus a margin of 0.75 percent. The new RCF with forward start in 2026 will have an interest rate of Term SOFR plus a margin of 0.85 percent. Drawing under the Liquidity Facility and new RCF will add a utilisation fee. A commitment fee of 35 percent of applicable margin is paid on the undrawn part of the facilities. The financial covenants are as follows:- Leverage Ratio: Net interest-bearing debt divided by twelve months rolling EBITDAX (excluding any impacts from IFRS 16) shall not exceed 3.5 times- Interest Coverage Ratio: Twelve months rolling EBITDA divided by Interest expenses (excluding any impacts from IFRS 16) shall be a minimum of 3.5 times The financial covenants in the group's current debt facilities exclude the effects from IFRS 16, and therefore cannot be directly derived from the group's financial statements. See reconciliations of Alternative Performance Measures for detailed information.As at 31 December 2023 the Leverage Ratio is 0.19 and Interest Coverage Ratio is 95.2 (see APM section for further details). Based on the group's current business plans and applying oil and gas price forward curves at end of 2023, the group\u2019s estimates show that the financial covenants will continue to comply with the covenants by a substantial margin.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRestrictedCashAndCashEquivalentsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__107": {
"value": "Note 20 Share capital and shareholders GroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022 Share capital 84.3 84.3 84.3 84.3Total number of shares (in 1 000) 632 022 632 022 632 022 632 022Nominal value per share in NOK 1.00 1.00 1.00 1.00There is only one single class of shares in the company and all shares carry a single voting right.The company acquires own shares in connection with the annual share purchase program for all employees, and potentially for use in relation to the LTIP program for EMT members at vesting in 2025 and onwards. During 2023 the company purchased 1 361 646 (0.2 percent of the share capital) and sold 862 255 (0.1 percent) own shares. The price per share was NOK 254.2 and 230.02 respectively. At year end 2023 the company had 728 456 own shares, equivalent to 0.1 percent of the total number of shares. The shares have a face value of NOK 1 and an average book value of NOK 259.4 per share. No. of shares Owning Overview of the 20 largest shareholders registered as of 31 December 2023(in 1 000)interestAker Capital 133 75821.16%BP Exploration Operating Company Ltd 100 30315.87%Nemesia 90 90914.38%Folketrygdfondet 33 3565.28%Capital Group 20 1973.20%BlackRock 14 7562.33%Vanguard 11 6031.84%DNB Asset Management AS 10 0081.58%MFS Investment Management 9 8291.56%KLP Kapitalforvaltning AS 5 2880.84%Avanza Bank AB 4 7740.76%Syquant Capital 4 7210.75%SAFE Investment Company Limited 4 6910.74%Janus Henderson Investors 4 5950.73%Danske Invest 4 3800.69%Storebrand Asset Management 4 3670.69%Nordea Funds 4 0620.64%State Street Global Advisors 3 2190.51%Invesco 3 1280.49%Magallanes Value Investors SGIIC 3 1140.49%Other 160 96425.47%Total 632 022100.00%",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__106": {
"value": "Note 20 Share capital and shareholders GroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022 Share capital 84.3 84.3 84.3 84.3Total number of shares (in 1 000) 632 022 632 022 632 022 632 022Nominal value per share in NOK 1.00 1.00 1.00 1.00There is only one single class of shares in the company and all shares carry a single voting right.The company acquires own shares in connection with the annual share purchase program for all employees, and potentially for use in relation to the LTIP program for EMT members at vesting in 2025 and onwards. During 2023 the company purchased 1 361 646 (0.2 percent of the share capital) and sold 862 255 (0.1 percent) own shares. The price per share was NOK 254.2 and 230.02 respectively. At year end 2023 the company had 728 456 own shares, equivalent to 0.1 percent of the total number of shares. The shares have a face value of NOK 1 and an average book value of NOK 259.4 per share. No. of shares Owning Overview of the 20 largest shareholders registered as of 31 December 2023(in 1 000)interestAker Capital 133 75821.16%BP Exploration Operating Company Ltd 100 30315.87%Nemesia 90 90914.38%Folketrygdfondet 33 3565.28%Capital Group 20 1973.20%BlackRock 14 7562.33%Vanguard 11 6031.84%DNB Asset Management AS 10 0081.58%MFS Investment Management 9 8291.56%KLP Kapitalforvaltning AS 5 2880.84%Avanza Bank AB 4 7740.76%Syquant Capital 4 7210.75%SAFE Investment Company Limited 4 6910.74%Janus Henderson Investors 4 5950.73%Danske Invest 4 3800.69%Storebrand Asset Management 4 3670.69%Nordea Funds 4 0620.64%State Street Global Advisors 3 2190.51%Invesco 3 1280.49%Magallanes Value Investors SGIIC 3 1140.49%Other 160 96425.47%Total 632 022100.00%",
"dimensions": {
"concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__108": {
"value": "Note 21 BondsOutstanding GroupParent(USD million)amount2)Senior Notes 3.000% (Jan 20/Jan 25)95.5 94.5 498.2 94.5 498.22)Senior Notes 2.875% (Sep 20/Jan 26)129.7 128.3 497.8 128.3 497.82)3)Senior Notes 2.000% (Jul 21/Jul 26)707.1 660.4 907.4 660.4 907.41)Senior Notes 5.600% (Jun 23/Jun 28)500.0 496.8 - 496.8 -Senior Notes 1.125% (May 21/May 29)750.0 824.8 795.3 824.8 795.3Senior Notes 3.750% (Jan 20/Jan 30)1 000.0 995.2 994.4 995.2 994.4Senior Notes 4.000% (Sep 20/Jan 31)750.0 745.9 745.3 745.9 745.33)Senior Notes 3.100% (Jul 21/Jul 31)1 000.0 859.3 840.8 859.3 840.81)Senior Notes 6.000% (Jun 23/Jun 33)1 000.0 993.0 - 993.0 -Long-term bonds - book value 5 798.2 5 279.2 5 798.2 5 279.2Long-term bonds - fair value 5 629.4 4 829.7 5 629.4 4 829.71) In June 2023 the company issued two new USD bonds:- USD 500 million Senior Notes 5.600% (Jun 2028)- USD 1,000 million Senior Notes 6.000% (Jun 2033)2) Parts of the proceeds from the new bonds were used to tender for our outstanding bonds maturing in 2025 and 2026.In total we repurchased the following volumes split per bond (principal amount):- USD 404.5 million on USD Senior Notes 3.000% (Jan 2025)- USD 370.3 million on USD Senior Notes 2.875% (Jan 2026)- USD 292.9 million on USD Senior Notes 2.000% (Jul 2026)The fair value of these bonds were lower than the book value at the time of repurchase. This resulted in a net gain of USD 43.7 million presented as other financial income.3) Prior to the repurchase mentioned above, these bonds had a nominal value of USD 1 billion and were recognised at fair value in connection with the Lundin Energy transaction at 30 June 2022. The difference between fair value and nominal value is linearly amortised over the lifetime of the bonds (see note 10).Interest is paid on a semi annual basis, except for the EUR Senior Notes which is paid on an annual basis. None of the bonds have financial covenants.The fair value of bonds are based on the listed prices in the active markets (level 1 in fair value hierarchy).",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDebtSecuritiesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__110": {
"value": "Note 22 Provision for abandonment liabilities GroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022 Provisions as of beginning of period 4 165.6 5 172.4 4 165.6 5 172.4 Incurred removal cost -160.2 -79.2 -160.2 -78.5 Accretion expense 166.3 119.9 166.3 107.9 Abandonment liabilities from acquisition of Lundin Energy - 745.9 - - Merger with ABP Norway AS - - - 598.6 Foreign currency translation - 6.7 - - Impact of changes to discount rate -101.2 -1 876.9 -101.2 -1 747.7Change in estimates and new provisions 484.1 76.9 484.1 113.0 Total provision for abandonment liabilities 4 554.7 4 165.6 4 554.7 4 165.6 Breakdown of the provisionShort-term 250.6 115.2 250.6 115.2 Long-term 4 304.1 4 050.4 4 304.1 4 050.4 Total provision for abandonment liabilities 4 554.7 4 165.6 4 554.7 4 165.6 Estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The nominal pre tax discount rate (risk free) at end of 2023 is between 4.0 percent and 4.9 percent, depending on the timing of the expected cash flows. The corresponding range at year end 2022 was between 3.9 and 4.7. The calculations assume an inflation rate of 2.0 percent for all applicable periods.Climate-related risk:As described in note 3 on climate-related risk, a sensitivity analysis have been performed to show the impact on the book value of abandonment provisions as at 31 December 2023, if cease of production of fields with estimated lifetime from 2040 were accelerated by ten years. Such acceleration would result in an increase in the book value of abandonment provision of USD 680 million.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherProvisionsContingentLiabilitiesAndContingentAssetsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__114-1": {
"value": "Note 23 DerivativesGroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Unrealised gain currency contracts 38.1 2.9 38.1 2.9Long-term derivatives included in assets 38.1 2.9 38.1 2.9Unrealised gain commodity derivatives 0.2 - 0.2 -Unrealised gain currency contracts 147.9 153.1 147.9 153.1Short-term derivatives included in assets 148.1 153.1 148.1 153.1Total derivatives included in assets 186.2 156.0 186.2 156.0Fair value of option related to sale of Cognite - 16.0 - 16.0Unrealised losses currency contracts 0.5 1.0 0.5 1.0Long-term derivatives included in liabilities 0.5 17.0 0.5 17.0Fair value of option related to sale of Cognite 4.8 - 4.8 -Unrealised losses currency contracts 28.0 34.9 28.0 34.9Short-term derivatives included in liabilities 32.8 34.9 32.8 34.9Total derivatives included in liabilities 33.3 51.9 33.3 51.9The company has various types of economic hedging instruments, but no hedge accounting is applied. Commodity derivatives are used to hedge the risk of oil price reduction. The company currently has limited exposure towards fluctuations in interest rate, but generally manages such exposure by using interest rate derivatives. Foreign currency exchange derivatives are used to manage the company's exposure to currency risks, mainly costs in NOK, EUR and GBP. These derivatives are mark to market with changes in market value recognised in the income statement. In the income statement, impacts from commodity derivatives are presented as other income, while impacts from other derivatives are presented as financial items.Note 28 Financial instrumentsCapital structure and equity The company's financial position has been developed and improved over time and has clear capital allocation principles. The main priority is a robust balance sheet with financial flexibility and investment grade credit rating. Maintaining our rating is particularly central as it gives us effective access to capital markets and serves as a foundation for future investments. The company has an investment grade rating by S&P Global, Fitch and Moody's. The company's production level, financial position and resource and reserve levels are important parameters in relation to the assigned rating. The company continues to optimise its capital structure by balancing the return on equity against liquidity requirements.The company monitors changes in financing needs, risk, assets and cash flows, and evaluates the capital structure continuously. To maintain the desired capital structure, the company considers various types of capital transactions, including refinancing of its debt, purchase or issue new shares or debt instruments, sell assets or pay back capital to the owners.Unless specified otherwise, the numbers below apply both to the group and the parent. Categories of financial assets and liabilities The company has the following financial assets and liabilities: financial assets and liabilities recognised at fair value through profit or loss, cash and receivables, and other liabilities. The latter two are recognised in the accounts at amortised cost, while the first item is recognised at fair value.Categories of financial assets and financial liabilities - Group and ParentFinancial Financial Financial Financial assets at fair assets liabilities at fair liabilities value through measured at value through measured at 31.12.2023profit and lossamortised costprofit and lossamortised costTotalAssetsTrade receivables - 658.8 - - 658.81)Other short-term receivable- 462.4 - - 462.4Cash and cash equivalents - 3 388.4 - - 3 388.4Long-term receivables 7.0 62.2 - - 69.1Derivatives 186.2 - - - 186.2Total financial assets 193.2 4 571.8 - - 4 764.9LiabilitiesDerivatives - - 33.3 - 33.3Trade creditors - - - 291.0 291.0Bonds - - - 5 798.2 5 798.2Other short-term liabilities - - - 1 071.0 1 071.0Total financial liabilities - - 33.3 7 160.2 7 193.41) Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.Financial Financial Financial Financial assets at fair assets liabilities at fair liabilities value through measured at value through measured at profit and lossamortised costprofit and lossamortised costTotal31.12.2022AssetsTrade receivables - 950.9 - - 950.91)Other short-term receivables- 562.3 - - 562.3Cash and cash equivalents - 2 756.0 - - 2 756.0Long-term receivables 11.0 158.6 - - 169.5Derivatives 156.0 - - - 156.0Total financial assets 167.0 4 427.8 - - 4 594.7LiabilitiesDerivatives - - 51.9 - 51.9Trade creditors - - - 133.9 133.9Bonds - - - 5 279.2 5 279.2Other short-term liabilities - - - 807.1 807.1Total financial liabilities - - 51.9 6 220.2 6 272.11) Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.Determination of fair value The fair value of forward exchange contracts is determined using the forward exchange rate at the end of the reporting period. The fair value of commodity derivatives is determined using the forward Brent blend curve at the end of the reporting period. The fair value of interest rate swaps and cross currency interest rate swaps is determined by using the expected floating interest rates at the end of the period and is confirmed by external market sources. See note 23 for detailed information about the derivatives.The following of the company's financial instruments have not been valued at fair value: trade debtors, other short-term receivables, long-term receivables, and other short-term liabilities and bonds. The carrying amount of cash and cash equivalents is approximately equal to fair value, since these instruments have a short term to maturity. Similarly, the carrying amount of trade receivable, other receivables, trade creditors and other short-term liabilities is materially the same as their fair value as they are entered into on ordinary terms and conditions.The Senior Notes are all listed on The Luxembourg Stock Exchange. The fair values for disclosure purposes are determined using the quoted value as of 31 December 2023.The following is a comparison between the book value and fair value of the company's financial instruments, except those where the carrying amount is a reasonable approximation of fair value (such as short-term trade receivables and payables in addition to instruments measured to fair value).31.12.202331.12.2022Fair value of financial instruments (USD million)Book value Fair value Book value Fair valueFinancial liabilities measured at amortised cost: Bonds 5 798.2 5 629.4 5 279.2 4 829.7Total financial liabilities 5 798.2 5 629.4 5 279.2 4 829.7Fair value hierarchyThe company classifies fair value measurements by employing a value hierarchy that reflects the significance of the input used in preparing the measurements. The fair value hierarchy consists of the following levels:Level 1 - input in the form of listed (unadjusted) prices in active markets for identical assets or liabilities.Level 2 - input other than listed prices of assets and liabilities included in Level 1 that is observable for assets or liabilities,either directly (i.e. as prices) or indirectly (i.e. derived from prices).Level 3 - input for assets or liabilities for which there is no observable market data (non-observable input). 31.12.2023Financial instruments recognised at fair value (USD million) Level 1 Level 2 Level 3Financial assets or liabilities measured at fair value with changes in value recognised through profit or loss:1)Long-term receivables- - 7.02)Derivatives- 157.7 -4.831.12.2022Financial instruments recognised at fair value (USD million) Level 1 Level 2 Level 3Financial assets or liabilities measured at fair value with changes in value recognised through profit or loss:1)Long-term receivables- - 11.02)Derivatives- 120.1 -16.01) The sale of 2.6 percent of Johan Sverdrup during 2019 (made by Lundin) included a contingent consideration based on future reserve reclassifications and is due in 2026, The valuation is considered level 3 in the fair value hierarchy.2) The level 3 figure relates to the put option granted to the buyer of the shares in Cognite AS, as described in note 18.The valuation is considered level 3 in the fair value hierarchy due to the significance of unobservable market data in the valuation.In the course of the reporting period, there were no changes in the fair value measurements that involved any transfers between levels. Reconciliation of cash flows from financing activitiesThe table below shows a reconciliation between the opening and the closing balances in the statement of financial position for liabilities arising from financing activities.Non-cash changesAmortisation and interest 1)31.12.2022 Cash flows Currency Otherexpense31.12.2023Bonds 5 279.2 486.1 45.0 28.8 -40.9 5 798.2Other interest-bearing debt (RCF) - -8.3 - - 8.3 -Accrued interest, classified under other current liabilities 98.1 -251.8 239.5 - - 85.8Lease debt 134.4 -133.5 - -1.2 704.5 704.2Paid dividends - -1 390.4 - - - -Treasury shares -7.1 -10.5 - - - -17.6Totals5 504.6 -1 308.5 284.5 27.6 671.9 6 570.5Non-cash changesAmortisation and interest 2)3)31.12.2021 Cash flows Currency Otherexpense31.12.2022Bonds 3 576.7 - 25.9 -49.4 1 726.0 5 279.2Other interest-bearing debt (RCF) - -601.1 - - 601.1 -Accrued interest, classified under other current liabilities 77.3 -156.5 177.3 - - 98.1Lease debt 136.2 -66.6 - -3.8 68.5 134.4Paid dividends - -1 005.7 - - -Treasury shares -8.6 1.5 - - - -7.1Totals3 781.6 -1 828.3 203.1 -53.2 2 395.5 5 504.61) Other includes gain related to repurchase of bonds, as described in note 21 and new lease debt, as described in note 252) Other includes transfer of bonds and other interest bearing debt to Aker BP in connection with the Lundin transaction3) Amortisation of Bonds in Parent was USD 14.7 million",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__113-1": {
"value": "Note 23 DerivativesGroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Unrealised gain currency contracts 38.1 2.9 38.1 2.9Long-term derivatives included in assets 38.1 2.9 38.1 2.9Unrealised gain commodity derivatives 0.2 - 0.2 -Unrealised gain currency contracts 147.9 153.1 147.9 153.1Short-term derivatives included in assets 148.1 153.1 148.1 153.1Total derivatives included in assets 186.2 156.0 186.2 156.0Fair value of option related to sale of Cognite - 16.0 - 16.0Unrealised losses currency contracts 0.5 1.0 0.5 1.0Long-term derivatives included in liabilities 0.5 17.0 0.5 17.0Fair value of option related to sale of Cognite 4.8 - 4.8 -Unrealised losses currency contracts 28.0 34.9 28.0 34.9Short-term derivatives included in liabilities 32.8 34.9 32.8 34.9Total derivatives included in liabilities 33.3 51.9 33.3 51.9The company has various types of economic hedging instruments, but no hedge accounting is applied. Commodity derivatives are used to hedge the risk of oil price reduction. The company currently has limited exposure towards fluctuations in interest rate, but generally manages such exposure by using interest rate derivatives. Foreign currency exchange derivatives are used to manage the company's exposure to currency risks, mainly costs in NOK, EUR and GBP. These derivatives are mark to market with changes in market value recognised in the income statement. In the income statement, impacts from commodity derivatives are presented as other income, while impacts from other derivatives are presented as financial items.Note 28 Financial instrumentsCapital structure and equity The company's financial position has been developed and improved over time and has clear capital allocation principles. The main priority is a robust balance sheet with financial flexibility and investment grade credit rating. Maintaining our rating is particularly central as it gives us effective access to capital markets and serves as a foundation for future investments. The company has an investment grade rating by S&P Global, Fitch and Moody's. The company's production level, financial position and resource and reserve levels are important parameters in relation to the assigned rating. The company continues to optimise its capital structure by balancing the return on equity against liquidity requirements.The company monitors changes in financing needs, risk, assets and cash flows, and evaluates the capital structure continuously. To maintain the desired capital structure, the company considers various types of capital transactions, including refinancing of its debt, purchase or issue new shares or debt instruments, sell assets or pay back capital to the owners.Unless specified otherwise, the numbers below apply both to the group and the parent. Categories of financial assets and liabilities The company has the following financial assets and liabilities: financial assets and liabilities recognised at fair value through profit or loss, cash and receivables, and other liabilities. The latter two are recognised in the accounts at amortised cost, while the first item is recognised at fair value.Categories of financial assets and financial liabilities - Group and ParentFinancial Financial Financial Financial assets at fair assets liabilities at fair liabilities value through measured at value through measured at 31.12.2023profit and lossamortised costprofit and lossamortised costTotalAssetsTrade receivables - 658.8 - - 658.81)Other short-term receivable- 462.4 - - 462.4Cash and cash equivalents - 3 388.4 - - 3 388.4Long-term receivables 7.0 62.2 - - 69.1Derivatives 186.2 - - - 186.2Total financial assets 193.2 4 571.8 - - 4 764.9LiabilitiesDerivatives - - 33.3 - 33.3Trade creditors - - - 291.0 291.0Bonds - - - 5 798.2 5 798.2Other short-term liabilities - - - 1 071.0 1 071.0Total financial liabilities - - 33.3 7 160.2 7 193.41) Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.Financial Financial Financial Financial assets at fair assets liabilities at fair liabilities value through measured at value through measured at profit and lossamortised costprofit and lossamortised costTotal31.12.2022AssetsTrade receivables - 950.9 - - 950.91)Other short-term receivables- 562.3 - - 562.3Cash and cash equivalents - 2 756.0 - - 2 756.0Long-term receivables 11.0 158.6 - - 169.5Derivatives 156.0 - - - 156.0Total financial assets 167.0 4 427.8 - - 4 594.7LiabilitiesDerivatives - - 51.9 - 51.9Trade creditors - - - 133.9 133.9Bonds - - - 5 279.2 5 279.2Other short-term liabilities - - - 807.1 807.1Total financial liabilities - - 51.9 6 220.2 6 272.11) Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.Determination of fair value The fair value of forward exchange contracts is determined using the forward exchange rate at the end of the reporting period. The fair value of commodity derivatives is determined using the forward Brent blend curve at the end of the reporting period. The fair value of interest rate swaps and cross currency interest rate swaps is determined by using the expected floating interest rates at the end of the period and is confirmed by external market sources. See note 23 for detailed information about the derivatives.The following of the company's financial instruments have not been valued at fair value: trade debtors, other short-term receivables, long-term receivables, and other short-term liabilities and bonds. The carrying amount of cash and cash equivalents is approximately equal to fair value, since these instruments have a short term to maturity. Similarly, the carrying amount of trade receivable, other receivables, trade creditors and other short-term liabilities is materially the same as their fair value as they are entered into on ordinary terms and conditions.The Senior Notes are all listed on The Luxembourg Stock Exchange. The fair values for disclosure purposes are determined using the quoted value as of 31 December 2023.The following is a comparison between the book value and fair value of the company's financial instruments, except those where the carrying amount is a reasonable approximation of fair value (such as short-term trade receivables and payables in addition to instruments measured to fair value).31.12.202331.12.2022Fair value of financial instruments (USD million)Book value Fair value Book value Fair valueFinancial liabilities measured at amortised cost: Bonds 5 798.2 5 629.4 5 279.2 4 829.7Total financial liabilities 5 798.2 5 629.4 5 279.2 4 829.7Fair value hierarchyThe company classifies fair value measurements by employing a value hierarchy that reflects the significance of the input used in preparing the measurements. The fair value hierarchy consists of the following levels:Level 1 - input in the form of listed (unadjusted) prices in active markets for identical assets or liabilities.Level 2 - input other than listed prices of assets and liabilities included in Level 1 that is observable for assets or liabilities,either directly (i.e. as prices) or indirectly (i.e. derived from prices).Level 3 - input for assets or liabilities for which there is no observable market data (non-observable input). 31.12.2023Financial instruments recognised at fair value (USD million) Level 1 Level 2 Level 3Financial assets or liabilities measured at fair value with changes in value recognised through profit or loss:1)Long-term receivables- - 7.02)Derivatives- 157.7 -4.831.12.2022Financial instruments recognised at fair value (USD million) Level 1 Level 2 Level 3Financial assets or liabilities measured at fair value with changes in value recognised through profit or loss:1)Long-term receivables- - 11.02)Derivatives- 120.1 -16.01) The sale of 2.6 percent of Johan Sverdrup during 2019 (made by Lundin) included a contingent consideration based on future reserve reclassifications and is due in 2026, The valuation is considered level 3 in the fair value hierarchy.2) The level 3 figure relates to the put option granted to the buyer of the shares in Cognite AS, as described in note 18.The valuation is considered level 3 in the fair value hierarchy due to the significance of unobservable market data in the valuation.In the course of the reporting period, there were no changes in the fair value measurements that involved any transfers between levels. Reconciliation of cash flows from financing activitiesThe table below shows a reconciliation between the opening and the closing balances in the statement of financial position for liabilities arising from financing activities.Non-cash changesAmortisation and interest 1)31.12.2022 Cash flows Currency Otherexpense31.12.2023Bonds 5 279.2 486.1 45.0 28.8 -40.9 5 798.2Other interest-bearing debt (RCF) - -8.3 - - 8.3 -Accrued interest, classified under other current liabilities 98.1 -251.8 239.5 - - 85.8Lease debt 134.4 -133.5 - -1.2 704.5 704.2Paid dividends - -1 390.4 - - - -Treasury shares -7.1 -10.5 - - - -17.6Totals5 504.6 -1 308.5 284.5 27.6 671.9 6 570.5Non-cash changesAmortisation and interest 2)3)31.12.2021 Cash flows Currency Otherexpense31.12.2022Bonds 3 576.7 - 25.9 -49.4 1 726.0 5 279.2Other interest-bearing debt (RCF) - -601.1 - - 601.1 -Accrued interest, classified under other current liabilities 77.3 -156.5 177.3 - - 98.1Lease debt 136.2 -66.6 - -3.8 68.5 134.4Paid dividends - -1 005.7 - - -Treasury shares -8.6 1.5 - - - -7.1Totals3 781.6 -1 828.3 203.1 -53.2 2 395.5 5 504.61) Other includes gain related to repurchase of bonds, as described in note 21 and new lease debt, as described in note 252) Other includes transfer of bonds and other interest bearing debt to Aker BP in connection with the Lundin transaction3) Amortisation of Bonds in Parent was USD 14.7 million",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDerivativeFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__112-1": {
"value": "Note 23 DerivativesGroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Unrealised gain currency contracts 38.1 2.9 38.1 2.9Long-term derivatives included in assets 38.1 2.9 38.1 2.9Unrealised gain commodity derivatives 0.2 - 0.2 -Unrealised gain currency contracts 147.9 153.1 147.9 153.1Short-term derivatives included in assets 148.1 153.1 148.1 153.1Total derivatives included in assets 186.2 156.0 186.2 156.0Fair value of option related to sale of Cognite - 16.0 - 16.0Unrealised losses currency contracts 0.5 1.0 0.5 1.0Long-term derivatives included in liabilities 0.5 17.0 0.5 17.0Fair value of option related to sale of Cognite 4.8 - 4.8 -Unrealised losses currency contracts 28.0 34.9 28.0 34.9Short-term derivatives included in liabilities 32.8 34.9 32.8 34.9Total derivatives included in liabilities 33.3 51.9 33.3 51.9The company has various types of economic hedging instruments, but no hedge accounting is applied. Commodity derivatives are used to hedge the risk of oil price reduction. The company currently has limited exposure towards fluctuations in interest rate, but generally manages such exposure by using interest rate derivatives. Foreign currency exchange derivatives are used to manage the company's exposure to currency risks, mainly costs in NOK, EUR and GBP. These derivatives are mark to market with changes in market value recognised in the income statement. In the income statement, impacts from commodity derivatives are presented as other income, while impacts from other derivatives are presented as financial items.As of year end 2023 the company has used currency derivatives to secure approximately NOK 35 billion in 2024 by selling USD at an average exchange rate of USD/NOK 10.51 and NOK 9 billion in 2025 at an average rate of USD/NOK 10.38. In addition, NOK 1.3 billion has been secured in 2026 using options, with an average strike price of USD/NOK 10.53.Note 28 Financial instrumentsCapital structure and equity The company's financial position has been developed and improved over time and has clear capital allocation principles. The main priority is a robust balance sheet with financial flexibility and investment grade credit rating. Maintaining our rating is particularly central as it gives us effective access to capital markets and serves as a foundation for future investments. The company has an investment grade rating by S&P Global, Fitch and Moody's. The company's production level, financial position and resource and reserve levels are important parameters in relation to the assigned rating. The company continues to optimise its capital structure by balancing the return on equity against liquidity requirements.The company monitors changes in financing needs, risk, assets and cash flows, and evaluates the capital structure continuously. To maintain the desired capital structure, the company considers various types of capital transactions, including refinancing of its debt, purchase or issue new shares or debt instruments, sell assets or pay back capital to the owners.Unless specified otherwise, the numbers below apply both to the group and the parent.Determination of fair value The fair value of forward exchange contracts is determined using the forward exchange rate at the end of the reporting period. The fair value of commodity derivatives is determined using the forward Brent blend curve at the end of the reporting period. The fair value of interest rate swaps and cross currency interest rate swaps is determined by using the expected floating interest rates at the end of the period and is confirmed by external market sources. See note 23 for detailed information about the derivatives.The following of the company's financial instruments have not been valued at fair value: trade debtors, other short-term receivables, long-term receivables, and other short-term liabilities and bonds. The carrying amount of cash and cash equivalents is approximately equal to fair value, since these instruments have a short term to maturity. Similarly, the carrying amount of trade receivable, other receivables, trade creditors and other short-term liabilities is materially the same as their fair value as they are entered into on ordinary terms and conditions.The Senior Notes are all listed on The Luxembourg Stock Exchange. The fair values for disclosure purposes are determined using the quoted value as of 31 December 2023.The following is a comparison between the book value and fair value of the company's financial instruments, except those where the carrying amount is a reasonable approximation of fair value (such as short-term trade receivables and payables in addition to instruments measured to fair value).31.12.202331.12.2022Fair value of financial instruments (USD million)Book value Fair value Book value Fair valueFinancial liabilities measured at amortised cost: Bonds 5 798.2 5 629.4 5 279.2 4 829.7Total financial liabilities 5 798.2 5 629.4 5 279.2 4 829.7Fair value hierarchyThe company classifies fair value measurements by employing a value hierarchy that reflects the significance of the input used in preparing the measurements. The fair value hierarchy consists of the following levels:Level 1 - input in the form of listed (unadjusted) prices in active markets for identical assets or liabilities.Level 2 - input other than listed prices of assets and liabilities included in Level 1 that is observable for assets or liabilities,either directly (i.e. as prices) or indirectly (i.e. derived from prices).Level 3 - input for assets or liabilities for which there is no observable market data (non-observable input). 31.12.2023Financial instruments recognised at fair value (USD million) Level 1 Level 2 Level 3Financial assets or liabilities measured at fair value with changes in value recognised through profit or loss:1)Long-term receivables- - 7.02)Derivatives- 157.7 -4.831.12.2022Financial instruments recognised at fair value (USD million) Level 1 Level 2 Level 3Financial assets or liabilities measured at fair value with changes in value recognised through profit or loss:1)Long-term receivables- - 11.02)Derivatives- 120.1 -16.01) The sale of 2.6 percent of Johan Sverdrup during 2019 (made by Lundin) included a contingent consideration based on future reserve reclassifications and is due in 2026, The valuation is considered level 3 in the fair value hierarchy.2) The level 3 figure relates to the put option granted to the buyer of the shares in Cognite AS, as described in note 18.The valuation is considered level 3 in the fair value hierarchy due to the significance of unobservable market data in the valuation.In the course of the reporting period, there were no changes in the fair value measurements that involved any transfers between levels. Reconciliation of cash flows from financing activitiesThe table below shows a reconciliation between the opening and the closing balances in the statement of financial position for liabilities arising from financing activities.Non-cash changesAmortisation and interest 1)31.12.2022 Cash flows Currency Otherexpense31.12.2023Bonds 5 279.2 486.1 45.0 28.8 -40.9 5 798.2Other interest-bearing debt (RCF) - -8.3 - - 8.3 -Accrued interest, classified under other current liabilities 98.1 -251.8 239.5 - - 85.8Lease debt 134.4 -133.5 - -1.2 704.5 704.2Paid dividends - -1 390.4 - - - -Treasury shares -7.1 -10.5 - - - -17.6Totals5 504.6 -1 308.5 284.5 27.6 671.9 6 570.5Non-cash changesAmortisation and interest 2)3)31.12.2021 Cash flows Currency Otherexpense31.12.2022Bonds 3 576.7 - 25.9 -49.4 1 726.0 5 279.2Other interest-bearing debt (RCF) - -601.1 - - 601.1 -Accrued interest, classified under other current liabilities 77.3 -156.5 177.3 - - 98.1Lease debt 136.2 -66.6 - -3.8 68.5 134.4Paid dividends - -1 005.7 - - -Treasury shares -8.6 1.5 - - - -7.1Totals3 781.6 -1 828.3 203.1 -53.2 2 395.5 5 504.61) Other includes gain related to repurchase of bonds, as described in note 21 and new lease debt, as described in note 252) Other includes transfer of bonds and other interest bearing debt to Aker BP in connection with the Lundin transaction3) Amortisation of Bonds in Parent was USD 14.7 million",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__118": {
"value": "Note 24 Other current liabilitiesGroupParentBreakdown of other current liabilities (USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Balances with licence partners 30.9 43.1 30.9 43.1Share of other current liabilities in licences 692.5 460.8 692.3 460.8Overlift of petroleum 42.8 30.9 42.8 30.9Accrued interest 85.8 95.8 85.8 95.8Payroll liabilities and other provisions 219.2 176.5 218.5 176.3Total other current liabilities 1 071.0 807.1 1 070.2 806.9",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__117": {
"value": "Note 24 Other current liabilitiesGroupParentBreakdown of other current liabilities (USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Balances with licence partners 30.9 43.1 30.9 43.1Share of other current liabilities in licences 692.5 460.8 692.3 460.8Overlift of petroleum 42.8 30.9 42.8 30.9Accrued interest 85.8 95.8 85.8 95.8Payroll liabilities and other provisions 219.2 176.5 218.5 176.3Total other current liabilities 1 071.0 807.1 1 070.2 806.9",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherCurrentLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__116": {
"value": "Note 24 Other current liabilitiesGroupParentBreakdown of other current liabilities (USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Balances with licence partners 30.9 43.1 30.9 43.1Share of other current liabilities in licences 692.5 460.8 692.3 460.8Overlift of petroleum 42.8 30.9 42.8 30.9Accrued interest 85.8 95.8 85.8 95.8Payroll liabilities and other provisions 219.2 176.5 218.5 176.3Total other current liabilities 1 071.0 807.1 1 070.2 806.9",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__115-1": {
"value": "As of year end 2023 the company has used currency derivatives to secure approximately NOK 35 billion in 2024 by selling USD at an average exchange rate of USD/NOK 10.51 and NOK 9 billion in 2025 at an average rate of USD/NOK 10.38. In addition, NOK 1.3 billion has been secured in 2026 using options, with an average strike price of USD/NOK 10.53.Categories of financial assets and liabilities The company has the following financial assets and liabilities: financial assets and liabilities recognised at fair value through profit or loss, cash and receivables, and other liabilities. The latter two are recognised in the accounts at amortised cost, while the first item is recognised at fair value.Categories of financial assets and financial liabilities - Group and ParentFinancial Financial Financial Financial assets at fair assets liabilities at fair liabilities value through measured at value through measured at 31.12.2023profit and lossamortised costprofit and lossamortised costTotalAssetsTrade receivables - 658.8 - - 658.81)Other short-term receivable- 462.4 - - 462.4Cash and cash equivalents - 3 388.4 - - 3 388.4Long-term receivables 7.0 62.2 - - 69.1Derivatives 186.2 - - - 186.2Total financial assets 193.2 4 571.8 - - 4 764.9LiabilitiesDerivatives - - 33.3 - 33.3Trade creditors - - - 291.0 291.0Bonds - - - 5 798.2 5 798.2Other short-term liabilities - - - 1 071.0 1 071.0Total financial liabilities - - 33.3 7 160.2 7 193.41) Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.Financial Financial Financial Financial assets at fair assets liabilities at fair liabilities value through measured at value through measured at profit and lossamortised costprofit and lossamortised costTotal31.12.2022AssetsTrade receivables - 950.9 - - 950.91)Other short-term receivables- 562.3 - - 562.3Cash and cash equivalents - 2 756.0 - - 2 756.0Long-term receivables 11.0 158.6 - - 169.5Derivatives 156.0 - - - 156.0Total financial assets 167.0 4 427.8 - - 4 594.7LiabilitiesDerivatives - - 51.9 - 51.9Trade creditors - - - 133.9 133.9Bonds - - - 5 279.2 5 279.2Other short-term liabilities - - - 807.1 807.1Total financial liabilities - - 51.9 6 220.2 6 272.11) Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__119": {
"value": "Note 25 Lease agreementsThe group has entered into leases for rig contracts, other licence related commitments and office premises. The leases do not contain any restrictions on the company's dividend policy or financing. Lease agreements that are planned to be applied on several operated licences, are generally recogised on a gross basis as Aker BP is deemed to be the primary obligator. A sublease is recognised upon commencement to the extent the related RoU asset will be subleased for more than 12 months.Significant lease agreementsFor 2023, the group had four operated rig commitments recognised as lease debt. This included the two jack-up rigs Noble Invincible and Noble Integrator. Noble Invincible commenced on a new contract in the beginning of April 2023, expected to expire in November 2027, including options to suspend the commitment for parts of the period. Noble Integrator was contracted by Valhall/Hod from 2022 until September 2023.In addition, we had the semi-submersible rig Deepsea Nordkapp contract with Odfjell Drilling during 2023. After exercising an extension option, committing the Deepsea Nordkapp for the completion of the Kobra East Gekko (KEG) scope, the rig contract was recognised in the statement of financial position when the KEG scope commenced in early 2023. After finalising the KEG scope, the Deepsea Nordkapp commenced on a new contract in October 2023 with a firm contract scope until end of 2026, with possible optionality to extend the contract period further. The new contract has thus been recognised as lease liability in 2023 for the firm period.Aker BP has further entered into a rig agreement with Saipem for the semi-submersible drilling rig Scarabeo 8. The contract duration is for three years with two one-year options and a mechanism of rate adjustment to market rates from the third year and onwards. The rig commenced with Aker BP in beginning of January 2023 and was recognised in the statement of financial position as a lease liability, including the two one-year option periods.In addition, Aker BP has a lease liability related to the semi-submersible rig Deepsea Atlantic, operated by Equinor on Johan Sverdrup expected to end around mid-2024.Other significant lease agreements Under the drilling and well construction alliance agreements, Aker BP entered into a five-year rig commitment for the jack-up rig Noble Integrator in 2022. Different rate structures will apply during the period reflecting different operating modes, agreed incentive schemes, and market developments. There will be different work scopes, with varying durations in the period from 2024 to 2027, including options to suspend the commitment for parts of the period. Noble Integrator is expected to commence operations in Q2 2024. The semi-submersible rig Deepsea Stavanger is expected to join the Aker BP rig fleet in the first half of 2025 for a five-year contract.The minimum commitments from the lease contracts described above that has not commenced within year end 2023, have been included as other commitments in note 26. Other lease informationNon-lease components such as the service element of rig commitments are not included as part of the lease debt. As at 31 December 2023 this amounts to USD 451 million.The total expenditure relating to short-term leases which are not recognised as part of lease liabilities was USD 4 million in 2023 (USD 71 million in 2022). The group does not have any residual value guarantees or variable lease payments. Extension options are included in the lease liability when, based on management's judgement, it is reasonably certain that an extension will be exercised. No sublease of right-of-use assets has been recognised as of year end 2023.The incremental borrowing rate applied in discounting of the nominal lease debt is between 2.40 percent and 6.90 percent, dependent on the duration of the lease and when it was intially recognised.GroupParent(USD million) 2023 2022 2023 2022Lease debt as of beginning of period 134.4 136.2 134.4 136.2New lease debt recognised in the period 704.5 33.8 704.5 54.41)Payments of lease debt-160.4 -74.1 -160.4 -67.6Interest expense on lease debt 26.9 7.5 26.9 7.1Lease debt from acquisition of Lundin Energy - 34.8 - 6.0Currency exchange differences -1.2 -3.8 -1.2 -1.8Total lease debt 704.2 134.4 704.2 134.4Break down of the lease debt to short-term and long-term liabilitiesShort-term 148.7 36.3 148.7 36.3Long-term 555.5 98.1 555.5 98.1Total lease debt 704.2 134.4 704.2 134.41) Payments of lease debt split by activities (USD million): 2023 2022 2023 2022Investments in fixed assets 95.7 46.9 95.7 41.7Abandonment activity 8.3 0.8 8.3 0.8Operating expenditures 11.3 13.9 11.3 13.9Exploration expenditures 12.0 6.2 12.0 6.2Other income 33.1 6.3 33.1 5.0Total 160.4 74.1 160.4 67.6Nominal lease debt maturity breakdown (USD million):Within one year 220.2 42.6 220.2 42.6Two to five years 528.4 87.2 528.4 87.2After five years 11.8 26.4 11.8 26.4Total 760.4 156.2 760.4 156.2See note 13 for disclosures relating to the right-of-use assets.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLeasesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__120": {
"value": "Note 26 CommitmentsCapital commitments and other contractual obligationsAker BP`s net share of capital commitments and other contractual obligations in the table below are mainly related to unavoidable costs related to development projects, non-rig commitments not recognised as lease liabilities, rig leases not yet commenced and booked future gas transportation capacity. Parts of the rig leases have been entered into in the company\u2019s name at the initial signing, and subsequently partly allocated to licences. The figures have been calculated based on the assumed net share for the company based on the planned use of the related leased assets as at 31 December 2023. The numbers below exclude any liabilities disclosed in note 25 in relation to right-of-use assets. GroupParent(USD million) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Within one year1 191.91 572.11 191.91 572.1One to five years753.8714.7753.8714.7After five years76.0284.076.0284.0Total 2 021.8 2 570.7 2 021.8 2 570.7The main part of the commitments within one year in the table above relates to non-cancellable expenditures on contracts entered into in connection with the PDO's delivered in 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCommitmentsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__121": {
"value": "Contingent liabilities During the normal course of its business, the company will be involved in disputes, including tax disputes. Potential tax claims related to previous taxable income of acquired companies can to some extent be reimbursed from the sellers. The company has made accruals for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS 37 and IAS 12. As for other licences on the NCS, the company has unlimited liability for damage, including pollution damage. The company has insured its pro rata liability on the NCS on a par with other oil companies. Facilities and liabilities towards third parties are covered by an operational insurance policy.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__122": {
"value": "Note 27 Transactions with related partiesThe three main shareholders in Aker BP is Aker Capital AS, BP Exploration Operating Company and Nemesia S.a.r.l, which are all considered to have significant influence over Aker BP. Aker BP has no transactions with entities controlled by Nemesia. Entities controlled by either of the Aker Group or BP Group are considered to be related parties under IFRS and are listed in the table below. The figures listed represent net charges to Aker BP. GroupParentRelated party (USD million) Revenues (-) / expenses (+) 31.12.2023 31.12.2022 31.12.2023 31.12.2022ABP Norway AS Interest cost - - - 9.2ABP Norway AS Interest income - - - -7.4ABP Norway ASOperating expenses - - - 18.51)ABP Norway ASRecharges- - - -52.5ABP Energy Holding BV Interest cost - - - 1.2aiZe AS Purchases of consultant and technology services13.1 5.1 13.1 5.1Aker ASA Board remuneration etc 0.5 0.9 0.5 0.92)Cognite ASPurchases of consultant and IT services 11.9 7.0 11.9 7.0Lily Akerkvartalet AS Office cost 0.7 0.5 0.7 0.5BP Oil International Ltd Sales of Oil and NGL -11 591.4 -8 796.6 -11 591.4 -5 707.5BP Gas Marketing Ltd Sales of Gas -1 083.1 -2 819.7 -1 083.1 -2 956.5GroupParentRelated party (USD million)Receivables (+) / liabilities (-) 31.12.2023 31.12.2022 31.12.2023 31.12.2022Aker BP UK LtdOther receivables - - 8.5 6.2BP Oil International Ltd Trade receivables 637.7 838.5 637.7 400.41) The figure represents total gross charges related to personnel employed by Aker BP ASA working for ABP Norway AS. These charges have been allocated to various licences and corporate activity based on timewriting.2) As described in note 18 Aker BP sold its share in Cognite during 2022. Due to the continuing involvement arising from the put option arrangement, the transactions with Cognite are still considered to be within related parties.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__124": {
"value": "Note 28 Financial instrumentsCapital structure and equity The company's financial position has been developed and improved over time and has clear capital allocation principles. The main priority is a robust balance sheet with financial flexibility and investment grade credit rating. Maintaining our rating is particularly central as it gives us effective access to capital markets and serves as a foundation for future investments. The company has an investment grade rating by S&P Global, Fitch and Moody's. The company's production level, financial position and resource and reserve levels are important parameters in relation to the assigned rating. The company continues to optimise its capital structure by balancing the return on equity against liquidity requirements.The company monitors changes in financing needs, risk, assets and cash flows, and evaluates the capital structure continuously. To maintain the desired capital structure, the company considers various types of capital transactions, including refinancing of its debt, purchase or issue new shares or debt instruments, sell assets or pay back capital to the owners.Unless specified otherwise, the numbers below apply both to the group and the parent.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__126": {
"value": "Categories of financial assets and liabilities The company has the following financial assets and liabilities: financial assets and liabilities recognised at fair value through profit or loss, cash and receivables, and other liabilities. The latter two are recognised in the accounts at amortised cost, while the first item is recognised at fair value.Categories of financial assets and financial liabilities - Group and ParentFinancial Financial Financial Financial assets at fair assets liabilities at fair liabilities value through measured at value through measured at 31.12.2023profit and lossamortised costprofit and lossamortised costTotalAssetsTrade receivables - 658.8 - - 658.81)Other short-term receivable- 462.4 - - 462.4Cash and cash equivalents - 3 388.4 - - 3 388.4Long-term receivables 7.0 62.2 - - 69.1Derivatives 186.2 - - - 186.2Total financial assets 193.2 4 571.8 - - 4 764.9LiabilitiesDerivatives - - 33.3 - 33.3Trade creditors - - - 291.0 291.0Bonds - - - 5 798.2 5 798.2Other short-term liabilities - - - 1 071.0 1 071.0Total financial liabilities - - 33.3 7 160.2 7 193.41) Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.Financial Financial Financial Financial assets at fair assets liabilities at fair liabilities value through measured at value through measured at profit and lossamortised costprofit and lossamortised costTotal31.12.2022AssetsTrade receivables - 950.9 - - 950.91)Other short-term receivables- 562.3 - - 562.3Cash and cash equivalents - 2 756.0 - - 2 756.0Long-term receivables 11.0 158.6 - - 169.5Derivatives 156.0 - - - 156.0Total financial assets 167.0 4 427.8 - - 4 594.7LiabilitiesDerivatives - - 51.9 - 51.9Trade creditors - - - 133.9 133.9Bonds - - - 5 279.2 5 279.2Other short-term liabilities - - - 807.1 807.1Total financial liabilities - - 51.9 6 220.2 6 272.11) Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialInstrumentsDesignatedAtFairValueThroughProfitOrLossExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__125": {
"value": "Financial risk The company has financed its activities with bonds (see note 21) and has an undrawn revolving credit facility with a syndication of banks (see note 19). In addition, the company has financial instruments such as trade receivable, trade creditors, cash balances etc., directly related to its day-to-day operations. For hedging purposes, the company has different types of economic hedging instruments, but no hedge accounting is applied. Commodity derivatives are used to hedge the risk for lower oil prices. Foreign currency exchange derivatives are used to reduce currency risk related to cash flows. For the year 2023 all outstanding debt hold fixed rate coupons. The group currently has limited exposure towards fluctuations in interest rates, but generally manages such exposure by using interest rate derivatives.The most important financial risks which the company is exposed to relate to lower oil and gas prices, change in foreign exchange rates and access to cost efficient funding.The company's risk management, including financial risk management, is designed to ensure identification, analysis and systematic and cost-efficient handling of risk. Established management procedures provide a sound basis for reporting and monitoring of the company's financial risk exposure. (i) Commodity price riskAker BP's revenues are derived from the sale of petroleum products, and the revenue flow is therefore exposed to oil and gas price fluctuations. The company is continuously evaluating and assessing opportunities for hedging as part of a prudent financial risk management process. The company had no material commodity derivatives exposure per 31 December 2023.(ii) Currency riskRevenues from sale of petroleum products are mainly in USD, EUR and GBP, while expenditures are mainly in NOK, USD, EUR and GBP. Sales and expenses in the same currency contribute to mitigating some of the currency risk. Currency derivatives may be used to further reduce this risk.The table below shows the company's exposure in NOK as of 31 December:Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 229.3 260.0 Trade creditors, tax payable, leasing liability and other short-term liabilities -4 515.7 -5 397.3 Net exposure to NOK -4 286.4 -5 137.3The amounts above does not include tax balances in NOK, as they are not deemed to be financial instruments. The company's management of currency risk takes into account the USD values of non-USD assets, liabilities, opex and investments over time, including those exposures arising from the requirement to perform the tax calculation in NOK while the company's functional currency is USD.The table below shows the impact on profit/loss from changes in NOK/USD exchange rate, including the impact from currency derivatives. For further information about currency derivatives, see note 23.(USD million) Change in exchange rate 31.12.2023 31.12.2022Effect on pre-tax profit/loss: + 10% -5.6 56.2- 10% 30.8 -68.7In 2023 the company had EUR/USD exposure related to bond, cash and cash equivalents and receivables from gassales. As the Senior Notes bond is EUR denominated, there is currency risk associated with the translation to the company\u2019s USD functional currency and the cash payments of interest and principle amounts, though EUR denominated gas sales and EUR Time Deposit mitigate the risks associated with payments.Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 750.8 1 407.5Bond, trade creditors and other short-term liabilities -936.7 -861.1Net exposure to EUR -185.9 546.5The table below shows the impact on profit/loss from changes in EUR/USD exchange rate for the EUR bond, cash and cash equivalents and receivables. (USD million)Change in exchange rate 31.12.2023 31.12.2022Effect on pre-tax profit/loss: + 10% 16.9 -49.7- 10% -20.7 60.7In 2023 the company had GBP/USD exposure related cash and cash equivalents and receivables from gas sales.The table below shows the company's exposure in GBP as of 31 December:Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 75.1 402.1Trade creditors and other short-term liabilities -52.2 -22.5Net exposure to GBP 22.9 379.6The table below shows the impact on profit/loss from changes in GBP/USD exchange rate for cash and cash equivalents and receivables.(USD million) Change in exchange rate Effect on pre-tax profit/loss: + 10% -2.1 -34.5- 10% 2.6 42.2The company is also exposed to changes in other exchange rates, but the amounts are deemed immaterial. (iii) Interest-rate riskIn 2023, the company had no outstanding debt liabilities exposed to floating interest rate risk, which is unchanged from 2022. The company is relatively limited exposed to interest-rate risk related to cash and cash equivalents. The terms of the company's debt instruments are described in notes 19 and 21. For all the relevant material financial agreements, Aker BP has in place new benchmark rates or a fallback clause to cater for the discontinuation of IBOR rates. The IBOR reform did not have any current impact on Aker BP and is not expected to significantly affect future periods. All our bonds are at fixed interest rate, and the RCF is linked to Term SOFR, as described in note 19.(iv) Liquidity risk/liquidity managementThe company's liquidity risk is the risk that it will not be able to meet its financial obligations as they fall due.Short-term (12 months) and long-term (five years) forecasts are prepared on a regular basis to plan the company's liquidity requirements. These plans are updated regularly for various scenarios and form part of the decision basis for the company's management and Board of Directors.Excess liquidity is defined as the sum of bank account balances, short-term bank deposits and unused credit facilities. For excess liquidity, the requirement for low liquidity risk (i.e. the risk of realisation on short notice) is generally more important than maximising the return.The company deems its maximum risk exposure to correspond with the book value of cash and cash equivalents, accounts receivable and other short-term receivables, see notes 15, 16 and 19. The company's objective for the placement and management of excess capital is to maintain a low risk profile and good liquidity.The company's liquid assets as of 31 December 2023 are deposited in bank accounts and on short term time deposits with banks. As of 31 December 2023, the group had cash reserves of USD 3 388 million (2022: USD 2 756 million). Revenues and expenses are managed on a day-to-day basis for liquidity risk management purposes.The table below shows the payment structure for the company's financial commitments, based on undiscounted contractual payments. For corresponding information on lease debt and capital commitments and other contractual obligations, reference is made to note 25 and 26.Contract related cash flowLess than 1 31.12.2023 Book value yearNon-derivative financial liabilities:Bonds5 798.2 216.1 311.2 1 928.2 5 136.5 7 592.0Trade creditors and other liabilities1 362.0 1 362.0 - - - 1 362.0Derivative financial liabilitiesDerivatives33.3 32.8 0.5 - - 33.3Total as of 31.12.20237 193.4 1 610.9 311.7 1 928.2 5 136.5 8 987.3Contract related cash flowLess than 1 31.12.2022 Book value yearNon-derivative financial liabilities:Bonds5 279.2 157.0 157.0 2 391.9 3 890.9 6 596.9Trade creditors and other liabilities941.0 941.0 - - - 941.0Derivative financial liabilitiesDerivatives51.9 34.9 17.0 - - 51.9Total as of 31.12.20226 272.1 1 132.9 174.0 2 391.9 3 890.9 7 589.8(v) Credit risk The risk of counterparties being financially incapable of fulfilling their obligations is regarded as minor as there have nothistorically been any losses on trade receivable. The company's customers and licence partners are generally large and credit worthy oil companies, and it has thus not been necessary to make any provision for credit losses.In the management of the company's liquid assets, low credit risk is prioritised. Liquid assets are generally placed in bank deposits that represent a low credit risk. All investments are subject to internal policy that requires a rating equivalent to A-2 from S&P and limits investment with a single counterparty.The maximum credit risk exposure corresponds to the book value of financial assets. The company deems its maximum risk exposure to correspond with the book value of cash and cash equivalents, accounts receivable and other short-term receivables, see notes 15, 16 and 19.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__127": {
"value": "(i) Commodity price riskAker BP's revenues are derived from the sale of petroleum products, and the revenue flow is therefore exposed to oil and gas price fluctuations. The company is continuously evaluating and assessing opportunities for hedging as part of a prudent financial risk management process. The company had no material commodity derivatives exposure per 31 December 2023.(ii) Currency riskRevenues from sale of petroleum products are mainly in USD, EUR and GBP, while expenditures are mainly in NOK, USD, EUR and GBP. Sales and expenses in the same currency contribute to mitigating some of the currency risk. Currency derivatives may be used to further reduce this risk.The table below shows the company's exposure in NOK as of 31 December:Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 229.3 260.0 Trade creditors, tax payable, leasing liability and other short-term liabilities -4 515.7 -5 397.3 Net exposure to NOK -4 286.4 -5 137.3The amounts above does not include tax balances in NOK, as they are not deemed to be financial instruments. The company's management of currency risk takes into account the USD values of non-USD assets, liabilities, opex and investments over time, including those exposures arising from the requirement to perform the tax calculation in NOK while the company's functional currency is USD.The table below shows the impact on profit/loss from changes in NOK/USD exchange rate, including the impact from currency derivatives. For further information about currency derivatives, see note 23.(USD million) Change in exchange rate 31.12.2023 31.12.2022Effect on pre-tax profit/loss: + 10% -5.6 56.2- 10% 30.8 -68.7In 2023 the company had EUR/USD exposure related to bond, cash and cash equivalents and receivables from gassales. As the Senior Notes bond is EUR denominated, there is currency risk associated with the translation to the company\u2019s USD functional currency and the cash payments of interest and principle amounts, though EUR denominated gas sales and EUR Time Deposit mitigate the risks associated with payments.Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 750.8 1 407.5Bond, trade creditors and other short-term liabilities -936.7 -861.1Net exposure to EUR -185.9 546.5The table below shows the impact on profit/loss from changes in EUR/USD exchange rate for the EUR bond, cash and cash equivalents and receivables. (USD million)Change in exchange rate 31.12.2023 31.12.2022Effect on pre-tax profit/loss: + 10% 16.9 -49.7- 10% -20.7 60.7In 2023 the company had GBP/USD exposure related cash and cash equivalents and receivables from gas sales.The table below shows the company's exposure in GBP as of 31 December:Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 75.1 402.1Trade creditors and other short-term liabilities -52.2 -22.5Net exposure to GBP 22.9 379.6The table below shows the impact on profit/loss from changes in GBP/USD exchange rate for cash and cash equivalents and receivables.(USD million) Change in exchange rate Effect on pre-tax profit/loss: + 10% -2.1 -34.5- 10% 2.6 42.2The company is also exposed to changes in other exchange rates, but the amounts are deemed immaterial. (iii) Interest-rate riskIn 2023, the company had no outstanding debt liabilities exposed to floating interest rate risk, which is unchanged from 2022. The company is relatively limited exposed to interest-rate risk related to cash and cash equivalents. The terms of the company's debt instruments are described in notes 19 and 21. For all the relevant material financial agreements, Aker BP has in place new benchmark rates or a fallback clause to cater for the discontinuation of IBOR rates. The IBOR reform did not have any current impact on Aker BP and is not expected to significantly affect future periods. All our bonds are at fixed interest rate, and the RCF is linked to Term SOFR, as described in note 19.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfMarketRiskExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__129": {
"value": "(iv) Liquidity risk/liquidity managementThe company's liquidity risk is the risk that it will not be able to meet its financial obligations as they fall due.Short-term (12 months) and long-term (five years) forecasts are prepared on a regular basis to plan the company's liquidity requirements. These plans are updated regularly for various scenarios and form part of the decision basis for the company's management and Board of Directors.Excess liquidity is defined as the sum of bank account balances, short-term bank deposits and unused credit facilities. For excess liquidity, the requirement for low liquidity risk (i.e. the risk of realisation on short notice) is generally more important than maximising the return.The company deems its maximum risk exposure to correspond with the book value of cash and cash equivalents, accounts receivable and other short-term receivables, see notes 15, 16 and 19. The company's objective for the placement and management of excess capital is to maintain a low risk profile and good liquidity.The company's liquid assets as of 31 December 2023 are deposited in bank accounts and on short term time deposits with banks. As of 31 December 2023, the group had cash reserves of USD 3 388 million (2022: USD 2 756 million). Revenues and expenses are managed on a day-to-day basis for liquidity risk management purposes.The table below shows the payment structure for the company's financial commitments, based on undiscounted contractual payments. For corresponding information on lease debt and capital commitments and other contractual obligations, reference is made to note 25 and 26.Contract related cash flowLess than 1 31.12.2023 Book value yearNon-derivative financial liabilities:Bonds5 798.2 216.1 311.2 1 928.2 5 136.5 7 592.0Trade creditors and other liabilities1 362.0 1 362.0 - - - 1 362.0Derivative financial liabilitiesDerivatives33.3 32.8 0.5 - - 33.3Total as of 31.12.20237 193.4 1 610.9 311.7 1 928.2 5 136.5 8 987.3Contract related cash flowLess than 1 31.12.2022 Book value yearNon-derivative financial liabilities:Bonds5 279.2 157.0 157.0 2 391.9 3 890.9 6 596.9Trade creditors and other liabilities941.0 941.0 - - - 941.0Derivative financial liabilitiesDerivatives51.9 34.9 17.0 - - 51.9Total as of 31.12.20226 272.1 1 132.9 174.0 2 391.9 3 890.9 7 589.8",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__128": {
"value": "(ii) Currency riskRevenues from sale of petroleum products are mainly in USD, EUR and GBP, while expenditures are mainly in NOK, USD, EUR and GBP. Sales and expenses in the same currency contribute to mitigating some of the currency risk. Currency derivatives may be used to further reduce this risk.The table below shows the company's exposure in NOK as of 31 December:Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 229.3 260.0 Trade creditors, tax payable, leasing liability and other short-term liabilities -4 515.7 -5 397.3 Net exposure to NOK -4 286.4 -5 137.3The amounts above does not include tax balances in NOK, as they are not deemed to be financial instruments. The company's management of currency risk takes into account the USD values of non-USD assets, liabilities, opex and investments over time, including those exposures arising from the requirement to perform the tax calculation in NOK while the company's functional currency is USD.The table below shows the impact on profit/loss from changes in NOK/USD exchange rate, including the impact from currency derivatives. For further information about currency derivatives, see note 23.(USD million) Change in exchange rate 31.12.2023 31.12.2022Effect on pre-tax profit/loss: + 10% -5.6 56.2- 10% 30.8 -68.7In 2023 the company had EUR/USD exposure related to bond, cash and cash equivalents and receivables from gassales. As the Senior Notes bond is EUR denominated, there is currency risk associated with the translation to the company\u2019s USD functional currency and the cash payments of interest and principle amounts, though EUR denominated gas sales and EUR Time Deposit mitigate the risks associated with payments.Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 750.8 1 407.5Bond, trade creditors and other short-term liabilities -936.7 -861.1Net exposure to EUR -185.9 546.5The table below shows the impact on profit/loss from changes in EUR/USD exchange rate for the EUR bond, cash and cash equivalents and receivables. (USD million)Change in exchange rate 31.12.2023 31.12.2022Effect on pre-tax profit/loss: + 10% 16.9 -49.7- 10% -20.7 60.7In 2023 the company had GBP/USD exposure related cash and cash equivalents and receivables from gas sales.The table below shows the company's exposure in GBP as of 31 December:Exposure relating to (USD million)31.12.2023 31.12.2022Cash and cash equivalents and receivables 75.1 402.1Trade creditors and other short-term liabilities -52.2 -22.5Net exposure to GBP 22.9 379.6The table below shows the impact on profit/loss from changes in GBP/USD exchange rate for cash and cash equivalents and receivables.(USD million) Change in exchange rate Effect on pre-tax profit/loss: + 10% -2.1 -34.5- 10% 2.6 42.2The company is also exposed to changes in other exchange rates, but the amounts are deemed immaterial.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEffectOfChangesInForeignExchangeRatesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__131": {
"value": "(v) Credit risk The risk of counterparties being financially incapable of fulfilling their obligations is regarded as minor as there have nothistorically been any losses on trade receivable. The company's customers and licence partners are generally large and credit worthy oil companies, and it has thus not been necessary to make any provision for credit losses.In the management of the company's liquid assets, low credit risk is prioritised. Liquid assets are generally placed in bank deposits that represent a low credit risk. All investments are subject to internal policy that requires a rating equivalent to A-2 from S&P and limits investment with a single counterparty.The maximum credit risk exposure corresponds to the book value of financial assets. The company deems its maximum risk exposure to correspond with the book value of cash and cash equivalents, accounts receivable and other short-term receivables, see notes 15, 16 and 19.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAllowanceForCreditLossesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__130": {
"value": "(v) Credit risk The risk of counterparties being financially incapable of fulfilling their obligations is regarded as minor as there have nothistorically been any losses on trade receivable. The company's customers and licence partners are generally large and credit worthy oil companies, and it has thus not been necessary to make any provision for credit losses.In the management of the company's liquid assets, low credit risk is prioritised. Liquid assets are generally placed in bank deposits that represent a low credit risk. All investments are subject to internal policy that requires a rating equivalent to A-2 from S&P and limits investment with a single counterparty.The maximum credit risk exposure corresponds to the book value of financial assets. The company deems its maximum risk exposure to correspond with the book value of cash and cash equivalents, accounts receivable and other short-term receivables, see notes 15, 16 and 19.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCreditRiskExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__139": {
"value": "Note 29 Investments in joint operationsFields operated: 31.12.2023 31.12.2022 Fields operated: 31.12.2023 31.12.2022Alvheim80.000 %80.000 % Tambar55.000 %55.000 %B\u00f8yla80.000 %80.000 %Tambar \u00d8st46.200 %46.200 %Edvard Grieg65.000 %65.000 % Ula80.000 %80.000 %Hod90.000 %90.000 % Valhall90.000 %90.000 %Ivar Aasen Unit36.171 %36.171 % Vilje46.904 %46.904 %Skogul65.000 %65.000 % Volund100.000 %100.000 %Skarv23.835 %23.835 % Volve50.000 %50.000 %Solveig65.000 %65.000 %\u00c6rfugl Nord30.000 %30.000 %Production licences in which Aker BP is the operator:Licence: 31.12.2023 31.12.2022 Licence: 31.12.2023 31.12.2022PL 001B35.000 %35.000 % PL 16750.000 %50.000 %PL 006B90.000 %90.000 % PL 167B50.000 %50.000 %PL 01980.000 %80.000 % PL 167C50.000 %50.000 %PL 019E80.000 %80.000 % PL 20380.000 %80.000 %PL 019F55.000 %55.000 % PL 21230.000 %30.000 %PL 02687.700 %87.700 % PL 212B30.000 %30.000 %PL 026B87.700 %87.700 % PL 212E30.000 %30.000 %PL 028B35.000 %35.000 % PL 24235.000 %35.000 %PL 03390.000 %90.000 % PL 26170.000 %70.000 %PL 033B90.000 %90.000 % PL 261C23.835 %23.835 %PL 03550.000 %50.000 % PL 26230.000 %30.000 %PL 035C50.000 %50.000 % PL 27250.000 %50.000 %PL 035D50.000 %0.000 % PL 272B50.000 %50.000 %PL 036C80.000 %80.000 % PL 272C50.000 %50.000 %PL 036D46.904 %46.904 % PL 272D50.000 %0.000 %PL 036E64.000 %64.000 % PL 30055.000 %55.000 %PL 036F64.000 %64.000 % PL 33377.800 %77.800 %PL 036G80.000 %0.000 % PL 33865.000 %65.000 %PL 06555.000 %55.000 % PL 338BS50.000 %50.000 %PL 065B55.000 %55.000 % PL 338C80.000 %80.000 %PL 088BS80.000 %80.000 % PL 338DS65.000 %65.000 %PL 102D50.000 %50.000 % PL 338E80.000 %80.000 %PL 102F60.000 %60.000 % PL 34080.000 %80.000 %PL 102G60.000 %60.000 % PL 340BS80.000 %80.000 %PL 102H50.000 %50.000 % PL 35965.000 %65.000 %PL 127C68.083 %68.083 % PL 36487.700 %87.700 %PL 127DS88.083 %88.083 % PL 44287.700 %87.700 %PL 14677.800 %77.800 % PL 442B87.700 %87.700 %PL 146B77.800 %77.800 % PL 442C87.700 %87.700 %PL 150100.000 %100.000 % PL 457BS40.000 %40.000 %PL 159D23.835 %23.835 % PL 46065.000 %65.000 %PL 159H23.835 %0.000 % PL 492100.000 %100.000 %Production licences in which Aker BP is the operator:Licence: 31.12.2023 31.12.2022 Licence: 31.12.2023 31.12.2022PL 50137.384 %37.384 % PL 10570.000 %60.000 %PL 501B37.384 %37.384 % PL 106650.000 %50.000 %PL 60955.000 %55.000 % PL 1066B50.000 %0.000 %PL 609B55.000 %55.000 %PL 10820.000 %50.000 %PL 609D55.000 %55.000 %PL 108340.000 %40.000 %PL 782SB60.000 %0.000 % PL 108460.000 %60.000 %PL 782SC60.000 %0.000 % PL 108555.000 %55.000 %PL 78440.000 %40.000 % PL 108877.800 %77.800 %PL 81560.000 %60.000 % PL 108950.000 %50.000 %PL 8180.000 %40.000 % PL 109140.000 %40.000 %PL 818B0.000 %40.000 % PL 109250.000 %50.000 %PL 822S87.700 %87.700 % PL 10940.000 %60.000 %PL 8300.000 %40.000 % PL 10950.000 %50.000 %PL 83835.000 %35.000 % PL 109770.000 %70.000 %PL 86780.000 %80.000 % PL 10990.000 %40.000 %PL 867B80.000 %80.000 % PL 110255.000 %55.000 %PL 86980.000 %80.000 % PL 111055.000 %40.000 %PL 87347.700 %47.700 % PL 11240.000 %23.835 %PL 87487.700 %87.700 % PL 113335.000 %35.000 %PL 88660.000 %60.000 % PL 113435.000 %35.000 %PL 886B60.000 %60.000 % PL 113940.000 %40.000 %PL 9060.000 %50.000 % PL 114170.000 %70.000 %PL 91980.000 %80.000 % PL 1141B70.000 %0.000 %PL 93240.000 %60.000 % PL 114282.060 %82.060 %PL 94170.000 %70.000 % PL 114382.060 %82.060 %PL 941B70.000 %70.000 % PL 114440.000 %40.000 %PL 94230.000 %30.000 % PL 115340.000 %40.000 %PL 97670.000 %40.000 % PL 11570.000 %60.000 %PL 97960.000 %60.000 % PL 115840.000 %40.000 %PL 100540.000 %40.000 % PL 116250.000 %50.000 %PL 100880.000 %90.000 % PL 116440.000 %40.000 %PL 103240.000 %40.000 % PL 117035.000 %35.000 %PL 104180.000 %70.000 % PL 117150.000 %0.000 %PL 104240.000 %40.000 % PL 117240.000 %0.000 %PL 104580.000 %80.000 % PL 117550.000 %0.000 %PL 1045B80.000 %80.000 % PL 117660.000 %0.000 %PL 10480.000 %50.000 %PL 119380.000 %0.000 %PL 10510.000 %60.000 %Number of licences in which Aker BP is the operator 126 126 Fields non-operated: 31.12.2023 31.12.2022Atla10.000 %10.000 %Enoch2.000 %2.000 %Johan Sverdrup31.573 %31.573 %Oda15.000 %15.000 %Production licences in which Aker BP is a partner:Licence: 31.12.2023 31.12.2022 Licence: 31.12.2023 31.12.2022PL 006C35.000 %35.000 % PL 95620.000 %20.000 %PL 048D10.000 %10.000 % PL 9680.000 %30.000 %PL 102C10.000 %10.000 % PL 98410.000 %0.000 %PL 12750.000 %50.000 % PL 98530.000 %30.000 %PL 211CS15.000 %15.000 % PL 9890.000 %30.000 %PL 22015.000 %15.000 % PL 104030.000 %30.000 %PL 229E50.000 %50.000 % PL 10640.000 %20.000 %PL 229G50.000 %50.000 % PL 108750.000 %50.000 %PL 26527.384 %27.384 % PL 109030.000 %30.000 %PL 40515.000 %15.000 % PL 110440.000 %40.000 %PL 50222.222 %22.222 % PL 110620.000 %20.000 %PL 53735.000 %35.000 % PL 1122 0.000 %20.000 %PL 537B35.000 %35.000 % PL 112330.000 %30.000 %PL 55430.000 %30.000 % PL 112630.000 %30.000 %PL 554B30.000 %30.000 % PL 112930.000 %30.000 %PL 554C30.000 %30.000 % PL 113120.000 %20.000 %PL 554D30.000 %30.000 % PL 113830.000 %30.000 %PL 554E30.000 %0.000 % PL 114040.000 %40.000 %PL 782S20.000 %20.000 % PL 114540.000 %40.000 %PL 782SB0.000 %20.000 % PL 114720.000 %20.000 %PL 782SC0.000 %20.000 % PL 1148B10.000 %0.000 %PL 782SD0.000 %20.000 % PL 114930.000 %30.000 %PL 820S26.000 %26.000 % PL 1149B30.000 %0.000 %PL 820SB26.000 %26.000 % PL 115120.000 %20.000 %PL 838B30.000 %30.000 % PL 115250.000 %50.000 %PL 89410.000 %10.000 % PL 115430.000 %30.000 %PL 8960.000 %30.000 % PL 116320.000 %20.000 %PL 91740.000 %40.000 % PL 116540.000 %40.000 %PL 917B0.000 %40.000 % PL 1182S30.000 %0.000 %PL 92910.000 %10.000 % PL 118520.000 %0.000 %PL 93520.000 %20.000 % PL 119130.000 %0.000 %PL 9430.000 %20.000 %Number of licences in which Aker BP is a partner 53 56 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfJointVenturesExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__140": {
"value": "Note 30 Business combinationThe acquisition of the Lundin Energy's oil and gas business was completed on 30 June 2022, Due to the significance of the transaction, the related business combination note is also included in these 2023 Financial Stataments, and this note is similar to the note provided in the 2022 Financial Statements. The transaction was announced on 21 December 2021, and Aker BP issued 271.91 million new shares to the owners of Lundin Energy as compensation. In addition, the group paid a cash consideration of USD 2.22 billion. The purpose of the transaction is to create the E&P company of the future which will offer low CO2 emmisions, low cost and an attractive growth pipeline in the industry. The acquisition included three Dutch and one Swiss legal entity, in addition to Lundin Energy Norway AS (renamed to ABP Norway AS at completion of the transaction). All oil and gas assets included in the transaction are located on the Norwegian Continental Shelf. The acquisition date for accounting purposes corresponds to the finalisation of the transaction on 30 June 2022. The acquisition is regarded as a business combination and has been accounted for using the acquisition method of accounting in accordance with IFRS 3. A purchase price allocation (PPA) has been performed to allocate the consideration to fair value of assets and liabilities in Lundin Energy. The PPA is performed as of the acquisition date, 30 June 2022. The 30 June closing share price at Oslo Stock Exchange (NOK 342.1) and the closing currency exchange rate (USD/NOK 9.9629) were used as a basis for measuring the value of the shares consideration, as set forth below. The value of the cash consideration is adjusted for certain settlement arrangements and currency impacts as the cash was transferred in Swedish Kronor. (USD million) 30.06.2022Value of cash consideration 2 221.8 Value of share consideration 9 336.6Total value of consideration 11 558.4 Estimated transaction cost incurred in Aker BP is approximately USD 8 million, and is included in the income statement as other operating expenses.Each identifiable asset and liability is measured at its acquisition date fair value based on guidance in IFRS 13. The standard defines fair value as 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. This definition emphasises that fair value is a market-based measurement, not an entity-specific measurement. When measuring fair value, the group uses the assumptions that market participants would use when pricing the asset or liability under current market conditions, including assumptions about risk. Acquired property, plant and equipment have been valued using the cost approach (replacement cost), while intangible assets (value of licences) have been valued using the income approach. Accounts receivable are recognised at gross contractual amounts due, as they relate to large and credit-worthy customers. Historically, there has been no significant uncollectible accounts receivable in Lundin Energy.Purchase price allocation(USD million) 30.06.2022Goodwill 12 542.91)Other intangible assets1 282.2Property, plant and equipment 7 663.3Right-of-use assets 34.8Long-term receivables 12.5Other non-current assets 0.2Inventories 40.2Trade receivables 389.8Other short-term receivables 217.5Intercompany 57.0Cash and cash equivalents 937.6Total assets 23 178.0(USD million) 30.06.2022Deferred taxes 5 802.6Long-term abandonment provision 724.3Long-term bonds 1 726.0Long-term derivatives 4.3Long-term lease debt 20.3Other interest-bearing debt 600.0Trade creditors 17.9Accrued public charges and indirect taxes 33.1Tax payable 2 181.0Short-term derivatives 199.4Short-term abandonment provision 21.6Short-term lease debt 14.5Other current liabilities 274.7Total liabilities 11 619.5Net assets and liabilities recognised 11 558.4Fair value of consideration paid on acquisition 11 558.41) Mainly related to undeveloped oil and gas assetsThe goodwill of USD 12.5 billion arises principally because of the following factors:1. The ability to capture synergies that can be realised from managing a larger portfolio of both acquired and existing fields on the Norwegian Continental Shelf, including workforce (\"residual goodwill\").2. The requirement to recognise deferred tax assets and liabilities for the difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. Licences under development and licences in production can only be sold in a market after tax, based on a decision made by the Norwegian Ministry of Finance pursuant to the Petroleum Taxation Act Section 10. The assessment of fair value of such licences is therefore based on cash flows after tax. Nevertheless, in accordance with IAS 12 Sections 15 and 19, a provision is made for deferred tax corresponding to the tax rate multiplied by the difference between the acquisition cost and the tax base. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax (\"technical goodwill\"). None of the goodwill recognised will be deductable for tax purposes.Reconciliation of goodwill from the acquisition of Lundin Energy (USD 1 000) 30.06.2022Goodwill related to synergies - residual goodwill 6 291.7Goodwill as a result of deferred tax - technical goodwill 6 251.2Net goodwill from the acquisition of Lundin Energy 12 542.9If the acquisition had taken place at the beginning of 2022, revenue would have increased by USD 3.7 billion and net income would have increased by USD 422 million. Parent company - accounting effect of mergers:As of 13 October 2022, the wholly owned subsidiary ABP Energy Holding BV was merged with the parent company Aker BP ASA. The merger was carried out in accordance with the Public Limited Liability Companies Act section 13-25, and the merger was carried out based on group continuity for accounting purposes. Upon completion of the merger, all assets, rights and obligations of ABP Energy Holding BV was transferred to Aker BP ASA without any consideration being rendered. At the same time, ABP Energy Holding BV was liquidated. The merger is considered a transaction for tax purposes. As of 31 December 2022, the wholly owned subsidiary ABP Norway AS was merged with the parent company Aker BP ASA. The merger was carried out in accordance with the Public Limited Liability Companies Act section 13-24, and the merger was carried out based on group continuity for accounting purposes. Upon completion of the merger, all assets, rights and obligations of ABP Norway AS was transferred to Aker BP ASA without any consideration being rendered. At the same time, ABP Norway AS was liquidated. The merger is based on company continuity from 1 January 2022 for tax purposes.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
}
},
"s8_notes__6__141": {
"value": "Note 31 Events after the balance sheet dateOn 18 January 2024, the Oslo District Court ruled that the Ministry of Energy's approvals for the plans for development and operation (PDO) for the Breidablikk, Tyrving, and Yggdrasil fields were invalid due to procedural errors. The court concluded that the state had failed to consider the effects of combustion emissions as part of the final PDO. In addition, the court issued a temporary injunction, preventing the state from making decisions that assume valid PDO approval for the projects. Currently, the ruling is non-binding in relation to the procedural errors. The state has filed an appeal against both the main ruling and the temporary injunction to the Borgarting Court of Appeal. Aker BP, which has participating interests and operates the Yggdrasil and Tyrving development projects, is not a party to the court case. The PDO approvals granted for Yggdrasil and Tyrving remain valid in relation to Aker BP. Aker BP continues executing the Yggdrasil and Tyrving projects in accordance with the permissions granted. In response to the current situation, a dedicated task force has been established to identify potential risks and coordinate the company\u2019s activities and risk-mitigating actions. The court case is deemed to have no material impact on the 2023 financial statements.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory",
"language": "en",
"entity": "scheme:549300NFTY73920OYK69",
"period": "2023-01-01T00:00:00/2024-01-01T00:00:00"
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}
}
}