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Notes
1 Summary of significant accounting policies
Norwegian Energy Company ASA (BlueNord, \u201cthe Company\u201d or \u201cthe Group\u201d) is a public limited liability company registered in Norway, with
headquarters in Oslo (Nedre Vollgate 1, 0158 Oslo). The Company has subsidiaries in Norway, Denmark, the Netherlands and the United
Kingdom. The Company is listed on the Oslo Stock Exchange.
The consolidated financial statements for 2022 were approved by the Board of Directors on 28 March 2023.
The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have
been consistently applied to all the years presented, unless otherwise stated. The Group also provides the disclosure requirements as specified
under the Norwegian Accounting Law (Regnskapsloven).
1.1 Basis of preparation
The consolidated financial statements of Norwegian Energy Company ASA (BlueNord) have been prepared in accordance with the IFRS and
interpretations from the IFRIC, as endorsed by the EU. The Group also provides information required in accordance with the Norwegian
Accounting Act and associated NGAAP standards.
The preparation of financial statements in accordance with IFRS requires the use of certain critical accounting estimates. It also requires
management to exercise its judgement in the process of applying the Group\u2019s accounting policies. The areas involving a higher degree of
judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed
in note 3.
In accordance with the Norwegian Accounting Act, section 3-3a, the Board of Directors confirms that the consolidated financial statements
have been prepared under the assumption of going concern and that this is the basis for the preparation of the financial statements.
The financial solidity and the Company\u2019s working capital and cash position are considered satisfactory in regards of the planned activity
level for the next 12 months.
The Board of Directors is of the opinion that the consolidated financial statements give a true and fair view of the Company\u2019s assets, debt,
financial position and financial results. The Board of Directors are not aware of any factors that materially affect the assessment of the
Company\u2019s position as of 31 December 2022, besides what is disclosed in the Director\u2019s Report and the financial statements.
The subtotals and totals in some of the tables may not equal the sum of the amounts shown due to rounding.
1.1.1 Changes in accounting policies and disclosures
No change in 2022.
Amendments to standards
Amendments to standards, issued are either not expected to impact Norwegian Energy Company ASA (BlueNord)\u2019s consolidated financial
statements materially, or are not expected to be relevant to the consolidated financial statements upon adoption .
1.2 Consolidation
Subsidiaries
Subsidiaries are all entities over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to,
variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are
fully consolidated from the date on which control is transferred to the Group. They are de-consolidated from the date that control ceases.
As of 31 December 2022, all consolidated subsidiaries are 100 percent controlled by the parent company, Norwegian Energy Company ASA
(BlueNord) or other Group companies. The proportion of the voting rights in the subsidiary undertakings held directly by the parent company
does not differ from the proportion of ordinary shares held. The parent company does not have any shareholdings in the preference shares of
subsidiary undertakings included in the group. All subsidiary undertakings are included in the consolidation.
The Group had the following subsidiaries on 31 December 2022: Name Country of incorporation and place of business Nature of business Ordinary shares directly held by parent (%) Ordinary shares held by the Group (%) Noreco Denmark A/S Denmark Intermediate holding company 100% Noreco Oil Denmark A/S Denmark Exploration and production activity 100% Noreco Petroleum Denmark A/S Denmark Exploration and production activity 100% Noreco Olie-og Gasudvinding Danmark B.V. Netherlands Exploration and production activity 100% Noreco DK Pipeline ApS Denmark Infrastructure oil and gas 100% Norwegian Energy Company UK Ltd Great Britain Exploration activity 100% 100% Noreco Oil (UK) Ltd Great Britain Exploration activity 100% Altinex AS Norway Intermediate holding company 100% 100% Djerv Energi AS Norway Dormant Company 100% 100% The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair values of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Acquisition-related costs are expensed as incurred, except if related to the issue of debt not at fair value through profit and loss (FVTPL) or equity securities. If the business combination is achieved in stages, the acquisition date carrying value of the acquirer\u2019s previously held equity interest in the acquiree is re - measured to fair value at the acquisition date; any gains or losses arising from such re-measurement are recognised in profit or loss. Any contingent consideration to be transferred or received by the Group is recognised at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration that is deemed to be an asset or liability is recognised in profit or loss. Contingent consideration that is classified as equity is not re-measured, and its subsequent settlement is accounted for within equity. Intercompany transactions, balances, income and unrealised gains on transactions between Group companies are eliminated. Unrealised losses are also eliminated. When necessary, amounts reported by subsidiaries have been adjusted to conform with the Group\u2019s accounting policies. Interest in jointly controlled assets A jointly controlled asset is a contractual agreement between two or more parties regarding a financial activity under joint control. The Group has ownership in licences that are not separate legal companies. The Company recognises its share of the assets, liabilities, revenues and expenses of the joint operation in the respective line items in the Company\u2019s financial statements based on its ownership share. 1.3 Segment reporting The Group\u2019s segments were established on the basis of the most appropriate distribution of resource and result measurement. Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Chief Executive Officer. The whole Group is considered a single operating segment. 1.4 Foreign currency translation a) Functional and presentation currency Items included in the financial statements of each of the Group\u2019s entities are measured using the currency of the primary economic environment in which the entity operates (\u201cthe functional currency\u201d). The consolidated financial statements are presented in US dollars (USD), which is the Group\u2019s presentation currency and the parent company and main operating companies functional currency. b) Transactions and balances Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions or valuation where items are re-measured. Foreign exchange gains and losses are recognised in the income statement as other financial income or other financial expenses.
c) Group companies
The results and financial position of all the group entities (none of which has the currency of a hyper-inflationary economy) that have a functional
currency different from the presentation currency are translated into the presentation currency as follows:
i) assets and liabilities for each financial position presented are translated at the closing rate at the date of that statement of financial position;
ii) income and expenses for each income statement are translated at the average monthly exchange rates (unless this average is not a
reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are
translated at the rate on the dates of the transactions); and
iii) all currency translation adjustments are recognised in other comprehensive income (OCI). Goodwill and fair value adjustments arising on the
acquisition of a foreign entity are treated as assets and liabilities of the foreign entity and translated at the closing rate. Currency translation
adjustments arising are recognised in other comprehensive income.
1.5 Property, plant and equipment
Property, plant and equipment include production facilities, machinery and equipment. Items of property, plant and equipment are measured at
cost, less accumulated depreciation and accumulated impairment losses. Cost includes purchase price or construction cost and any costs
directly attributable to bringing the assets to a working condition for their intended use, including capitalised borrowing expenses incurred up
until the time the asset is ready to be put into operation.
For property, plant and equipment where asset retirement obligations for decommissioning and dismantling are recognised as a liability, this
value is added to acquisition cost for the respective assets. Borrowing costs that are not directly attributable to the acquisition, construction or
production of a qualifying asset are recognised in the income statement using the effective interest method.
When parts of an item of property, plant and equipment have different useful lives, they are accounted for as separate items (major components)
of property, plant and equipment, and depreciated separately.
Subsequent costs are included in the asset\u2019s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that
future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. The carrying amount
of the replaced part is derecognised. All other repairs and maintenance are charged to the income statement during the financial period in
which they are incurred.
Expenses related to drilling and equipment for exploration wells where proven and probable reserves are discovered are capitalised and
depreciated using the unit-of-production (UoP) method based on the proven and probable reserves expected to be produced from the well.
Development cost related to construction, installation and completion of infrastructural facilities, such as platforms, pipelines and drilling of
production wells, are capitalised as producing oil and gas fields. They are depreciated using the unit-of-production method based on the proven
and probable developed reserves expected to be recovered from the area for the economic lifetime of the field. For fields where the oil share of
the reserves constitutes the most significant part of the value, the capitalised cost is depreciated based on produced barrels of oil. This
generally gives a more systematic allocation of depreciation expenses over the useful life than using all produced oil equivalents. If realisation
of the probable reserves demands further future investments, these are added to the basis of depreciation.
Acquired assets used for extraction and production of petroleum deposits, including licence rights, are depreciated using the UoP method
based on proven and probable reserves.
Historical cost price for other assets is depreciated over the estimated useful economic life of the asset, using the straight-line method.
The estimated useful lives are as follows:
\u2022 Office equipment and fixtures: three to five years
Depreciation methods, useful lives, residual values and reserves are reviewed at each reporting date and adjusted if appropriate.
1.6 Intangible assets
Oil and gas exploration and development expenditures
The Group applies the successful efforts method of accounting for oil and gas exploration expenditures. Expenditures to acquire interests in oil
and gas properties and to drill and equip exploratory wells are capitalised as exploration expenditures within intangible assets until the well is
complete and the results have been evaluated, or there is any other indicator of a potential impairment. Exploration wells that discover
potentially economic quantities of oil and natural gas remain capitalised as intangible assets during the evaluation phase of the discovery. This
evaluation is normally finalised within one year. If, following the evaluation, the exploratory well has not found potentially commercial quantities of
hydrocarbons, the capitalised expenditures are evaluated for derecognition or tested for impairment. Geological and geophysical expenditures
and other exploration and evaluation expenditures are expensed as incurred.
Capitalised exploration expenditures, including expenditures to acquire interests in oil and gas properties, related to wells that find proved
reserves are transferred from exploration expenditures (intangible assets) to property, plant and equipment at the time of sanctioning of the
development project.
Other intangible assets
Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business
combination is their fair value at the date of acquisition. Following initial recognition, intangible assets with definite lives are carried at cost less
any accumulated amortisation and accumulated impairment losses, if any. Internally generated intangible assets, excluding capitalised
development costs, are not capitalised. Instead, the related expenditure is recognised in profit or loss in the period in which the expenditure is
incurred. Intangible assets are amortised over the useful economic life and assessed for impairment whenever there is an indication that the
intangible asset may be impaired. The amortisation period and the amortisation method for an intangible asset is reviewed at least at the end of
each reporting period. Changes in the expected useful life or the expected pattern of consumption of future economic benefits embodied in the
asset are considered to modify the amortisation period or method, as appropriate, and are treated as changes in accounting estimates. The
amortisation expense on intangible assets is recognised in the Consolidated Statement of Comprehensive income in the line-item depreciation
and amortisation.
1.7 Impairment of non-financial assets
a) Unit of account
The Group applies each prospect, discovery, or field as unit of account for allocation of profit or loss and financial position items.
When performing impairment testing of licence and capitalised exploration expenditures and production facilities, each prospect, discovery, or
field is tested separately as long as they are not defined to be part of a larger cash generating unit.
Developed fields producing from the same offshore installation are treated as one joint cash generating unit. The size of a cash generating unit
cannot be larger than an operational segment.
b) Impairment testing
Intangible assets with an indefinite useful life are not subject to amortisation and are tested annually for impairment. For oil and gas exploration
and development expenditures, see note 1.6 above regarding assessment of impairment and derecognition. Property, plant and equipment
subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not
be recoverable. An impairment loss is recognised for the amount by which the asset\u2019s carrying amount exceeds its recoverable amount.
The recoverable amount is the higher of an asset\u2019s fair value less costs of disposal and value in use. For the purposes of assessing impairment,
assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash generating units). Non-financial assets other
than goodwill that suffered impairment write-downs are assessed for potential impairment reversal at each reporting date as to whether there is
an indication that an impairment loss may no longer exist or may have decreased.
1.8 Financial assets
1.8.1 Classification
The Group classifies financial assets and financial liabilities according to IFRS 9 through the mixed measurement model with three primary
measurement categories for financial assets: amortised cost, fair value through OCI and fair value through profit and loss (P&L). The
classification depends on the entity\u2019s business model and the contractual cash flow characteristics of the financial assets. Management
determines the classification of its financial assets at initial recognition.
a) Financial assets and liabilities at fair value through profit or loss
Financial assets at fair value through profit or loss are financial assets held for trading that are not measured at amortised cost or at fair value
through OCI. IFRS 9 requires that for a financial liability designated as at fair value through profit or loss the effects of changes in the liability\u2019s
credit risk shall be included in OCI instead of through profit and loss. Derivatives, including embedded derivatives, are also recognised at fair
value through profit or loss unless they are designated as hedges. Assets in this category are classified as current assets if expected to be
settled within 12 months, otherwise they are classified as non-current.
b) Financial assets and liabilities at amortised cost
The Group measures financial assets at amortised cost if both of the following conditions are met:
\u2022 the financial asset is held within a business model with the objective to hold financial assets in order to collect contractual cash flows; and
\u2022 the contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the
principal amount outstanding.
Financial assets at amortised cost are subsequently measured using the effective interest (EIR) method and are subject to impairment testing.
Gains and losses are recognised in profit or loss when the asset is derecognised, modified or impaired.
These assets are included in current assets, except for maturities greater than 12 months after the end of the reporting period. These are
classified as non-current assets.
The Group\u2019s financial assets categorised as at amortised cost comprise trade and other receivables, contract assets, restricted cash and cash
and cash equivalents in the statement of financial position (notes 1.11 and 1.12).
The Group measures interest-bearing loans and borrowings (financial liabilities) at amortised cost using the effective interest method.
1.8.2 Recognition and measurement
Regular purchases and sales of financial assets are recognised on the trade-date \u2013 the date on which the Group commits to purchase or sell the
asset. Investments are initially recognised at fair value plus transaction costs for all financial assets not carried at fair value through profit or loss.
Financial assets carried at fair value through profit or loss, are initially recognised at fair value, and transaction costs are expensed in the income
statement. Financial assets are derecognised when the rights to receive cash flows from the investments have expired or have been transferred
and the Group has transferred substantially all risks and rewards of ownership. Financial assets at fair value through profit or loss are
subsequently carried at fair value. Trade and other receivables are subsequently carried at amortised cost using the effective interest method.
Gains or losses arising from changes in the fair value of the \u201cfinancial assets at fair value through profit or loss\u201d category is presented in the
income statement within \u2018Financial items\u2019 in the period in which they arise.
1.9 Impairment of financial assets
The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments (financial assets) not held at fair value through
profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows
that the Group expects to receive, discounted at an approximation of the original effective interest rate. The expected cash flows will include
cash flows from the sale of collateral held or other credit enhancements that are integral to the contractual terms.
The Group applies a simplified approach in calculating ECLs for trade receivables and contract assets. Therefore, the Group does not track
changes in credit risk, but instead recognises a loss allowance based on lifetime ECLs at each reporting date.
1.10 Derivative financial instruments and hedging activities
Derivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re-measured at their fair
value. The method of recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument, and if so,
the nature of the item being hedged.
The Group uses derivative financial instruments, such as forward commodity contracts and options, to reduce the exposure to commodity
price volatility. The Group has elected to apply cash flow hedge accounting designating these derivatives. Such derivative financial instruments
are initially recognised at fair value on the date on which a derivative contract is entered into and from the date of start of cash flow hedge
accounting. These are subsequently re-measured at fair value and the effective portion of the gain or loss on the hedging instrument is
recognised in OCI, while any ineffective portion is recognised immediately in profit or loss (financial income or financial expenses). The cash
flow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of
the hedged item. The amount accumulated in OCI is reclassified to profit or loss as a reclassification adjustment in the same periods during
which the hedged cash flows affect profit or loss. If cash flow hedge accounting is discontinued, the amount that has been accumulated in OCI
must remain in accumulated OCI if the hedged future cash flows are still expected to occur. Otherwise, the amount will be immediately
reclassified to profit or loss as a reclassification adjustment. Derivatives are carried as financial assets when the fair value is positive and as
financial liabilities when the fair value is negative.
Commodity contracts that were entered into and continue to be held for the purpose of the delivery of a non-financial item in accordance with the Group\u2019s
expected sale requirements fall within the exception from IFRS 9, which is known as the \u201cnormal purchase or sale exemption\u201d or the \u201cown use\u201d scope
exception. For these contracts and the host part of the contracts containing embedded derivatives, they are accounted for as executory contracts. The
Group recognises such contracts in its statement of financial position only when one of the parties meets its obligation under the contract to deliver either
cash or a non-financial asset. The volume hedging agreement with Shell ended on 31 December 2020 and is not relevant in 2022.
1.11 Trade receivables
Trade receivables are amounts due from customers for oil and gas sold or services performed in the ordinary course of business. If collection
is expected in one year or less (or in the normal operating cycle of the business if longer), they are classified as current assets. If not, they are
presented as non-current assets.
Trade receivables are measured at amortised cost using the effective interest method, less provision for impairment.
1.12 Cash and cash equivalents
Cash and cash equivalents include cash, bank deposits and short-term liquid placements, that immediately and with insignificant risk of
changes in value can be converted to known cash amounts and with a remaining maturity less than three months from the date of acquisition.
In the consolidated statement of financial position, bank overdrafts are shown within borrowings in current liabilities.
1.13 Over/under-lifting of hydrocarbons Over/under-lifting occurs when the Group has lifted and sold more or less hydrocarbons from a producing field than what the Group is entitled to at the time of lifting. Over-lifting of hydrocarbons is presented as other current liabilities, under-lifting of hydrocarbons is presented as other current assets. The value of under-lifting is measured at the lower of production expenses and the estimated sales value, less estimated sales costs and the value of over-lifting is measured at production expenses. Over-lifting and under-lifting of hydrocarbons are presented at gross value. Over/under-lift positions at the statement of financial position date are expected to be settled within 12 months from the statement of the financial position date . 1.14 Share capital, Treasury share reserves and share premium Ordinary shares are classified as equity. Costs directly attributable to the issue of new shares or option shares are recognised as a deduction from equity, net of any tax effects. Treasury share reserves are recognised as a deduction on equity at nominal value, the difference between nominal value and purchase price is deducted from other equity. 1.15 Trade payables Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Trade payables are classified as current liabilities if payment is due within one year or less (or in the normal operating cycle of the business if longer). If not, they are presented as non-current liabilities. Trade payables are measured at fair value and subsequent measurements are considered trade payables at amortised cost when using effective interest rate. 1.16 Borrowings Borrowings (financial liabilities) are classified as measured at amortised cost. Borrowings that are subsequently measured at amortised cost using the effective interest method are recognised initially at fair value, net of transaction costs incurred. For hybrid (combined) instrument that includes a non-derivative host contract that is not accounted for at FVTPL and an embedded derivative that is accounted for at FVTPL such as the convertible bond, the Company has elected an accounting polity that all of the transaction costs are always allocated to and deducted from the carrying amount of the non-derivative host contract on initial recognition. The subsequent measurement depends on which category they have been classified into. The categories applicable for the Company are either financial liabilities measured at fair value through OCI or financial liabilities measured at amortised cost using the effective interest method. The convertible bond loan has been determined to contain embedded derivatives, which is accounted for separately as a derivative at fair value through profit or loss, while the loan element is measured at amortised cost (note 3.1). Borrowings are classified as non-current if contractual maturity is more than 12 months from the statement of financial position date. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the end of the reporting period. If the Group is in breach with any covenants on the statement of financial position date, and a waiver has not been approved before or on the statement of financial position date with 12 months duration or more after the statement of financial position date, the loan is classified as current even if expected maturity is longer than 12 months after the statement of financial position date. Fees paid on the establishment of loan facilities are recognised as transaction costs of the loan to the extent that it is probable that some or all of the facility will be drawn down. In this case, the fee is deferred until the drawdown occurs. To the extent there is no evidence that it is probable that some or all of the facility will be drawn down, the fee is capitalised as a prepayment for liquidity services and amortised over the period of the facility to which it relates. A financial liability is derecognised when the obligation under the liability is discharged or cancelled, or when the contractual obligation expires. When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, the exchange or modification is treated as the derecognition of the original liability and the recognition of a new liability. The difference in the respective carrying amounts is recognised in the statement of comprehensive income as a gain or loss under financial items. Transaction costs incurred during this process are treated as a cost of the settlement of the old debt and included in the gain or loss calculation. 1.17 Borrowing costs General and specific borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale. Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation. All other borrowing costs are recognised in profit or loss in the period in which they are incurred.
1.18 Current and deferred income tax
The tax expense for the period comprises current tax, tax impact from refund of exploration expenses and deferred tax. Tax is recognised in the
income statement, except to the extent that it relates to items recognised in OCI or directly in equity. In this case, the tax is also recognised in OCI
or directly in equity, respectively.
The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the statement of financial position
date in the countries where the Company and its subsidiaries operate and generate taxable income. Management periodically evaluates
positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. It establishes provisions
where appropriate on the basis of amounts expected to be paid to the tax authorities.
Deferred income tax is recognised on temporary differences arising between the tax bases of assets, and liabilities and their carrying amounts
in the consolidated financial statements. However, deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill;
deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business
combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred income tax is determined using
nominal tax rates (and laws) that have been enacted or substantively enacted by the statement of financial position date and are expected to
apply when the related deferred income tax asset is realised, or the deferred income tax liability is settled.
Deferred tax assets are recognised only to the extent that it is probable that future taxable profit will be available against which the temporary
differences can be utilised.
Deferred income tax assets are recognised on deductible temporary differences arising from investments in subsidiaries, associates and joint
arrangements only to the extent that it is probable that the temporary difference will reverse in the future and there is sufficient taxable profit
available against which the temporary difference can be utilised.
Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax
liabilities and when the deferred income tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same
taxable entity or different taxable entities where there is an intention to settle the balances on a net basis.
Producers of oil and gas on the Danish continental shelf are subject to the hydrocarbon tax regime under which income derived from the sale of
oil and gas is taxed at an elevated 64 percent. Any income deriving from other activities than first-time sales of hydrocarbons is taxed at the
ordinary corporate income rate of currently 22 percent. The 64 percent is calculated as the sum of the (chapter 2) tax of 25 percent plus a
specific hydrocarbon tax (chapter 3a) of 52 percent, in which the 25 percent tax payable is deductible. When calculating the 52 percent tax, the
Company is allowed to deduct an uplift (i.e. increased depreciation basis for tax purposes) of 30 percent of the investments in property, plant
and equipment (PP&E) over a period of six years. Through an agreement from 2017, licence holders on the Danish continental shelf have had
the possibility of applying new rules whereby the Company will have the possibility of increased uplift and accelerated depreciation during the
period from 2017 to 2025. At the same time, the companies utilising the benefit are also liable for a repayment of the tax benefits previously
received, this will materialise from 2022 through 2037 with an oil price (indexed from 2017) above USD 75. The repayment cannot exceed the
indexed benefit from the applied rules.
1.19 Pensions
The Group only has defined contribution plans as of 31 December 2022. For the defined contribution plan, the Group pays contributions to
publicly or privately administered pension insurance plans on a mandatory, contractual or voluntary basis. The Group has no legal or
constructive obligations to pay further contributions if the fund does not hold sufficient assets to pay all employees the benefits relating to
employee service in the current and prior periods. The contributions are recognised as employee benefit expense when they are due. Prepaid
contributions are recognised as an asset to the extent that a cash refund or a reduction in the future payments is available.
1.20 Share-based payments
The Group operates a number of equity-settled, share-based compensation plans, under which the entity receives services from employees as
consideration for equity instruments (options) of the Group. The fair value of the employee services received in exchange for the grant of the options is
recognised as an expense. The total amount to be expensed is determined by reference to the fair value of the options or shares granted:
Fair value:
\u2022 Including any market performance conditions.
\u2022 Excludes the impact of any service and non-market performance vesting conditions (for example, profitability, sales growth targets and
remaining an employee of the entity over a specified time period).
Non-market performance and service conditions are included in assumptions about the number of options or shares that are expected to vest.
The total expense is recognised over the vesting period (which is the period over which all of the specified vesting conditions are to be satisfied).
At the end of each reporting period, the Group revises its estimates of the number of options that are expected to vest based on the non-market
vesting conditions. It recognises the impact of the revision to original estimates, if any, in the income statement, with a corresponding adjustment
to equity.
When the options are exercised, the Company issues new shares. The proceeds received net of any directly attributable transaction costs are
credited to share capital (nominal value) and share premium. The social security contributions payable in connection with the grant of the share
options is considered an integral part of the grant itself, and the charge will be treated as a cash-settled transaction.
1.21 Provisions
Provisions are recognised when the Company has a present obligation (legal or constructive) arising from a past event, and it is probable (more
likely than not) that it will result in an outflow from the entity of resources embodying economic benefits, and that a reliable estimate can be made
of the amount of the obligation.
Restructuring provisions comprise lease termination penalties and employee termination payments. Provisions are measured at the present
value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the
time value of money and the risks specific to the obligation. The increase in the provision due to passage of time is recognised as
interest expense.
1.21.1 Asset retirement obligations
Provisions reflect the estimated cost of decommissioning and removal of wells and production facilities used for the production of
hydrocarbons. Asset retirement obligations are measured at net present value of the anticipated future cost (estimated based on current day
costs inflated). The liability is calculated on the basis of current removal requirements and is discounted to present value using a risk-free rate
adjusted for credit margin. Liabilities are recognised when they arise and are adjusted continually in accordance with changes in requirements,
price levels etc. When a decommissioning liability is recognised or the estimate changes, a corresponding amount is recorded to increase or
decrease the related asset and is depreciated in line with the asset. Increase in the provision as a result of the time value of money is recognised
in the income statement as a financial expense. If abandonment cost through agreements with partners have been limited to a given amount,
this then forms the basis for the recognised liability.
1.22 Contingent liabilities and assets
Contingent liabilities are defined as:
\u2022 Possible obligations that arise from past events, whose existence depends on uncertain future events.
\u2022 Present obligations which have not been recognised because it is not probable that they will result in a payment.
\u2022 The amount of the obligation cannot be measured with sufficient reliability.
Specific mention of material contingent liabilities is disclosed, with the exception of contingent liabilities where the possibility of an outflow of
resources embodying economic benefits is remote.
Contingent assets are not recognised in the financial statements but are disclosed if there is a certain probability that a benefit will accrue to
the Group.
1.23 Revenue recognition
Revenue is recognised when the customer obtains control of the hydrocarbons, which is ordinarily at the point of delivery (lifting and sales)
when title passes (sales method). Over/under-lifting occurs when the Group has lifted and sold more or less hydrocarbons from a producing
field than what the Group is entitled to at the time of lifting. See note 1.13 for a description of accounting for over/under-lifting of hydrocarbons in
the statement of financial position.
1.24 Production expenses
Production expenses are expenses that are directly attached to production of hydrocarbons, e.g. expenses for operating and maintaining production
facilities and installations. Expenses mainly consist of man-hours, insurance, processing costs, environmental fees, transport costs etc.
1.25 Interest income
Interest income is recognised using the effective interest method.
1.26 Consolidated statement of cash flows
The consolidated statement of cash flows is prepared according to the indirect method. See note 1.12 for the definition of \u201ccash and cash
equivalents\u201d.
2 Financial risk management
2.1 Financial risk factors
The Group\u2019s activities expose it to financial risks: market risk (including currency risk, price risk, interest rate risk), credit risk and liquidity risk. The
Group uses bond loans to finance its operations in connection with the day-to-day business, financial instruments, such as bank deposits, trade
receivables and payables, and other current liabilities that arise directly from its operations, are utilised.
Market risk
Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in the market prices.
Market risk comprises three types of risk: foreign currency risk, price risk and interest rate risk. Financial instruments affected by market risk
include loans and borrowings, deposits, trade receivables, trade payables, accrued liabilities and derivative financial instruments.
a) Foreign currency risk
The Group is composed of businesses with various functional currencies including USD, EUR, GBP and DKK. The Group is exposed to foreign
exchange risk for series of payments in other currencies than the functional currency, mainly related to the ratio between NOK and USD, DKK
and USD, EUR and USD and GBP and USD. The Group\u2019s statement of financial position includes significant assets and liabilities, which are
recorded in other currencies than the Group\u2019s presentation currency. As such, the Group\u2019s equity is sensitive to changes in foreign exchange
rates. See note 15 Non-current receivables, trade receivable and other current receivables, note 17 Restricted Cash, Bank Deposits, Cash and
Cash Equivalents, note 18 Financial instruments, note 21 Asset retirement obligation, note 22 Borrowings and note 23 Trade payables and other
payables, note 27 Contingencies and commitments. A decrease in the closing rate of NOK, EUR and DKK with 10 percent compared to USD
would have the following impact on financial assets, financial liabilities and equity:
USD million NOK DKK EUR
Financial assets 1 48 11
Financial liabilities 0 15 \u20131
Effect net result/equity 1 33 13
The Company considers the currency risk relating to the different financial instruments as low, as the main financial items held in a currency
other than the functional currency of the respective components is offset by positions in other components of the Group and/or hedged. With
regards to trade receivables and payables, the Company deems the risk to be immaterial.
b) Price risk
Norwegian Energy Company ASA (BlueNord) produces and sells hydrocarbons in Denmark and is as a result exposed to changes in
commodity prices. The Group has a material commodity price hedging programme in place that mitigates the risk of near-term price
movements. As of 31 December 2022, Norwegian Energy Company ASA (BlueNord) had commodity derivatives measured at fair value. A
change in the value directly affects the Company\u2019s OCI and recorded equity, and hence the Group is exposed to the fair value development of
these financial instruments. Assuming an increase in the commodity price at 31 December 2022 of 10 percent and assuming this change will
have full effect on the whole curve, the effect on the value of commodity derivatives would have the following impact:
USD million Equity OCI Net result
Commodity price +10% -25 -25 0
Commodity price -10% 25 25 0
The effect on equity would be equal to the change in value of the commodity derivatives. The change in value of hedging contracts over time will
be offset by the realised value of the contract when the hedge instrument matures, therefore the underlying value to Norwegian Energy
Company ASA (BlueNord)\u2019s business operations is not impacted by changes in the derivative value at any point in time.
c) Interest rate risk
The Group has loans with fixed and floating interest rates. Loans with fixed interest rate expose the Group to risk (premium/discount) associated
with changes in the market interest rate. At year-end, the Group has a total of USD 1.1 billion (2021: USD 1.2 billion) in interest-bearing debt
(carrying amount), the principal amount was USD 1.2 billion. The Group\u2019s RBL facility has a floating interest rate comprising the aggregate of
SOFR and 4.0 percent per annum, while the Group\u2019s Bond debt (NOR13 and NOR14) have a fixed interest rate exposure. The reserve-based
lending facility is linked to the SOFR rate as set at the time of redetermination. A variance of +1 percent in the SOFR rate would result in
USD 9.0 million of interest charges to Norwegian Energy Company ASA (BlueNord) per annum, however the Company has hedged this
interest rate until 30 June 2024 at a rate of 0.40 percent to cover any increase in SOFR rate. For further information about the Group\u2019s interest-
bearing debt, see note 22.
All bank deposits (USD 472.1 million) are at floating interest rates. See note 17 Restricted cash, bank deposits, cash and cash equivalents for
further information about bank deposits. The Group considers the risk exposure to changes in market interest to be at an acceptable level.
Liquidity risk The Group has certain financial commitments arising from its operations and other agreements entered into which are expected to be met by liquid assets, proceeds from external financing and cash flow from operations. The Group monitors its liquidity situation continuously to ensure it will be able to meet its financial obligations as they fall due. As of 31 December 2022, none of the Group\u2019s interest-bearing debt were falling due within the next 12 months. Credit risk The Group\u2019s most significant credit risk arises principally from recognised receivables related to the Group\u2019s operation. The credit risk arising from the production of oil, gas and natural gas liquids (NGLs) is considered limited, as sales are to major oil companies with considerable financial resources. The counterparty in derivatives are large international banks and insurance companies whose credit risk is considered low. 2.2 Capital risk management The Group\u2019s objectives when managing capital is to safeguard the Group\u2019s ability to continue as a going concern in order to provide return for shareholders and benefits for other stakeholders and to maintain an acceptable capital structure to reduce the cost of capital. The Group monitors the debt with the basis of cash flows, equity ratio and the gearing ratio. The Group\u2019s debt restricts the payment of dividends until two quarters after the completion of the Tyra redevelopment project; subsequent to this date, NOR14 limits dividend payments to 50 percent of the Group\u2019s net profit after tax for the previous year. See further information regarding borrowings and covenants in note 22. 2.3 Fair value estimation The Group has certain financial instruments carried at fair value. The different fair value hierarchy levels have been defined as follows: Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities The fair value of financial instruments traded in active markets is based on quoted market prices at the statement of financial position date. A market is regarded as active if quoted prices are readily and regularly available from an exchange, dealer, broker, industry group, pricing service, or regulatory agency, and those prices represent actual and regularly occurring market transactions on an arm\u2019s length basis. The quoted market price used for financial assets held by the Group is the current bid price. Level 2: Inputs other than quoted prices included within Level 1 that are observable for the assets or liability, either directly or indirectly The fair value of financial instruments that are not traded in an active market (for example, over-the-counter derivatives) is determined by using valuation techniques. These valuation techniques maximise the use of observable market data where it is available and rely as little as possible on entity specific estimates. If all significant inputs required to fair value an instrument are observable, the instrument is included in Level 2. If one or more of the significant inputs is not based on observable market data, the instrument is included in Level 3. Specified valuation techniques used to value financial instruments include: \u2022 quoted market prices or dealer quotes for similar instruments; \u2022 the fair value of interest rate swaps is calculated as the present value of the estimated future cash flows based on observable yield curves; and \u2022 the fair value of forward foreign exchange contracts is determined using forward exchange rates at the statement of financial position date, with the resulting value discounted back to present value. Level 3: Inputs for other assets or liabilities that are not based on observable market data In Level 3, there are one financial instrument, the embedded derivatives in the convertible bond. The fair value of the embedded derivatives is calculated based on the Black-Scholes-Merton valuation model. A change in the share price of +/- 10 percent would have the following impact on the embedded derivates, net result and equity: Share price Sensitivity analysis 10% -10% Embedded derivatives USD million (11) 10 Effect net result/equity USD million (11) 10 It is evaluated that there is no tax effect of changes in fair value of the contingent consideration and embedded derivatives. See note 18 for fair value hierarchy and further information.
3 Critical accounting estimates and judgements
3.1 Critical accounting estimates and assumptions
Estimates and judgements are continually evaluated and are based on historical experience and other factors, including expectations of future
events that are believed to be reasonable under the circumstances.
The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities
within the next financial year are addressed below.
a) Estimated value of financial assets and financial liabilities
The embedded derivatives in the convertible debt have been recognised separately at fair value through profit and loss. The value of this
embedded derivative has been calculated using the Black-Scholes-Merton valuation model using assumptions for share price, volatility of
share price, and other inputs which are subject to significant uncertainty.
For financial assets at amortised cost, an assessment is made on whether objective evidence is present that financial assets or groups of
financial assets should be written down.
For more details, see note 18 Financial Instruments.
b) Income tax
All figures reported in the statement of comprehensive income and the statement of financial position are based on the Group\u2019s tax calculations
and should be regarded as estimates until the tax for the year has been settled. Tax authorities can be of a different opinion than the Company.
See also note 13.
c) Asset retirement obligation
Production of oil and gas is subject to statutory requirements relating to decommissioning and removal obligation once production has ceased.
Provisions to cover these future decommissioning and removal expenditures must be recognised at the time the statutory requirement arises.
The costs will often incur sometime in the future, and there is significant uncertainty attached to the scale and complexity of the
decommissioning and removal involved. Estimated future costs (estimated based on current costs inflated) are based on known
decommissioning and removal technology, expected future price levels, and the expected future decommissioning and removal date,
discounted to net present value using a risk-free rate adjusted for credit margin. Changes in one or more of these factors could result in changes
in the decommissioning and removal liabilities. See note 21 Asset Retirement Obligations for further details about decommissioning and
removal obligations.
d) Depreciation and impairment of fixed assets
The estimation of the recoverable amount of oil and gas assets as well as the estimation of available commercially depletable reserves is
subject to significant uncertainty, primarily related to future oil and gas price levels. Impairment assessments are made to the extent there are
indicators of reduced values of fixed assets. UoP depreciations are amended on a prospective basis following regular reserves estimation
updates performed by the Group. For more details, see note 11 Impairments.
3.2 Critical judgements in applying the entity\u2019s accounting policies
a) Accounting for convertible debt
The Group has issued bonds with conversion rights and other embedded derivatives (but the conversion feature is the main element). The
conversion feature has been determined to constitute an embedded derivative and has been separated from the loan contract. The loan
element has been recognised at amortised cost. At initial recognition, the loan was measured as the residual amount of the proceeds from the
bond issue, less issue costs, less the calculated fair value of the conversion feature. The process of determining whether the conversion feature
in the convertible bond arrangement should be treated as a liability or an equity component requires the application of significant judgement.
The convertible bond is either a financial liability (including certain embedded derivative features which may require separation) or a compound
instrument (i.e. such a liability plus an equity conversion option). The Group has assessed that the holder\u2019s conversion option does not involve
receiving a fixed number of shares by giving up a fixed stated principal amount of bond, hence the Group has assessed this instrument is not a
compound instrument with an equity part. Further multiple embedded derivatives have been identified in the host contract that has been
assessed is not readily separable and independent of each other, and as such is treated as a single compound embedded derivative. Also, the
fair value measurement of the conversion feature using the Black-Scholes-Merton valuation model, requires significant judgement when
selecting and applying the required assumptions.
4 Revenue USD million 2022 2021 Sale of oil 552.1 416.0 Sale of gas and NGL 408.4 142.4 Other income 6.4 6.9 Total revenue 966.9 565.3 Oil-lifted volumes (mmbbl) 7.32 7.20 Effective oil price USD/bbl 75.5 57. 8 Gas lifted volumes (mmboe) 2.3 2.3 Effective gas price EUR/MWh 101.9 30.4 Effective gas price USD/boe 181.1 61.5 In 2022, sale of oil amounted to USD 552.1 million and sale of gas amounted to USD 408.4 million, realised prices were USD 75.5 per bbl of oil and USD 181.1 per boe gas lifted during the year, adjusted for settlement of price hedges in place with financial institutions. During 2022, Norwegian Energy Company ASA (BlueNord) recognised the settlement of price hedges that were put in place with financial institutions in the market as revenue, when these price hedges match the physical sale of oil and gas. Price hedges in excess of actual liftings are treated as financial income or expenses based on the required accounting treatment for these instruments during the period. Revenue per customer 2022 2021 Shell Trading International 77.7% 90.1% \u00d8rsted Salg & Service AS 32.5% 28.4% Shell Energy Europe Limited 16.2% 8.2% CommonwealthBank 1) -1.9% -4.7% SEB Skandinaviska Enskilda Banken AB 1) -2.4% 0.0% BNP Paribas 1) -4.2% -10.2% Natixis 1) -8.0% -11.9% Lloyds Bank Corporate Markets PLC 1) -10.0% 0.0% Total revenue 100.0% 100.0% 1) The negative percentages represent the settlement of commodity hedges in place with financial institutions. 5 Production expenses USD million 2022 2021 Direct field opex (233.1) (210.9) Tariff and transportation expenses (43.3) (44.3) Production general and administrative (G&A) (32.1) (41.8) Field operating cost (308.5) (297.0) Total produced volumes (mmboe) 9.8 9.8 In USD per boe (31.6) (30.2) Adjustments for: Concept studies (1.5) \u2013 Change in inventory position 4.0 (0.7) Over/under-lift of oil and NGL 7.7 14.0 Insurance & other (19.4) (21.6) Stock scrap (5.6) 12.6 Production expenses (323.4) (292.7) Production expenses for the year directly attributable to the lifting and transportation to market of Norwegian Energy Company ASA (BlueNord)\u2019s oil and gas production is in total USD 308.5 million, which equates to USD 31.6 per boe produced during 2022 (2021: USD 30.2 per boe produced). Actual production expenses in 2022 was in line with the expectation. The increase compared with 2021 is mainly driven by the high activity on workovers to maintain base production in with some increased costs from inflation.
6 Exploration and evaluation expenses
USD million 2022 2021
Other exploration and evaluation costs (0.7) (0.7)
Total exploration and evaluation costs (0.7) (0.7)
7 Personnel expenses
USD million Note 2022 2021
Salaries (9.2) (9.5)
Social security tax (1.0) (0.8)
Pension costs
20 (0.5) (0.6)
Costs relating to share-based payments
24 (1.4) (0.3)
Other personnel expenses (0.4) (0.3)
Total personnel expenses (12.5) (11.5)
Average number of employees 30.5 27.4
Please see the Executive Remuneration Report 2022 for compensation to key management and Board of Directors in the period 2018-2022.
8 Other operating expenses
USD million 2022 2021
Consultant fees (15.3) (8.2)
Other operating expenses (3.8) (2.7)
Total other operating expenses (19.1) (10.9)
USD, 1000 excl. VAT 2022 2021
Auditor\u2019s fees (625.8) (575.1)
Other assurance service (84.6) (5.4)
Total audit fees (710.4) (580.5)
9 Intangible assets
Intangible assets at 31 December 2022
USD million
Capitalised
exploration
expenditures
Conceptual
studies Licence Tota l
Book value 31 December 21 1.4 \u2013 164.7 166.0
Acquisition costs 31 December 21 1.4 \u2013 186.0 187.4
Additions 0.5 1.9 \u2013 2.4
Acquisition costs 31 December 22 1.8 1.9 186.0 189.8
Accumulated depreciation, amortisation and write-downs
31 December 21 \u2013 \u2013 (21.3) (21.3)
Depreciation/amortisation \u2013 \u2013 (8.0) (8.0)
Accumulated depreciation, amortisation and write-downs
31 December 22 \u2013 \u2013 (29.4) (29.4)
Book value 31 December 22 1.8 1.9 156.6 160.4
Intangible assets at 31 December 2021 USD million Capitalised exploration expenditures Conceptual studies Licence Total Book value 31 December 20 1.9 \u2013 172.7 174.6 Acquisition costs 31 December 20 1.9 \u2013 186.0 187. 8 Additions (0.5) \u2013 \u2013 (0.5) Acquisition costs 31 December 21 1.4 \u2013 186.0 187.4 Accumulated depreciation and write-downs 31 December 20 \u2013 \u2013 (13.3) (13.3) Depreciation/amortisation \u2013 \u2013 (8.0) (8.0) Accumulated depreciation and write-downs 31 December 21 \u2013 \u2013 (21.3) (21.3) Book value 31 December 21 1.4 \u2013 164.7 166.0 10 Property, plant and equipment Property, plant and equipment at 31 December 2022 USD million Asset under construction Production facilities Other assets Tot al Book value 31 December 21 818.5 1,078.5 1.7 1,898.7 Acquisition costs 31 December 21 818.5 1,346.6 3.1 2,168.2 Sale of assets \u2013 (0.2) (0.2) (0.4) Additions 232.4 9.1 0.2 241.6 Revaluation abandonment assets \u2013 (102.8) \u2013 (102.8) Currency translation adjustment \u2013 (0.1) (0.1) (0.2) Acquisition costs 31 December 22 1,050.9 1,252.5 3.1 2,306.4 Depreciation and write-downs 31 December 21 \u2013 (268.2) (1.4) (269.6) Sale of asset, reversal depreciation \u2013 0.1 \u2013 0.1 Depreciation \u2013 (124.8) \u2013 (125.1) Currency translation adjustment \u2013 0.0 (0.3) 0.0 Depreciation and write-downs 31 December 22 \u2013 (392.9) (1.7) (394.6) Book value 31 December 22 1,050.9 859.6 1.4 1,911.9 Property, plant and equipment at 31 December 2021 USD million Asset under construction Production facilities Other assets Total Book value 31 December 20 607.7 1,093.9 2.5 1,704.1 Acquisition costs 31 December 20 607.7 1,258.7 3.2 1,869.6 Additions 210.8 17.5 0.1 228.4 Acquisition of abandonment asset \u2013 70.6 \u2013 70.6 Disposal \u2013 \u2013 \u2013 \u2013 Currency translation adjustment \u2013 (0.2) (0.1) (0.3) Acquisition costs 31 December 21 818.5 1,346.6 (0.1) 2,168.3 Accumulated depreciation and write-downs 31 December 20 \u2013 (164.9) (0.1) (165.9) Depreciation \u2013 (103.3) (0.1) (103.7) Currency translation adjustment \u2013 0.0 0.0 0.1 Accumulated depreciation and write-downs 31 December 21 \u2013 (268.2) (0.2) (269.6) Book value 31 December 21 818.5 1,078.5 1.3 1,898.7
11 Impairments
Impairment testing
Impairment testing of our asset base is performed periodically and/or when impairment triggers are identified. In Q4 2022, Norwegian Energy
Company ASA (BlueNord) carried out a periodical impairment test for the fixed assets and related tangible assets. Impairment is recognised
when the book value of an asset or a cash generating unit exceeds the recoverable amount. The recoverable amount is the higher of the assets
fair value less cost to sell and value in use. In Q4 2022, the recoverable amount was calculated as the expected future cash flow from the asset,
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. Cash flows are projected for the estimated lifetime of the fields, which exceed five years.
Commodity prices
Future commodity price levels are a key assumption and have a significant impact on the net present value (NPV). Forecasted oil and gas prices
are based on management\u2019s 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 2023
to the end of 2025. From 2026, the oil and gas prices are based on the Company\u2019s long-term price assumptions.
Nominal oil prices applied in the impairment test are as follows:
Year USD/BBL
2023 80.0
2024 75.0
2025 70.0
From 2026 onwards 65.0
Nominal gas prices applied in the impairment test are as follows:
Year EUR/MWH
2023 60.0
2024 60.0
2025 50.0
From 2026 onwards 30.0
Oil and gas reserves
Future cash flows are calculated on the basis of expected production profiles and probable remaining reserves.
Future expenditure
Future opex, capex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost.
Discount rate
The discount rate is derived from the weighted average cost of capital (\u201cWACC\u201d) for a market participant. The post-tax nominal discount rate
used is 9.2 percent.
Exchange rates
The exchange rate from US dollar to Danish kroner is a blended rate of 7.02 throughout the forecast period. The applied blended rate is taken as
75 percent of the market rate at 6.87 and 25 percent of the Operator\u2019s Budget Book rate at 7.46. The US dollar to euro exchange rate is 0.92
throughout the forecast period. The US dollar to euro rate has been pegged to a euro to Danish kroner rate of 7.44, sensitivity analysis based on
exchange rates will maintain the euro to Danish kroner exchange rate.
Inflation
The long-term inflation rate is assumed to be two percent.
Impairment testing of assets including tangible and intangible asset values
Both the tangible and intangible asset value attached to a cash generating unit is tested as part of the impairment assessment. The carrying
value of the assets is the sum of tangible assets and intangible assets as of the assessment date.
Result of impairment assessment
The impairment assessment has not resulted in any impairment charge being recognised.
Sensitivity analysis The table below shows how the impairment or reversal of impairment of assets would be affected by changes in the various assumptions, given that the remaining assumptions are constant. Sensitivity Change in NPV Implied Impairment (if applicable) USD 1 ,000 Long-term price +10% 11% \u2013 Long-term price -10% -12% (207.4) USD:DKK FX rate +10% -2% \u2013 USD:DKK FX rate -10% 3% \u2013 WACC +1.0% -5% (49.1) WACC -1.0% 5% \u2013 Inflation rate +1.0% 6% \u2013 Inflation rate -1.0% -5% (63.1) 12 Financial Income and Expenses Financial income USD million 2022 2021 Value adjustment interest swap unrealised 1) 10.2 1.0 Value adjustment of embedded derivatives 2) \u2013 6.0 Interest income 4.0 0.0 Extinguishment of bond loan 33.7 \u2013 Foreign exchange gains 11.0 20.9 Total financial income 58.8 27.8 Financial expenses USD million 2022 2021 Value adjustment of embedded derivatives 2) (132.3) \u2013 Value adjustment of FX contract \u2013 (1.0) Value adjustment amortised cost RBL \u2013 (5.3) Utilisation of derivatives \u2013 (3.7) Unrealised loss derivatives \u2013 (7.5) Interest expense from bond loans (46.5) (43.7) Interest expense from bank debt 3) (48.9) (45.3) Interest expenses current liabilities (0.1) (0.0) Accretion expense related to asset retirement obligations (48.0) (34.9) Foreign exchange losses (8.5) (15.3) Other financial expenses (3.4) (3.5) Total financial expenses (287.8) (160.2) Net financial items (229.0) (132.3) 1) Fair value adjustment of interest swap related to RBL facility, ineffective part. 2) Fair value adjustment of the embedded derivatives of the convertible bonds. 3) Net of realised interest swap. 1 3 Tax Tax rates Producers of oil and gas on the Danish continental shelf are subject to the hydrocarbon tax regime under which, income derived from the sale of oil and gas is taxed at an elevated 64 percent. Any income deriving from other activities than first-time sales of hydrocarbons is taxed at the ordinary corporate income rate of currently 22 percent. The 64 percent is calculated as the sum of the \u201cChapter 2\u201d tax of 25 percent plus a specific hydrocarbon tax (chapter 3a) of 52 percent, in which the 25 percent tax payable is deductible. Income generated in Norway and United Kingdom is subject to regular corporate tax at 22 percent.
Tax expense
USD million
Income tax in profit/loss (Danish corporate income tax and hydrocarbon tax) 2022
Income tax current year (139.9)
Repayment of tax benefit related to chapter 3b (62.7)
Income tax for prior years (2.0)
Current income tax (204.6)
Deferred tax movements (65.9)
Prior year adjustment, deferred tax (8.6)
Deferred tax expense (74.5)
Tax (expense)/income (279.2)
Income tax in profit/loss is solely derived from the Group\u2019s activities on the Danish continental shelf, of which the major part is subject to the
elevated 64 percent hydrocarbon tax.
Tax (expense)/income related to OCI
Cash flow hedges (102.9)
Tax (expense)/income related to OCI (102.9)
Income tax on OCI is related to the unrealised fair value changes in derivatives designated in cash flow hedges. To the extent derivatives are
associated with the sale of oil and gas, results from cash flow hedges are subject to 64 percent hydrocarbon tax.
Reconciliation of nominal to actual tax rate Hydrocarbon tax 64% Corporate tax 22% In total
Result before tax 364.1 (115.4) 248.7
Expected tax on profit before tax 233.0 64% (25.4) 22% 207.6
Tax effect of:
Prior year adjustment 9.6 3% 0.2 0% 9.8
FX adjustment of net operating losses carried forward in DKK
1)
37.3 10% \u2013 0% 37. 3
Repayment of tax benefit related to chapter 3b
2)
30.1 8% \u2013 0% 30.1
Investment uplift on CAPEX projects
3)
(36.8) (10%) \u2013 0% (36.8)
Permanent differences \u2013 0% 29.1 (25%) 29.1
No recognition of tax assets in Norway and UK \u2013 0% 2.0 2% 2.0
Tax expense (income) in profit/loss 273.2 75% 6.0 5% 279.2
1) Deferred tax movement no cash effect.
2) From 2022 onwards, an additional tax cost related to the special tax incentive scheme (chapter 3b) is levied if commodity prices exceed certain thresholds. This tax is payable on net proceeds
from sales (incl. hedging results), less costs and fiscal depreciation and constitutes a repayment of the benefit previously achieved. The repayment cannot exceed the accumulated tax benefit
achieved from the special tax incentive rules during the development period. For 2022, Norwegian Energy Company ASA (BlueNord) estimates USD 30.1 million year to date.
3) The cost in the hydrocarbon tax regime is positively impacted by the 39 percent investment uplift on the Tyra Redevelopment project.
Reconciliation of nominal to actual tax rate, continues Hydrocarbon tax 64% Corporate tax 22% In total
OCI before tax 148.5 35.8 184.3
Expected tax on OCI before tax (95.1) 64% (7.9) 22% (102.9)
Tax effect of:
Non-taxable currency translation adjustment \u2013 \u2013 \u2013
Tax in OCI (95.1) 64% (7.9) 22% (102.9)
Current income tax payable
Tax payable relates to the Group\u2019s entities in Denmark. The amounts payable as of 31 December 22 were:
Hydrocarbon tax pertaining to pre-acquisition period 2019 not indemnified by the Seller (10.2)
Hydrocarbon tax for prior years (Denmark) (12.7)
Hydrocarbon and corporate tax for 2021 and 2022 (Denmark) (126.3)
Corporate tax for 22% (13.9)
Repayment of tax benefit related to chapter 3b (45.9)
Tax payables (209.0)
Current income taxes for current and prior periods are measured at the amount that is expected to be paid to or be refunded from the tax authorities, as at the balance sheet date. Due to the complexity in the legislative framework and the limited amount of guidance from relevant case law, the measurement of taxable profits within the oil and gas industry is associated with some degree of uncertainty. Uncertain tax liabilities are recognised with the probable value if their probability is more likely than not. Tax payable of USD 209.0 million, of which USD 191 million is an actual cash payable to be paid in 2023. As of 31 December 2022, the Company has provided an estimated USD 10.2 million pertaining to hydrocarbon tax in the part of pre-acquisition period, which is not indemnified by the Seller. Deferred tax Deferred tax assets are measured at the amount that is expected to result in taxes due to temporary differences and the value of tax losses. The recognised deferred tax asset relates to the following balance sheet items, all pertaining to the Group\u2019s activities on the Danish continental shelf: USD million Deferred tax and deferred tax asset 01.01.22 Effect recognised in profit/loss Effect recognised in OCI 31.12.2022 Property, plant and equipment 624.6 11.5 \u2013 636.1 Intangible assets, licences 17. 2 7.9 \u2013 25.1 Inventories and receivables 26.7 2.6 \u2013 29.3 Asset retirement obligation (ARO) provision (611.1) 46.7 \u2013 (564.5) Other assets and liabilities \u2013 (2.8) \u2013 (2.8) Tax loss carryforward, corporate tax (22%) (2.0) 0.1 1.9 \u2013 Tax loss carryforward, chapter 2 tax (25%) (22.8) (14.4) 37.1 (0.1) Tax loss carryforward, chapter 3a tax (52%) (558.3) 28.5 57.9 (471.9) Deferred tax asset, net (525.7) 80.0 96.9 (348.8) Tax loss carry forwards Tax losses are recognised in accordance with the expected utilisation hereof in subsequent income years based on the current business outlook and economic projections. Due to the limited taxable activity in UK and Norway, corporate tax losses in these jurisdictions are not capitalised. Tax losses in Denmark and UK under the hydrocarbon tax regime may be carried forward indefinitely and the utilisation is not subject to an annual cap. Losses are carried forward in Danish kroner and British pounds. Tax losses carried forward, Denmark Million DKK Corporate tax (22%) \u2013 Chapter 2 Hydrocarbon tax (25%) \u2013 Chapter 3a Hydrocarbon tax (52%) 5,773.5 Tax losses carried forward, Norway Million NOK Corporate tax Norway (22%) 1,071.4 Tax losses carried forward, UK Million GBP/USD Trade losses, UK (hydrocarbon s 330(2)) 75.0 Trade losses, UK (hydrocarbon), USD 96.0 Pre-trading capital expenditure, UK (hydrocarbon), GBP 41.0 14 Earnings per share Earnings per share are calculated by dividing the profit attributable to ordinary shareholders of the parent company by the weighted average number of ordinary shares in issue during the year. USD million 2022 2021 Profit (loss) attributable to ordinary shareholders from operations (31) (53) Profit (loss) basis for fully diluted shareholders from operations 131 (33) Weighted average number of shares (basic) 25,004,296 24,110,852 Adjustments convertible bond loan 5,822,649 11,149,488 Adjustments option schemes 391,868 \u2013 Weighted average number of shares (diluted) 31,218,813 35,260,340 Earnings per share in USD (1.2) (2.2) Earnings per share in USD diluted (1.2) (2.2) 15 Trade receivables and other current receivables USD million 2022 2021 Non-current assets Convertible loan CarbonCuts 0.2 \u2013 Loan CarbonCuts 0.6 \u2013 Total non-current receivables 0.8 \u2013 Current assets Trade receivables 42.1 40.4 Accrued revenue 52.3 47.1 Under-lift of oil/NGL 8.9 1.2 Prepayments 24.2 20.1 Other receivables 1.1 0.2 Total trade receivables and other current receivables 128.6 108.9 Ageing analysis of trade receivables on 31 December 2022 Past due USD million Total Not past due > 30 days 30-60 days 61-90 days 91-120 days > 120 days Trade receivables 42.1 42.1 \u2013 \u2013 \u2013 \u2013 \u2013 Total 42.1 42.1 \u2013 \u2013 \u2013 \u2013 \u2013 Ageing analysis of trade receivables on 31 December 2021 Past due USD million Tot al Not past due > 30 days 30-60 days 61-90 days 91-120 days > 120 days Trade receivables 40.4 38.2 \u2013 \u2013 \u2013 \u2013 2.2 Total 40.4 38.2 \u2013 \u2013 \u2013 \u2013 2.2 16 Inventories USD million 2022 2021 Product inventory, oil 21.6 17.7 Other stock (spares and consumables)* 34.3 33.8 Total inventories 55.9 51.4 * As of 31.12.2022 there are no provisions for obsolete stock. 17 Restricted cash, bank deposits, cash and cash equivalents USD million 2022 2021 Non-current assets Restricted cash pledged as security for abandonment obligation related to Nini/Cecilie 61.1 65.0 Restricted cash pledged as security for cash call obligations towards TotalEnergies 1) 142.5 140.5 Total non-current restricted cash 203.7 205.5 Current assets Unrestricted cash, bank deposits, cash equivalents 268.4 122.7 Total bank deposits 472.1 328.1 1) Norwegian Energy Company ASA (BlueNord) has made a USD 140 million deposit into a cash call security account in accordance with a cash call security agreement with TotalEnergies E&P Denmark A/S as operator of the DUC. All payment obligations from Norwegian Energy Company ASA (BlueNord) to the cash call security account have been made and there will be no further increase. 18 Financial instruments 18.1 Fair value hierarchy The table below analyses financial instruments carried at fair value, by valuation method. The different levels have been defined as follows: Level 1 Quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 Inputs for the asset or liability that are not based on observable market data. On 31 December 2022 USD million Level 1 Level 2 Level 3 Total Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 11.1 \u2013 11.1 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 44.6 \u2013 44.6 - Derivative instruments price hedge \u2013 108.9 \u2013 108.9 Total assets \u2013 164.6 \u2013 164.6 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 10.0 10.0 - Embedded derivatives convertible bond NOR15 \u2013 \u2013 38.9 38. Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 166.8 \u2013 166.8 Total liabilities \u2013 166.8 48.9 215.7 On 31 December 2021 USD million Level 1 Level 2 Level 3 Tota l Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 1.0 \u2013 1.0 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 8.8 \u2013 8. Total assets \u2013 9.7 \u2013 9.7 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 12.1 12.1 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 205.1 \u2013 205.1 Total liabilities \u2013 205.1 12.1 217.2
18.2 Financial instruments by category
On 31 December 2022
USD million
Financial
assets at
amortised cost
Assets at fair
value through
profit or loss
Fair value \u2013
hedging
instruments Total
Assets
Convertible loan CarbonCuts 0.2 \u2013 \u2013 0.2
Loan CarbonCuts 0.6 \u2013 \u2013 0.6
Derivative instruments interest swap \u2013 \u2013 55.7 55.7
Derivative instruments price hedge \u2013 \u2013 108.9 108.9
Trade receivables and other current assets 128.6 \u2013 \u2013 128.6
Restricted cash 203.7 \u2013 \u2013 203.7
Bank deposits, cash and cash equivalents 268.4 \u2013 \u2013 268.4
Total 601.5 \u2013 164.6 766.1
USD million
Financial
liabilities at
amortised cost
Liabilities at fair
value through
profit or loss
Fair value \u2013
hedging
instruments Total
Liabilities
Derivative instruments price hedge \u2013 \u2013 166.8 166.8
Embedded derivatives convertible bond NOR13 \u2013 10.0 \u2013 10.0
Embedded derivatives convertible bond NOR15 \u2013 38.9 \u2013 38.9
Convertible bond loans 188.7 \u2013 \u2013 188.7
Senior unsecured bond loan 166.9 \u2013 \u2013 166.9
Reserve-based lending facility 764.0 \u2013 \u2013 764.0
Deferred consideration 25.0 \u2013 \u2013 25.0
Trade payables and other current liabilities 115.6 \u2013 \u2013 115.6
Total 1,260.2 48.9 166.8 1,476.0
On 31 December 2021
USD million
Financial
assets at
amortised cost
Assets at fair
value through
profit or loss
Fair value \u2013
hedging
instruments Tot al
Assets
Derivative instruments price hedge \u2013 \u2013 9.7 9.7
Trade receivables and other current assets 108.9 \u2013 \u2013 108.9
Restricted cash 205.5 \u2013 \u2013 205.5
Bank deposits, cash and cash equivalents 122.7 \u2013 \u2013 122.7
Total 437.0 \u2013 9.7 446.8
USD million
Financial
liabilities at
amortised cost
Liabilities at fair
value through
profit or loss
Fair value \u2013
hedging
instruments Tot al
Liabilities
Derivative instruments price hedge \u2013 \u2013 205.1 205.1
Embedded derivatives convertible bond NOR13 \u2013 12.1 \u2013 12.1
Convertible bond loans 157.1 \u2013 \u2013 157.1
Senior unsecured bond loan 164.9 \u2013 \u2013 164.9
Reserve-based lending facility 857.3 \u2013 \u2013 857.3
Deferred consideration 25.0 \u2013 \u2013 25.0
Trade payables and other current liabilities 130.5 \u2013 \u2013 130.5
Total 1,334.8 12.1 205.1 1,552.1
18.3 Financial instruments \u2014 fair values
Set out below is a comparison of the carrying amounts and fair value of financial instruments as at 31 December 2022:
USD million
Total amount
outstanding*
Carrying
amount
Fair
value
Financial assets
Convertible loan CarbonCuts 0.2 0.2
Loan CarbonCuts 0.6 0.6
Derivative instruments interest swap 55.7 55.7
Derivative instruments price hedge 108.9 108.9
Trade receivables and other current assets 128.6 128.6
Restricted cash 203.7 203.7
Bank deposits, cash, cash equivalents and quoted shares 268.4 268.4
Total 766.1 766.1
Financial liabilities
Derivative instruments price hedge 166.8 166.8
Embedded derivative convertible bond NOR13 10.0 10.0
Embedded derivative convertible bond NOR15 38.9 38.9
Convertible bond loans 221.5 188.7 211.5
Senior unsecured bond loan 175.0 166.9 175.0
Reserve-based lending facility 800.0 764.0 800.0
Deferred consideration 25.0 25.0
Trade payables and other current liabilities 115.6 115.6
Total 1,196.5 1,476.0 1,542.8
* Total amount outstanding on the bonds and under the RBL facility.
The NOR13 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through
profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost. The embedded derivative is valued on an option
valuation basis, the carrying value as of 31 December 2022 was USD 10.0 million due to the majority of the NOR13 instrument being converted into the
new NOR15 instrument. On 13 January 2022, the majority of the remaining NOR13 convertible instrument was converted into equity, leaving only USD
0.2 million which will be subject to the NOR13 amendments as proposed by the company in November 2022.
The NOR15 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value
through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost, a total of USD 4.4 million in
transaction cost is included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of
31 December 2022 was USD 38.9 million. The assumptions in establishing the option value as of 31 December 2022 are shown below.
The following table list the inputs to the model used to calculate the fair value of the embedded derivatives:
NOR13 2022
Valuation date (date) 31 Dec 22
Agreement execution date (date) 24 Jul 19
Par value of bonds (USD) 13,810,094
Reference share price at time of agreement (NOK) 232
Fair value at grant date (USD) 53,942,754
PIK interest rate (%) 8.00%
Expected life (years) 0.9
Number of options (#) 476,648
Conversion price (NOK) 238
Fixed FX rate of agreement (USD:NOK) 8.180
Risk-free rate (based on government bonds) (%) 3.18%
Expected volatility (%) 48.31%
Model used Black-Scholes-Merton
NOR15 2022
Valuation date (date) 31 Dec 22
Agreement execution date (date) 30 Dec 22
Par value of bonds (USD) 207,641,201
Reference share price at time of agreement (NOK) 395
Fair value at grant date (USD) 38,928,552
PIK interest rate (%) 8.00%
Expected life (years) 3.0
Number of options (#) 4,037,301
Conversion price (NOK) 537
Fixed FX rate of agreement (USD:NOK) 10.440
Risk-free rate (based on government bonds) (%) 3.18%
Expected volatility (%) 48.31%
Model used Black-Scholes-Merton
The RBL facility is measured at amortised cost, in addition a total of USD 53 million in transaction cost has been capitalised. Transaction costs
are deducted from the amount initially recognised and are expensed over the period during which the debt is outstanding under the effective
interest method.
The senior unsecured bond loan is measured at amortised cost; a total of USD 7.6 million in transaction costs are deducted from the amount
initially recognised.
18.4 Hedging
The Group actively seeks to reduce the risk it is exposed to regarding fluctuating commodity prices through the establishment of hedging
arrangements. To the extent more than 100 percent of the projected production is hedged any value adjustments to the instruments covering in
excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. In 2022 no part
of the hedging instruments was considered ineffective. Time value related to hedging arrangements is considered insignificant and generally
the valuation of the instruments do not take into consideration the time value.
Currently, all the Company\u2019s commodity price hedging arrangements is executed solely in the market through forward contracts.
Under its RBL facility, Norwegian Energy Company ASA (BlueNord) has a rolling hedge requirement based on a minimum level of production
corresponding to the RBL banking case forecast.
The Company has entered into a USD 1.0 billion swap transaction with a group of banks to fix the Company\u2019s floating interest rate exposure under
its RBL facility from 1 November 2021 until 30 June 2024. Norwegian Energy Company ASA (BlueNord) will as a result pay interest on its RBL
cash drawings equal to 0.4041 percent plus the applicable margin. Norwegian Energy Company ASA (BlueNord) applies hedge accounting to
the Company\u2019s hedging arrangements. To the extent more than 100 percent of the Company\u2019s interest under its RBL facility is hedged any value
adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item
in the income statement. The ineffective amount in 2022 charged to financial items in the income statement were an income of USD 10.2 million.
As at 31 December 2022
Maturity
Less than
one month
One to three
months
Three to six
months
Six to nine
months
Nine to 12
months
More than
12 months
Commodity forward sales contracts:
Notional quantity (in mboe) \u2013 1,448 1,350 990 937 3,391
Notional amount (in USD million) \u2013 134 104 88 76 246
Average hedged sales price (in USD per boe) \u2013 92 77 89 81 72
Hedge reserve movement
The table below shows the movement in the hedge reserve from changes in the cash flow hedges.
USD million Hedge reserve
Balance as of 1 January 2022 (67.5)
Realised cash flow hedge 242.2
Related tax \u2013 realised cash flow hedge (155.0)
Changes in fair value (57.9)
Related tax \u2013 changes in fair value 52.1
Balance as of 31 December 2022 13.9
19 Share capital
Norwegian Energy Company ASA (BlueNord) owns 137.162 of its own shares. All shares have equal rights. All shares are fully paid.
Changes in number of shares and share capital:
No. of shares Share capital*
Number of shares and share capital as of 1 January 2021 24,549,013 29.5
Number of shares and share capital as of 31 December 2021 24,549,013 29.5
Issue of shares 1,159,411 1.4
Capital reduction, approved and registered \u2013 (29.3)
Number of shares and share capital as of 31 December 2022 25,708,424 1.7
No. of shares
Treasury share
reserve*
Number of treasury shares and treasury share reserve as of 1 January 2021 (438,161) (0.5)
Number of treasury shares and treasury share reserve as of 31 December 2021 (438,161) (0.5)
Sale of treasury shares 300,999 0.3
Number of treasury shares and treasury share reserve as of 31 December 2022 (137,162) (0.1)
* In USD million.
Changes in 2022
The Company received conversion notice from bondholders holding NOR13 Bonds for USD 33.6 million, which pursuant to the bond term are
convertible into 1,159,411 new shares in the Company at a conversion price of USD 28.9734. Following such conversions the share capital is
increased with NOK 11.6/USD 1.4 million.
The share capital is reduced with NOK 243.2/USD 29.3 million by reducing the nominal value of the shares. The reduction amount was
transferred to share premium fund. The share capital reduction has been registered in the Norwegian Registry of Business Enterprises on
28 December 2022. Following the share capital reduction, the Company\u2019s share capital is NOK 13.9/USD 1.7 million divided on 25.708.424
shares, each with a nominal value of NOK 0.5398295.
The Company sold 300.999 of its own shares in relation to exercise of options held by former Director of the Board and former members of the
Executive Team.
Overview of shareholders at 28 March 2023:
Shareholder* Shareholding
Ownership
share Voting share
Euroclear Bank S.A./N.V. 6,243,331 23.8% 23.8%
Goldman Sachs International 5,189,939 19.8% 19.8%
SOBER AS 1,850,000 7.1% 7.1%
Barclays Bank PLC 1,540,368 5.9% 5.9%
J.P. Morgan Securities LLC 1,435,010 5.5% 5.5%
Bank of America 774,408 3.0% 3.0%
J.P. Morgan Securities LLC 588,649 2.7% 2.7%
BNP Paribas 585,000 2.2% 2.2%
Sbakkejord AS 341,262 2.2% 2.2%
CLEARSTREAM BANKING S.A. 586,202 2.2% 2.2%
SOSYFR INVEST AS 268,368 1.6% 1.6%
Soci\u00e9t\u00e9 G\u00e9n\u00e9rale 425,000 1.3% 1.3%
Morgan Stanley & Co. Int. Plc. 300,225 1.2% 1.2%
FINSNES INVEST AS 318,000 1.1% 1.1%
VELDE HOLDING AS 222,222 1.0% 1.0%
Barclays Bank PLC 700,216 1.0% 1.0%
Goldman Sachs & Co. LLC 203,349 0.9% 0.9%
DNB BANK ASA 257,969 0.8% 0.8%
The Bank of New York Mellon SA/NV 228,149 0.8% 0.8%
OUSDAL AS 200,000 0.8% 0.8%
Total 22,257,667 85% 85%
Other owners (ownership <0,42%) 3,944,377 15.1% 15.1%
Total number of shares at 28 March 2023 26,202,044 100% 100%
*Nominee holder.
20 Post-employment benefits
Defined contribution plan
The Group has defined contribution plans for its employees. Pension costs related to the Company\u2019s defined contribution plan amounts to
USD 513 thousand for 2022. For 2021, the corresponding costs were USD 558 thousand.
The Norwegian companies are obliged to have occupational pension in accordance with the Norwegian act related to mandatory occupational
pension. All Norwegian companies meet the Norwegian requirements for mandatory occupational pension (\u201cobligatorisk tjenestepensjon\u201d).
Correspondingly, the affiliates in Denmark and United Kingdom comply with the requirement for mandatory occupational pension by local
legislation
21 Asset retirement obligations
USD million 31.12.2022 31.12.2021
Balance on 01.01. 1,029.2 950.3
Provisions and change of estimates made during the year (107.0) 64.9
Accretion expense 48.1 35.2
Incurred cost removal (14.4) (21.0)
Currency translation adjustment (0.1) (0.2)
Total provision made for asset retirement obligations 955.8 1,029.2
Break down of short-term and long-term asset retirement obligations
Short-term 9.8 26.2
Long-term 946.1 1,003.0
Total provision for asset retirement obligations 955.8 1,029.2
Estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations
and guidelines. The obligations are measured at net present value, assuming an inflation rate of 2.0 percent (2021: 2.0 percent) and a nominal
discount rate before tax of 5.5 percent (2021: 5 percent). The credit margin included in the discount rate is 2.5 percent.
The change in estimate during the year includes a decrease of USD 70 million as a result of the discount rate increasing by 0.5 percent.
The asset retirement estimate from the operator includes both USD and DKK costs and as a result there is a further decrease of USD 39 million
due to the weakening of DKK to USD. The net remaining change in estimate is due to more minor impacts on cost estimates, additional provision
for Tyra II installations offset by a change in expected timing of costs being incurred. Most of the removal activities are expected to be executed
many years into the future. This makes the ultimate asset retirement costs and timing highly uncertain. Costs and timing can be affected by
changes in regulations, technology, estimated reserves, economic cut-off date etc. The provision at the reporting date represents
management\u2019s best estimate of the present value of the future asset retirement costs required.
As part of the overall restructuring in 2015, an agreement was reached that entails that the partners took over Norwegian Energy Company ASA
(BlueNord)\u2019s share of the Nini/Cecilie licences, however Norwegian Energy Company ASA (BlueNord) remains liable for the asset retirement
obligation towards the licence partners. The liability related to Nini/Cecilie is capped at the escrow amount, which is currently USD 61.1 million/
DKK 426.0 million.
The balance as per 31.12.2022 is USD 890.8 million for DUC, USD 61.1 million for Nini/Cecilie, USD 2.3 million for Lulita (non-DUC share) and
USD 1.6 million for Tyra F-3 pipeline.
Sensitivity analysis
The table below shows how the asset retirement obligation would be affected by changes in the various assumptions, given that the remaining
assumptions are constant.
Sensitivity
ARO
($\u2019mm)
Change in
provision
Abandonment Cost Estimate increase +10% 979.2 10.0 %
Abandonment Cost Estimate decrease -10% 807.0 -10.0 %
Discount rate +1.0% 768.2 -14.0 %
Discount rate -1.0% 1,042.7 17.0 %
Inflation rate +1.0% 1,041.3 17.0 %
Inflation rate -1.0% 767.1 -14.0 %
22 Borrowings
22.1 Summary of borrowings
31.12.2022 31.12.2021
USD million Principal amount Book value Principal amount Book value
NOR13 Convertible Bond 13.8 13.1 185.0 157.1
NOR15 Convertible Bond
2)
207.6 175.7 \u2013 \u2013
NOR14 Senior Unsecured Bond
3)
175.0 166.9 175.0 164.9
Total non-current bonds 396.5 355.6 360.0 322.1
Reserve-based lending facility
3)
800.0 764.0 900.0 857.3
Deferred Consideration
4)
\u2013 \u2013 25.0 25.0
Total non-current debt 800.0 764.0 925.0 882.3
Deferred Consideration
4)
25.0 25.0 \u2013 \u2013
Total current debt 25.0 25.0 \u2013 \u2013
Total borrowings 1,221.5 1,144.6 1,285.0 1,204.3
Cash flows Non-cash changes
Movements in interest-bearing liabilities 31.12.21
Receipts/
payments
Conversion
to shares
Conversion
NOR15
PI K*/
Amortisation 31.12.22
NOR13 Convertible Bond 157.1 \u2013 (29.6) (143.3) 28.8 13.1
NOR15 Convertible Bond \u2013 (4.4) \u2013 168.7 11.4 175.7
NOR14 Senior Unsecured Bond 164.9 (15.8) \u2013 \u2013 17.7 166.9
Reserve-based lending facility 857.3 (100.0) \u2013 \u2013 6.7 764.0
Deferred Consideration 25.0 \u2013 \u2013 \u2013 \u2013 25.0
Total movement non-current interest-bearing liabilities 1,204.3 (120.2) (29.6) 25.5 64.7 1,144.6
Total movement in interest-bearing liabilities 1,204.3 (120.2) (29.6) 25.5 64.7 1,144.6
* PIK = Payment In Kind.
Note: Book values reported on the basis of amortised cost for NOR14, the reserve-based lending facility and the convertible bond loan element of NOR13 and NOR15.
1) The Company issued a convertible bond loan of USD 158 million in 2019 where the lender was granted a right to convert the loan into new shares in the Company by way of set-off against
the claim on the Company. The loan carries an interest of 8 percent p.a. on a PIK basis, with an alternative option to pay cash interest at 6 percent p.a., payable semi-annually. In 2022, four
conversions with a carrying amount of USD 36.6 million took place and USD 29.6 million of amortised cost was derecognised from the financial liability to equity. In December 2022,
USD 143.3 million was transferred into the new convertible instrument NOR15. The principal amount transferred was USD 151.4 million. Of the remaining USD 13.8 million outstanding on
31 December 2022, USD 13.6 million was converted into equity by 13 January. The remaining balance of USD 0.2 million was subject to the NOR13 amendments as proposed by the Company
in November 2022 on 19 January 2023.
2) The Company issued a convertible bond loan of USD 207.6 million in December 2022, made up of a transfer from NOR13 of USD 151.4 million plus additional compensation bonds of
USD 56.2 million. Similarly, to NOR13, the lender was granted a right to convert the loan into new shares in the Company by way of set-off against the claim on the Company. The loan carries an
interest of 8 percent p.a. on a PIK basis, with an alternative option to pay cash interest at 6 percent p.a., payable semi-annually.
3) The Company entered into an increased reserve-based lending facility in Q2 2021. The facility has a seven-year tenor with a maximum limit of USD 1.1 billion, with a maximum of USD 1.0 billion available
for cash drawdown by the Company. Interest is accrued on the drawn amount with an interest rate comprising the aggregate of SOFR and 4 percent per annum, 4.5 percent per annum from February
2023. The amount drawn on 30 September was USD 800 million, Norwegian Energy Company ASA (BlueNord) made a USD 100 million repayment in July 2022.
4) In accordance with the Sales Purchase Agreement USD 25 million of the consideration is due the earliest of March 2023 or finalising Tyra Redevelopment.
22.2 Details on borrowing
Details on borrowings outstanding on 31 December 2022
Reserve-based lending facility
In April 2021, Norwegian Energy Company ASA (BlueNord) amended its existing senior secured reserve-based credit facility to commit to a
seven-year senior reserve-based credit facility of USD 1.1 billion. The facility is a reserve-based credit facility secured against certain cash flows
generated by the Group. The amount available under the facility is recalculated every six months based upon the calculated cash flow
generated by certain producing fields and fields under development at an oil price and economic assumptions agreed with the banking
syndicate providing the facility. The facility is secured by a pledge over the shares of certain Group companies, a pledge over the Company\u2019s
working interest in its share of the DUC licence and security over insurances, hedging contracts, project accounts, intercompany loans and
material contracts. The pledged assets on 31 December 2022 amounted to USD 1 ,323 million and represented the carrying value of the pledge
of the Group companies whose shares are pledged as described in the section 5 below (Assets pledged as security for interest-bearing debt).
Pledge value: carrying value of shares held in Altinex AS, Noreco Denmark A/S, Noreco Oil Denmark A/S, Noreco Petroleum Denmark A/S
by Norwegian Energy Company ASA (BlueNord).
NOR13
In July 2019, Norwegian Energy Company ASA (BlueNord) issued a subordinated convertible bond loan of USD 158 million with a tenor of eight
years where the lender was granted a right to convert the loan into new shares in the Company at a conversion price of NOK 240 (USD 29.3) per
share by way of set-off against the claim on the Company. The loan has a mandatory conversion to equity after five years and carries an interest
of 8 percent p.a. on a PIK basis, with an alternative option to pay cash interest at 6 percent p.a., payable semi-annually. Should the instrument be
in place beyond the five-year conversion period, the interest rate on NOR13 will be reduced to 0.0 percent for the remaining term of the loan.
In November 2022, Norwegian Energy Company ASA (BlueNord) proposed for some amendments to the NOR13 bond which included a
two-year delay in the mandatory conversion date (8 November 2023 to 31 December 2025) and an inclusion of a call option to allow the
Company to redeem the NOR13 bond with cash in December 2025. To reflect the premium of the then share price relative to the NOR13
previous conversion price, the principal amount was updated from approximately USD 165 million to approximately USD 227 million by way of
issuance of compensation bonds. Conversion price was reset to USD 51.4307 per share and interest rate remains unchanged.
Following the proposed amendments, a claim arose from two minority NOR13 bondholders in which Norwegian Energy Company ASA
(BlueNord) received a temporary injunction from the Oslo District Court that restricted the NOR13 amendments from being implemented (the
\u201cRuling\u201d). To allow the NOR13 bondholders who wanted to benefit from the commercial position represented by the amendments, Norwegian
Energy Company ASA (BlueNord) proposed a new NOR15 subordinated convertible bond for the bondholders to exchange their holdings of
NOR13 for NOR15 (see note below).
In December 2022, the Oslo District Court confirmed that the temporary injunction was withdrawn, and the Ruling is no longer in effect.
The exchange offer for NOR15 continued as planned, with 91.6 percent of the outstanding NOR13 bonds exchanged to the new NOR15 bonds,
and the remainder converted to equity or remained subject to the NOR13 amendments. The value of the NOR13 convertible bond at year
end is USD 13.8 million of which USD 13.6 million converted in January 2023.
NOR14
In December 2019, Norwegian Energy Company ASA (BlueNord) successfully completed the issue of a USD 175 million unsecured bond.
The proceeds are utilised for general corporate purposes and the bond carries an interest of 9 percent p.a., payable semi-annually, with a
six and a half-year tenor.
NOR15
In December 2022, Norwegian Energy Company ASA (BlueNord) launched an exchange offer for the NOR13 bondholders in exchange for a
new subordinated convertible bond of USD 208 million, with revised terms and a later and more flexible conversion date in 2025. The Company
issued a total of 207,641,201 new NOR15 bonds, each with a nominal value of USD 1. The NOR15 bond terms mirror the amendments of the
NOR13 bond except that inter alia a tap issue mechanism has been included. Interest payments are on similar terms with NOR13, which is an
interest of 8 percent p.a. on a PIK basis, with an alternative option to pay cash interest at six percent p.a., payable semi-annually.
22.3 Covenants
Covenants relating to interest-bearing debt
Reserve-based lending facility
The reserve-based credit facility constitutes senior debt of the Company and is secured on a first priority basis against certain of the Company\u2019s
subsidiaries and their assets. The reserve-based credit facility agreement contains a financial covenant that the ratio of Net Debt to EBITDAX
(earnings before interest, tax, depreciation, amortisation and exploration) shall be: less than 6.0:1.0 at the end of financial years 2021 and 2022;
less than 3.5:1.0 at the end of financial year 2023; and less than 3.0:1.0 at the end of financial year 2024 onwards until the expiry of the facility.
Each test is carried out on the audited full year financial statements of Norwegian Energy Company ASA (BlueNord). Norwegian Energy
Company ASA (BlueNord) must also demonstrate minimum liquidity on a look forward basis of USD 50 million during the relevant period, which is
currently to the completion of the Tyra redevelopment project. The agreement also includes special covenants which, among other, restrict the
Company from taking on additional secured debt, provide parameters for minimum and maximum hedging requirements and restrict declaration
of dividends or other distributions. Norwegian Energy Company ASA (BlueNord) is in compliance with these covenants at the end of 2022.
NOR14
In July 2021, Norwegian Energy Company ASA (BlueNord)\u2019s written resolution regarding the addition of further headroom under the Leverage
Ratio covenant through to the end of 2023 was resolved and approved by the Company\u2019s NOR14 bondholders. Based on this written resolution,
the maximum Leverage Ratio has been amended to 7.0x (from 5.0x) during the Tyra Redevelopment Period ending Q2 2023, 6.0x (from 3.0x)
during Q3 2023 and 5.0x (from 3.0x) during Q4 2023. From Q1 2024 onwards, the maximum Leverage Ratio will revert to 3.0x per the original
bond terms. In addition to the change in maximum permitted leverage, Norwegian Energy Company ASA (BlueNord)\u2019s minimum liquidity
threshold has increased to USD 75 million until the end of 2023 (from USD 50 million until end Q2 2023 and USD 25 million during Q3 and
Q4 2023). Norwegian Energy Company ASA (BlueNord) is in compliance with the covenants at the end of 2022.
22.4 Payment structure
Payment structure (USD million)
Year NOR13 NOR14 NOR15
Reserve-based
lending facility
Deferred
consideration Total
2023 \u2013 \u2013 \u2013 \u2013 25.0 25.0
2024 \u2013 \u2013 \u2013 75.0 \u2013 75.0
2025 \u2013 \u2013 \u2013 275.0 \u2013 275.0
2026 \u2013 175.0 \u2013 275.0 \u2013 450.0
2027 \u2013 \u2013 \u2013 138.0 \u2013 138.0
2028 \u2013 \u2013 \u2013 38.0 \u2013 38.0
Total \u2013 175.0 \u2013 800.0 25.0 1,000.0
Interest payments (USD million):
Year NOR13* NOR14 NOR15*
Reserve-based
lending facility
Deferred
consideration Total
Interest rate 9.0% \u2013 SOFR** 4.0%
2023 \u2013 15.8 \u2013 76.7 1.0 93.7
2024 \u2013 15.8 \u2013 75.8 \u2013 91.6
2025 \u2013 15.8 \u2013 58.7 \u2013 74. 5
2026 \u2013 7.9 \u2013 33.4 \u2013 41.3
2027 \u2013 \u2013 \u2013 8.9 \u2013 8.9
2028 \u2013 \u2013 \u2013 0.3 \u2013 0.3
Total \u2013 55.3 \u2013 253.9 1.0 310.2
* NOR13/NOR15 carries a variable interest charge of: (i) 6 percent per annum in cash, payable semi-annually, or; (ii) 8 percent per annum PIK cumulative interest, rolled up semi-annually, to add
to NOR13/NOR15 capital on conversion at expiry of the bond. Currently, the Company has elected the PIK interest of 8 percent and is therefore forecasting no cash interest payments on
NOR13/NOR15 in the above table.
** In Q3 2021, the Company entered a USD 1.0 billion swap transaction with a group of banks to fix the Company\u2019s floating interest rate (LIBOR/SOFR from 1 November 2021) exposure under its
Reserve Lending Facility from November 2021 until 30 June 2024. Norwegian Energy Company ASA (BlueNord) will, as a result, pay interest on its RBL cash drawings equal to 0.4041 percent
plus the applicable margin.
22.5 Assets pledged as security for interest-bearing debt
Net book value in the separate financial statements of assets pledged as securities
The Group has the following pledged assets for the reserve-based lending facility:
USD million 2022 2021
BlueNord shares in Altinex AS 393.5 392.6
Altinex AS shares in Noreco Olie-og Gasutvinding Danmark B.V and other companies 621.5 1,371.5
Loans from Parent to subsidiaries 308.3 300.1
Total net book value 1,323.3 2,064.3
23 Trade payables and other payables
USD million 2022 2021
Trade payable 17.0 5.4
Liabilities to operators relating to joint venture licences 66.8 73.4
Accrued interest 3.3 2.5
Salary accruals 2.5 2.1
Public duties payable 8.3 14.0
Deferred consideration 25.0 \u2013
Other current liabilities 17.7 33.1
Total trade payables and other current liabilities 140.6 130.5
Trade and other payables held in currency
USD million 2022 2021
USD 54.7 82.9
DKK 71.2 22.5
EUR 11.3 21.7
GBP 0.8 1.9
NOK 2.6 1.4
Total 140.6 130.5
24 Share-based compensation
Please see the Executive Remuneration Report 2022 for more details on long-term incentive scheme to key management and Board of
Directors in the period 2018 \u2013 2022.
Number of
Share
options
Retention
shares
Performance
shares
Total share options outstanding as at 1 January 2021 983,868 \u2013 \u2013
Share options relinquished in 2021 (235,000) \u2013 \u2013
Outstanding at 31 December 2021 748 ,868 \u2013 \u2013
Granted in 2022 122,000 112,825 188,935
Exercised in 2022 (301,000) \u2013 \u2013
Translated in 2022 (178,000) \u2013 \u2013
Outstanding at 31 December 2022 391,868 112,825 188,935
The expense recognised during the year is shown in the following table:
USD million 2022 2021
Expense arising from equity-settled share-based payment transactions 0.0 0.3
Expense arising from Retention shares and Performance shares 1.4 \u2013
Total expense arising from long-term incentive schemes 1.4 0.3
The following table list the inputs to the model used:
Weighted averages 2022
Fair value of options at valuation date (NOK) 83
Share price at valuation date (NOK) 143
Exercise price (NOK) 160
Expected volatility 57.49%
Expected life (years) 2.7
Expected dividends n/a
Risk-free rate (based on government bonds) 0.35%
25 Guarantees
Overview of issued guarantees on 31 December 2022
The parent company of the Group, Norwegian Energy Company ASA (BlueNord) has issued a parent company guarantee on behalf of its
subsidiary Norwegian Energy Company UK Ltd and Noreco Oil (UK) Limited. Norwegian Energy Company ASA (BlueNord) guarantees that,
if any amounts become payable by Norwegian Energy Company UK Ltd or by Noreco Oil (UK) Limited to the UK Secretary of State under the
terms of the licence and the company does not repay those amounts on first demand, Norwegian Energy Company ASA (BlueNord) shall pay
to the UK Secretary of State on demand an amount equal to all such amounts. Under the forfeiture agreement Premier assumes this risk as
between Premier and Norwegian Energy Company ASA (BlueNord) so, while this contingent liability to the Secretary of State would need to
be recognised in any future sale of the company, Noreco Oil (UK) Limited does have recourse against Premier if it defaults in its performance.
On 6 December 2007, Norwegian Energy Company ASA (BlueNord) issued a parent company guarantee to the Danish Ministry of Climate,
Energy and Building on behalf of its subsidiary Noreco Oil Denmark A/S and Noreco Petroleum Denmark A/S.
On 31 December 2012, Norwegian Energy Company ASA (BlueNord) issued a parent company guarantee on behalf of its subsidiary Noreco
Norway AS. Norwegian Energy Company ASA (BlueNord) guarantees that, if any amounts become payable by Noreco Norway AS to the
Norwegian Secretary of State under the terms of the licences and the company does not repay those amounts on first demand, Norwegian
Energy Company ASA (BlueNord) shall pay to the Norwegian Secretary of State on demand an amount equal to all such amounts. Noreco
Norway AS was liquidated in 2018, however as per 31.12.2022, the guarantee has not been withdrawn.
The Company has provided a parent company guarantee to the Danish Ministry of Climate, Energy and Utilities related to the Group\u2019s
activities on the DCS, including Norwegian Energy Company ASA (BlueNord)\u2019s participation in the Tyra West Pipeline and the Lulita licence.
The Company has also provided a parent company guarantee towards the lenders in relation to the Company\u2019s USD 1.1 billion reserve-based
lending facility and customary obligations/guarantees under joint operating agreements. Norwegian Energy Company ASA (BlueNord) has
also provided a parent company guarantee to Shell Energy Europe Limited in relation to its subsidiary Noreco Oil Denmark A/S\u2019s obligations
under a gas offtake and transportation agreement capped at EUR 30 million.
Furthermore, the Company has provided a parent company guarantee to TotalEnergies EP Danmark A/S for its obligations under the JOA
together with a guarantee from Shell. Norwegian Energy Company ASA (BlueNord) has provided standby letters of credit of USD 100 million,
issued under the USD 100 million sub-limit of the RBL facility for the benefit of Shell in connection with this guarantee.
In relation to Norwegian Energy Company ASA (BlueNord)\u2019s historic operations in the UK North Sea, the Company has issued a parent
company guarantee on behalf of its subsidiaries Norwegian Energy Company UK Ltd and BlueNord Oil (UK) Limited.
26 Investments in jointly owned assets
Investments in jointly own assets are included in the accounts by recognising the Groups share of the assets, liabilities, revenues and expenses
related to the joint operation.
The Group holds the following licence equities on 31 December 2022:
Licence Field Country Ownership share
DUC DUC Denmark 36.8 %
1/90 Lulita Part Denmark 20.0 %
7/86 Lulita Part Denmark 20.0 %
8/06B \u2013 Denmark 36.8 %
27 Contingencies and commitments
Financial commitments
As a partner in DUC, the Company has commitment to fund its proportional share of the budget and work programmes of the DUC. In
December each year, the operating budget (which includes operating expenditures, capital expenditure related to production, exploration and
abandonment) for the following year, is agreed amongst the DUC partners. For the coming four years, the average operating budget is expected
to be around USD 230 million per year. Capital and abandonment expenditure for individual projects, such as Tyra, are approved separately.
Norwegian Energy Company ASA (BlueNord)\u2019s capital commitments are principally related to the ongoing Tyra redevelopment project.
The gross capital and abandonment expenditure budget for the Tyra redevelopment project at the time of the investment decision was
DKK 21 billion which in 2022 was increased to DKK 26.3 billion and DKK 20.6 billion had been incurred by the end of 2022. Based on the current
project schedule, Norwegian Energy Company ASA (BlueNord) will be required to fund its proportional share of this remaining expenditure over
the next two years with Tyra to restart production by end of 2023. Further, Norwegian Energy Company ASA (BlueNord) has capital
commitments to infill wells planned for Halfdan in 2023 with a gross DUC budget of DKK 0.6 billion.
The DUC is obliged to use the specially constructed oil trunk line, pumps and terminal facilities and to contribute to the construction and
financing costs thereof as a result of an agreement entered into with the Danish government. This obligation is approximately USD 18 million
per year (2022: USD 16 million gross).
In addition to the above and in order to obtain the consent of TotalEnergies EP Danmark A/S to the acquisition, Noreco Oil Denmark A/S agreed
to deposit cash in a secured cash call security account in favour of Total E&P Danmark A/S (the concessionaire in respect of the Sole
Concession). On 31 December 2022, the escrow account was USD 143 million. All payment obligations from Norwegian Energy Company ASA
(BlueNord) to the cash call security account have been made and there will be no further increase. The cash call security amount will then
decrease to USD 100 million at the end of the year in which the Tyra redevelopment project is completed and can, on certain terms and
conditions, be replaced with a letter of credit or other type of security.
Contingent liabilities
In relation to the Nini and Cecilie fields, Norwegian Energy Company ASA (BlueNord) was in 2015 prevented from making payments for its share
of production costs and was consequently in breach of the licence agreements. In accordance with the JOAs, the Nini and Cecilie licences were
forfeitured and the licences were taken over by the partners, whereas the debt remained with Norwegian Energy Company ASA (BlueNord).
Norwegian Energy Company ASA (BlueNord) and representatives from the bondholders reached an agreement during 2015 which entails that
the Danish Norwegian Energy Company ASA (BlueNord) entity remains liable for the abandonment obligation, but the liability is in any and all
circumstances limited to a maximum amount equal to the restricted cash account of USD 61 million (DKK 427 million), adjusted for interest.
The total provision made for the asset retirement obligations reflects this.
The Company has received a claim regarding the level of \u00d8rsted pipeline tariffs charged since 2013. As the relevant authority
(Forsyningstilsynet) is currently reassessing their view, Norwegian Energy Company ASA (BlueNord) believes that there is no basis for this
claim prior to a new ruling setting the appropriate level of these tariffs. Given the outcome of this and any consequent liability is not yet known,
the Company has not recognised a provision for this claim.
During the normal course of its business, the Company may be involved in disputes, including tax disputes. The Company has not made
accruals for possible liabilities related to litigation and claims based on management\u2019s best judgement.
Norwegian Energy Company ASA (BlueNord) has unlimited liability for damage in relation to its participation in the DUC. The Company has
insured its pro rata liability in line with standard market practice.
Apart from the issues discussed above, the Group is not involved in claims from public authorities, legal claims or arbitrations that could have
a significant negative impact on the Company\u2019s financial position or results.
28 Related party transactions
Other than fees to directors of the board the group did not have any transactions with related parties during 2022.
29 Subsequent events
There are no events with significant accounting impacts that have occurred between the end of the reporting period and the date of this report.
The Company monitors the Russia-Ukraine war closely and has not identified any negative impact on the Company\u2019s assets or income.
", "dimensions": { "concept": "ifrs-full:DisclosureOfNotesAndOtherExplanatoryInformationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-363": { "value": "1 Summary of significant accounting policies Norwegian Energy Company ASA (BlueNord, \u201cthe Company\u201d or \u201cthe Group\u201d) is a public limited liability company registered in Norway, with headquarters in Oslo (Nedre Vollgate 1, 0158 Oslo). The Company has subsidiaries in Norway, Denmark, the Netherlands and the United Kingdom. The Company is listed on the Oslo Stock Exchange. The consolidated financial statements for 2022 were approved by the Board of Directors on 28 March 2023. The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated. The Group also provides the disclosure requirements as specified under the Norwegian Accounting Law (Regnskapsloven). 1.1 Basis of preparation The consolidated financial statements of Norwegian Energy Company ASA (BlueNord) have been prepared in accordance with the IFRS and interpretations from the IFRIC, as endorsed by the EU. The Group also provides information required in accordance with the Norwegian Accounting Act and associated NGAAP standards. The preparation of financial statements in accordance with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group\u2019s accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in note 3. In accordance with the Norwegian Accounting Act, section 3-3a, the Board of Directors confirms that the consolidated financial statements have been prepared under the assumption of going concern and that this is the basis for the preparation of the financial statements. The financial solidity and the Company\u2019s working capital and cash position are considered satisfactory in regards of the planned activity level for the next 12 months. The Board of Directors is of the opinion that the consolidated financial statements give a true and fair view of the Company\u2019s assets, debt, financial position and financial results. The Board of Directors are not aware of any factors that materially affect the assessment of the Company\u2019s position as of 31 December 2022, besides what is disclosed in the Director\u2019s Report and the financial statements. The subtotals and totals in some of the tables may not equal the sum of the amounts shown due to rounding. 1.1.1 Changes in accounting policies and disclosures No change in 2022. Amendments to standards Amendments to standards, issued are either not expected to impact Norwegian Energy Company ASA (BlueNord)\u2019s consolidated financial statements materially, or are not expected to be relevant to the consolidated financial statements upon adoption . 1.2 Consolidation Subsidiaries Subsidiaries are all entities over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are de-consolidated from the date that control ceases. As of 31 December 2022, all consolidated subsidiaries are 100 percent controlled by the parent company, Norwegian Energy Company ASA (BlueNord) or other Group companies. The proportion of the voting rights in the subsidiary undertakings held directly by the parent company does not differ from the proportion of ordinary shares held. The parent company does not have any shareholdings in the preference shares of subsidiary undertakings included in the group. All subsidiary undertakings are included in the consolidation. The Group had the following subsidiaries on 31 December 2022: Name Country of incorporation and place of business Nature of business Ordinary shares directly held by parent (%) Ordinary shares held by the Group (%) Noreco Denmark A/S Denmark Intermediate holding company 100% Noreco Oil Denmark A/S Denmark Exploration and production activity 100% Noreco Petroleum Denmark A/S Denmark Exploration and production activity 100% Noreco Olie-og Gasudvinding Danmark B.V. Netherlands Exploration and production activity 100% Noreco DK Pipeline ApS Denmark Infrastructure oil and gas 100% Norwegian Energy Company UK Ltd Great Britain Exploration activity 100% 100% Noreco Oil (UK) Ltd Great Britain Exploration activity 100% Altinex AS Norway Intermediate holding company 100% 100% Djerv Energi AS Norway Dormant Company 100% 100% The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair values of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Acquisition-related costs are expensed as incurred, except if related to the issue of debt not at fair value through profit and loss (FVTPL) or equity securities. If the business combination is achieved in stages, the acquisition date carrying value of the acquirer\u2019s previously held equity interest in the acquiree is re - measured to fair value at the acquisition date; any gains or losses arising from such re-measurement are recognised in profit or loss. Any contingent consideration to be transferred or received by the Group is recognised at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration that is deemed to be an asset or liability is recognised in profit or loss. Contingent consideration that is classified as equity is not re-measured, and its subsequent settlement is accounted for within equity. Intercompany transactions, balances, income and unrealised gains on transactions between Group companies are eliminated. Unrealised losses are also eliminated. When necessary, amounts reported by subsidiaries have been adjusted to conform with the Group\u2019s accounting policies. Interest in jointly controlled assets A jointly controlled asset is a contractual agreement between two or more parties regarding a financial activity under joint control. The Group has ownership in licences that are not separate legal companies. The Company recognises its share of the assets, liabilities, revenues and expenses of the joint operation in the respective line items in the Company\u2019s financial statements based on its ownership share. 1.3 Segment reporting The Group\u2019s segments were established on the basis of the most appropriate distribution of resource and result measurement. Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Chief Executive Officer. The whole Group is considered a single operating segment. 1.4 Foreign currency translation a) Functional and presentation currency Items included in the financial statements of each of the Group\u2019s entities are measured using the currency of the primary economic environment in which the entity operates (\u201cthe functional currency\u201d). The consolidated financial statements are presented in US dollars (USD), which is the Group\u2019s presentation currency and the parent company and main operating companies functional currency. b) Transactions and balances Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions or valuation where items are re-measured. Foreign exchange gains and losses are recognised in the income statement as other financial income or other financial expenses. c) Group companies The results and financial position of all the group entities (none of which has the currency of a hyper-inflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows: i) assets and liabilities for each financial position presented are translated at the closing rate at the date of that statement of financial position; ii) income and expenses for each income statement are translated at the average monthly exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the rate on the dates of the transactions); and iii) all currency translation adjustments are recognised in other comprehensive income (OCI). Goodwill and fair value adjustments arising on the acquisition of a foreign entity are treated as assets and liabilities of the foreign entity and translated at the closing rate. Currency translation adjustments arising are recognised in other comprehensive income. 1.5 Property, plant and equipment Property, plant and equipment include production facilities, machinery and equipment. Items of property, plant and equipment are measured at cost, less accumulated depreciation and accumulated impairment losses. Cost includes purchase price or construction cost and any costs directly attributable to bringing the assets to a working condition for their intended use, including capitalised borrowing expenses incurred up until the time the asset is ready to be put into operation. For property, plant and equipment where asset retirement obligations for decommissioning and dismantling are recognised as a liability, this value is added to acquisition cost for the respective assets. Borrowing costs that are not directly attributable to the acquisition, construction or production of a qualifying asset are recognised in the income statement using the effective interest method. When parts of an item of property, plant and equipment have different useful lives, they are accounted for as separate items (major components) of property, plant and equipment, and depreciated separately. Subsequent costs are included in the asset\u2019s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. The carrying amount of the replaced part is derecognised. All other repairs and maintenance are charged to the income statement during the financial period in which they are incurred. Expenses related to drilling and equipment for exploration wells where proven and probable reserves are discovered are capitalised and depreciated using the unit-of-production (UoP) method based on the proven and probable reserves expected to be produced from the well. Development cost related to construction, installation and completion of infrastructural facilities, such as platforms, pipelines and drilling of production wells, are capitalised as producing oil and gas fields. They are depreciated using the unit-of-production method based on the proven and probable developed reserves expected to be recovered from the area for the economic lifetime of the field. For fields where the oil share of the reserves constitutes the most significant part of the value, the capitalised cost is depreciated based on produced barrels of oil. This generally gives a more systematic allocation of depreciation expenses over the useful life than using all produced oil equivalents. If realisation of the probable reserves demands further future investments, these are added to the basis of depreciation. Acquired assets used for extraction and production of petroleum deposits, including licence rights, are depreciated using the UoP method based on proven and probable reserves. Historical cost price for other assets is depreciated over the estimated useful economic life of the asset, using the straight-line method. The estimated useful lives are as follows: \u2022 Office equipment and fixtures: three to five years Depreciation methods, useful lives, residual values and reserves are reviewed at each reporting date and adjusted if appropriate. 1.6 Intangible assets Oil and gas exploration and development expenditures The Group applies the successful efforts method of accounting for oil and gas exploration expenditures. Expenditures to acquire interests in oil and gas properties and to drill and equip exploratory wells are capitalised as exploration expenditures within intangible assets until the well is complete and the results have been evaluated, or there is any other indicator of a potential impairment. Exploration wells that discover potentially economic quantities of oil and natural gas remain capitalised as intangible assets during the evaluation phase of the discovery. This evaluation is normally finalised within one year. If, following the evaluation, the exploratory well has not found potentially commercial quantities of hydrocarbons, the capitalised expenditures are evaluated for derecognition or tested for impairment. Geological and geophysical expenditures and other exploration and evaluation expenditures are expensed as incurred. Capitalised exploration expenditures, including expenditures to acquire interests in oil and gas properties, related to wells that find proved reserves are transferred from exploration expenditures (intangible assets) to property, plant and equipment at the time of sanctioning of the development project. Other intangible assets Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets with definite lives are carried at cost less any accumulated amortisation and accumulated impairment losses, if any. Internally generated intangible assets, excluding capitalised development costs, are not capitalised. Instead, the related expenditure is recognised in profit or loss in the period in which the expenditure is incurred. Intangible assets are amortised over the useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortisation period and the amortisation method for an intangible asset is reviewed at least at the end of each reporting period. Changes in the expected useful life or the expected pattern of consumption of future economic benefits embodied in the asset are considered to modify the amortisation period or method, as appropriate, and are treated as changes in accounting estimates. The amortisation expense on intangible assets is recognised in the Consolidated Statement of Comprehensive income in the line-item depreciation and amortisation. 1.7 Impairment of non-financial assets a) Unit of account The Group applies each prospect, discovery, or field as unit of account for allocation of profit or loss and financial position items. When performing impairment testing of licence and capitalised exploration expenditures and production facilities, each prospect, discovery, or field is tested separately as long as they are not defined to be part of a larger cash generating unit. Developed fields producing from the same offshore installation are treated as one joint cash generating unit. The size of a cash generating unit cannot be larger than an operational segment. b) Impairment testing Intangible assets with an indefinite useful life are not subject to amortisation and are tested annually for impairment. For oil and gas exploration and development expenditures, see note 1.6 above regarding assessment of impairment and derecognition. Property, plant and equipment subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset\u2019s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset\u2019s fair value less costs of disposal and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash generating units). Non-financial assets other than goodwill that suffered impairment write-downs are assessed for potential impairment reversal at each reporting date as to whether there is an indication that an impairment loss may no longer exist or may have decreased. 1.8 Financial assets 1.8.1 Classification The Group classifies financial assets and financial liabilities according to IFRS 9 through the mixed measurement model with three primary measurement categories for financial assets: amortised cost, fair value through OCI and fair value through profit and loss (P&L). The classification depends on the entity\u2019s business model and the contractual cash flow characteristics of the financial assets. Management determines the classification of its financial assets at initial recognition. a) Financial assets and liabilities at fair value through profit or loss Financial assets at fair value through profit or loss are financial assets held for trading that are not measured at amortised cost or at fair value through OCI. IFRS 9 requires that for a financial liability designated as at fair value through profit or loss the effects of changes in the liability\u2019s credit risk shall be included in OCI instead of through profit and loss. Derivatives, including embedded derivatives, are also recognised at fair value through profit or loss unless they are designated as hedges. Assets in this category are classified as current assets if expected to be settled within 12 months, otherwise they are classified as non-current. b) Financial assets and liabilities at amortised cost The Group measures financial assets at amortised cost if both of the following conditions are met: \u2022 the financial asset is held within a business model with the objective to hold financial assets in order to collect contractual cash flows; and \u2022 the contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding. Financial assets at amortised cost are subsequently measured using the effective interest (EIR) method and are subject to impairment testing. Gains and losses are recognised in profit or loss when the asset is derecognised, modified or impaired. These assets are included in current assets, except for maturities greater than 12 months after the end of the reporting period. These are classified as non-current assets. The Group\u2019s financial assets categorised as at amortised cost comprise trade and other receivables, contract assets, restricted cash and cash and cash equivalents in the statement of financial position (notes 1.11 and 1.12). The Group measures interest-bearing loans and borrowings (financial liabilities) at amortised cost using the effective interest method. 1.8.2 Recognition and measurement Regular purchases and sales of financial assets are recognised on the trade-date \u2013 the date on which the Group commits to purchase or sell the asset. Investments are initially recognised at fair value plus transaction costs for all financial assets not carried at fair value through profit or loss. Financial assets carried at fair value through profit or loss, are initially recognised at fair value, and transaction costs are expensed in the income statement. Financial assets are derecognised when the rights to receive cash flows from the investments have expired or have been transferred and the Group has transferred substantially all risks and rewards of ownership. Financial assets at fair value through profit or loss are subsequently carried at fair value. Trade and other receivables are subsequently carried at amortised cost using the effective interest method. Gains or losses arising from changes in the fair value of the \u201cfinancial assets at fair value through profit or loss\u201d category is presented in the income statement within \u2018Financial items\u2019 in the period in which they arise. 1.9 Impairment of financial assets The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments (financial assets) not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Group expects to receive, discounted at an approximation of the original effective interest rate. The expected cash flows will include cash flows from the sale of collateral held or other credit enhancements that are integral to the contractual terms. The Group applies a simplified approach in calculating ECLs for trade receivables and contract assets. Therefore, the Group does not track changes in credit risk, but instead recognises a loss allowance based on lifetime ECLs at each reporting date. 1.10 Derivative financial instruments and hedging activities Derivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re-measured at their fair value. The method of recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument, and if so, the nature of the item being hedged. The Group uses derivative financial instruments, such as forward commodity contracts and options, to reduce the exposure to commodity price volatility. The Group has elected to apply cash flow hedge accounting designating these derivatives. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and from the date of start of cash flow hedge accounting. These are subsequently re-measured at fair value and the effective portion of the gain or loss on the hedging instrument is recognised in OCI, while any ineffective portion is recognised immediately in profit or loss (financial income or financial expenses). The cash flow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item. The amount accumulated in OCI is reclassified to profit or loss as a reclassification adjustment in the same periods during which the hedged cash flows affect profit or loss. If cash flow hedge accounting is discontinued, the amount that has been accumulated in OCI must remain in accumulated OCI if the hedged future cash flows are still expected to occur. Otherwise, the amount will be immediately reclassified to profit or loss as a reclassification adjustment. Derivatives are carried as financial assets when the fair value is positive and as financial liabilities when the fair value is negative. Commodity contracts that were entered into and continue to be held for the purpose of the delivery of a non-financial item in accordance with the Group\u2019s expected sale requirements fall within the exception from IFRS 9, which is known as the \u201cnormal purchase or sale exemption\u201d or the \u201cown use\u201d scope exception. For these contracts and the host part of the contracts containing embedded derivatives, they are accounted for as executory contracts. The Group recognises such contracts in its statement of financial position only when one of the parties meets its obligation under the contract to deliver either cash or a non-financial asset. The volume hedging agreement with Shell ended on 31 December 2020 and is not relevant in 2022. 1.11 Trade receivables Trade receivables are amounts due from customers for oil and gas sold or services performed in the ordinary course of business. If collection is expected in one year or less (or in the normal operating cycle of the business if longer), they are classified as current assets. If not, they are presented as non-current assets. Trade receivables are measured at amortised cost using the effective interest method, less provision for impairment. 1.12 Cash and cash equivalents Cash and cash equivalents include cash, bank deposits and short-term liquid placements, that immediately and with insignificant risk of changes in value can be converted to known cash amounts and with a remaining maturity less than three months from the date of acquisition. In the consolidated statement of financial position, bank overdrafts are shown within borrowings in current liabilities. 1.13 Over/under-lifting of hydrocarbons Over/under-lifting occurs when the Group has lifted and sold more or less hydrocarbons from a producing field than what the Group is entitled to at the time of lifting. Over-lifting of hydrocarbons is presented as other current liabilities, under-lifting of hydrocarbons is presented as other current assets. The value of under-lifting is measured at the lower of production expenses and the estimated sales value, less estimated sales costs and the value of over-lifting is measured at production expenses. Over-lifting and under-lifting of hydrocarbons are presented at gross value. Over/under-lift positions at the statement of financial position date are expected to be settled within 12 months from the statement of the financial position date . 1.14 Share capital, Treasury share reserves and share premium Ordinary shares are classified as equity. Costs directly attributable to the issue of new shares or option shares are recognised as a deduction from equity, net of any tax effects. Treasury share reserves are recognised as a deduction on equity at nominal value, the difference between nominal value and purchase price is deducted from other equity. 1.15 Trade payables Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Trade payables are classified as current liabilities if payment is due within one year or less (or in the normal operating cycle of the business if longer). If not, they are presented as non-current liabilities. Trade payables are measured at fair value and subsequent measurements are considered trade payables at amortised cost when using effective interest rate. 1.16 Borrowings Borrowings (financial liabilities) are classified as measured at amortised cost. Borrowings that are subsequently measured at amortised cost using the effective interest method are recognised initially at fair value, net of transaction costs incurred. For hybrid (combined) instrument that includes a non-derivative host contract that is not accounted for at FVTPL and an embedded derivative that is accounted for at FVTPL such as the convertible bond, the Company has elected an accounting polity that all of the transaction costs are always allocated to and deducted from the carrying amount of the non-derivative host contract on initial recognition. The subsequent measurement depends on which category they have been classified into. The categories applicable for the Company are either financial liabilities measured at fair value through OCI or financial liabilities measured at amortised cost using the effective interest method. The convertible bond loan has been determined to contain embedded derivatives, which is accounted for separately as a derivative at fair value through profit or loss, while the loan element is measured at amortised cost (note 3.1). Borrowings are classified as non-current if contractual maturity is more than 12 months from the statement of financial position date. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the end of the reporting period. If the Group is in breach with any covenants on the statement of financial position date, and a waiver has not been approved before or on the statement of financial position date with 12 months duration or more after the statement of financial position date, the loan is classified as current even if expected maturity is longer than 12 months after the statement of financial position date. Fees paid on the establishment of loan facilities are recognised as transaction costs of the loan to the extent that it is probable that some or all of the facility will be drawn down. In this case, the fee is deferred until the drawdown occurs. To the extent there is no evidence that it is probable that some or all of the facility will be drawn down, the fee is capitalised as a prepayment for liquidity services and amortised over the period of the facility to which it relates. A financial liability is derecognised when the obligation under the liability is discharged or cancelled, or when the contractual obligation expires. When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, the exchange or modification is treated as the derecognition of the original liability and the recognition of a new liability. The difference in the respective carrying amounts is recognised in the statement of comprehensive income as a gain or loss under financial items. Transaction costs incurred during this process are treated as a cost of the settlement of the old debt and included in the gain or loss calculation. 1.17 Borrowing costs General and specific borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale. Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation. All other borrowing costs are recognised in profit or loss in the period in which they are incurred. 1.18 Current and deferred income tax The tax expense for the period comprises current tax, tax impact from refund of exploration expenses and deferred tax. Tax is recognised in the income statement, except to the extent that it relates to items recognised in OCI or directly in equity. In this case, the tax is also recognised in OCI or directly in equity, respectively. The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the statement of financial position date in the countries where the Company and its subsidiaries operate and generate taxable income. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. It establishes provisions where appropriate on the basis of amounts expected to be paid to the tax authorities. Deferred income tax is recognised on temporary differences arising between the tax bases of assets, and liabilities and their carrying amounts in the consolidated financial statements. However, deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill; deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred income tax is determined using nominal tax rates (and laws) that have been enacted or substantively enacted by the statement of financial position date and are expected to apply when the related deferred income tax asset is realised, or the deferred income tax liability is settled. Deferred tax assets are recognised only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilised. Deferred income tax assets are recognised on deductible temporary differences arising from investments in subsidiaries, associates and joint arrangements only to the extent that it is probable that the temporary difference will reverse in the future and there is sufficient taxable profit available against which the temporary difference can be utilised. Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when the deferred income tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis. Producers of oil and gas on the Danish continental shelf are subject to the hydrocarbon tax regime under which income derived from the sale of oil and gas is taxed at an elevated 64 percent. Any income deriving from other activities than first-time sales of hydrocarbons is taxed at the ordinary corporate income rate of currently 22 percent. The 64 percent is calculated as the sum of the (chapter 2) tax of 25 percent plus a specific hydrocarbon tax (chapter 3a) of 52 percent, in which the 25 percent tax payable is deductible. When calculating the 52 percent tax, the Company is allowed to deduct an uplift (i.e. increased depreciation basis for tax purposes) of 30 percent of the investments in property, plant and equipment (PP&E) over a period of six years. Through an agreement from 2017, licence holders on the Danish continental shelf have had the possibility of applying new rules whereby the Company will have the possibility of increased uplift and accelerated depreciation during the period from 2017 to 2025. At the same time, the companies utilising the benefit are also liable for a repayment of the tax benefits previously received, this will materialise from 2022 through 2037 with an oil price (indexed from 2017) above USD 75. The repayment cannot exceed the indexed benefit from the applied rules. 1.19 Pensions The Group only has defined contribution plans as of 31 December 2022. For the defined contribution plan, the Group pays contributions to publicly or privately administered pension insurance plans on a mandatory, contractual or voluntary basis. The Group has no legal or constructive obligations to pay further contributions if the fund does not hold sufficient assets to pay all employees the benefits relating to employee service in the current and prior periods. The contributions are recognised as employee benefit expense when they are due. Prepaid contributions are recognised as an asset to the extent that a cash refund or a reduction in the future payments is available. 1.20 Share-based payments The Group operates a number of equity-settled, share-based compensation plans, under which the entity receives services from employees as consideration for equity instruments (options) of the Group. The fair value of the employee services received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed is determined by reference to the fair value of the options or shares granted: Fair value: \u2022 Including any market performance conditions. \u2022 Excludes the impact of any service and non-market performance vesting conditions (for example, profitability, sales growth targets and remaining an employee of the entity over a specified time period). Non-market performance and service conditions are included in assumptions about the number of options or shares that are expected to vest. The total expense is recognised over the vesting period (which is the period over which all of the specified vesting conditions are to be satisfied). At the end of each reporting period, the Group revises its estimates of the number of options that are expected to vest based on the non-market vesting conditions. It recognises the impact of the revision to original estimates, if any, in the income statement, with a corresponding adjustment to equity. When the options are exercised, the Company issues new shares. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium. The social security contributions payable in connection with the grant of the share options is considered an integral part of the grant itself, and the charge will be treated as a cash-settled transaction. 1.21 Provisions Provisions are recognised when the Company has a present obligation (legal or constructive) arising from a past event, and it is probable (more likely than not) that it will result in an outflow from the entity of resources embodying economic benefits, and that a reliable estimate can be made of the amount of the obligation. Restructuring provisions comprise lease termination penalties and employee termination payments. Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to passage of time is recognised as interest expense. 1.21.1 Asset retirement obligations Provisions reflect the estimated cost of decommissioning and removal of wells and production facilities used for the production of hydrocarbons. Asset retirement obligations are measured at net present value of the anticipated future cost (estimated based on current day costs inflated). The liability is calculated on the basis of current removal requirements and is discounted to present value using a risk-free rate adjusted for credit margin. Liabilities are recognised when they arise and are adjusted continually in accordance with changes in requirements, price levels etc. When a decommissioning liability is recognised or the estimate changes, a corresponding amount is recorded to increase or decrease the related asset and is depreciated in line with the asset. Increase in the provision as a result of the time value of money is recognised in the income statement as a financial expense. If abandonment cost through agreements with partners have been limited to a given amount, this then forms the basis for the recognised liability. 1.22 Contingent liabilities and assets Contingent liabilities are defined as: \u2022 Possible obligations that arise from past events, whose existence depends on uncertain future events. \u2022 Present obligations which have not been recognised because it is not probable that they will result in a payment. \u2022 The amount of the obligation cannot be measured with sufficient reliability. Specific mention of material contingent liabilities is disclosed, with the exception of contingent liabilities where the possibility of an outflow of resources embodying economic benefits is remote. Contingent assets are not recognised in the financial statements but are disclosed if there is a certain probability that a benefit will accrue to the Group. 1.23 Revenue recognition Revenue is recognised when the customer obtains control of the hydrocarbons, which is ordinarily at the point of delivery (lifting and sales) when title passes (sales method). Over/under-lifting occurs when the Group has lifted and sold more or less hydrocarbons from a producing field than what the Group is entitled to at the time of lifting. See note 1.13 for a description of accounting for over/under-lifting of hydrocarbons in the statement of financial position. 1.24 Production expenses Production expenses are expenses that are directly attached to production of hydrocarbons, e.g. expenses for operating and maintaining production facilities and installations. Expenses mainly consist of man-hours, insurance, processing costs, environmental fees, transport costs etc. 1.25 Interest income Interest income is recognised using the effective interest method. 1.26 Consolidated statement of cash flows The consolidated statement of cash flows is prepared according to the indirect method. See note 1.12 for the definition of \u201ccash and cash equivalents\u201d. ", "dimensions": { "concept": "ifrs-full:DisclosureOfSummaryOfSignificantAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-364": { "value": "Norwegian Energy Company ASA (BlueNord, \u201cthe Company\u201d or \u201cthe Group\u201d) is a public limited liability company registered in Norway, with headquarters in Oslo (Nedre Vollgate 1, 0158 Oslo). The Company has subsidiaries in Norway, Denmark, the Netherlands and the United Kingdom. The Company is listed on the Oslo Stock Exchange. The consolidated financial statements for 2022 were approved by the Board of Directors on 28 March 2023. The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated. The Group also provides the disclosure requirements as specified under the Norwegian Accounting Law (Regnskapsloven). ", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-1": { "value": "Norwegian Energy Company ASA", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-2": { "value": "public limited liability company ", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-419": { "value": "The consolidated financial statements for 2022 were approved by the Board of Directors on 28 March 2023", "dimensions": { "concept": "ifrs-full:DisclosureOfAuthorisationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-366": { "value": "1.1 Basis of preparation The consolidated financial statements of Norwegian Energy Company ASA (BlueNord) have been prepared in accordance with the IFRS and interpretations from the IFRIC, as endorsed by the EU. The Group also provides information required in accordance with the Norwegian Accounting Act and associated NGAAP standards. The preparation of financial statements in accordance with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group\u2019s accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in note 3. In accordance with the Norwegian Accounting Act, section 3-3a, the Board of Directors confirms that the consolidated financial statements have been prepared under the assumption of going concern and that this is the basis for the preparation of the financial statements. The financial solidity and the Company\u2019s working capital and cash position are considered satisfactory in regards of the planned activity level for the next 12 months. The Board of Directors is of the opinion that the consolidated financial statements give a true and fair view of the Company\u2019s assets, debt, financial position and financial results. The Board of Directors are not aware of any factors that materially affect the assessment of the Company\u2019s position as of 31 December 2022, besides what is disclosed in the Director\u2019s Report and the financial statements. The subtotals and totals in some of the tables may not equal the sum of the amounts shown due to rounding. ", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-420": { "value": "The consolidated financial statements of Norwegian Energy Company ASA (BlueNord) have been prepared in accordance with the IFRS and interpretations from the IFRIC, as endorsed by the EU. The Group also provides information required in accordance with the Norwegian Accounting Act and associated NGAAP standards. ", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-367": { "value": "1.1.1 Changes in accounting policies and disclosures No change in 2022. Amendments to standards Amendments to standards, issued are either not expected to impact Norwegian Energy Company ASA (BlueNord)\u2019s consolidated financial statements materially, or are not expected to be relevant to the consolidated financial statements upon adoption ", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-365": { "value": "1.2 Consolidation Subsidiaries Subsidiaries are all entities over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are de-consolidated from the date that control ceases. As of 31 December 2022, all consolidated subsidiaries are 100 percent controlled by the parent company, Norwegian Energy Company ASA (BlueNord) or other Group companies. The proportion of the voting rights in the subsidiary undertakings held directly by the parent company does not differ from the proportion of ordinary shares held. The parent company does not have any shareholdings in the preference shares of subsidiary undertakings included in the group. All subsidiary undertakings are included in the consolidation. The Group had the following subsidiaries on 31 December 2022: Name Country of incorporation and place of business Nature of business Ordinary shares directly held by parent (%) Ordinary shares held by the Group (%) Noreco Denmark A/S Denmark Intermediate holding company 100% Noreco Oil Denmark A/S Denmark Exploration and production activity 100% Noreco Petroleum Denmark A/S Denmark Exploration and production activity 100% Noreco Olie-og Gasudvinding Danmark B.V. Netherlands Exploration and production activity 100% Noreco DK Pipeline ApS Denmark Infrastructure oil and gas 100% Norwegian Energy Company UK Ltd Great Britain Exploration activity 100% 100% Noreco Oil (UK) Ltd Great Britain Exploration activity 100% Altinex AS Norway Intermediate holding company 100% 100% Djerv Energi AS Norway Dormant Company 100% 100% The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair values of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Acquisition-related costs are expensed as incurred, except if related to the issue of debt not at fair value through profit and loss (FVTPL) or equity securities. If the business combination is achieved in stages, the acquisition date carrying value of the acquirer\u2019s previously held equity interest in the acquiree is re - measured to fair value at the acquisition date; any gains or losses arising from such re-measurement are recognised in profit or loss. Any contingent consideration to be transferred or received by the Group is recognised at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration that is deemed to be an asset or liability is recognised in profit or loss. Contingent consideration that is classified as equity is not re-measured, and its subsequent settlement is accounted for within equity. Intercompany transactions, balances, income and unrealised gains on transactions between Group companies are eliminated. Unrealised losses are also eliminated. When necessary, amounts reported by subsidiaries have been adjusted to conform with the Group\u2019s accounting policies. Interest in jointly controlled assets A jointly controlled asset is a contractual agreement between two or more parties regarding a financial activity under joint control. The Group has ownership in licences that are not separate legal companies. The Company recognises its share of the assets, liabilities, revenues and expenses of the joint operation in the respective line items in the Company\u2019s financial statements based on its ownership share. ", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-421": { "value": "Subsidiaries Subsidiaries are all entities over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are de-consolidated from the date that control ceases. As of 31 December 2022, all consolidated subsidiaries are 100 percent controlled by the parent company, Norwegian Energy Company ASA (BlueNord) or other Group companies. The proportion of the voting rights in the subsidiary undertakings held directly by the parent company does not differ from the proportion of ordinary shares held. The parent company does not have any shareholdings in the preference shares of subsidiary undertakings included in the group. All subsidiary undertakings are included in the consolidation.
The Group had the following subsidiaries on 31 December 2022:
Name
Country of
incorporation and
place of business Nature of business
Ordinary shares
directly held
by parent (%)
Ordinary shares
held by the
Group (%)
Noreco Denmark A/S Denmark Intermediate holding company 100%
Noreco Oil Denmark A/S Denmark Exploration and production activity 100%
Noreco Petroleum Denmark A/S Denmark Exploration and production activity 100%
Noreco Olie-og Gasudvinding Danmark B.V. Netherlands Exploration and production activity 100%
Noreco DK Pipeline ApS Denmark Infrastructure oil and gas 100%
Norwegian Energy Company UK Ltd Great Britain Exploration activity 100% 100%
Noreco Oil (UK) Ltd Great Britain Exploration activity 100%
Altinex AS Norway Intermediate holding company 100% 100%
Djerv Energi AS Norway Dormant Company 100% 100%
The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a
subsidiary is the fair values of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued
by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration
arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially
at their fair values at the acquisition date.
Acquisition-related costs are expensed as incurred, except if related to the issue of debt not at fair value through profit and loss (FVTPL) or
equity securities. If the business combination is achieved in stages, the acquisition date carrying value of the acquirer\u2019s previously held equity
interest in the acquiree is re - measured to fair value at the acquisition date; any gains or losses arising from such re-measurement are
recognised in profit or loss.
Any contingent consideration to be transferred or received by the Group is recognised at fair value at the acquisition date. Subsequent changes
to the fair value of the contingent consideration that is deemed to be an asset or liability is recognised in profit or loss. Contingent consideration
that is classified as equity is not re-measured, and its subsequent settlement is accounted for within equity. Intercompany transactions,
balances, income and unrealised gains on transactions between Group companies are eliminated. Unrealised losses are also eliminated. When
necessary, amounts reported by subsidiaries have been adjusted to conform with the Group\u2019s accounting policies.
Interest in jointly controlled assets
A jointly controlled asset is a contractual agreement between two or more parties regarding a financial activity under joint control. The Group
has ownership in licences that are not separate legal companies. The Company recognises its share of the assets, liabilities, revenues and
expenses of the joint operation in the respective line items in the Company\u2019s financial statements based on its ownership share.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSubsidiariesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-369": { "value": "
1.3 Segment reporting
The Group\u2019s segments were established on the basis of the most appropriate distribution of resource and result measurement. Operating
segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating
decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the
Chief Executive Officer. The whole Group is considered a single operating segment.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSegmentReportingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-368": { "value": "
1.4 Foreign currency translation
a) Functional and presentation currency
Items included in the financial statements of each of the Group\u2019s entities are measured using the currency of the primary economic environment
in which the entity operates (\u201cthe functional currency\u201d). The consolidated financial statements are presented in US dollars (USD), which is the
Group\u2019s presentation currency and the parent company and main operating companies functional currency.
b) Transactions and balances
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions or
valuation where items are re-measured. Foreign exchange gains and losses are recognised in the income statement as other financial income
or other financial expenses.
c) Group companies The results and financial position of all the group entities (none of which has the currency of a hyper-inflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows: i) assets and liabilities for each financial position presented are translated at the closing rate at the date of that statement of financial position; ii) income and expenses for each income statement are translated at the average monthly exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the rate on the dates of the transactions); and iii) all currency translation adjustments are recognised in other comprehensive income (OCI). Goodwill and fair value adjustments arising on the acquisition of a foreign entity are treated as assets and liabilities of the foreign entity and translated at the closing rate. Currency translation adjustments arising are recognised in other comprehensive income. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-422": { "value": "a) Functional and presentation currency Items included in the financial statements of each of the Group\u2019s entities are measured using the currency of the primary economic environment in which the entity operates (\u201cthe functional currency\u201d). The consolidated financial statements are presented in US dollars (USD), which is the Group\u2019s presentation currency and the parent company and main operating companies functional currency. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-462": { "value": "1.5 Property, plant and equipment Property, plant and equipment include production facilities, machinery and equipment. Items of property, plant and equipment are measured at cost, less accumulated depreciation and accumulated impairment losses. Cost includes purchase price or construction cost and any costs directly attributable to bringing the assets to a working condition for their intended use, including capitalised borrowing expenses incurred up until the time the asset is ready to be put into operation. For property, plant and equipment where asset retirement obligations for decommissioning and dismantling are recognised as a liability, this value is added to acquisition cost for the respective assets. Borrowing costs that are not directly attributable to the acquisition, construction or production of a qualifying asset are recognised in the income statement using the effective interest method. When parts of an item of property, plant and equipment have different useful lives, they are accounted for as separate items (major components) of property, plant and equipment, and depreciated separately. Subsequent costs are included in the asset\u2019s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. The carrying amount of the replaced part is derecognised. All other repairs and maintenance are charged to the income statement during the financial period in which they are incurred. Expenses related to drilling and equipment for exploration wells where proven and probable reserves are discovered are capitalised and depreciated using the unit-of-production (UoP) method based on the proven and probable reserves expected to be produced from the well. Development cost related to construction, installation and completion of infrastructural facilities, such as platforms, pipelines and drilling of production wells, are capitalised as producing oil and gas fields. They are depreciated using the unit-of-production method based on the proven and probable developed reserves expected to be recovered from the area for the economic lifetime of the field. For fields where the oil share of the reserves constitutes the most significant part of the value, the capitalised cost is depreciated based on produced barrels of oil. This generally gives a more systematic allocation of depreciation expenses over the useful life than using all produced oil equivalents. If realisation of the probable reserves demands further future investments, these are added to the basis of depreciation. Acquired assets used for extraction and production of petroleum deposits, including licence rights, are depreciated using the UoP method based on proven and probable reserves. Historical cost price for other assets is depreciated over the estimated useful economic life of the asset, using the straight-line method. The estimated useful lives are as follows: \u2022 Office equipment and fixtures: three to five years Depreciation methods, useful lives, residual values and reserves are reviewed at each reporting date and adjusted if appropriate. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForExplorationAndEvaluationExpenditures", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-450": { "value": "1.5 Property, plant and equipment Property, plant and equipment include production facilities, machinery and equipment. Items of property, plant and equipment are measured at cost, less accumulated depreciation and accumulated impairment losses. Cost includes purchase price or construction cost and any costs directly attributable to bringing the assets to a working condition for their intended use, including capitalised borrowing expenses incurred up until the time the asset is ready to be put into operation. For property, plant and equipment where asset retirement obligations for decommissioning and dismantling are recognised as a liability, this value is added to acquisition cost for the respective assets. Borrowing costs that are not directly attributable to the acquisition, construction or production of a qualifying asset are recognised in the income statement using the effective interest method. When parts of an item of property, plant and equipment have different useful lives, they are accounted for as separate items (major components) of property, plant and equipment, and depreciated separately. Subsequent costs are included in the asset\u2019s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. The carrying amount of the replaced part is derecognised. All other repairs and maintenance are charged to the income statement during the financial period in which they are incurred. Expenses related to drilling and equipment for exploration wells where proven and probable reserves are discovered are capitalised and depreciated using the unit-of-production (UoP) method based on the proven and probable reserves expected to be produced from the well. Development cost related to construction, installation and completion of infrastructural facilities, such as platforms, pipelines and drilling of production wells, are capitalised as producing oil and gas fields. They are depreciated using the unit-of-production method based on the proven and probable developed reserves expected to be recovered from the area for the economic lifetime of the field. For fields where the oil share of the reserves constitutes the most significant part of the value, the capitalised cost is depreciated based on produced barrels of oil. This generally gives a more systematic allocation of depreciation expenses over the useful life than using all produced oil equivalents. If realisation of the probable reserves demands further future investments, these are added to the basis of depreciation. Acquired assets used for extraction and production of petroleum deposits, including licence rights, are depreciated using the UoP method based on proven and probable reserves. Historical cost price for other assets is depreciated over the estimated useful economic life of the asset, using the straight-line method. The estimated useful lives are as follows: \u2022 Office equipment and fixtures: three to five years Depreciation methods, useful lives, residual values and reserves are reviewed at each reporting date and adjusted if appropriate. 1.6 Intangible assets Oil and gas exploration and development expenditures The Group applies the successful efforts method of accounting for oil and gas exploration expenditures. Expenditures to acquire interests in oil and gas properties and to drill and equip exploratory wells are capitalised as exploration expenditures within intangible assets until the well is complete and the results have been evaluated, or there is any other indicator of a potential impairment. Exploration wells that discover potentially economic quantities of oil and natural gas remain capitalised as intangible assets during the evaluation phase of the discovery. This evaluation is normally finalised within one year. If, following the evaluation, the exploratory well has not found potentially commercial quantities of hydrocarbons, the capitalised expenditures are evaluated for derecognition or tested for impairment. Geological and geophysical expenditures and other exploration and evaluation expenditures are expensed as incurred. Capitalised exploration expenditures, including expenditures to acquire interests in oil and gas properties, related to wells that find proved reserves are transferred from exploration expenditures (intangible assets) to property, plant and equipment at the time of sanctioning of the development project. Other intangible assets Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets with definite lives are carried at cost less any accumulated amortisation and accumulated impairment losses, if any. Internally generated intangible assets, excluding capitalised development costs, are not capitalised. Instead, the related expenditure is recognised in profit or loss in the period in which the expenditure is incurred. Intangible assets are amortised over the useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortisation period and the amortisation method for an intangible asset is reviewed at least at the end of each reporting period. Changes in the expected useful life or the expected pattern of consumption of future economic benefits embodied in the asset are considered to modify the amortisation period or method, as appropriate, and are treated as changes in accounting estimates. The amortisation expense on intangible assets is recognised in the Consolidated Statement of Comprehensive income in the line-item depreciation and amortisation. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-423": { "value": "1.5 Property, plant and equipment Property, plant and equipment include production facilities, machinery and equipment. Items of property, plant and equipment are measured at cost, less accumulated depreciation and accumulated impairment losses. Cost includes purchase price or construction cost and any costs directly attributable to bringing the assets to a working condition for their intended use, including capitalised borrowing expenses incurred up until the time the asset is ready to be put into operation. For property, plant and equipment where asset retirement obligations for decommissioning and dismantling are recognised as a liability, this value is added to acquisition cost for the respective assets. Borrowing costs that are not directly attributable to the acquisition, construction or production of a qualifying asset are recognised in the income statement using the effective interest method. When parts of an item of property, plant and equipment have different useful lives, they are accounted for as separate items (major components) of property, plant and equipment, and depreciated separately. Subsequent costs are included in the asset\u2019s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. The carrying amount of the replaced part is derecognised. All other repairs and maintenance are charged to the income statement during the financial period in which they are incurred. Expenses related to drilling and equipment for exploration wells where proven and probable reserves are discovered are capitalised and depreciated using the unit-of-production (UoP) method based on the proven and probable reserves expected to be produced from the well. Development cost related to construction, installation and completion of infrastructural facilities, such as platforms, pipelines and drilling of production wells, are capitalised as producing oil and gas fields. They are depreciated using the unit-of-production method based on the proven and probable developed reserves expected to be recovered from the area for the economic lifetime of the field. For fields where the oil share of the reserves constitutes the most significant part of the value, the capitalised cost is depreciated based on produced barrels of oil. This generally gives a more systematic allocation of depreciation expenses over the useful life than using all produced oil equivalents. If realisation of the probable reserves demands further future investments, these are added to the basis of depreciation. Acquired assets used for extraction and production of petroleum deposits, including licence rights, are depreciated using the UoP method based on proven and probable reserves. Historical cost price for other assets is depreciated over the estimated useful economic life of the asset, using the straight-line method. The estimated useful lives are as follows: \u2022 Office equipment and fixtures: three to five years Depreciation methods, useful lives, residual values and reserves are reviewed at each reporting date and adjusted if appropriate. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRepairsAndMaintenanceExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-370": { "value": "1.5 Property, plant and equipment Property, plant and equipment include production facilities, machinery and equipment. Items of property, plant and equipment are measured at cost, less accumulated depreciation and accumulated impairment losses. Cost includes purchase price or construction cost and any costs directly attributable to bringing the assets to a working condition for their intended use, including capitalised borrowing expenses incurred up until the time the asset is ready to be put into operation. For property, plant and equipment where asset retirement obligations for decommissioning and dismantling are recognised as a liability, this value is added to acquisition cost for the respective assets. Borrowing costs that are not directly attributable to the acquisition, construction or production of a qualifying asset are recognised in the income statement using the effective interest method. When parts of an item of property, plant and equipment have different useful lives, they are accounted for as separate items (major components) of property, plant and equipment, and depreciated separately. Subsequent costs are included in the asset\u2019s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. The carrying amount of the replaced part is derecognised. All other repairs and maintenance are charged to the income statement during the financial period in which they are incurred. Expenses related to drilling and equipment for exploration wells where proven and probable reserves are discovered are capitalised and depreciated using the unit-of-production (UoP) method based on the proven and probable reserves expected to be produced from the well. Development cost related to construction, installation and completion of infrastructural facilities, such as platforms, pipelines and drilling of production wells, are capitalised as producing oil and gas fields. They are depreciated using the unit-of-production method based on the proven and probable developed reserves expected to be recovered from the area for the economic lifetime of the field. For fields where the oil share of the reserves constitutes the most significant part of the value, the capitalised cost is depreciated based on produced barrels of oil. This generally gives a more systematic allocation of depreciation expenses over the useful life than using all produced oil equivalents. If realisation of the probable reserves demands further future investments, these are added to the basis of depreciation. Acquired assets used for extraction and production of petroleum deposits, including licence rights, are depreciated using the UoP method based on proven and probable reserves. Historical cost price for other assets is depreciated over the estimated useful economic life of the asset, using the straight-line method. The estimated useful lives are as follows: \u2022 Office equipment and fixtures: three to five years Depreciation methods, useful lives, residual values and reserves are reviewed at each reporting date and adjusted if appropriate. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-424": { "value": "1.6 Intangible assets Oil and gas exploration and development expenditures The Group applies the successful efforts method of accounting for oil and gas exploration expenditures. Expenditures to acquire interests in oil and gas properties and to drill and equip exploratory wells are capitalised as exploration expenditures within intangible assets until the well is complete and the results have been evaluated, or there is any other indicator of a potential impairment. Exploration wells that discover potentially economic quantities of oil and natural gas remain capitalised as intangible assets during the evaluation phase of the discovery. This evaluation is normally finalised within one year. If, following the evaluation, the exploratory well has not found potentially commercial quantities of hydrocarbons, the capitalised expenditures are evaluated for derecognition or tested for impairment. Geological and geophysical expenditures and other exploration and evaluation expenditures are expensed as incurred. Capitalised exploration expenditures, including expenditures to acquire interests in oil and gas properties, related to wells that find proved reserves are transferred from exploration expenditures (intangible assets) to property, plant and equipment at the time of sanctioning of the development project. Other intangible assets Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets with definite lives are carried at cost less any accumulated amortisation and accumulated impairment losses, if any. Internally generated intangible assets, excluding capitalised development costs, are not capitalised. Instead, the related expenditure is recognised in profit or loss in the period in which the expenditure is incurred. Intangible assets are amortised over the useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortisation period and the amortisation method for an intangible asset is reviewed at least at the end of each reporting period. Changes in the expected useful life or the expected pattern of consumption of future economic benefits embodied in the asset are considered to modify the amortisation period or method, as appropriate, and are treated as changes in accounting estimates. The amortisation expense on intangible assets is recognised in the Consolidated Statement of Comprehensive income in the line-item depreciation and amortisation. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsOtherThanGoodwillExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-425": { "value": "1.7 Impairment of non-financial assets a) Unit of account The Group applies each prospect, discovery, or field as unit of account for allocation of profit or loss and financial position items. When performing impairment testing of licence and capitalised exploration expenditures and production facilities, each prospect, discovery, or field is tested separately as long as they are not defined to be part of a larger cash generating unit. Developed fields producing from the same offshore installation are treated as one joint cash generating unit. The size of a cash generating unit cannot be larger than an operational segment. b) Impairment testing Intangible assets with an indefinite useful life are not subject to amortisation and are tested annually for impairment. For oil and gas exploration and development expenditures, see note 1.6 above regarding assessment of impairment and derecognition. Property, plant and equipment subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset\u2019s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset\u2019s fair value less costs of disposal and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash generating units). Non-financial assets other than goodwill that suffered impairment write-downs are assessed for potential impairment reversal at each reporting date as to whether there is an indication that an impairment loss may no longer exist or may have decreased. 1.9 Impairment of financial assets The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments (financial assets) not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Group expects to receive, discounted at an approximation of the original effective interest rate. The expected cash flows will include cash flows from the sale of collateral held or other credit enhancements that are integral to the contractual terms. The Group applies a simplified approach in calculating ECLs for trade receivables and contract assets. Therefore, the Group does not track changes in credit risk, but instead recognises a loss allowance based on lifetime ECLs at each reporting date. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-371": { "value": "1.7 Impairment of non-financial assets a) Unit of account The Group applies each prospect, discovery, or field as unit of account for allocation of profit or loss and financial position items. When performing impairment testing of licence and capitalised exploration expenditures and production facilities, each prospect, discovery, or field is tested separately as long as they are not defined to be part of a larger cash generating unit. Developed fields producing from the same offshore installation are treated as one joint cash generating unit. The size of a cash generating unit cannot be larger than an operational segment. b) Impairment testing Intangible assets with an indefinite useful life are not subject to amortisation and are tested annually for impairment. For oil and gas exploration and development expenditures, see note 1.6 above regarding assessment of impairment and derecognition. Property, plant and equipment subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset\u2019s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset\u2019s fair value less costs of disposal and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash generating units). Non-financial assets other than goodwill that suffered impairment write-downs are assessed for potential impairment reversal at each reporting date as to whether there is an indication that an impairment loss may no longer exist or may have decreased. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfNonfinancialAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-463": { "value": "1.8 Financial assets 1.8.1 Classification The Group classifies financial assets and financial liabilities according to IFRS 9 through the mixed measurement model with three primary measurement categories for financial assets: amortised cost, fair value through OCI and fair value through profit and loss (P&L). The classification depends on the entity\u2019s business model and the contractual cash flow characteristics of the financial assets. Management determines the classification of its financial assets at initial recognition. a) Financial assets and liabilities at fair value through profit or loss Financial assets at fair value through profit or loss are financial assets held for trading that are not measured at amortised cost or at fair value through OCI. IFRS 9 requires that for a financial liability designated as at fair value through profit or loss the effects of changes in the liability\u2019s credit risk shall be included in OCI instead of through profit and loss. Derivatives, including embedded derivatives, are also recognised at fair value through profit or loss unless they are designated as hedges. Assets in this category are classified as current assets if expected to be settled within 12 months, otherwise they are classified as non-current. b) Financial assets and liabilities at amortised cost The Group measures financial assets at amortised cost if both of the following conditions are met: \u2022 the financial asset is held within a business model with the objective to hold financial assets in order to collect contractual cash flows; and \u2022 the contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding. Financial assets at amortised cost are subsequently measured using the effective interest (EIR) method and are subject to impairment testing. Gains and losses are recognised in profit or loss when the asset is derecognised, modified or impaired. These assets are included in current assets, except for maturities greater than 12 months after the end of the reporting period. These are classified as non-current assets. The Group\u2019s financial assets categorised as at amortised cost comprise trade and other receivables, contract assets, restricted cash and cash and cash equivalents in the statement of financial position (notes 1.11 and 1.12). The Group measures interest-bearing loans and borrowings (financial liabilities) at amortised cost using the effective interest method. 1.8.2 Recognition and measurement Regular purchases and sales of financial assets are recognised on the trade-date \u2013 the date on which the Group commits to purchase or sell the asset. Investments are initially recognised at fair value plus transaction costs for all financial assets not carried at fair value through profit or loss. Financial assets carried at fair value through profit or loss, are initially recognised at fair value, and transaction costs are expensed in the income statement. Financial assets are derecognised when the rights to receive cash flows from the investments have expired or have been transferred and the Group has transferred substantially all risks and rewards of ownership. Financial assets at fair value through profit or loss are subsequently carried at fair value. Trade and other receivables are subsequently carried at amortised cost using the effective interest method. Gains or losses arising from changes in the fair value of the \u201cfinancial assets at fair value through profit or loss\u201d category is presented in the income statement within \u2018Financial items\u2019 in the period in which they arise. 1.9 Impairment of financial assets The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments (financial assets) not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Group expects to receive, discounted at an approximation of the original effective interest rate. The expected cash flows will include cash flows from the sale of collateral held or other credit enhancements that are integral to the contractual terms. The Group applies a simplified approach in calculating ECLs for trade receivables and contract assets. Therefore, the Group does not track changes in credit risk, but instead recognises a loss allowance based on lifetime ECLs at each reporting date. 1.10 Derivative financial instruments and hedging activities Derivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re-measured at their fair value. The method of recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument, and if so, the nature of the item being hedged. The Group uses derivative financial instruments, such as forward commodity contracts and options, to reduce the exposure to commodity price volatility. The Group has elected to apply cash flow hedge accounting designating these derivatives. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and from the date of start of cash flow hedge accounting. These are subsequently re-measured at fair value and the effective portion of the gain or loss on the hedging instrument is recognised in OCI, while any ineffective portion is recognised immediately in profit or loss (financial income or financial expenses). The cash flow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item. The amount accumulated in OCI is reclassified to profit or loss as a reclassification adjustment in the same periods during which the hedged cash flows affect profit or loss. If cash flow hedge accounting is discontinued, the amount that has been accumulated in OCI must remain in accumulated OCI if the hedged future cash flows are still expected to occur. Otherwise, the amount will be immediately reclassified to profit or loss as a reclassification adjustment. Derivatives are carried as financial assets when the fair value is positive and as financial liabilities when the fair value is negative. Commodity contracts that were entered into and continue to be held for the purpose of the delivery of a non-financial item in accordance with the Group\u2019s expected sale requirements fall within the exception from IFRS 9, which is known as the \u201cnormal purchase or sale exemption\u201d or the \u201cown use\u201d scope exception. For these contracts and the host part of the contracts containing embedded derivatives, they are accounted for as executory contracts. The Group recognises such contracts in its statement of financial position only when one of the parties meets its obligation under the contract to deliver either cash or a non-financial asset. The volume hedging agreement with Shell ended on 31 December 2020 and is not relevant in 2022. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-372": { "value": "1.8 Financial assets 1.8.1 Classification The Group classifies financial assets and financial liabilities according to IFRS 9 through the mixed measurement model with three primary measurement categories for financial assets: amortised cost, fair value through OCI and fair value through profit and loss (P&L). The classification depends on the entity\u2019s business model and the contractual cash flow characteristics of the financial assets. Management determines the classification of its financial assets at initial recognition. a) Financial assets and liabilities at fair value through profit or loss Financial assets at fair value through profit or loss are financial assets held for trading that are not measured at amortised cost or at fair value through OCI. IFRS 9 requires that for a financial liability designated as at fair value through profit or loss the effects of changes in the liability\u2019s credit risk shall be included in OCI instead of through profit and loss. Derivatives, including embedded derivatives, are also recognised at fair value through profit or loss unless they are designated as hedges. Assets in this category are classified as current assets if expected to be settled within 12 months, otherwise they are classified as non-current. b) Financial assets and liabilities at amortised cost The Group measures financial assets at amortised cost if both of the following conditions are met: \u2022 the financial asset is held within a business model with the objective to hold financial assets in order to collect contractual cash flows; and \u2022 the contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding. Financial assets at amortised cost are subsequently measured using the effective interest (EIR) method and are subject to impairment testing. Gains and losses are recognised in profit or loss when the asset is derecognised, modified or impaired. These assets are included in current assets, except for maturities greater than 12 months after the end of the reporting period. These are classified as non-current assets. The Group\u2019s financial assets categorised as at amortised cost comprise trade and other receivables, contract assets, restricted cash and cash and cash equivalents in the statement of financial position (notes 1.11 and 1.12). The Group measures interest-bearing loans and borrowings (financial liabilities) at amortised cost using the effective interest method. 1.8.2 Recognition and measurement Regular purchases and sales of financial assets are recognised on the trade-date \u2013 the date on which the Group commits to purchase or sell the asset. Investments are initially recognised at fair value plus transaction costs for all financial assets not carried at fair value through profit or loss. Financial assets carried at fair value through profit or loss, are initially recognised at fair value, and transaction costs are expensed in the income statement. Financial assets are derecognised when the rights to receive cash flows from the investments have expired or have been transferred and the Group has transferred substantially all risks and rewards of ownership. Financial assets at fair value through profit or loss are subsequently carried at fair value. Trade and other receivables are subsequently carried at amortised cost using the effective interest method. Gains or losses arising from changes in the fair value of the \u201cfinancial assets at fair value through profit or loss\u201d category is presented in the income statement within \u2018Financial items\u2019 in the period in which they arise. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-426": { "value": "a) Financial assets and liabilities at fair value through profit or loss Financial assets at fair value through profit or loss are financial assets held for trading that are not measured at amortised cost or at fair value through OCI. IFRS 9 requires that for a financial liability designated as at fair value through profit or loss the effects of changes in the liability\u2019s credit risk shall be included in OCI instead of through profit and loss. Derivatives, including embedded derivatives, are also recognised at fair value through profit or loss unless they are designated as hedges. Assets in this category are classified as current assets if expected to be settled within 12 months, otherwise they are classified as non-current. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-373": { "value": "1.9 Impairment of financial assets The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments (financial assets) not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Group expects to receive, discounted at an approximation of the original effective interest rate. The expected cash flows will include cash flows from the sale of collateral held or other credit enhancements that are integral to the contractual terms. The Group applies a simplified approach in calculating ECLs for trade receivables and contract assets. Therefore, the Group does not track changes in credit risk, but instead recognises a loss allowance based on lifetime ECLs at each reporting date. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfFinancialAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-374": { "value": "1.10 Derivative financial instruments and hedging activities Derivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re-measured at their fair value. The method of recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument, and if so, the nature of the item being hedged. The Group uses derivative financial instruments, such as forward commodity contracts and options, to reduce the exposure to commodity price volatility. The Group has elected to apply cash flow hedge accounting designating these derivatives. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and from the date of start of cash flow hedge accounting. These are subsequently re-measured at fair value and the effective portion of the gain or loss on the hedging instrument is recognised in OCI, while any ineffective portion is recognised immediately in profit or loss (financial income or financial expenses). The cash flow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item. The amount accumulated in OCI is reclassified to profit or loss as a reclassification adjustment in the same periods during which the hedged cash flows affect profit or loss. If cash flow hedge accounting is discontinued, the amount that has been accumulated in OCI must remain in accumulated OCI if the hedged future cash flows are still expected to occur. Otherwise, the amount will be immediately reclassified to profit or loss as a reclassification adjustment. Derivatives are carried as financial assets when the fair value is positive and as financial liabilities when the fair value is negative. Commodity contracts that were entered into and continue to be held for the purpose of the delivery of a non-financial item in accordance with the Group\u2019s expected sale requirements fall within the exception from IFRS 9, which is known as the \u201cnormal purchase or sale exemption\u201d or the \u201cown use\u201d scope exception. For these contracts and the host part of the contracts containing embedded derivatives, they are accounted for as executory contracts. The Group recognises such contracts in its statement of financial position only when one of the parties meets its obligation under the contract to deliver either cash or a non-financial asset. The volume hedging agreement with Shell ended on 31 December 2020 and is not relevant in 2022. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-427": { "value": "1.10 Derivative financial instruments and hedging activities Derivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re-measured at their fair value. The method of recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument, and if so, the nature of the item being hedged. The Group uses derivative financial instruments, such as forward commodity contracts and options, to reduce the exposure to commodity price volatility. The Group has elected to apply cash flow hedge accounting designating these derivatives. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and from the date of start of cash flow hedge accounting. These are subsequently re-measured at fair value and the effective portion of the gain or loss on the hedging instrument is recognised in OCI, while any ineffective portion is recognised immediately in profit or loss (financial income or financial expenses). The cash flow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item. The amount accumulated in OCI is reclassified to profit or loss as a reclassification adjustment in the same periods during which the hedged cash flows affect profit or loss. If cash flow hedge accounting is discontinued, the amount that has been accumulated in OCI must remain in accumulated OCI if the hedged future cash flows are still expected to occur. Otherwise, the amount will be immediately reclassified to profit or loss as a reclassification adjustment. Derivatives are carried as financial assets when the fair value is positive and as financial liabilities when the fair value is negative. Commodity contracts that were entered into and continue to be held for the purpose of the delivery of a non-financial item in accordance with the Group\u2019s expected sale requirements fall within the exception from IFRS 9, which is known as the \u201cnormal purchase or sale exemption\u201d or the \u201cown use\u201d scope exception. For these contracts and the host part of the contracts containing embedded derivatives, they are accounted for as executory contracts. The Group recognises such contracts in its statement of financial position only when one of the parties meets its obligation under the contract to deliver either cash or a non-financial asset. The volume hedging agreement with Shell ended on 31 December 2020 and is not relevant in 2022. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-375": { "value": "1.11 Trade receivables Trade receivables are amounts due from customers for oil and gas sold or services performed in the ordinary course of business. If collection is expected in one year or less (or in the normal operating cycle of the business if longer), they are classified as current assets. If not, they are presented as non-current assets. Trade receivables are measured at amortised cost using the effective interest method, less provision for impairment. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-376": { "value": "1.12 Cash and cash equivalents Cash and cash equivalents include cash, bank deposits and short-term liquid placements, that immediately and with insignificant risk of changes in value can be converted to known cash amounts and with a remaining maturity less than three months from the date of acquisition. In the consolidated statement of financial position, bank overdrafts are shown within borrowings in current liabilities. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-377": { "value": "
1.13 Over/under-lifting of hydrocarbons
Over/under-lifting occurs when the Group has lifted and sold more or less hydrocarbons from a producing field than what the Group is entitled
to at the time of lifting. Over-lifting of hydrocarbons is presented as other current liabilities, under-lifting of hydrocarbons is presented as other
current assets. The value of under-lifting is measured at the lower of production expenses and the estimated sales value, less estimated sales
costs and the value of over-lifting is measured at production expenses. Over-lifting and under-lifting of hydrocarbons are presented at gross
value. Over/under-lift positions at the statement of financial position date are expected to be settled within 12 months from the statement of the
financial position date .
", "dimensions": { "concept": "norwegianenergy:DescriptionOfAccountingPolicyForOverUnderLiftingOfHydrocarbons", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-451": { "value": "1.13 Over/under-lifting of hydrocarbons Over/under-lifting occurs when the Group has lifted and sold more or less hydrocarbons from a producing field than what the Group is entitled to at the time of lifting. Over-lifting of hydrocarbons is presented as other current liabilities, under-lifting of hydrocarbons is presented as other current assets. The value of under-lifting is measured at the lower of production expenses and the estimated sales value, less estimated sales costs and the value of over-lifting is measured at production expenses. Over-lifting and under-lifting of hydrocarbons are presented at gross value. Over/under-lift positions at the statement of financial position date are expected to be settled within 12 months from the statement of the financial position date 1.21.1 Asset retirement obligations Provisions reflect the estimated cost of decommissioning and removal of wells and production facilities used for the production of hydrocarbons. Asset retirement obligations are measured at net present value of the anticipated future cost (estimated based on current day costs inflated). The liability is calculated on the basis of current removal requirements and is discounted to present value using a risk-free rate adjusted for credit margin. Liabilities are recognised when they arise and are adjusted continually in accordance with changes in requirements, price levels etc. When a decommissioning liability is recognised or the estimate changes, a corresponding amount is recorded to increase or decrease the related asset and is depreciated in line with the asset. Increase in the provision as a result of the time value of money is recognised in the income statement as a financial expense. If abandonment cost through agreements with partners have been limited to a given amount, this then forms the basis for the recognised liability. ", "dimensions": { "concept": "ifrs-full:DescriptionOfOtherAccountingPoliciesRelevantToUnderstandingOfFinancialStatements", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-428": { "value": "
1.14 Share capital, Treasury share reserves and share premium
Ordinary shares are classified as equity. Costs directly attributable to the issue of new shares or option shares are recognised as a deduction
from equity, net of any tax effects. Treasury share reserves are recognised as a deduction on equity at nominal value, the difference between
nominal value and purchase price is deducted from other equity.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIssuedCapitalExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-381": { "value": "1.14 Share capital, Treasury share reserves and share premium Ordinary shares are classified as equity. Costs directly attributable to the issue of new shares or option shares are recognised as a deduction from equity, net of any tax effects. Treasury share reserves are recognised as a deduction on equity at nominal value, the difference between nominal value and purchase price is deducted from other equity. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTreasurySharesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-378": { "value": "
1.15 Trade payables
Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Trade
payables are classified as current liabilities if payment is due within one year or less (or in the normal operating cycle of the business if longer).
If not, they are presented as non-current liabilities.
Trade payables are measured at fair value and subsequent measurements are considered trade payables at amortised cost when using
effective interest rate.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-379": { "value": "
1.16 Borrowings
Borrowings (financial liabilities) are classified as measured at amortised cost. Borrowings that are subsequently measured at amortised cost
using the effective interest method are recognised initially at fair value, net of transaction costs incurred. For hybrid (combined) instrument that
includes a non-derivative host contract that is not accounted for at FVTPL and an embedded derivative that is accounted for at FVTPL such as
the convertible bond, the Company has elected an accounting polity that all of the transaction costs are always allocated to and deducted from
the carrying amount of the non-derivative host contract on initial recognition. The subsequent measurement depends on which category they
have been classified into. The categories applicable for the Company are either financial liabilities measured at fair value through OCI or
financial liabilities measured at amortised cost using the effective interest method. The convertible bond loan has been determined to contain
embedded derivatives, which is accounted for separately as a derivative at fair value through profit or loss, while the loan element is measured
at amortised cost (note 3.1).
Borrowings are classified as non-current if contractual maturity is more than 12 months from the statement of financial position date. Borrowings
are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the
end of the reporting period. If the Group is in breach with any covenants on the statement of financial position date, and a waiver has not been
approved before or on the statement of financial position date with 12 months duration or more after the statement of financial position date, the
loan is classified as current even if expected maturity is longer than 12 months after the statement of financial position date.
Fees paid on the establishment of loan facilities are recognised as transaction costs of the loan to the extent that it is probable that some or all of
the facility will be drawn down. In this case, the fee is deferred until the drawdown occurs. To the extent there is no evidence that it is probable
that some or all of the facility will be drawn down, the fee is capitalised as a prepayment for liquidity services and amortised over the period of the
facility to which it relates.
A financial liability is derecognised when the obligation under the liability is discharged or cancelled, or when the contractual obligation expires.
When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability
are substantially modified, the exchange or modification is treated as the derecognition of the original liability and the recognition of a new
liability. The difference in the respective carrying amounts is recognised in the statement of comprehensive income as a gain or loss under
financial items. Transaction costs incurred during this process are treated as a cost of the settlement of the old debt and included in the gain or
loss calculation.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-380": { "value": "
1.17 Borrowing costs
General and specific borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets
that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time
as the assets are substantially ready for their intended use or sale. Investment income earned on the temporary investment of specific
borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation.
All other borrowing costs are recognised in profit or loss in the period in which they are incurred.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingCostsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-429": { "value": "1.18 Current and deferred income tax The tax expense for the period comprises current tax, tax impact from refund of exploration expenses and deferred tax. Tax is recognised in the income statement, except to the extent that it relates to items recognised in OCI or directly in equity. In this case, the tax is also recognised in OCI or directly in equity, respectively. The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the statement of financial position date in the countries where the Company and its subsidiaries operate and generate taxable income. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. It establishes provisions where appropriate on the basis of amounts expected to be paid to the tax authorities. Deferred income tax is recognised on temporary differences arising between the tax bases of assets, and liabilities and their carrying amounts in the consolidated financial statements. However, deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill; deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred income tax is determined using nominal tax rates (and laws) that have been enacted or substantively enacted by the statement of financial position date and are expected to apply when the related deferred income tax asset is realised, or the deferred income tax liability is settled. Deferred tax assets are recognised only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilised. Deferred income tax assets are recognised on deductible temporary differences arising from investments in subsidiaries, associates and joint arrangements only to the extent that it is probable that the temporary difference will reverse in the future and there is sufficient taxable profit available against which the temporary difference can be utilised. Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when the deferred income tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis. Producers of oil and gas on the Danish continental shelf are subject to the hydrocarbon tax regime under which income derived from the sale of oil and gas is taxed at an elevated 64 percent. Any income deriving from other activities than first-time sales of hydrocarbons is taxed at the ordinary corporate income rate of currently 22 percent. The 64 percent is calculated as the sum of the (chapter 2) tax of 25 percent plus a specific hydrocarbon tax (chapter 3a) of 52 percent, in which the 25 percent tax payable is deductible. When calculating the 52 percent tax, the Company is allowed to deduct an uplift (i.e. increased depreciation basis for tax purposes) of 30 percent of the investments in property, plant and equipment (PP&E) over a period of six years. Through an agreement from 2017, licence holders on the Danish continental shelf have had the possibility of applying new rules whereby the Company will have the possibility of increased uplift and accelerated depreciation during the period from 2017 to 2025. At the same time, the companies utilising the benefit are also liable for a repayment of the tax benefits previously received, this will materialise from 2022 through 2037 with an oil price (indexed from 2017) above USD 75. The repayment cannot exceed the indexed benefit from the applied rules. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-382": { "value": "1.18 Current and deferred income tax The tax expense for the period comprises current tax, tax impact from refund of exploration expenses and deferred tax. Tax is recognised in the income statement, except to the extent that it relates to items recognised in OCI or directly in equity. In this case, the tax is also recognised in OCI or directly in equity, respectively. The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the statement of financial position date in the countries where the Company and its subsidiaries operate and generate taxable income. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. It establishes provisions where appropriate on the basis of amounts expected to be paid to the tax authorities. Deferred income tax is recognised on temporary differences arising between the tax bases of assets, and liabilities and their carrying amounts in the consolidated financial statements. However, deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill; deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred income tax is determined using nominal tax rates (and laws) that have been enacted or substantively enacted by the statement of financial position date and are expected to apply when the related deferred income tax asset is realised, or the deferred income tax liability is settled. Deferred tax assets are recognised only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilised. Deferred income tax assets are recognised on deductible temporary differences arising from investments in subsidiaries, associates and joint arrangements only to the extent that it is probable that the temporary difference will reverse in the future and there is sufficient taxable profit available against which the temporary difference can be utilised. Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when the deferred income tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis. Producers of oil and gas on the Danish continental shelf are subject to the hydrocarbon tax regime under which income derived from the sale of oil and gas is taxed at an elevated 64 percent. Any income deriving from other activities than first-time sales of hydrocarbons is taxed at the ordinary corporate income rate of currently 22 percent. The 64 percent is calculated as the sum of the (chapter 2) tax of 25 percent plus a specific hydrocarbon tax (chapter 3a) of 52 percent, in which the 25 percent tax payable is deductible. When calculating the 52 percent tax, the Company is allowed to deduct an uplift (i.e. increased depreciation basis for tax purposes) of 30 percent of the investments in property, plant and equipment (PP&E) over a period of six years. Through an agreement from 2017, licence holders on the Danish continental shelf have had the possibility of applying new rules whereby the Company will have the possibility of increased uplift and accelerated depreciation during the period from 2017 to 2025. At the same time, the companies utilising the benefit are also liable for a repayment of the tax benefits previously received, this will materialise from 2022 through 2037 with an oil price (indexed from 2017) above USD 75. The repayment cannot exceed the indexed benefit from the applied rules. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-383": { "value": "1.19 Pensions The Group only has defined contribution plans as of 31 December 2022. For the defined contribution plan, the Group pays contributions to publicly or privately administered pension insurance plans on a mandatory, contractual or voluntary basis. The Group has no legal or constructive obligations to pay further contributions if the fund does not hold sufficient assets to pay all employees the benefits relating to employee service in the current and prior periods. The contributions are recognised as employee benefit expense when they are due. Prepaid contributions are recognised as an asset to the extent that a cash refund or a reduction in the future payments is available. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-384": { "value": "1.20 Share-based payments The Group operates a number of equity-settled, share-based compensation plans, under which the entity receives services from employees as consideration for equity instruments (options) of the Group. The fair value of the employee services received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed is determined by reference to the fair value of the options or shares granted: Fair value: \u2022 Including any market performance conditions. \u2022 Excludes the impact of any service and non-market performance vesting conditions (for example, profitability, sales growth targets and remaining an employee of the entity over a specified time period). Non-market performance and service conditions are included in assumptions about the number of options or shares that are expected to vest. The total expense is recognised over the vesting period (which is the period over which all of the specified vesting conditions are to be satisfied). At the end of each reporting period, the Group revises its estimates of the number of options that are expected to vest based on the non-market vesting conditions. It recognises the impact of the revision to original estimates, if any, in the income statement, with a corresponding adjustment to equity. When the options are exercised, the Company issues new shares. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium. The social security contributions payable in connection with the grant of the share options is considered an integral part of the grant itself, and the charge will be treated as a cash-settled transaction. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSharebasedPaymentTransactionsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-385": { "value": "1.21 Provisions Provisions are recognised when the Company has a present obligation (legal or constructive) arising from a past event, and it is probable (more likely than not) that it will result in an outflow from the entity of resources embodying economic benefits, and that a reliable estimate can be made of the amount of the obligation. Restructuring provisions comprise lease termination penalties and employee termination payments. Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to passage of time is recognised as interest expense. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-430": { "value": "1.21.1 Asset retirement obligations Provisions reflect the estimated cost of decommissioning and removal of wells and production facilities used for the production of hydrocarbons. Asset retirement obligations are measured at net present value of the anticipated future cost (estimated based on current day costs inflated). The liability is calculated on the basis of current removal requirements and is discounted to present value using a risk-free rate adjusted for credit margin. Liabilities are recognised when they arise and are adjusted continually in accordance with changes in requirements, price levels etc. When a decommissioning liability is recognised or the estimate changes, a corresponding amount is recorded to increase or decrease the related asset and is depreciated in line with the asset. Increase in the provision as a result of the time value of money is recognised in the income statement as a financial expense. If abandonment cost through agreements with partners have been limited to a given amount, this then forms the basis for the recognised liability. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-386": { "value": "1.21.1 Asset retirement obligations Provisions reflect the estimated cost of decommissioning and removal of wells and production facilities used for the production of hydrocarbons. Asset retirement obligations are measured at net present value of the anticipated future cost (estimated based on current day costs inflated). The liability is calculated on the basis of current removal requirements and is discounted to present value using a risk-free rate adjusted for credit margin. Liabilities are recognised when they arise and are adjusted continually in accordance with changes in requirements, price levels etc. When a decommissioning liability is recognised or the estimate changes, a corresponding amount is recorded to increase or decrease the related asset and is depreciated in line with the asset. Increase in the provision as a result of the time value of money is recognised in the income statement as a financial expense. If abandonment cost through agreements with partners have been limited to a given amount, this then forms the basis for the recognised liability. ", "dimensions": { "concept": "norwegianenergy:DescriptionOfAccountingPolicyForAssetRetirementObligations", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-387": { "value": "1.22 Contingent liabilities and assets Contingent liabilities are defined as: \u2022 Possible obligations that arise from past events, whose existence depends on uncertain future events. \u2022 Present obligations which have not been recognised because it is not probable that they will result in a payment. \u2022 The amount of the obligation cannot be measured with sufficient reliability. Specific mention of material contingent liabilities is disclosed, with the exception of contingent liabilities where the possibility of an outflow of resources embodying economic benefits is remote. Contingent assets are not recognised in the financial statements but are disclosed if there is a certain probability that a benefit will accrue to the Group. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-388": { "value": "1.23 Revenue recognition Revenue is recognised when the customer obtains control of the hydrocarbons, which is ordinarily at the point of delivery (lifting and sales) when title passes (sales method). Over/under-lifting occurs when the Group has lifted and sold more or less hydrocarbons from a producing field than what the Group is entitled to at the time of lifting. See note 1.13 for a description of accounting for over/under-lifting of hydrocarbons in the statement of financial position. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-389": { "value": "1.24 Production expenses Production expenses are expenses that are directly attached to production of hydrocarbons, e.g. expenses for operating and maintaining production facilities and installations. Expenses mainly consist of man-hours, insurance, processing costs, environmental fees, transport costs etc. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForExpensesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-390": { "value": "1.25 Interest income Interest income is recognised using the effective interest method. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInterestIncomeAndExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-391": { "value": "1.26 Consolidated statement of cash flows The consolidated statement of cash flows is prepared according to the indirect method. See note 1.12 for the definition of \u201ccash and cash equivalents\u201d. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForCashFlowsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-392": { "value": "2 Financial risk management 2.1 Financial risk factors The Group\u2019s activities expose it to financial risks: market risk (including currency risk, price risk, interest rate risk), credit risk and liquidity risk. The Group uses bond loans to finance its operations in connection with the day-to-day business, financial instruments, such as bank deposits, trade receivables and payables, and other current liabilities that arise directly from its operations, are utilised. Market risk Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in the market prices. Market risk comprises three types of risk: foreign currency risk, price risk and interest rate risk. Financial instruments affected by market risk include loans and borrowings, deposits, trade receivables, trade payables, accrued liabilities and derivative financial instruments. a) Foreign currency risk The Group is composed of businesses with various functional currencies including USD, EUR, GBP and DKK. The Group is exposed to foreign exchange risk for series of payments in other currencies than the functional currency, mainly related to the ratio between NOK and USD, DKK and USD, EUR and USD and GBP and USD. The Group\u2019s statement of financial position includes significant assets and liabilities, which are recorded in other currencies than the Group\u2019s presentation currency. As such, the Group\u2019s equity is sensitive to changes in foreign exchange rates. See note 15 Non-current receivables, trade receivable and other current receivables, note 17 Restricted Cash, Bank Deposits, Cash and Cash Equivalents, note 18 Financial instruments, note 21 Asset retirement obligation, note 22 Borrowings and note 23 Trade payables and other payables, note 27 Contingencies and commitments. A decrease in the closing rate of NOK, EUR and DKK with 10 percent compared to USD would have the following impact on financial assets, financial liabilities and equity: USD million NOK DKK EUR Financial assets 1 48 11 Financial liabilities 0 15 \u20131 Effect net result/equity 1 33 13 The Company considers the currency risk relating to the different financial instruments as low, as the main financial items held in a currency other than the functional currency of the respective components is offset by positions in other components of the Group and/or hedged. With regards to trade receivables and payables, the Company deems the risk to be immaterial. b) Price risk Norwegian Energy Company ASA (BlueNord) produces and sells hydrocarbons in Denmark and is as a result exposed to changes in commodity prices. The Group has a material commodity price hedging programme in place that mitigates the risk of near-term price movements. As of 31 December 2022, Norwegian Energy Company ASA (BlueNord) had commodity derivatives measured at fair value. A change in the value directly affects the Company\u2019s OCI and recorded equity, and hence the Group is exposed to the fair value development of these financial instruments. Assuming an increase in the commodity price at 31 December 2022 of 10 percent and assuming this change will have full effect on the whole curve, the effect on the value of commodity derivatives would have the following impact: USD million Equity OCI Net result Commodity price +10% -25 -25 0 Commodity price -10% 25 25 0 The effect on equity would be equal to the change in value of the commodity derivatives. The change in value of hedging contracts over time will be offset by the realised value of the contract when the hedge instrument matures, therefore the underlying value to Norwegian Energy Company ASA (BlueNord)\u2019s business operations is not impacted by changes in the derivative value at any point in time. c) Interest rate risk The Group has loans with fixed and floating interest rates. Loans with fixed interest rate expose the Group to risk (premium/discount) associated with changes in the market interest rate. At year-end, the Group has a total of USD 1.1 billion (2021: USD 1.2 billion) in interest-bearing debt (carrying amount), the principal amount was USD 1.2 billion. The Group\u2019s RBL facility has a floating interest rate comprising the aggregate of SOFR and 4.0 percent per annum, while the Group\u2019s Bond debt (NOR13 and NOR14) have a fixed interest rate exposure. The reserve-based lending facility is linked to the SOFR rate as set at the time of redetermination. A variance of +1 percent in the SOFR rate would result in USD 9.0 million of interest charges to Norwegian Energy Company ASA (BlueNord) per annum, however the Company has hedged this interest rate until 30 June 2024 at a rate of 0.40 percent to cover any increase in SOFR rate. For further information about the Group\u2019s interest- bearing debt, see note 22. All bank deposits (USD 472.1 million) are at floating interest rates. See note 17 Restricted cash, bank deposits, cash and cash equivalents for further information about bank deposits. The Group considers the risk exposure to changes in market interest to be at an acceptable level. Liquidity risk The Group has certain financial commitments arising from its operations and other agreements entered into which are expected to be met by liquid assets, proceeds from external financing and cash flow from operations. The Group monitors its liquidity situation continuously to ensure it will be able to meet its financial obligations as they fall due. As of 31 December 2022, none of the Group\u2019s interest-bearing debt were falling due within the next 12 months. Credit risk The Group\u2019s most significant credit risk arises principally from recognised receivables related to the Group\u2019s operation. The credit risk arising from the production of oil, gas and natural gas liquids (NGLs) is considered limited, as sales are to major oil companies with considerable financial resources. The counterparty in derivatives are large international banks and insurance companies whose credit risk is considered low. 2.2 Capital risk management The Group\u2019s objectives when managing capital is to safeguard the Group\u2019s ability to continue as a going concern in order to provide return for shareholders and benefits for other stakeholders and to maintain an acceptable capital structure to reduce the cost of capital. The Group monitors the debt with the basis of cash flows, equity ratio and the gearing ratio. The Group\u2019s debt restricts the payment of dividends until two quarters after the completion of the Tyra redevelopment project; subsequent to this date, NOR14 limits dividend payments to 50 percent of the Group\u2019s net profit after tax for the previous year. See further information regarding borrowings and covenants in note 22. ", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-431": { "value": "Market risk Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in the market prices. Market risk comprises three types of risk: foreign currency risk, price risk and interest rate risk. Financial instruments affected by market risk include loans and borrowings, deposits, trade receivables, trade payables, accrued liabilities and derivative financial instruments. a) Foreign currency risk The Group is composed of businesses with various functional currencies including USD, EUR, GBP and DKK. The Group is exposed to foreign exchange risk for series of payments in other currencies than the functional currency, mainly related to the ratio between NOK and USD, DKK and USD, EUR and USD and GBP and USD. The Group\u2019s statement of financial position includes significant assets and liabilities, which are recorded in other currencies than the Group\u2019s presentation currency. As such, the Group\u2019s equity is sensitive to changes in foreign exchange rates. See note 15 Non-current receivables, trade receivable and other current receivables, note 17 Restricted Cash, Bank Deposits, Cash and Cash Equivalents, note 18 Financial instruments, note 21 Asset retirement obligation, note 22 Borrowings and note 23 Trade payables and other payables, note 27 Contingencies and commitments. A decrease in the closing rate of NOK, EUR and DKK with 10 percent compared to USD would have the following impact on financial assets, financial liabilities and equity: USD million NOK DKK EUR Financial assets 1 48 11 Financial liabilities 0 15 \u20131 Effect net result/equity 1 33 13 The Company considers the currency risk relating to the different financial instruments as low, as the main financial items held in a currency other than the functional currency of the respective components is offset by positions in other components of the Group and/or hedged. With regards to trade receivables and payables, the Company deems the risk to be immaterial. b) Price risk Norwegian Energy Company ASA (BlueNord) produces and sells hydrocarbons in Denmark and is as a result exposed to changes in commodity prices. The Group has a material commodity price hedging programme in place that mitigates the risk of near-term price movements. As of 31 December 2022, Norwegian Energy Company ASA (BlueNord) had commodity derivatives measured at fair value. A change in the value directly affects the Company\u2019s OCI and recorded equity, and hence the Group is exposed to the fair value development of these financial instruments. Assuming an increase in the commodity price at 31 December 2022 of 10 percent and assuming this change will have full effect on the whole curve, the effect on the value of commodity derivatives would have the following impact: USD million Equity OCI Net result Commodity price +10% -25 -25 0 Commodity price -10% 25 25 0 The effect on equity would be equal to the change in value of the commodity derivatives. The change in value of hedging contracts over time will be offset by the realised value of the contract when the hedge instrument matures, therefore the underlying value to Norwegian Energy Company ASA (BlueNord)\u2019s business operations is not impacted by changes in the derivative value at any point in time. c) Interest rate risk The Group has loans with fixed and floating interest rates. Loans with fixed interest rate expose the Group to risk (premium/discount) associated with changes in the market interest rate. At year-end, the Group has a total of USD 1.1 billion (2021: USD 1.2 billion) in interest-bearing debt (carrying amount), the principal amount was USD 1.2 billion. The Group\u2019s RBL facility has a floating interest rate comprising the aggregate of SOFR and 4.0 percent per annum, while the Group\u2019s Bond debt (NOR13 and NOR14) have a fixed interest rate exposure. The reserve-based lending facility is linked to the SOFR rate as set at the time of redetermination. A variance of +1 percent in the SOFR rate would result in USD 9.0 million of interest charges to Norwegian Energy Company ASA (BlueNord) per annum, however the Company has hedged this interest rate until 30 June 2024 at a rate of 0.40 percent to cover any increase in SOFR rate. For further information about the Group\u2019s interest- bearing debt, see note 22. All bank deposits (USD 472.1 million) are at floating interest rates. See note 17 Restricted cash, bank deposits, cash and cash equivalents for further information about bank deposits. The Group considers the risk exposure to changes in market interest to be at an acceptable level. ", "dimensions": { "concept": "ifrs-full:DisclosureOfMarketRiskExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-452": { "value": "a) Foreign currency risk The Group is composed of businesses with various functional currencies including USD, EUR, GBP and DKK. The Group is exposed to foreign exchange risk for series of payments in other currencies than the functional currency, mainly related to the ratio between NOK and USD, DKK and USD, EUR and USD and GBP and USD. The Group\u2019s statement of financial position includes significant assets and liabilities, which are recorded in other currencies than the Group\u2019s presentation currency. As such, the Group\u2019s equity is sensitive to changes in foreign exchange rates. See note 15 Non-current receivables, trade receivable and other current receivables, note 17 Restricted Cash, Bank Deposits, Cash and Cash Equivalents, note 18 Financial instruments, note 21 Asset retirement obligation, note 22 Borrowings and note 23 Trade payables and other payables, note 27 Contingencies and commitments. A decrease in the closing rate of NOK, EUR and DKK with 10 percent compared to USD would have the following impact on financial assets, financial liabilities and equity: USD million NOK DKK EUR Financial assets 1 48 11 Financial liabilities 0 15 \u20131 Effect net result/equity 1 33 13 The Company considers the currency risk relating to the different financial instruments as low, as the main financial items held in a currency other than the functional currency of the respective components is offset by positions in other components of the Group and/or hedged. With regards to trade receivables and payables, the Company deems the risk to be immaterial. ", "dimensions": { "concept": "ifrs-full:DisclosureOfEffectOfChangesInForeignExchangeRatesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-432": { "value": "
Liquidity risk
The Group has certain financial commitments arising from its operations and other agreements entered into which are expected to be met by
liquid assets, proceeds from external financing and cash flow from operations. The Group monitors its liquidity situation continuously to ensure it
will be able to meet its financial obligations as they fall due. As of 31 December 2022, none of the Group\u2019s interest-bearing debt were falling due
within the next 12 months.
", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-433": { "value": "
Credit risk
The Group\u2019s most significant credit risk arises principally from recognised receivables related to the Group\u2019s operation. The credit risk arising
from the production of oil, gas and natural gas liquids (NGLs) is considered limited, as sales are to major oil companies with considerable
financial resources. The counterparty in derivatives are large international banks and insurance companies whose credit risk is considered low.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCreditRiskExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-434": { "value": "
2.2 Capital risk management
The Group\u2019s objectives when managing capital is to safeguard the Group\u2019s ability to continue as a going concern in order to provide return for
shareholders and benefits for other stakeholders and to maintain an acceptable capital structure to reduce the cost of capital.
The Group monitors the debt with the basis of cash flows, equity ratio and the gearing ratio. The Group\u2019s debt restricts the payment of dividends
until two quarters after the completion of the Tyra redevelopment project; subsequent to this date, NOR14 limits dividend payments to
50 percent of the Group\u2019s net profit after tax for the previous year. See further information regarding borrowings and covenants in note 22.
", "dimensions": { "concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-393": { "value": "
2.3 Fair value estimation
The Group has certain financial instruments carried at fair value. The different fair value hierarchy levels have been defined as follows:
Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities
The fair value of financial instruments traded in active markets is based on quoted market prices at the statement of financial position date.
A market is regarded as active if quoted prices are readily and regularly available from an exchange, dealer, broker, industry group, pricing
service, or regulatory agency, and those prices represent actual and regularly occurring market transactions on an arm\u2019s length basis.
The quoted market price used for financial assets held by the Group is the current bid price.
Level 2: Inputs other than quoted prices included within Level 1 that are observable for the assets or liability, either directly or indirectly
The fair value of financial instruments that are not traded in an active market (for example, over-the-counter derivatives) is determined by using
valuation techniques. These valuation techniques maximise the use of observable market data where it is available and rely as little as possible
on entity specific estimates. If all significant inputs required to fair value an instrument are observable, the instrument is included in Level 2. If one
or more of the significant inputs is not based on observable market data, the instrument is included in Level 3. Specified valuation techniques
used to value financial instruments include:
\u2022 quoted market prices or dealer quotes for similar instruments;
\u2022 the fair value of interest rate swaps is calculated as the present value of the estimated future cash flows based on observable yield curves;
and
\u2022 the fair value of forward foreign exchange contracts is determined using forward exchange rates at the statement of financial position date,
with the resulting value discounted back to present value.
Level 3: Inputs for other assets or liabilities that are not based on observable market data
In Level 3, there are one financial instrument, the embedded derivatives in the convertible bond.
The fair value of the embedded derivatives is calculated based on the Black-Scholes-Merton valuation model. A change in the share price of
+/- 10 percent would have the following impact on the embedded derivates, net result and equity:
Share price
Sensitivity analysis
10% -10%
Embedded derivatives USD million (11) 10
Effect net result/equity USD million (11) 10
It is evaluated that there is no tax effect of changes in fair value of the contingent consideration and embedded derivatives. See note 18 for fair
value hierarchy and further information.
", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-394": { "value": "3 Critical accounting estimates and judgements 3.1 Critical accounting estimates and assumptions Estimates and judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are addressed below. a) Estimated value of financial assets and financial liabilities The embedded derivatives in the convertible debt have been recognised separately at fair value through profit and loss. The value of this embedded derivative has been calculated using the Black-Scholes-Merton valuation model using assumptions for share price, volatility of share price, and other inputs which are subject to significant uncertainty. For financial assets at amortised cost, an assessment is made on whether objective evidence is present that financial assets or groups of financial assets should be written down. For more details, see note 18 Financial Instruments. b) Income tax All figures reported in the statement of comprehensive income and the statement of financial position are based on the Group\u2019s tax calculations and should be regarded as estimates until the tax for the year has been settled. Tax authorities can be of a different opinion than the Company. See also note 13. c) Asset retirement obligation Production of oil and gas is subject to statutory requirements relating to decommissioning and removal obligation once production has ceased. Provisions to cover these future decommissioning and removal expenditures must be recognised at the time the statutory requirement arises. The costs will often incur sometime in the future, and there is significant uncertainty attached to the scale and complexity of the decommissioning and removal involved. Estimated future costs (estimated based on current costs inflated) are based on known decommissioning and removal technology, expected future price levels, and the expected future decommissioning and removal date, discounted to net present value using a risk-free rate adjusted for credit margin. Changes in one or more of these factors could result in changes in the decommissioning and removal liabilities. See note 21 Asset Retirement Obligations for further details about decommissioning and removal obligations. d) Depreciation and impairment of fixed assets The estimation of the recoverable amount of oil and gas assets as well as the estimation of available commercially depletable reserves is subject to significant uncertainty, primarily related to future oil and gas price levels. Impairment assessments are made to the extent there are indicators of reduced values of fixed assets. UoP depreciations are amended on a prospective basis following regular reserves estimation updates performed by the Group. For more details, see note 11 Impairments. 3.2 Critical judgements in applying the entity\u2019s accounting policies a) Accounting for convertible debt The Group has issued bonds with conversion rights and other embedded derivatives (but the conversion feature is the main element). The conversion feature has been determined to constitute an embedded derivative and has been separated from the loan contract. The loan element has been recognised at amortised cost. At initial recognition, the loan was measured as the residual amount of the proceeds from the bond issue, less issue costs, less the calculated fair value of the conversion feature. The process of determining whether the conversion feature in the convertible bond arrangement should be treated as a liability or an equity component requires the application of significant judgement. The convertible bond is either a financial liability (including certain embedded derivative features which may require separation) or a compound instrument (i.e. such a liability plus an equity conversion option). The Group has assessed that the holder\u2019s conversion option does not involve receiving a fixed number of shares by giving up a fixed stated principal amount of bond, hence the Group has assessed this instrument is not a compound instrument with an equity part. Further multiple embedded derivatives have been identified in the host contract that has been assessed is not readily separable and independent of each other, and as such is treated as a single compound embedded derivative. Also, the fair value measurement of the conversion feature using the Black-Scholes-Merton valuation model, requires significant judgement when selecting and applying the required assumptions. ", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-435": { "value": "3.1 Critical accounting estimates and assumptions Estimates and judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are addressed below. a) Estimated value of financial assets and financial liabilities The embedded derivatives in the convertible debt have been recognised separately at fair value through profit and loss. The value of this embedded derivative has been calculated using the Black-Scholes-Merton valuation model using assumptions for share price, volatility of share price, and other inputs which are subject to significant uncertainty. For financial assets at amortised cost, an assessment is made on whether objective evidence is present that financial assets or groups of financial assets should be written down. For more details, see note 18 Financial Instruments. b) Income tax All figures reported in the statement of comprehensive income and the statement of financial position are based on the Group\u2019s tax calculations and should be regarded as estimates until the tax for the year has been settled. Tax authorities can be of a different opinion than the Company. See also note 13. c) Asset retirement obligation Production of oil and gas is subject to statutory requirements relating to decommissioning and removal obligation once production has ceased. Provisions to cover these future decommissioning and removal expenditures must be recognised at the time the statutory requirement arises. The costs will often incur sometime in the future, and there is significant uncertainty attached to the scale and complexity of the decommissioning and removal involved. Estimated future costs (estimated based on current costs inflated) are based on known decommissioning and removal technology, expected future price levels, and the expected future decommissioning and removal date, discounted to net present value using a risk-free rate adjusted for credit margin. Changes in one or more of these factors could result in changes in the decommissioning and removal liabilities. See note 21 Asset Retirement Obligations for further details about decommissioning and removal obligations. d) Depreciation and impairment of fixed assets The estimation of the recoverable amount of oil and gas assets as well as the estimation of available commercially depletable reserves is subject to significant uncertainty, primarily related to future oil and gas price levels. Impairment assessments are made to the extent there are indicators of reduced values of fixed assets. UoP depreciations are amended on a prospective basis following regular reserves estimation updates performed by the Group. For more details, see note 11 Impairments. ", "dimensions": { "concept": "ifrs-full:ExplanationOfAssumptionAboutFutureWithSignificantRiskOfResultingInMaterialAdjustments", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-395": { "value": "
4 Revenue
USD million 2022 2021
Sale of oil 552.1 416.0
Sale of gas and NGL 408.4 142.4
Other income 6.4 6.9
Total revenue 966.9 565.3
Oil-lifted volumes (mmbbl) 7.32 7.20
Effective oil price USD/bbl 75.5 57. 8
Gas lifted volumes (mmboe) 2.3 2.3
Effective gas price EUR/MWh 101.9 30.4
Effective gas price USD/boe 181.1 61.5
In 2022, sale of oil amounted to USD 552.1 million and sale of gas amounted to USD 408.4 million, realised prices were USD 75.5 per bbl of oil
and USD 181.1 per boe gas lifted during the year, adjusted for settlement of price hedges in place with financial institutions.
During 2022, Norwegian Energy Company ASA (BlueNord) recognised the settlement of price hedges that were put in place with financial
institutions in the market as revenue, when these price hedges match the physical sale of oil and gas. Price hedges in excess of actual liftings are
treated as financial income or expenses based on the required accounting treatment for these instruments during the period.
Revenue per customer 2022 2021
Shell Trading International 77.7% 90.1%
\u00d8rsted Salg & Service AS 32.5% 28.4%
Shell Energy Europe Limited 16.2% 8.2%
CommonwealthBank
1)
-1.9% -4.7%
SEB Skandinaviska Enskilda Banken AB
1)
-2.4% 0.0%
BNP Paribas
1)
-4.2% -10.2%
Natixis
1)
-8.0% -11.9%
Lloyds Bank Corporate Markets PLC
1)
-10.0% 0.0%
Total revenue 100.0% 100.0%
1) The negative percentages represent the settlement of commodity hedges in place with financial institutions.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-396": { "value": "
5 Production expenses
USD million 2022 2021
Direct field opex (233.1) (210.9)
Tariff and transportation expenses (43.3) (44.3)
Production general and administrative (G&A) (32.1) (41.8)
Field operating cost (308.5) (297.0)
Total produced volumes (mmboe) 9.8 9.8
In USD per boe (31.6) (30.2)
Adjustments for:
Concept studies (1.5) \u2013
Change in inventory position 4.0 (0.7)
Over/under-lift of oil and NGL 7.7 14.0
Insurance & other (19.4) (21.6)
Stock scrap (5.6) 12.6
Production expenses (323.4) (292.7)
Production expenses for the year directly attributable to the lifting and transportation to market of Norwegian Energy Company ASA
(BlueNord)\u2019s oil and gas production is in total USD 308.5 million, which equates to USD 31.6 per boe produced during 2022 (2021: USD 30.2 per
boe produced). Actual production expenses in 2022 was in line with the expectation. The increase compared with 2021 is mainly driven by the
high activity on workovers to maintain base production in with some increased costs from inflation.
", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-436": { "value": "5 Production expenses USD million 2022 2021 Direct field opex (233.1) (210.9) Tariff and transportation expenses (43.3) (44.3) Production general and administrative (G&A) (32.1) (41.8) Field operating cost (308.5) (297.0) Total produced volumes (mmboe) 9.8 9.8 In USD per boe (31.6) (30.2) Adjustments for: Concept studies (1.5) \u2013 Change in inventory position 4.0 (0.7) Over/under-lift of oil and NGL 7.7 14.0 Insurance & other (19.4) (21.6) Stock scrap (5.6) 12.6 Production expenses (323.4) (292.7) Production expenses for the year directly attributable to the lifting and transportation to market of Norwegian Energy Company ASA (BlueNord)\u2019s oil and gas production is in total USD 308.5 million, which equates to USD 31.6 per boe produced during 2022 (2021: USD 30.2 per boe produced). Actual production expenses in 2022 was in line with the expectation. The increase compared with 2021 is mainly driven by the high activity on workovers to maintain base production in with some increased costs from inflation. ", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesByNatureExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-397": { "value": "6 Exploration and evaluation expenses USD million 2022 2021 Other exploration and evaluation costs (0.7) (0.7) Total exploration and evaluation costs (0.7) (0.7) ", "dimensions": { "concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-454": { "value": "7 Personnel expenses USD million Note 2022 2021 Salaries (9.2) (9.5) Social security tax (1.0) (0.8) Pension costs 20 (0.5) (0.6) Costs relating to share-based payments 24 (1.4) (0.3) Other personnel expenses (0.4) (0.3) Total personnel expenses (12.5) (11.5) Average number of employees 30.5 27.4 Please see the Executive Remuneration Report 2022 for compensation to key management and Board of Directors in the period 2018-2022. 20 Post-employment benefits Defined contribution plan The Group has defined contribution plans for its employees. Pension costs related to the Company\u2019s defined contribution plan amounts to USD 513 thousand for 2022. For 2021, the corresponding costs were USD 558 thousand. The Norwegian companies are obliged to have occupational pension in accordance with the Norwegian act related to mandatory occupational pension. All Norwegian companies meet the Norwegian requirements for mandatory occupational pension (\u201cobligatorisk tjenestepensjon\u201d). Correspondingly, the affiliates in Denmark and United Kingdom comply with the requirement for mandatory occupational pension by local legislation ", "dimensions": { "concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-398": { "value": "7 Personnel expenses USD million Note 2022 2021 Salaries (9.2) (9.5) Social security tax (1.0) (0.8) Pension costs 20 (0.5) (0.6) Costs relating to share-based payments 24 (1.4) (0.3) Other personnel expenses (0.4) (0.3) Total personnel expenses (12.5) (11.5) Average number of employees 30.5 27.4 Please see the Executive Remuneration Report 2022 for compensation to key management and Board of Directors in the period 2018-2022. ", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutEmployeesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-399": { "value": "8 Other operating expenses USD million 2022 2021 Consultant fees (15.3) (8.2) Other operating expenses (3.8) (2.7) Total other operating expenses (19.1) (10.9) USD, 1000 excl. VAT 2022 2021 Auditor\u2019s fees (625.8) (575.1) Other assurance service (84.6) (5.4) Total audit fees (710.4) (580.5) ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-437": { "value": "USD, 1000 excl. VAT 2022 2021 Auditor\u2019s fees (625.8) (575.1) Other assurance service (84.6) (5.4) Total audit fees (710.4) (580.5) ", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-453": { "value": "9 Intangible assets Intangible assets at 31 December 2022 USD million Capitalised exploration expenditures Conceptual studies Licence Tota l Book value 31 December 21 1.4 \u2013 164.7 166.0 Acquisition costs 31 December 21 1.4 \u2013 186.0 187.4 Additions 0.5 1.9 \u2013 2.4 Acquisition costs 31 December 22 1.8 1.9 186.0 189.8 Accumulated depreciation, amortisation and write-downs 31 December 21 \u2013 \u2013 (21.3) (21.3) Depreciation/amortisation \u2013 \u2013 (8.0) (8.0) Accumulated depreciation, amortisation and write-downs 31 December 22 \u2013 \u2013 (29.4) (29.4) Book value 31 December 22 1.8 1.9 156.6 160.4 Intangible assets at 31 December 2021 USD million Capitalised exploration expenditures Conceptual studies Licence Total Book value 31 December 20 1.9 \u2013 172.7 174.6 Acquisition costs 31 December 20 1.9 \u2013 186.0 187. 8 Additions (0.5) \u2013 \u2013 (0.5) Acquisition costs 31 December 21 1.4 \u2013 186.0 187.4 Accumulated depreciation and write-downs 31 December 20 \u2013 \u2013 (13.3) (13.3) Depreciation/amortisation \u2013 \u2013 (8.0) (8.0) Accumulated depreciation and write-downs 31 December 21 \u2013 \u2013 (21.3) (21.3) Book value 31 December 21 1.4 \u2013 164.7 166.0 10 Property, plant and equipment Property, plant and equipment at 31 December 2022 USD million Asset under construction Production facilities Other assets Tot al Book value 31 December 21 818.5 1,078.5 1.7 1,898.7 Acquisition costs 31 December 21 818.5 1,346.6 3.1 2,168.2 Sale of assets \u2013 (0.2) (0.2) (0.4) Additions 232.4 9.1 0.2 241.6 Revaluation abandonment assets \u2013 (102.8) \u2013 (102.8) Currency translation adjustment \u2013 (0.1) (0.1) (0.2) Acquisition costs 31 December 22 1,050.9 1,252.5 3.1 2,306.4 Depreciation and write-downs 31 December 21 \u2013 (268.2) (1.4) (269.6) Sale of asset, reversal depreciation \u2013 0.1 \u2013 0.1 Depreciation \u2013 (124.8) \u2013 (125.1) Currency translation adjustment \u2013 0.0 (0.3) 0.0 Depreciation and write-downs 31 December 22 \u2013 (392.9) (1.7) (394.6) Book value 31 December 22 1,050.9 859.6 1.4 1,911.9 Property, plant and equipment at 31 December 2021 USD million Asset under construction Production facilities Other assets Total Book value 31 December 20 607.7 1,093.9 2.5 1,704.1 Acquisition costs 31 December 20 607.7 1,258.7 3.2 1,869.6 Additions 210.8 17.5 0.1 228.4 Acquisition of abandonment asset \u2013 70.6 \u2013 70.6 Disposal \u2013 \u2013 \u2013 \u2013 Currency translation adjustment \u2013 (0.2) (0.1) (0.3) Acquisition costs 31 December 21 818.5 1,346.6 (0.1) 2,168.3 Accumulated depreciation and write-downs 31 December 20 \u2013 (164.9) (0.1) (165.9) Depreciation \u2013 (103.3) (0.1) (103.7) Currency translation adjustment \u2013 0.0 0.0 0.1 Accumulated depreciation and write-downs 31 December 21 \u2013 (268.2) (0.2) (269.6) Book value 31 December 21 818.5 1,078.5 1.3 1,898.7 ", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-438": { "value": "9 Intangible assets Intangible assets at 31 December 2022 USD million Capitalised exploration expenditures Conceptual studies Licence Tota l Book value 31 December 21 1.4 \u2013 164.7 166.0 Acquisition costs 31 December 21 1.4 \u2013 186.0 187.4 Additions 0.5 1.9 \u2013 2.4 Acquisition costs 31 December 22 1.8 1.9 186.0 189.8 Accumulated depreciation, amortisation and write-downs 31 December 21 \u2013 \u2013 (21.3) (21.3) Depreciation/amortisation \u2013 \u2013 (8.0) (8.0) Accumulated depreciation, amortisation and write-downs 31 December 22 \u2013 \u2013 (29.4) (29.4) Book value 31 December 22 1.8 1.9 156.6 160.4
Intangible assets at 31 December 2021
USD million
Capitalised
exploration
expenditures
Conceptual
studies Licence Total
Book value 31 December 20 1.9 \u2013 172.7 174.6
Acquisition costs 31 December 20 1.9 \u2013 186.0 187. 8
Additions (0.5) \u2013 \u2013 (0.5)
Acquisition costs 31 December 21 1.4 \u2013 186.0 187.4
Accumulated depreciation and write-downs 31 December 20 \u2013 \u2013 (13.3) (13.3)
Depreciation/amortisation \u2013 \u2013 (8.0) (8.0)
Accumulated depreciation and write-downs 31 December 21 \u2013 \u2013 (21.3) (21.3)
Book value 31 December 21 1.4 \u2013 164.7 166.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-400": { "value": "
10 Property, plant and equipment
Property, plant and equipment at 31 December 2022
USD million
Asset under
construction
Production
facilities Other assets Tot al
Book value 31 December 21 818.5 1,078.5 1.7 1,898.7
Acquisition costs 31 December 21 818.5 1,346.6 3.1 2,168.2
Sale of assets \u2013 (0.2) (0.2) (0.4)
Additions 232.4 9.1 0.2 241.6
Revaluation abandonment assets \u2013 (102.8) \u2013 (102.8)
Currency translation adjustment \u2013 (0.1) (0.1) (0.2)
Acquisition costs 31 December 22 1,050.9 1,252.5 3.1 2,306.4
Depreciation and write-downs 31 December 21 \u2013 (268.2) (1.4) (269.6)
Sale of asset, reversal depreciation \u2013 0.1 \u2013 0.1
Depreciation \u2013 (124.8) \u2013 (125.1)
Currency translation adjustment \u2013 0.0 (0.3) 0.0
Depreciation and write-downs 31 December 22 \u2013 (392.9) (1.7) (394.6)
Book value 31 December 22 1,050.9 859.6 1.4 1,911.9
Property, plant and equipment at 31 December 2021
USD million
Asset under
construction
Production
facilities Other assets Total
Book value 31 December 20 607.7 1,093.9 2.5 1,704.1
Acquisition costs 31 December 20 607.7 1,258.7 3.2 1,869.6
Additions 210.8 17.5 0.1 228.4
Acquisition of abandonment asset \u2013 70.6 \u2013 70.6
Disposal \u2013 \u2013 \u2013 \u2013
Currency translation adjustment \u2013 (0.2) (0.1) (0.3)
Acquisition costs 31 December 21 818.5 1,346.6 (0.1) 2,168.3
Accumulated depreciation and write-downs 31 December 20 \u2013 (164.9) (0.1) (165.9)
Depreciation \u2013 (103.3) (0.1) (103.7)
Currency translation adjustment \u2013 0.0 0.0 0.1
Accumulated depreciation and write-downs 31 December 21 \u2013 (268.2) (0.2) (269.6)
Book value 31 December 21 818.5 1,078.5 1.3 1,898.7
", "dimensions": { "concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-401": { "value": "11 Impairments Impairment testing Impairment testing of our asset base is performed periodically and/or when impairment triggers are identified. In Q4 2022, Norwegian Energy Company ASA (BlueNord) carried out a periodical impairment test for the fixed assets and related tangible assets. Impairment is recognised when the book value of an asset or a cash generating unit exceeds the recoverable amount. The recoverable amount is the higher of the assets fair value less cost to sell and value in use. In Q4 2022, the recoverable amount was calculated as the expected future cash flow from the asset, 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. Cash flows are projected for the estimated lifetime of the fields, which exceed five years. Commodity prices Future commodity price levels are a key assumption and have a significant impact on the net present value (NPV). Forecasted oil and gas prices are based on management\u2019s 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 2023 to the end of 2025. From 2026, the oil and gas prices are based on the Company\u2019s long-term price assumptions. Nominal oil prices applied in the impairment test are as follows: Year USD/BBL 2023 80.0 2024 75.0 2025 70.0 From 2026 onwards 65.0 Nominal gas prices applied in the impairment test are as follows: Year EUR/MWH 2023 60.0 2024 60.0 2025 50.0 From 2026 onwards 30.0 Oil and gas reserves Future cash flows are calculated on the basis of expected production profiles and probable remaining reserves. Future expenditure Future opex, capex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost. Discount rate The discount rate is derived from the weighted average cost of capital (\u201cWACC\u201d) for a market participant. The post-tax nominal discount rate used is 9.2 percent. Exchange rates The exchange rate from US dollar to Danish kroner is a blended rate of 7.02 throughout the forecast period. The applied blended rate is taken as 75 percent of the market rate at 6.87 and 25 percent of the Operator\u2019s Budget Book rate at 7.46. The US dollar to euro exchange rate is 0.92 throughout the forecast period. The US dollar to euro rate has been pegged to a euro to Danish kroner rate of 7.44, sensitivity analysis based on exchange rates will maintain the euro to Danish kroner exchange rate. Inflation The long-term inflation rate is assumed to be two percent. Impairment testing of assets including tangible and intangible asset values Both the tangible and intangible asset value attached to a cash generating unit is tested as part of the impairment assessment. The carrying value of the assets is the sum of tangible assets and intangible assets as of the assessment date. Result of impairment assessment The impairment assessment has not resulted in any impairment charge being recognised.
Sensitivity analysis
The table below shows how the impairment or reversal of impairment of assets would be affected by changes in the various assumptions, given
that the remaining assumptions are constant.
Sensitivity Change in NPV
Implied Impairment
(if applicable)
USD 1 ,000
Long-term price +10% 11% \u2013
Long-term price -10% -12% (207.4)
USD:DKK FX rate +10% -2% \u2013
USD:DKK FX rate -10% 3% \u2013
WACC +1.0% -5% (49.1)
WACC -1.0% 5% \u2013
Inflation rate +1.0% 6% \u2013
Inflation rate -1.0% -5% (63.1)
", "dimensions": { "concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-402": { "value": "
12 Financial Income and Expenses
Financial income
USD million 2022 2021
Value adjustment interest swap unrealised
1)
10.2 1.0
Value adjustment of embedded derivatives
2)
\u2013 6.0
Interest income 4.0 0.0
Extinguishment of bond loan 33.7 \u2013
Foreign exchange gains 11.0 20.9
Total financial income 58.8 27.8
Financial expenses
USD million 2022 2021
Value adjustment of embedded derivatives
2)
(132.3) \u2013
Value adjustment of FX contract \u2013 (1.0)
Value adjustment amortised cost RBL \u2013 (5.3)
Utilisation of derivatives \u2013 (3.7)
Unrealised loss derivatives \u2013 (7.5)
Interest expense from bond loans (46.5) (43.7)
Interest expense from bank debt
3)
(48.9) (45.3)
Interest expenses current liabilities (0.1) (0.0)
Accretion expense related to asset retirement obligations (48.0) (34.9)
Foreign exchange losses (8.5) (15.3)
Other financial expenses (3.4) (3.5)
Total financial expenses (287.8) (160.2)
Net financial items (229.0) (132.3)
1) Fair value adjustment of interest swap related to RBL facility, ineffective part.
2) Fair value adjustment of the embedded derivatives of the convertible bonds.
3) Net of realised interest swap.
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-471": { "value": "12 Financial Income and Expenses Financial income USD million 2022 2021 Value adjustment interest swap unrealised 1) 10.2 1.0 Value adjustment of embedded derivatives 2) \u2013 6.0 Interest income 4.0 0.0 Extinguishment of bond loan 33.7 \u2013 Foreign exchange gains 11.0 20.9 Total financial income 58.8 27.8 Financial expenses USD million 2022 2021 Value adjustment of embedded derivatives 2) (132.3) \u2013 Value adjustment of FX contract \u2013 (1.0) Value adjustment amortised cost RBL \u2013 (5.3) Utilisation of derivatives \u2013 (3.7) Unrealised loss derivatives \u2013 (7.5) Interest expense from bond loans (46.5) (43.7) Interest expense from bank debt 3) (48.9) (45.3) Interest expenses current liabilities (0.1) (0.0) Accretion expense related to asset retirement obligations (48.0) (34.9) Foreign exchange losses (8.5) (15.3) Other financial expenses (3.4) (3.5) Total financial expenses (287.8) (160.2) Net financial items (229.0) (132.3) 1) Fair value adjustment of interest swap related to RBL facility, ineffective part. 2) Fair value adjustment of the embedded derivatives of the convertible bonds. 3) Net of realised interest swap", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-469": { "value": "12 Financial Income and Expenses Financial income USD million 2022 2021 Value adjustment interest swap unrealised 1) 10.2 1.0 Value adjustment of embedded derivatives 2) \u2013 6.0 Interest income 4.0 0.0 Extinguishment of bond loan 33.7 \u2013 Foreign exchange gains 11.0 20.9 Total financial income 58.8 27.8 Financial expenses USD million 2022 2021 Value adjustment of embedded derivatives 2) (132.3) \u2013 Value adjustment of FX contract \u2013 (1.0) Value adjustment amortised cost RBL \u2013 (5.3) Utilisation of derivatives \u2013 (3.7) Unrealised loss derivatives \u2013 (7.5) Interest expense from bond loans (46.5) (43.7) Interest expense from bank debt 3) (48.9) (45.3) Interest expenses current liabilities (0.1) (0.0) Accretion expense related to asset retirement obligations (48.0) (34.9) Foreign exchange losses (8.5) (15.3) Other financial expenses (3.4) (3.5) Total financial expenses (287.8) (160.2) Net financial items (229.0) (132.3) 1) Fair value adjustment of interest swap related to RBL facility, ineffective part. 2) Fair value adjustment of the embedded derivatives of the convertible bonds. 3) Net of realised interest swap", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-464": { "value": "12 Financial Income and Expenses Financial income USD million 2022 2021 Value adjustment interest swap unrealised 1) 10.2 1.0 Value adjustment of embedded derivatives 2) \u2013 6.0 Interest income 4.0 0.0 Extinguishment of bond loan 33.7 \u2013 Foreign exchange gains 11.0 20.9 Total financial income 58.8 27.8 Financial expenses USD million 2022 2021 Value adjustment of embedded derivatives 2) (132.3) \u2013 Value adjustment of FX contract \u2013 (1.0) Value adjustment amortised cost RBL \u2013 (5.3) Utilisation of derivatives \u2013 (3.7) Unrealised loss derivatives \u2013 (7.5) Interest expense from bond loans (46.5) (43.7) Interest expense from bank debt 3) (48.9) (45.3) Interest expenses current liabilities (0.1) (0.0) Accretion expense related to asset retirement obligations (48.0) (34.9) Foreign exchange losses (8.5) (15.3) Other financial expenses (3.4) (3.5) Total financial expenses (287.8) (160.2) Net financial items (229.0) (132.3) 1) Fair value adjustment of interest swap related to RBL facility, ineffective part. 2) Fair value adjustment of the embedded derivatives of the convertible bonds. 3) Net of realised interest swap", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-455": { "value": "12 Financial Income and Expenses Financial income USD million 2022 2021 Value adjustment interest swap unrealised 1) 10.2 1.0 Value adjustment of embedded derivatives 2) \u2013 6.0 Interest income 4.0 0.0 Extinguishment of bond loan 33.7 \u2013 Foreign exchange gains 11.0 20.9 Total financial income 58.8 27.8 Financial expenses USD million 2022 2021 Value adjustment of embedded derivatives 2) (132.3) \u2013 Value adjustment of FX contract \u2013 (1.0) Value adjustment amortised cost RBL \u2013 (5.3) Utilisation of derivatives \u2013 (3.7) Unrealised loss derivatives \u2013 (7.5) Interest expense from bond loans (46.5) (43.7) Interest expense from bank debt 3) (48.9) (45.3) Interest expenses current liabilities (0.1) (0.0) Accretion expense related to asset retirement obligations (48.0) (34.9) Foreign exchange losses (8.5) (15.3) Other financial expenses (3.4) (3.5) Total financial expenses (287.8) (160.2) Net financial items (229.0) (132.3) 1) Fair value adjustment of interest swap related to RBL facility, ineffective part. 2) Fair value adjustment of the embedded derivatives of the convertible bonds. 3) Net of realised interest swap", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-439": { "value": "12 Financial Income and Expenses Financial income USD million 2022 2021 Value adjustment interest swap unrealised 1) 10.2 1.0 Value adjustment of embedded derivatives 2) \u2013 6.0 Interest income 4.0 0.0 Extinguishment of bond loan 33.7 \u2013 Foreign exchange gains 11.0 20.9 Total financial income 58.8 27.8 Financial expenses USD million 2022 2021 Value adjustment of embedded derivatives 2) (132.3) \u2013 Value adjustment of FX contract \u2013 (1.0) Value adjustment amortised cost RBL \u2013 (5.3) Utilisation of derivatives \u2013 (3.7) Unrealised loss derivatives \u2013 (7.5) Interest expense from bond loans (46.5) (43.7) Interest expense from bank debt 3) (48.9) (45.3) Interest expenses current liabilities (0.1) (0.0) Accretion expense related to asset retirement obligations (48.0) (34.9) Foreign exchange losses (8.5) (15.3) Other financial expenses (3.4) (3.5) Total financial expenses (287.8) (160.2) Net financial items (229.0) (132.3) 1) Fair value adjustment of interest swap related to RBL facility, ineffective part. 2) Fair value adjustment of the embedded derivatives of the convertible bonds. 3) Net of realised interest swap", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-403": { "value": "
1 3 Tax
Tax rates
Producers of oil and gas on the Danish continental shelf are subject to the hydrocarbon tax regime under which, income derived from the sale of
oil and gas is taxed at an elevated 64 percent. Any income deriving from other activities than first-time sales of hydrocarbons is taxed at the
ordinary corporate income rate of currently 22 percent. The 64 percent is calculated as the sum of the \u201cChapter 2\u201d tax of 25 percent plus a
specific hydrocarbon tax (chapter 3a) of 52 percent, in which the 25 percent tax payable is deductible. Income generated in Norway and United
Kingdom is subject to regular corporate tax at 22 percent.
Tax expense USD million Income tax in profit/loss (Danish corporate income tax and hydrocarbon tax) 2022 Income tax current year (139.9) Repayment of tax benefit related to chapter 3b (62.7) Income tax for prior years (2.0) Current income tax (204.6) Deferred tax movements (65.9) Prior year adjustment, deferred tax (8.6) Deferred tax expense (74.5) Tax (expense)/income (279.2) Income tax in profit/loss is solely derived from the Group\u2019s activities on the Danish continental shelf, of which the major part is subject to the elevated 64 percent hydrocarbon tax. Tax (expense)/income related to OCI Cash flow hedges (102.9) Tax (expense)/income related to OCI (102.9) Income tax on OCI is related to the unrealised fair value changes in derivatives designated in cash flow hedges. To the extent derivatives are associated with the sale of oil and gas, results from cash flow hedges are subject to 64 percent hydrocarbon tax. Reconciliation of nominal to actual tax rate Hydrocarbon tax 64% Corporate tax 22% In total Result before tax 364.1 (115.4) 248.7 Expected tax on profit before tax 233.0 64% (25.4) 22% 207.6 Tax effect of: Prior year adjustment 9.6 3% 0.2 0% 9.8 FX adjustment of net operating losses carried forward in DKK1) 37.3 10% \u2013 0% 37. 3 Repayment of tax benefit related to chapter 3b2) 30.1 8% \u2013 0% 30.1 Investment uplift on CAPEX projects3) (36.8) (10%) \u2013 0% (36.8) Permanent differences \u2013 0% 29.1 (25%) 29.1 No recognition of tax assets in Norway and UK \u2013 0% 2.0 2% 2.0 Tax expense (income) in profit/loss 273.2 75% 6.0 5% 279.2 1) Deferred tax movement no cash effect. 2) From 2022 onwards, an additional tax cost related to the special tax incentive scheme (chapter 3b) is levied if commodity prices exceed certain thresholds. This tax is payable on net proceeds from sales (incl. hedging results), less costs and fiscal depreciation and constitutes a repayment of the benefit previously achieved. The repayment cannot exceed the accumulated tax benefit achieved from the special tax incentive rules during the development period. For 2022, Norwegian Energy Company ASA (BlueNord) estimates USD 30.1 million year to date. 3) The cost in the hydrocarbon tax regime is positively impacted by the 39 percent investment uplift on the Tyra Redevelopment project. Reconciliation of nominal to actual tax rate, continues Hydrocarbon tax 64% Corporate tax 22% In total OCI before tax 148.5 35.8 184.3 Expected tax on OCI before tax (95.1) 64% (7.9) 22% (102.9) Tax effect of: Non-taxable currency translation adjustment \u2013 \u2013 \u2013 Tax in OCI (95.1) 64% (7.9) 22% (102.9) Current income tax payable Tax payable relates to the Group\u2019s entities in Denmark. The amounts payable as of 31 December 22 were: Hydrocarbon tax pertaining to pre-acquisition period 2019 not indemnified by the Seller (10.2) Hydrocarbon tax for prior years (Denmark) (12.7) Hydrocarbon and corporate tax for 2021 and 2022 (Denmark) (126.3) Corporate tax for 22% (13.9) Repayment of tax benefit related to chapter 3b (45.9) Tax payables (209.0)
Current income taxes for current and prior periods are measured at the amount that is expected to be paid to or be refunded from the tax
authorities, as at the balance sheet date. Due to the complexity in the legislative framework and the limited amount of guidance from relevant
case law, the measurement of taxable profits within the oil and gas industry is associated with some degree of uncertainty. Uncertain tax
liabilities are recognised with the probable value if their probability is more likely than not. Tax payable of USD 209.0 million, of which
USD 191 million is an actual cash payable to be paid in 2023.
As of 31 December 2022, the Company has provided an estimated USD 10.2 million pertaining to hydrocarbon tax in the part of pre-acquisition
period, which is not indemnified by the Seller.
Deferred tax
Deferred tax assets are measured at the amount that is expected to result in taxes due to temporary differences and the value of tax losses.
The recognised deferred tax asset relates to the following balance sheet items, all pertaining to the Group\u2019s activities on the Danish
continental shelf:
USD million
Deferred tax and deferred tax asset 01.01.22
Effect
recognised in
profit/loss
Effect
recognised in
OCI 31.12.2022
Property, plant and equipment 624.6 11.5 \u2013 636.1
Intangible assets, licences 17. 2 7.9 \u2013 25.1
Inventories and receivables 26.7 2.6 \u2013 29.3
Asset retirement obligation (ARO) provision (611.1) 46.7 \u2013 (564.5)
Other assets and liabilities \u2013 (2.8) \u2013 (2.8)
Tax loss carryforward, corporate tax (22%) (2.0) 0.1 1.9 \u2013
Tax loss carryforward, chapter 2 tax (25%) (22.8) (14.4) 37.1 (0.1)
Tax loss carryforward, chapter 3a tax (52%) (558.3) 28.5 57.9 (471.9)
Deferred tax asset, net (525.7) 80.0 96.9 (348.8)
Tax loss carry forwards
Tax losses are recognised in accordance with the expected utilisation hereof in subsequent income years based on the current business
outlook and economic projections.
Due to the limited taxable activity in UK and Norway, corporate tax losses in these jurisdictions are not capitalised.
Tax losses in Denmark and UK under the hydrocarbon tax regime may be carried forward indefinitely and the utilisation is not subject to an
annual cap. Losses are carried forward in Danish kroner and British pounds.
Tax losses carried forward, Denmark Million DKK
Corporate tax (22%) \u2013
Chapter 2 Hydrocarbon tax (25%) \u2013
Chapter 3a Hydrocarbon tax (52%) 5,773.5
Tax losses carried forward, Norway Million NOK
Corporate tax Norway (22%) 1,071.4
Tax losses carried forward, UK Million GBP/USD
Trade losses, UK (hydrocarbon s 330(2)) 75.0
Trade losses, UK (hydrocarbon), USD 96.0
Pre-trading capital expenditure, UK (hydrocarbon), GBP 41.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-440": { "value": "1 3 Tax Tax rates Producers of oil and gas on the Danish continental shelf are subject to the hydrocarbon tax regime under which, income derived from the sale of oil and gas is taxed at an elevated 64 percent. Any income deriving from other activities than first-time sales of hydrocarbons is taxed at the ordinary corporate income rate of currently 22 percent. The 64 percent is calculated as the sum of the \u201cChapter 2\u201d tax of 25 percent plus a specific hydrocarbon tax (chapter 3a) of 52 percent, in which the 25 percent tax payable is deductible. Income generated in Norway and United Kingdom is subject to regular corporate tax at 22 percent. Tax expense USD million Income tax in profit/loss (Danish corporate income tax and hydrocarbon tax) 2022 Income tax current year (139.9) Repayment of tax benefit related to chapter 3b (62.7) Income tax for prior years (2.0) Current income tax (204.6) Deferred tax movements (65.9) Prior year adjustment, deferred tax (8.6) Deferred tax expense (74.5) Tax (expense)/income (279.2) Income tax in profit/loss is solely derived from the Group\u2019s activities on the Danish continental shelf, of which the major part is subject to the elevated 64 percent hydrocarbon tax. Tax (expense)/income related to OCI Cash flow hedges (102.9) Tax (expense)/income related to OCI (102.9) Income tax on OCI is related to the unrealised fair value changes in derivatives designated in cash flow hedges. To the extent derivatives are associated with the sale of oil and gas, results from cash flow hedges are subject to 64 percent hydrocarbon tax. Reconciliation of nominal to actual tax rate Hydrocarbon tax 64% Corporate tax 22% In total Result before tax 364.1 (115.4) 248.7 Expected tax on profit before tax 233.0 64% (25.4) 22% 207.6 Tax effect of: Prior year adjustment 9.6 3% 0.2 0% 9.8 FX adjustment of net operating losses carried forward in DKK1) 37.3 10% \u2013 0% 37. 3 Repayment of tax benefit related to chapter 3b2) 30.1 8% \u2013 0% 30.1 Investment uplift on CAPEX projects3) (36.8) (10%) \u2013 0% (36.8) Permanent differences \u2013 0% 29.1 (25%) 29.1 No recognition of tax assets in Norway and UK \u2013 0% 2.0 2% 2.0 Tax expense (income) in profit/loss 273.2 75% 6.0 5% 279.2 1) Deferred tax movement no cash effect. 2) From 2022 onwards, an additional tax cost related to the special tax incentive scheme (chapter 3b) is levied if commodity prices exceed certain thresholds. This tax is payable on net proceeds from sales (incl. hedging results), less costs and fiscal depreciation and constitutes a repayment of the benefit previously achieved. The repayment cannot exceed the accumulated tax benefit achieved from the special tax incentive rules during the development period. For 2022, Norwegian Energy Company ASA (BlueNord) estimates USD 30.1 million year to date. 3) The cost in the hydrocarbon tax regime is positively impacted by the 39 percent investment uplift on the Tyra Redevelopment project. Reconciliation of nominal to actual tax rate, continues Hydrocarbon tax 64% Corporate tax 22% In total OCI before tax 148.5 35.8 184.3 Expected tax on OCI before tax (95.1) 64% (7.9) 22% (102.9) Tax effect of: Non-taxable currency translation adjustment \u2013 \u2013 \u2013 Tax in OCI (95.1) 64% (7.9) 22% (102.9) Current income tax payable Tax payable relates to the Group\u2019s entities in Denmark. The amounts payable as of 31 December 22 were: Hydrocarbon tax pertaining to pre-acquisition period 2019 not indemnified by the Seller (10.2) Hydrocarbon tax for prior years (Denmark) (12.7) Hydrocarbon and corporate tax for 2021 and 2022 (Denmark) (126.3) Corporate tax for 22% (13.9) Repayment of tax benefit related to chapter 3b (45.9) Tax payables (209.0) Current income taxes for current and prior periods are measured at the amount that is expected to be paid to or be refunded from the tax authorities, as at the balance sheet date. Due to the complexity in the legislative framework and the limited amount of guidance from relevant case law, the measurement of taxable profits within the oil and gas industry is associated with some degree of uncertainty. Uncertain tax liabilities are recognised with the probable value if their probability is more likely than not. Tax payable of USD 209.0 million, of which USD 191 million is an actual cash payable to be paid in 2023. As of 31 December 2022, the Company has provided an estimated USD 10.2 million pertaining to hydrocarbon tax in the part of pre-acquisition period, which is not indemnified by the Seller. Deferred tax Deferred tax assets are measured at the amount that is expected to result in taxes due to temporary differences and the value of tax losses. The recognised deferred tax asset relates to the following balance sheet items, all pertaining to the Group\u2019s activities on the Danish continental shelf: USD million Deferred tax and deferred tax asset 01.01.22 Effect recognised in profit/loss Effect recognised in OCI 31.12.2022 Property, plant and equipment 624.6 11.5 \u2013 636.1 Intangible assets, licences 17. 2 7.9 \u2013 25.1 Inventories and receivables 26.7 2.6 \u2013 29.3 Asset retirement obligation (ARO) provision (611.1) 46.7 \u2013 (564.5) Other assets and liabilities \u2013 (2.8) \u2013 (2.8) Tax loss carryforward, corporate tax (22%) (2.0) 0.1 1.9 \u2013 Tax loss carryforward, chapter 2 tax (25%) (22.8) (14.4) 37.1 (0.1) Tax loss carryforward, chapter 3a tax (52%) (558.3) 28.5 57.9 (471.9) Deferred tax asset, net (525.7) 80.0 96.9 (348.8) Tax loss carry forwards Tax losses are recognised in accordance with the expected utilisation hereof in subsequent income years based on the current business outlook and economic projections. Due to the limited taxable activity in UK and Norway, corporate tax losses in these jurisdictions are not capitalised. Tax losses in Denmark and UK under the hydrocarbon tax regime may be carried forward indefinitely and the utilisation is not subject to an annual cap. Losses are carried forward in Danish kroner and British pounds. Tax losses carried forward, Denmark Million DKK Corporate tax (22%) \u2013 Chapter 2 Hydrocarbon tax (25%) \u2013 Chapter 3a Hydrocarbon tax (52%) 5,773.5 Tax losses carried forward, Norway Million NOK Corporate tax Norway (22%) 1,071.4 Tax losses carried forward, UK Million GBP/USD Trade losses, UK (hydrocarbon s 330(2)) 75.0 Trade losses, UK (hydrocarbon), USD 96.0 Pre-trading capital expenditure, UK (hydrocarbon), GBP 41.0 ", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-456": { "value": "3 Tax Tax rates Producers of oil and gas on the Danish continental shelf are subject to the hydrocarbon tax regime under which, income derived from the sale of oil and gas is taxed at an elevated 64 percent. Any income deriving from other activities than first-time sales of hydrocarbons is taxed at the ordinary corporate income rate of currently 22 percent. The 64 percent is calculated as the sum of the \u201cChapter 2\u201d tax of 25 percent plus a specific hydrocarbon tax (chapter 3a) of 52 percent, in which the 25 percent tax payable is deductible. Income generated in Norway and United Kingdom is subject to regular corporate tax at 22 percent. Tax expense USD million Income tax in profit/loss (Danish corporate income tax and hydrocarbon tax) 2022 Income tax current year (139.9) Repayment of tax benefit related to chapter 3b (62.7) Income tax for prior years (2.0) Current income tax (204.6) Deferred tax movements (65.9) Prior year adjustment, deferred tax (8.6) Deferred tax expense (74.5) Tax (expense)/income (279.2) Income tax in profit/loss is solely derived from the Group\u2019s activities on the Danish continental shelf, of which the major part is subject to the elevated 64 percent hydrocarbon tax. Tax (expense)/income related to OCI Cash flow hedges (102.9) Tax (expense)/income related to OCI (102.9) Income tax on OCI is related to the unrealised fair value changes in derivatives designated in cash flow hedges. To the extent derivatives are associated with the sale of oil and gas, results from cash flow hedges are subject to 64 percent hydrocarbon tax. Reconciliation of nominal to actual tax rate Hydrocarbon tax 64% Corporate tax 22% In total Result before tax 364.1 (115.4) 248.7 Expected tax on profit before tax 233.0 64% (25.4) 22% 207.6 Tax effect of: Prior year adjustment 9.6 3% 0.2 0% 9.8 FX adjustment of net operating losses carried forward in DKK1) 37.3 10% \u2013 0% 37. 3 Repayment of tax benefit related to chapter 3b2) 30.1 8% \u2013 0% 30.1 Investment uplift on CAPEX projects3) (36.8) (10%) \u2013 0% (36.8) Permanent differences \u2013 0% 29.1 (25%) 29.1 No recognition of tax assets in Norway and UK \u2013 0% 2.0 2% 2.0 Tax expense (income) in profit/loss 273.2 75% 6.0 5% 279.2 1) Deferred tax movement no cash effect. 2) From 2022 onwards, an additional tax cost related to the special tax incentive scheme (chapter 3b) is levied if commodity prices exceed certain thresholds. This tax is payable on net proceeds from sales (incl. hedging results), less costs and fiscal depreciation and constitutes a repayment of the benefit previously achieved. The repayment cannot exceed the accumulated tax benefit achieved from the special tax incentive rules during the development period. For 2022, Norwegian Energy Company ASA (BlueNord) estimates USD 30.1 million year to date. 3) The cost in the hydrocarbon tax regime is positively impacted by the 39 percent investment uplift on the Tyra Redevelopment project. Reconciliation of nominal to actual tax rate, continues Hydrocarbon tax 64% Corporate tax 22% In total OCI before tax 148.5 35.8 184.3 Expected tax on OCI before tax (95.1) 64% (7.9) 22% (102.9) Tax effect of: Non-taxable currency translation adjustment \u2013 \u2013 \u2013 Tax in OCI (95.1) 64% (7.9) 22% (102.9) Current income tax payable Tax payable relates to the Group\u2019s entities in Denmark. The amounts payable as of 31 December 22 were: Hydrocarbon tax pertaining to pre-acquisition period 2019 not indemnified by the Seller (10.2) Hydrocarbon tax for prior years (Denmark) (12.7) Hydrocarbon and corporate tax for 2021 and 2022 (Denmark) (126.3) Corporate tax for 22% (13.9) Repayment of tax benefit related to chapter 3b (45.9) Tax payables (209.0) Current income taxes for current and prior periods are measured at the amount that is expected to be paid to or be refunded from the tax authorities, as at the balance sheet date. Due to the complexity in the legislative framework and the limited amount of guidance from relevant case law, the measurement of taxable profits within the oil and gas industry is associated with some degree of uncertainty. Uncertain tax liabilities are recognised with the probable value if their probability is more likely than not. Tax payable of USD 209.0 million, of which USD 191 million is an actual cash payable to be paid in 2023. As of 31 December 2022, the Company has provided an estimated USD 10.2 million pertaining to hydrocarbon tax in the part of pre-acquisition period, which is not indemnified by the Seller. Deferred tax Deferred tax assets are measured at the amount that is expected to result in taxes due to temporary differences and the value of tax losses. The recognised deferred tax asset relates to the following balance sheet items, all pertaining to the Group\u2019s activities on the Danish continental shelf: USD million Deferred tax and deferred tax asset 01.01.22 Effect recognised in profit/loss Effect recognised in OCI 31.12.2022 Property, plant and equipment 624.6 11.5 \u2013 636.1 Intangible assets, licences 17. 2 7.9 \u2013 25.1 Inventories and receivables 26.7 2.6 \u2013 29.3 Asset retirement obligation (ARO) provision (611.1) 46.7 \u2013 (564.5) Other assets and liabilities \u2013 (2.8) \u2013 (2.8) Tax loss carryforward, corporate tax (22%) (2.0) 0.1 1.9 \u2013 Tax loss carryforward, chapter 2 tax (25%) (22.8) (14.4) 37.1 (0.1) Tax loss carryforward, chapter 3a tax (52%) (558.3) 28.5 57.9 (471.9) Deferred tax asset, net (525.7) 80.0 96.9 (348.8) Tax loss carry forwards Tax losses are recognised in accordance with the expected utilisation hereof in subsequent income years based on the current business outlook and economic projections. Due to the limited taxable activity in UK and Norway, corporate tax losses in these jurisdictions are not capitalised. Tax losses in Denmark and UK under the hydrocarbon tax regime may be carried forward indefinitely and the utilisation is not subject to an annual cap. Losses are carried forward in Danish kroner and British pounds. Tax losses carried forward, Denmark Million DKK Corporate tax (22%) \u2013 Chapter 2 Hydrocarbon tax (25%) \u2013 Chapter 3a Hydrocarbon tax (52%) 5,773.5 Tax losses carried forward, Norway Million NOK Corporate tax Norway (22%) 1,071.4 Tax losses carried forward, UK Million GBP/USD Trade losses, UK (hydrocarbon s 330(2)) 75.0 Trade losses, UK (hydrocarbon), USD 96.0 Pre-trading capital expenditure, UK (hydrocarbon), GBP 41.0 ", "dimensions": { "concept": "ifrs-full:DisclosureOfTaxReceivablesAndPayablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-404": { "value": "
14 Earnings per share
Earnings per share are calculated by dividing the profit attributable to ordinary shareholders of the parent company by the weighted average
number of ordinary shares in issue during the year.
USD million 2022 2021
Profit (loss) attributable to ordinary shareholders from operations (31) (53)
Profit (loss) basis for fully diluted shareholders from operations 131 (33)
Weighted average number of shares (basic) 25,004,296 24,110,852
Adjustments convertible bond loan 5,822,649 11,149,488
Adjustments option schemes 391,868 \u2013
Weighted average number of shares (diluted) 31,218,813 35,260,340
Earnings per share in USD (1.2) (2.2)
Earnings per share in USD diluted (1.2) (2.2)
", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-405": { "value": "
15 Trade receivables and other current receivables
USD million 2022 2021
Non-current assets
Convertible loan CarbonCuts 0.2 \u2013
Loan CarbonCuts 0.6 \u2013
Total non-current receivables 0.8 \u2013
Current assets
Trade receivables 42.1 40.4
Accrued revenue 52.3 47.1
Under-lift of oil/NGL 8.9 1.2
Prepayments 24.2 20.1
Other receivables 1.1 0.2
Total trade receivables and other current receivables 128.6 108.9
Ageing analysis of trade receivables on 31 December 2022
Past due
USD million Total Not past due > 30 days 30-60 days 61-90 days 91-120 days > 120 days
Trade receivables 42.1 42.1 \u2013 \u2013 \u2013 \u2013 \u2013
Total 42.1 42.1 \u2013 \u2013 \u2013 \u2013 \u2013
Ageing analysis of trade receivables on 31 December 2021
Past due
USD million Tot al Not past due > 30 days 30-60 days 61-90 days 91-120 days > 120 days
Trade receivables 40.4 38.2 \u2013 \u2013 \u2013 \u2013 2.2
Total 40.4 38.2 \u2013 \u2013 \u2013 \u2013 2.2
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-465": { "value": "15 Trade receivables and other current receivables USD million 2022 2021 Non-current assets Convertible loan CarbonCuts 0.2 \u2013 Loan CarbonCuts 0.6 \u2013 Total non-current receivables 0.8 \u2013 Current assets Trade receivables 42.1 40.4 Accrued revenue 52.3 47.1 Under-lift of oil/NGL 8.9 1.2 Prepayments 24.2 20.1 Other receivables 1.1 0.2 Total trade receivables and other current receivables 128.6 108.9 Ageing analysis of trade receivables on 31 December 2022 Past due USD million Total Not past due > 30 days 30-60 days 61-90 days 91-120 days > 120 days Trade receivables 42.1 42.1 \u2013 \u2013 \u2013 \u2013 \u2013 Total 42.1 42.1 \u2013 \u2013 \u2013 \u2013 \u2013 Ageing analysis of trade receivables on 31 December 2021 Past due USD million Tot al Not past due > 30 days 30-60 days 61-90 days 91-120 days > 120 days Trade receivables 40.4 38.2 \u2013 \u2013 \u2013 \u2013 2.2 Total 40.4 38.2 \u2013 \u2013 \u2013 \u2013 2.2 ", "dimensions": { "concept": "ifrs-full:DisclosureOfPrepaymentsAndOtherAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-457": { "value": "15 Trade receivables and other current receivables USD million 2022 2021 Non-current assets Convertible loan CarbonCuts 0.2 \u2013 Loan CarbonCuts 0.6 \u2013 Total non-current receivables 0.8 \u2013 Current assets Trade receivables 42.1 40.4 Accrued revenue 52.3 47.1 Under-lift of oil/NGL 8.9 1.2 Prepayments 24.2 20.1 Other receivables 1.1 0.2 Total trade receivables and other current receivables 128.6 108.9 Ageing analysis of trade receivables on 31 December 2022 Past due USD million Total Not past due > 30 days 30-60 days 61-90 days 91-120 days > 120 days Trade receivables 42.1 42.1 \u2013 \u2013 \u2013 \u2013 \u2013 Total 42.1 42.1 \u2013 \u2013 \u2013 \u2013 \u2013 Ageing analysis of trade receivables on 31 December 2021 Past due USD million Tot al Not past due > 30 days 30-60 days 61-90 days 91-120 days > 120 days Trade receivables 40.4 38.2 \u2013 \u2013 \u2013 \u2013 2.2 Total 40.4 38.2 \u2013 \u2013 \u2013 \u2013 2.2 ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-441": { "value": "15 Trade receivables and other current receivables USD million 2022 2021 Non-current assets Convertible loan CarbonCuts 0.2 \u2013 Loan CarbonCuts 0.6 \u2013 Total non-current receivables 0.8 \u2013 Current assets Trade receivables 42.1 40.4 Accrued revenue 52.3 47.1 Under-lift of oil/NGL 8.9 1.2 Prepayments 24.2 20.1 Other receivables 1.1 0.2 Total trade receivables and other current receivables 128.6 108.9 Ageing analysis of trade receivables on 31 December 2022 Past due USD million Total Not past due > 30 days 30-60 days 61-90 days 91-120 days > 120 days Trade receivables 42.1 42.1 \u2013 \u2013 \u2013 \u2013 \u2013 Total 42.1 42.1 \u2013 \u2013 \u2013 \u2013 \u2013 Ageing analysis of trade receivables on 31 December 2021 Past due USD million Tot al Not past due > 30 days 30-60 days 61-90 days 91-120 days > 120 days Trade receivables 40.4 38.2 \u2013 \u2013 \u2013 \u2013 2.2 Total 40.4 38.2 \u2013 \u2013 \u2013 \u2013 2.2 ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-406": { "value": "
16 Inventories
USD million 2022 2021
Product inventory, oil 21.6 17.7
Other stock (spares and consumables)* 34.3 33.8
Total inventories 55.9 51.4
* As of 31.12.2022 there are no provisions for obsolete stock.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-407": { "value": "
17 Restricted cash, bank deposits, cash and cash equivalents
USD million 2022 2021
Non-current assets
Restricted cash pledged as security for abandonment obligation related to Nini/Cecilie 61.1 65.0
Restricted cash pledged as security for cash call obligations towards TotalEnergies
1)
142.5 140.5
Total non-current restricted cash 203.7 205.5
Current assets
Unrestricted cash, bank deposits, cash equivalents 268.4 122.7
Total bank deposits 472.1 328.1
1) Norwegian Energy Company ASA (BlueNord) has made a USD 140 million deposit into a cash call security account in accordance with a cash call security agreement with TotalEnergies
E&P Denmark A/S as operator of the DUC. All payment obligations from Norwegian Energy Company ASA (BlueNord) to the cash call security account have been made and there will be
no further increase.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRestrictedCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-458": { "value": "17 Restricted cash, bank deposits, cash and cash equivalents USD million 2022 2021 Non-current assets Restricted cash pledged as security for abandonment obligation related to Nini/Cecilie 61.1 65.0 Restricted cash pledged as security for cash call obligations towards TotalEnergies 1) 142.5 140.5 Total non-current restricted cash 203.7 205.5 Current assets Unrestricted cash, bank deposits, cash equivalents 268.4 122.7 Total bank deposits 472.1 328.1 1) Norwegian Energy Company ASA (BlueNord) has made a USD 140 million deposit into a cash call security account in accordance with a cash call security agreement with TotalEnergies E&P Denmark A/S as operator of the DUC. All payment obligations from Norwegian Energy Company ASA (BlueNord) to the cash call security account have been made and there will be no further increase. ", "dimensions": { "concept": "ifrs-full:DisclosureOfDepositsFromBanksExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-442": { "value": "17 Restricted cash, bank deposits, cash and cash equivalents USD million 2022 2021 Non-current assets Restricted cash pledged as security for abandonment obligation related to Nini/Cecilie 61.1 65.0 Restricted cash pledged as security for cash call obligations towards TotalEnergies 1) 142.5 140.5 Total non-current restricted cash 203.7 205.5 Current assets Unrestricted cash, bank deposits, cash equivalents 268.4 122.7 Total bank deposits 472.1 328.1 1) Norwegian Energy Company ASA (BlueNord) has made a USD 140 million deposit into a cash call security account in accordance with a cash call security agreement with TotalEnergies E&P Denmark A/S as operator of the DUC. All payment obligations from Norwegian Energy Company ASA (BlueNord) to the cash call security account have been made and there will be no further increase. ", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-408": { "value": "
18 Financial instruments
18.1 Fair value hierarchy
The table below analyses financial instruments carried at fair value, by valuation method.
The different levels have been defined as follows:
Level 1 Quoted prices (unadjusted) in active markets for identical assets or liabilities.
Level 2 Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.
Level 3 Inputs for the asset or liability that are not based on observable market data.
On 31 December 2022
USD million Level 1 Level 2 Level 3 Total
Assets
Financial assets at fair value through profit or loss
- Derivative instruments interest swap \u2013 11.1 \u2013 11.1
Financial assets at fair value hedging instruments
- Derivative instruments interest swap \u2013 44.6 \u2013 44.6
- Derivative instruments price hedge \u2013 108.9 \u2013 108.9
Total assets \u2013 164.6 \u2013 164.6
Liabilities
Financial liabilities at fair value through profit or loss
- Embedded derivatives convertible bond NOR13 \u2013 \u2013 10.0 10.0
- Embedded derivatives convertible bond NOR15 \u2013 \u2013 38.9 38. 9
Financial liabilities at fair value hedging instruments
- Derivative instruments price hedge \u2013 166.8 \u2013 166.8
Total liabilities \u2013 166.8 48.9 215.7
On 31 December 2021
USD million Level 1 Level 2 Level 3 Tota l
Assets
Financial assets at fair value through profit or loss
- Derivative instruments interest swap \u2013 1.0 \u2013 1.0
Financial assets at fair value hedging instruments
- Derivative instruments interest swap \u2013 8.8 \u2013 8. 8
Total assets \u2013 9.7 \u2013 9.7
Liabilities
Financial liabilities at fair value through profit or loss
- Embedded derivatives convertible bond NOR13 \u2013 \u2013 12.1 12.1
Financial liabilities at fair value hedging instruments
- Derivative instruments price hedge \u2013 205.1 \u2013 205.1
Total liabilities \u2013 205.1 12.1 217.2
18.2 Financial instruments by category On 31 December 2022 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Total Assets Convertible loan CarbonCuts 0.2 \u2013 \u2013 0.2 Loan CarbonCuts 0.6 \u2013 \u2013 0.6 Derivative instruments interest swap \u2013 \u2013 55.7 55.7 Derivative instruments price hedge \u2013 \u2013 108.9 108.9 Trade receivables and other current assets 128.6 \u2013 \u2013 128.6 Restricted cash 203.7 \u2013 \u2013 203.7 Bank deposits, cash and cash equivalents 268.4 \u2013 \u2013 268.4 Total 601.5 \u2013 164.6 766.1 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Total Liabilities Derivative instruments price hedge \u2013 \u2013 166.8 166.8 Embedded derivatives convertible bond NOR13 \u2013 10.0 \u2013 10.0 Embedded derivatives convertible bond NOR15 \u2013 38.9 \u2013 38.9 Convertible bond loans 188.7 \u2013 \u2013 188.7 Senior unsecured bond loan 166.9 \u2013 \u2013 166.9 Reserve-based lending facility 764.0 \u2013 \u2013 764.0 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 115.6 \u2013 \u2013 115.6 Total 1,260.2 48.9 166.8 1,476.0 On 31 December 2021 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Assets Derivative instruments price hedge \u2013 \u2013 9.7 9.7 Trade receivables and other current assets 108.9 \u2013 \u2013 108.9 Restricted cash 205.5 \u2013 \u2013 205.5 Bank deposits, cash and cash equivalents 122.7 \u2013 \u2013 122.7 Total 437.0 \u2013 9.7 446.8 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Liabilities Derivative instruments price hedge \u2013 \u2013 205.1 205.1 Embedded derivatives convertible bond NOR13 \u2013 12.1 \u2013 12.1 Convertible bond loans 157.1 \u2013 \u2013 157.1 Senior unsecured bond loan 164.9 \u2013 \u2013 164.9 Reserve-based lending facility 857.3 \u2013 \u2013 857.3 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 130.5 \u2013 \u2013 130.5 Total 1,334.8 12.1 205.1 1,552.1 18.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments as at 31 December 2022: USD million Total amount outstanding* Carrying amount Fair value Financial assets Convertible loan CarbonCuts 0.2 0.2 Loan CarbonCuts 0.6 0.6 Derivative instruments interest swap 55.7 55.7 Derivative instruments price hedge 108.9 108.9 Trade receivables and other current assets 128.6 128.6 Restricted cash 203.7 203.7 Bank deposits, cash, cash equivalents and quoted shares 268.4 268.4 Total 766.1 766.1 Financial liabilities Derivative instruments price hedge 166.8 166.8 Embedded derivative convertible bond NOR13 10.0 10.0 Embedded derivative convertible bond NOR15 38.9 38.9 Convertible bond loans 221.5 188.7 211.5 Senior unsecured bond loan 175.0 166.9 175.0 Reserve-based lending facility 800.0 764.0 800.0 Deferred consideration 25.0 25.0 Trade payables and other current liabilities 115.6 115.6 Total 1,196.5 1,476.0 1,542.8 * Total amount outstanding on the bonds and under the RBL facility. The NOR13 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 10.0 million due to the majority of the NOR13 instrument being converted into the new NOR15 instrument. On 13 January 2022, the majority of the remaining NOR13 convertible instrument was converted into equity, leaving only USD 0.2 million which will be subject to the NOR13 amendments as proposed by the company in November 2022. The NOR15 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost, a total of USD 4.4 million in transaction cost is included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 38.9 million. The assumptions in establishing the option value as of 31 December 2022 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives: NOR13 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 24 Jul 19 Par value of bonds (USD) 13,810,094 Reference share price at time of agreement (NOK) 232 Fair value at grant date (USD) 53,942,754 PIK interest rate (%) 8.00% Expected life (years) 0.9 Number of options (#) 476,648 Conversion price (NOK) 238 Fixed FX rate of agreement (USD:NOK) 8.180 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton NOR15 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 30 Dec 22 Par value of bonds (USD) 207,641,201 Reference share price at time of agreement (NOK) 395 Fair value at grant date (USD) 38,928,552 PIK interest rate (%) 8.00% Expected life (years) 3.0 Number of options (#) 4,037,301 Conversion price (NOK) 537 Fixed FX rate of agreement (USD:NOK) 10.440 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton The RBL facility is measured at amortised cost, in addition a total of USD 53 million in transaction cost has been capitalised. Transaction costs are deducted from the amount initially recognised and are expensed over the period during which the debt is outstanding under the effective interest method. The senior unsecured bond loan is measured at amortised cost; a total of USD 7.6 million in transaction costs are deducted from the amount initially recognised. 18.4 Hedging The Group actively seeks to reduce the risk it is exposed to regarding fluctuating commodity prices through the establishment of hedging arrangements. To the extent more than 100 percent of the projected production is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. In 2022 no part of the hedging instruments was considered ineffective. Time value related to hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value. Currently, all the Company\u2019s commodity price hedging arrangements is executed solely in the market through forward contracts. Under its RBL facility, Norwegian Energy Company ASA (BlueNord) has a rolling hedge requirement based on a minimum level of production corresponding to the RBL banking case forecast. The Company has entered into a USD 1.0 billion swap transaction with a group of banks to fix the Company\u2019s floating interest rate exposure under its RBL facility from 1 November 2021 until 30 June 2024. Norwegian Energy Company ASA (BlueNord) will as a result pay interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin. Norwegian Energy Company ASA (BlueNord) applies hedge accounting to the Company\u2019s hedging arrangements. To the extent more than 100 percent of the Company\u2019s interest under its RBL facility is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. The ineffective amount in 2022 charged to financial items in the income statement were an income of USD 10.2 million. As at 31 December 2022 Maturity Less than one month One to three months Three to six months Six to nine months Nine to 12 months More than 12 months Commodity forward sales contracts: Notional quantity (in mboe) \u2013 1,448 1,350 990 937 3,391 Notional amount (in USD million) \u2013 134 104 88 76 246 Average hedged sales price (in USD per boe) \u2013 92 77 89 81 72 Hedge reserve movement The table below shows the movement in the hedge reserve from changes in the cash flow hedges. USD million Hedge reserve Balance as of 1 January 2022 (67.5) Realised cash flow hedge 242.2 Related tax \u2013 realised cash flow hedge (155.0) Changes in fair value (57.9) Related tax \u2013 changes in fair value 52.1 Balance as of 31 December 2022 13.9 ", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-473": { "value": "18 Financial instruments 18.1 Fair value hierarchy The table below analyses financial instruments carried at fair value, by valuation method. The different levels have been defined as follows: Level 1 Quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 Inputs for the asset or liability that are not based on observable market data. On 31 December 2022 USD million Level 1 Level 2 Level 3 Total Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 11.1 \u2013 11.1 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 44.6 \u2013 44.6 - Derivative instruments price hedge \u2013 108.9 \u2013 108.9 Total assets \u2013 164.6 \u2013 164.6 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 10.0 10.0 - Embedded derivatives convertible bond NOR15 \u2013 \u2013 38.9 38. 9 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 166.8 \u2013 166.8 Total liabilities \u2013 166.8 48.9 215.7 On 31 December 2021 USD million Level 1 Level 2 Level 3 Tota l Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 1.0 \u2013 1.0 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 8.8 \u2013 8. 8 Total assets \u2013 9.7 \u2013 9.7 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 12.1 12.1 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 205.1 \u2013 205.1 Total liabilities \u2013 205.1 12.1 217.2 18.2 Financial instruments by category On 31 December 2022 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Total Assets Convertible loan CarbonCuts 0.2 \u2013 \u2013 0.2 Loan CarbonCuts 0.6 \u2013 \u2013 0.6 Derivative instruments interest swap \u2013 \u2013 55.7 55.7 Derivative instruments price hedge \u2013 \u2013 108.9 108.9 Trade receivables and other current assets 128.6 \u2013 \u2013 128.6 Restricted cash 203.7 \u2013 \u2013 203.7 Bank deposits, cash and cash equivalents 268.4 \u2013 \u2013 268.4 Total 601.5 \u2013 164.6 766.1 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Total Liabilities Derivative instruments price hedge \u2013 \u2013 166.8 166.8 Embedded derivatives convertible bond NOR13 \u2013 10.0 \u2013 10.0 Embedded derivatives convertible bond NOR15 \u2013 38.9 \u2013 38.9 Convertible bond loans 188.7 \u2013 \u2013 188.7 Senior unsecured bond loan 166.9 \u2013 \u2013 166.9 Reserve-based lending facility 764.0 \u2013 \u2013 764.0 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 115.6 \u2013 \u2013 115.6 Total 1,260.2 48.9 166.8 1,476.0 On 31 December 2021 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Assets Derivative instruments price hedge \u2013 \u2013 9.7 9.7 Trade receivables and other current assets 108.9 \u2013 \u2013 108.9 Restricted cash 205.5 \u2013 \u2013 205.5 Bank deposits, cash and cash equivalents 122.7 \u2013 \u2013 122.7 Total 437.0 \u2013 9.7 446.8 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Liabilities Derivative instruments price hedge \u2013 \u2013 205.1 205.1 Embedded derivatives convertible bond NOR13 \u2013 12.1 \u2013 12.1 Convertible bond loans 157.1 \u2013 \u2013 157.1 Senior unsecured bond loan 164.9 \u2013 \u2013 164.9 Reserve-based lending facility 857.3 \u2013 \u2013 857.3 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 130.5 \u2013 \u2013 130.5 Total 1,334.8 12.1 205.1 1,552.1 18.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments as at 31 December 2022: USD million Total amount outstanding* Carrying amount Fair value Financial assets Convertible loan CarbonCuts 0.2 0.2 Loan CarbonCuts 0.6 0.6 Derivative instruments interest swap 55.7 55.7 Derivative instruments price hedge 108.9 108.9 Trade receivables and other current assets 128.6 128.6 Restricted cash 203.7 203.7 Bank deposits, cash, cash equivalents and quoted shares 268.4 268.4 Total 766.1 766.1 Financial liabilities Derivative instruments price hedge 166.8 166.8 Embedded derivative convertible bond NOR13 10.0 10.0 Embedded derivative convertible bond NOR15 38.9 38.9 Convertible bond loans 221.5 188.7 211.5 Senior unsecured bond loan 175.0 166.9 175.0 Reserve-based lending facility 800.0 764.0 800.0 Deferred consideration 25.0 25.0 Trade payables and other current liabilities 115.6 115.6 Total 1,196.5 1,476.0 1,542.8 * Total amount outstanding on the bonds and under the RBL facility. The NOR13 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 10.0 million due to the majority of the NOR13 instrument being converted into the new NOR15 instrument. On 13 January 2022, the majority of the remaining NOR13 convertible instrument was converted into equity, leaving only USD 0.2 million which will be subject to the NOR13 amendments as proposed by the company in November 2022. The NOR15 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost, a total of USD 4.4 million in transaction cost is included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 38.9 million. The assumptions in establishing the option value as of 31 December 2022 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives: NOR13 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 24 Jul 19 Par value of bonds (USD) 13,810,094 Reference share price at time of agreement (NOK) 232 Fair value at grant date (USD) 53,942,754 PIK interest rate (%) 8.00% Expected life (years) 0.9 Number of options (#) 476,648 Conversion price (NOK) 238 Fixed FX rate of agreement (USD:NOK) 8.180 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton NOR15 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 30 Dec 22 Par value of bonds (USD) 207,641,201 Reference share price at time of agreement (NOK) 395 Fair value at grant date (USD) 38,928,552 PIK interest rate (%) 8.00% Expected life (years) 3.0 Number of options (#) 4,037,301 Conversion price (NOK) 537 Fixed FX rate of agreement (USD:NOK) 10.440 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton The RBL facility is measured at amortised cost, in addition a total of USD 53 million in transaction cost has been capitalised. Transaction costs are deducted from the amount initially recognised and are expensed over the period during which the debt is outstanding under the effective interest method. The senior unsecured bond loan is measured at amortised cost; a total of USD 7.6 million in transaction costs are deducted from the amount initially recognised. 18.4 Hedging The Group actively seeks to reduce the risk it is exposed to regarding fluctuating commodity prices through the establishment of hedging arrangements. To the extent more than 100 percent of the projected production is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. In 2022 no part of the hedging instruments was considered ineffective. Time value related to hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value. Currently, all the Company\u2019s commodity price hedging arrangements is executed solely in the market through forward contracts. Under its RBL facility, Norwegian Energy Company ASA (BlueNord) has a rolling hedge requirement based on a minimum level of production corresponding to the RBL banking case forecast. The Company has entered into a USD 1.0 billion swap transaction with a group of banks to fix the Company\u2019s floating interest rate exposure under its RBL facility from 1 November 2021 until 30 June 2024. Norwegian Energy Company ASA (BlueNord) will as a result pay interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin. Norwegian Energy Company ASA (BlueNord) applies hedge accounting to the Company\u2019s hedging arrangements. To the extent more than 100 percent of the Company\u2019s interest under its RBL facility is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. The ineffective amount in 2022 charged to financial items in the income statement were an income of USD 10.2 million. As at 31 December 2022 Maturity Less than one month One to three months Three to six months Six to nine months Nine to 12 months More than 12 months Commodity forward sales contracts: Notional quantity (in mboe) \u2013 1,448 1,350 990 937 3,391 Notional amount (in USD million) \u2013 134 104 88 76 246 Average hedged sales price (in USD per boe) \u2013 92 77 89 81 72 Hedge reserve movement The table below shows the movement in the hedge reserve from changes in the cash flow hedges. USD million Hedge reserve Balance as of 1 January 2022 (67.5) Realised cash flow hedge 242.2 Related tax \u2013 realised cash flow hedge (155.0) Changes in fair value (57.9) Related tax \u2013 changes in fair value 52.1 Balance as of 31 December 2022 13.9 ", "dimensions": { "concept": "ifrs-full:DisclosureOfDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-472": { "value": "18 Financial instruments 18.1 Fair value hierarchy The table below analyses financial instruments carried at fair value, by valuation method. The different levels have been defined as follows: Level 1 Quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 Inputs for the asset or liability that are not based on observable market data. On 31 December 2022 USD million Level 1 Level 2 Level 3 Total Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 11.1 \u2013 11.1 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 44.6 \u2013 44.6 - Derivative instruments price hedge \u2013 108.9 \u2013 108.9 Total assets \u2013 164.6 \u2013 164.6 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 10.0 10.0 - Embedded derivatives convertible bond NOR15 \u2013 \u2013 38.9 38. 9 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 166.8 \u2013 166.8 Total liabilities \u2013 166.8 48.9 215.7 On 31 December 2021 USD million Level 1 Level 2 Level 3 Tota l Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 1.0 \u2013 1.0 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 8.8 \u2013 8. 8 Total assets \u2013 9.7 \u2013 9.7 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 12.1 12.1 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 205.1 \u2013 205.1 Total liabilities \u2013 205.1 12.1 217.2 18.2 Financial instruments by category On 31 December 2022 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Total Assets Convertible loan CarbonCuts 0.2 \u2013 \u2013 0.2 Loan CarbonCuts 0.6 \u2013 \u2013 0.6 Derivative instruments interest swap \u2013 \u2013 55.7 55.7 Derivative instruments price hedge \u2013 \u2013 108.9 108.9 Trade receivables and other current assets 128.6 \u2013 \u2013 128.6 Restricted cash 203.7 \u2013 \u2013 203.7 Bank deposits, cash and cash equivalents 268.4 \u2013 \u2013 268.4 Total 601.5 \u2013 164.6 766.1 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Total Liabilities Derivative instruments price hedge \u2013 \u2013 166.8 166.8 Embedded derivatives convertible bond NOR13 \u2013 10.0 \u2013 10.0 Embedded derivatives convertible bond NOR15 \u2013 38.9 \u2013 38.9 Convertible bond loans 188.7 \u2013 \u2013 188.7 Senior unsecured bond loan 166.9 \u2013 \u2013 166.9 Reserve-based lending facility 764.0 \u2013 \u2013 764.0 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 115.6 \u2013 \u2013 115.6 Total 1,260.2 48.9 166.8 1,476.0 On 31 December 2021 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Assets Derivative instruments price hedge \u2013 \u2013 9.7 9.7 Trade receivables and other current assets 108.9 \u2013 \u2013 108.9 Restricted cash 205.5 \u2013 \u2013 205.5 Bank deposits, cash and cash equivalents 122.7 \u2013 \u2013 122.7 Total 437.0 \u2013 9.7 446.8 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Liabilities Derivative instruments price hedge \u2013 \u2013 205.1 205.1 Embedded derivatives convertible bond NOR13 \u2013 12.1 \u2013 12.1 Convertible bond loans 157.1 \u2013 \u2013 157.1 Senior unsecured bond loan 164.9 \u2013 \u2013 164.9 Reserve-based lending facility 857.3 \u2013 \u2013 857.3 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 130.5 \u2013 \u2013 130.5 Total 1,334.8 12.1 205.1 1,552.1 18.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments as at 31 December 2022: USD million Total amount outstanding* Carrying amount Fair value Financial assets Convertible loan CarbonCuts 0.2 0.2 Loan CarbonCuts 0.6 0.6 Derivative instruments interest swap 55.7 55.7 Derivative instruments price hedge 108.9 108.9 Trade receivables and other current assets 128.6 128.6 Restricted cash 203.7 203.7 Bank deposits, cash, cash equivalents and quoted shares 268.4 268.4 Total 766.1 766.1 Financial liabilities Derivative instruments price hedge 166.8 166.8 Embedded derivative convertible bond NOR13 10.0 10.0 Embedded derivative convertible bond NOR15 38.9 38.9 Convertible bond loans 221.5 188.7 211.5 Senior unsecured bond loan 175.0 166.9 175.0 Reserve-based lending facility 800.0 764.0 800.0 Deferred consideration 25.0 25.0 Trade payables and other current liabilities 115.6 115.6 Total 1,196.5 1,476.0 1,542.8 * Total amount outstanding on the bonds and under the RBL facility. The NOR13 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 10.0 million due to the majority of the NOR13 instrument being converted into the new NOR15 instrument. On 13 January 2022, the majority of the remaining NOR13 convertible instrument was converted into equity, leaving only USD 0.2 million which will be subject to the NOR13 amendments as proposed by the company in November 2022. The NOR15 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost, a total of USD 4.4 million in transaction cost is included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 38.9 million. The assumptions in establishing the option value as of 31 December 2022 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives: NOR13 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 24 Jul 19 Par value of bonds (USD) 13,810,094 Reference share price at time of agreement (NOK) 232 Fair value at grant date (USD) 53,942,754 PIK interest rate (%) 8.00% Expected life (years) 0.9 Number of options (#) 476,648 Conversion price (NOK) 238 Fixed FX rate of agreement (USD:NOK) 8.180 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton NOR15 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 30 Dec 22 Par value of bonds (USD) 207,641,201 Reference share price at time of agreement (NOK) 395 Fair value at grant date (USD) 38,928,552 PIK interest rate (%) 8.00% Expected life (years) 3.0 Number of options (#) 4,037,301 Conversion price (NOK) 537 Fixed FX rate of agreement (USD:NOK) 10.440 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton The RBL facility is measured at amortised cost, in addition a total of USD 53 million in transaction cost has been capitalised. Transaction costs are deducted from the amount initially recognised and are expensed over the period during which the debt is outstanding under the effective interest method. The senior unsecured bond loan is measured at amortised cost; a total of USD 7.6 million in transaction costs are deducted from the amount initially recognised. 18.4 Hedging The Group actively seeks to reduce the risk it is exposed to regarding fluctuating commodity prices through the establishment of hedging arrangements. To the extent more than 100 percent of the projected production is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. In 2022 no part of the hedging instruments was considered ineffective. Time value related to hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value. Currently, all the Company\u2019s commodity price hedging arrangements is executed solely in the market through forward contracts. Under its RBL facility, Norwegian Energy Company ASA (BlueNord) has a rolling hedge requirement based on a minimum level of production corresponding to the RBL banking case forecast. The Company has entered into a USD 1.0 billion swap transaction with a group of banks to fix the Company\u2019s floating interest rate exposure under its RBL facility from 1 November 2021 until 30 June 2024. Norwegian Energy Company ASA (BlueNord) will as a result pay interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin. Norwegian Energy Company ASA (BlueNord) applies hedge accounting to the Company\u2019s hedging arrangements. To the extent more than 100 percent of the Company\u2019s interest under its RBL facility is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. The ineffective amount in 2022 charged to financial items in the income statement were an income of USD 10.2 million. As at 31 December 2022 Maturity Less than one month One to three months Three to six months Six to nine months Nine to 12 months More than 12 months Commodity forward sales contracts: Notional quantity (in mboe) \u2013 1,448 1,350 990 937 3,391 Notional amount (in USD million) \u2013 134 104 88 76 246 Average hedged sales price (in USD per boe) \u2013 92 77 89 81 72 Hedge reserve movement The table below shows the movement in the hedge reserve from changes in the cash flow hedges. USD million Hedge reserve Balance as of 1 January 2022 (67.5) Realised cash flow hedge 242.2 Related tax \u2013 realised cash flow hedge (155.0) Changes in fair value (57.9) Related tax \u2013 changes in fair value 52.1 Balance as of 31 December 2022 13.9 ", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsHeldForTradingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-470": { "value": "18 Financial instruments 18.1 Fair value hierarchy The table below analyses financial instruments carried at fair value, by valuation method. The different levels have been defined as follows: Level 1 Quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 Inputs for the asset or liability that are not based on observable market data. On 31 December 2022 USD million Level 1 Level 2 Level 3 Total Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 11.1 \u2013 11.1 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 44.6 \u2013 44.6 - Derivative instruments price hedge \u2013 108.9 \u2013 108.9 Total assets \u2013 164.6 \u2013 164.6 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 10.0 10.0 - Embedded derivatives convertible bond NOR15 \u2013 \u2013 38.9 38. 9 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 166.8 \u2013 166.8 Total liabilities \u2013 166.8 48.9 215.7 On 31 December 2021 USD million Level 1 Level 2 Level 3 Tota l Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 1.0 \u2013 1.0 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 8.8 \u2013 8. 8 Total assets \u2013 9.7 \u2013 9.7 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 12.1 12.1 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 205.1 \u2013 205.1 Total liabilities \u2013 205.1 12.1 217.2 18.2 Financial instruments by category On 31 December 2022 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Total Assets Convertible loan CarbonCuts 0.2 \u2013 \u2013 0.2 Loan CarbonCuts 0.6 \u2013 \u2013 0.6 Derivative instruments interest swap \u2013 \u2013 55.7 55.7 Derivative instruments price hedge \u2013 \u2013 108.9 108.9 Trade receivables and other current assets 128.6 \u2013 \u2013 128.6 Restricted cash 203.7 \u2013 \u2013 203.7 Bank deposits, cash and cash equivalents 268.4 \u2013 \u2013 268.4 Total 601.5 \u2013 164.6 766.1 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Total Liabilities Derivative instruments price hedge \u2013 \u2013 166.8 166.8 Embedded derivatives convertible bond NOR13 \u2013 10.0 \u2013 10.0 Embedded derivatives convertible bond NOR15 \u2013 38.9 \u2013 38.9 Convertible bond loans 188.7 \u2013 \u2013 188.7 Senior unsecured bond loan 166.9 \u2013 \u2013 166.9 Reserve-based lending facility 764.0 \u2013 \u2013 764.0 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 115.6 \u2013 \u2013 115.6 Total 1,260.2 48.9 166.8 1,476.0 On 31 December 2021 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Assets Derivative instruments price hedge \u2013 \u2013 9.7 9.7 Trade receivables and other current assets 108.9 \u2013 \u2013 108.9 Restricted cash 205.5 \u2013 \u2013 205.5 Bank deposits, cash and cash equivalents 122.7 \u2013 \u2013 122.7 Total 437.0 \u2013 9.7 446.8 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Liabilities Derivative instruments price hedge \u2013 \u2013 205.1 205.1 Embedded derivatives convertible bond NOR13 \u2013 12.1 \u2013 12.1 Convertible bond loans 157.1 \u2013 \u2013 157.1 Senior unsecured bond loan 164.9 \u2013 \u2013 164.9 Reserve-based lending facility 857.3 \u2013 \u2013 857.3 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 130.5 \u2013 \u2013 130.5 Total 1,334.8 12.1 205.1 1,552.1 18.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments as at 31 December 2022: USD million Total amount outstanding* Carrying amount Fair value Financial assets Convertible loan CarbonCuts 0.2 0.2 Loan CarbonCuts 0.6 0.6 Derivative instruments interest swap 55.7 55.7 Derivative instruments price hedge 108.9 108.9 Trade receivables and other current assets 128.6 128.6 Restricted cash 203.7 203.7 Bank deposits, cash, cash equivalents and quoted shares 268.4 268.4 Total 766.1 766.1 Financial liabilities Derivative instruments price hedge 166.8 166.8 Embedded derivative convertible bond NOR13 10.0 10.0 Embedded derivative convertible bond NOR15 38.9 38.9 Convertible bond loans 221.5 188.7 211.5 Senior unsecured bond loan 175.0 166.9 175.0 Reserve-based lending facility 800.0 764.0 800.0 Deferred consideration 25.0 25.0 Trade payables and other current liabilities 115.6 115.6 Total 1,196.5 1,476.0 1,542.8 * Total amount outstanding on the bonds and under the RBL facility. The NOR13 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 10.0 million due to the majority of the NOR13 instrument being converted into the new NOR15 instrument. On 13 January 2022, the majority of the remaining NOR13 convertible instrument was converted into equity, leaving only USD 0.2 million which will be subject to the NOR13 amendments as proposed by the company in November 2022. The NOR15 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost, a total of USD 4.4 million in transaction cost is included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 38.9 million. The assumptions in establishing the option value as of 31 December 2022 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives: NOR13 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 24 Jul 19 Par value of bonds (USD) 13,810,094 Reference share price at time of agreement (NOK) 232 Fair value at grant date (USD) 53,942,754 PIK interest rate (%) 8.00% Expected life (years) 0.9 Number of options (#) 476,648 Conversion price (NOK) 238 Fixed FX rate of agreement (USD:NOK) 8.180 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton NOR15 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 30 Dec 22 Par value of bonds (USD) 207,641,201 Reference share price at time of agreement (NOK) 395 Fair value at grant date (USD) 38,928,552 PIK interest rate (%) 8.00% Expected life (years) 3.0 Number of options (#) 4,037,301 Conversion price (NOK) 537 Fixed FX rate of agreement (USD:NOK) 10.440 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton The RBL facility is measured at amortised cost, in addition a total of USD 53 million in transaction cost has been capitalised. Transaction costs are deducted from the amount initially recognised and are expensed over the period during which the debt is outstanding under the effective interest method. The senior unsecured bond loan is measured at amortised cost; a total of USD 7.6 million in transaction costs are deducted from the amount initially recognised. 18.4 Hedging The Group actively seeks to reduce the risk it is exposed to regarding fluctuating commodity prices through the establishment of hedging arrangements. To the extent more than 100 percent of the projected production is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. In 2022 no part of the hedging instruments was considered ineffective. Time value related to hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value. Currently, all the Company\u2019s commodity price hedging arrangements is executed solely in the market through forward contracts. Under its RBL facility, Norwegian Energy Company ASA (BlueNord) has a rolling hedge requirement based on a minimum level of production corresponding to the RBL banking case forecast. The Company has entered into a USD 1.0 billion swap transaction with a group of banks to fix the Company\u2019s floating interest rate exposure under its RBL facility from 1 November 2021 until 30 June 2024. Norwegian Energy Company ASA (BlueNord) will as a result pay interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin. Norwegian Energy Company ASA (BlueNord) applies hedge accounting to the Company\u2019s hedging arrangements. To the extent more than 100 percent of the Company\u2019s interest under its RBL facility is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. The ineffective amount in 2022 charged to financial items in the income statement were an income of USD 10.2 million. As at 31 December 2022 Maturity Less than one month One to three months Three to six months Six to nine months Nine to 12 months More than 12 months Commodity forward sales contracts: Notional quantity (in mboe) \u2013 1,448 1,350 990 937 3,391 Notional amount (in USD million) \u2013 134 104 88 76 246 Average hedged sales price (in USD per boe) \u2013 92 77 89 81 72 Hedge reserve movement The table below shows the movement in the hedge reserve from changes in the cash flow hedges. USD million Hedge reserve Balance as of 1 January 2022 (67.5) Realised cash flow hedge 242.2 Related tax \u2013 realised cash flow hedge (155.0) Changes in fair value (57.9) Related tax \u2013 changes in fair value 52.1 Balance as of 31 December 2022 13.9 ", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialLiabilitiesHeldForTradingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-466": { "value": "18 Financial instruments 18.1 Fair value hierarchy The table below analyses financial instruments carried at fair value, by valuation method. The different levels have been defined as follows: Level 1 Quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 Inputs for the asset or liability that are not based on observable market data. On 31 December 2022 USD million Level 1 Level 2 Level 3 Total Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 11.1 \u2013 11.1 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 44.6 \u2013 44.6 - Derivative instruments price hedge \u2013 108.9 \u2013 108.9 Total assets \u2013 164.6 \u2013 164.6 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 10.0 10.0 - Embedded derivatives convertible bond NOR15 \u2013 \u2013 38.9 38. 9 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 166.8 \u2013 166.8 Total liabilities \u2013 166.8 48.9 215.7 On 31 December 2021 USD million Level 1 Level 2 Level 3 Tota l Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 1.0 \u2013 1.0 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 8.8 \u2013 8. 8 Total assets \u2013 9.7 \u2013 9.7 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 12.1 12.1 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 205.1 \u2013 205.1 Total liabilities \u2013 205.1 12.1 217.2 18.2 Financial instruments by category On 31 December 2022 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Total Assets Convertible loan CarbonCuts 0.2 \u2013 \u2013 0.2 Loan CarbonCuts 0.6 \u2013 \u2013 0.6 Derivative instruments interest swap \u2013 \u2013 55.7 55.7 Derivative instruments price hedge \u2013 \u2013 108.9 108.9 Trade receivables and other current assets 128.6 \u2013 \u2013 128.6 Restricted cash 203.7 \u2013 \u2013 203.7 Bank deposits, cash and cash equivalents 268.4 \u2013 \u2013 268.4 Total 601.5 \u2013 164.6 766.1 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Total Liabilities Derivative instruments price hedge \u2013 \u2013 166.8 166.8 Embedded derivatives convertible bond NOR13 \u2013 10.0 \u2013 10.0 Embedded derivatives convertible bond NOR15 \u2013 38.9 \u2013 38.9 Convertible bond loans 188.7 \u2013 \u2013 188.7 Senior unsecured bond loan 166.9 \u2013 \u2013 166.9 Reserve-based lending facility 764.0 \u2013 \u2013 764.0 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 115.6 \u2013 \u2013 115.6 Total 1,260.2 48.9 166.8 1,476.0 On 31 December 2021 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Assets Derivative instruments price hedge \u2013 \u2013 9.7 9.7 Trade receivables and other current assets 108.9 \u2013 \u2013 108.9 Restricted cash 205.5 \u2013 \u2013 205.5 Bank deposits, cash and cash equivalents 122.7 \u2013 \u2013 122.7 Total 437.0 \u2013 9.7 446.8 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Liabilities Derivative instruments price hedge \u2013 \u2013 205.1 205.1 Embedded derivatives convertible bond NOR13 \u2013 12.1 \u2013 12.1 Convertible bond loans 157.1 \u2013 \u2013 157.1 Senior unsecured bond loan 164.9 \u2013 \u2013 164.9 Reserve-based lending facility 857.3 \u2013 \u2013 857.3 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 130.5 \u2013 \u2013 130.5 Total 1,334.8 12.1 205.1 1,552.1 18.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments as at 31 December 2022: USD million Total amount outstanding* Carrying amount Fair value Financial assets Convertible loan CarbonCuts 0.2 0.2 Loan CarbonCuts 0.6 0.6 Derivative instruments interest swap 55.7 55.7 Derivative instruments price hedge 108.9 108.9 Trade receivables and other current assets 128.6 128.6 Restricted cash 203.7 203.7 Bank deposits, cash, cash equivalents and quoted shares 268.4 268.4 Total 766.1 766.1 Financial liabilities Derivative instruments price hedge 166.8 166.8 Embedded derivative convertible bond NOR13 10.0 10.0 Embedded derivative convertible bond NOR15 38.9 38.9 Convertible bond loans 221.5 188.7 211.5 Senior unsecured bond loan 175.0 166.9 175.0 Reserve-based lending facility 800.0 764.0 800.0 Deferred consideration 25.0 25.0 Trade payables and other current liabilities 115.6 115.6 Total 1,196.5 1,476.0 1,542.8 * Total amount outstanding on the bonds and under the RBL facility. The NOR13 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 10.0 million due to the majority of the NOR13 instrument being converted into the new NOR15 instrument. On 13 January 2022, the majority of the remaining NOR13 convertible instrument was converted into equity, leaving only USD 0.2 million which will be subject to the NOR13 amendments as proposed by the company in November 2022. The NOR15 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost, a total of USD 4.4 million in transaction cost is included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 38.9 million. The assumptions in establishing the option value as of 31 December 2022 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives: NOR13 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 24 Jul 19 Par value of bonds (USD) 13,810,094 Reference share price at time of agreement (NOK) 232 Fair value at grant date (USD) 53,942,754 PIK interest rate (%) 8.00% Expected life (years) 0.9 Number of options (#) 476,648 Conversion price (NOK) 238 Fixed FX rate of agreement (USD:NOK) 8.180 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton NOR15 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 30 Dec 22 Par value of bonds (USD) 207,641,201 Reference share price at time of agreement (NOK) 395 Fair value at grant date (USD) 38,928,552 PIK interest rate (%) 8.00% Expected life (years) 3.0 Number of options (#) 4,037,301 Conversion price (NOK) 537 Fixed FX rate of agreement (USD:NOK) 10.440 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton The RBL facility is measured at amortised cost, in addition a total of USD 53 million in transaction cost has been capitalised. Transaction costs are deducted from the amount initially recognised and are expensed over the period during which the debt is outstanding under the effective interest method. The senior unsecured bond loan is measured at amortised cost; a total of USD 7.6 million in transaction costs are deducted from the amount initially recognised. 18.4 Hedging The Group actively seeks to reduce the risk it is exposed to regarding fluctuating commodity prices through the establishment of hedging arrangements. To the extent more than 100 percent of the projected production is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. In 2022 no part of the hedging instruments was considered ineffective. Time value related to hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value. Currently, all the Company\u2019s commodity price hedging arrangements is executed solely in the market through forward contracts. Under its RBL facility, Norwegian Energy Company ASA (BlueNord) has a rolling hedge requirement based on a minimum level of production corresponding to the RBL banking case forecast. The Company has entered into a USD 1.0 billion swap transaction with a group of banks to fix the Company\u2019s floating interest rate exposure under its RBL facility from 1 November 2021 until 30 June 2024. Norwegian Energy Company ASA (BlueNord) will as a result pay interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin. Norwegian Energy Company ASA (BlueNord) applies hedge accounting to the Company\u2019s hedging arrangements. To the extent more than 100 percent of the Company\u2019s interest under its RBL facility is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. The ineffective amount in 2022 charged to financial items in the income statement were an income of USD 10.2 million. As at 31 December 2022 Maturity Less than one month One to three months Three to six months Six to nine months Nine to 12 months More than 12 months Commodity forward sales contracts: Notional quantity (in mboe) \u2013 1,448 1,350 990 937 3,391 Notional amount (in USD million) \u2013 134 104 88 76 246 Average hedged sales price (in USD per boe) \u2013 92 77 89 81 72 Hedge reserve movement The table below shows the movement in the hedge reserve from changes in the cash flow hedges. USD million Hedge reserve Balance as of 1 January 2022 (67.5) Realised cash flow hedge 242.2 Related tax \u2013 realised cash flow hedge (155.0) Changes in fair value (57.9) Related tax \u2013 changes in fair value 52.1 Balance as of 31 December 2022 13.9 ", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-459": { "value": "18 Financial instruments 18.1 Fair value hierarchy The table below analyses financial instruments carried at fair value, by valuation method. The different levels have been defined as follows: Level 1 Quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 Inputs for the asset or liability that are not based on observable market data. On 31 December 2022 USD million Level 1 Level 2 Level 3 Total Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 11.1 \u2013 11.1 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 44.6 \u2013 44.6 - Derivative instruments price hedge \u2013 108.9 \u2013 108.9 Total assets \u2013 164.6 \u2013 164.6 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 10.0 10.0 - Embedded derivatives convertible bond NOR15 \u2013 \u2013 38.9 38. 9 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 166.8 \u2013 166.8 Total liabilities \u2013 166.8 48.9 215.7 On 31 December 2021 USD million Level 1 Level 2 Level 3 Tota l Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 1.0 \u2013 1.0 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 8.8 \u2013 8. 8 Total assets \u2013 9.7 \u2013 9.7 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 12.1 12.1 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 205.1 \u2013 205.1 Total liabilities \u2013 205.1 12.1 217.2 18.2 Financial instruments by category On 31 December 2022 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Total Assets Convertible loan CarbonCuts 0.2 \u2013 \u2013 0.2 Loan CarbonCuts 0.6 \u2013 \u2013 0.6 Derivative instruments interest swap \u2013 \u2013 55.7 55.7 Derivative instruments price hedge \u2013 \u2013 108.9 108.9 Trade receivables and other current assets 128.6 \u2013 \u2013 128.6 Restricted cash 203.7 \u2013 \u2013 203.7 Bank deposits, cash and cash equivalents 268.4 \u2013 \u2013 268.4 Total 601.5 \u2013 164.6 766.1 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Total Liabilities Derivative instruments price hedge \u2013 \u2013 166.8 166.8 Embedded derivatives convertible bond NOR13 \u2013 10.0 \u2013 10.0 Embedded derivatives convertible bond NOR15 \u2013 38.9 \u2013 38.9 Convertible bond loans 188.7 \u2013 \u2013 188.7 Senior unsecured bond loan 166.9 \u2013 \u2013 166.9 Reserve-based lending facility 764.0 \u2013 \u2013 764.0 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 115.6 \u2013 \u2013 115.6 Total 1,260.2 48.9 166.8 1,476.0 On 31 December 2021 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Assets Derivative instruments price hedge \u2013 \u2013 9.7 9.7 Trade receivables and other current assets 108.9 \u2013 \u2013 108.9 Restricted cash 205.5 \u2013 \u2013 205.5 Bank deposits, cash and cash equivalents 122.7 \u2013 \u2013 122.7 Total 437.0 \u2013 9.7 446.8 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Liabilities Derivative instruments price hedge \u2013 \u2013 205.1 205.1 Embedded derivatives convertible bond NOR13 \u2013 12.1 \u2013 12.1 Convertible bond loans 157.1 \u2013 \u2013 157.1 Senior unsecured bond loan 164.9 \u2013 \u2013 164.9 Reserve-based lending facility 857.3 \u2013 \u2013 857.3 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 130.5 \u2013 \u2013 130.5 Total 1,334.8 12.1 205.1 1,552.1 18.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments as at 31 December 2022: USD million Total amount outstanding* Carrying amount Fair value Financial assets Convertible loan CarbonCuts 0.2 0.2 Loan CarbonCuts 0.6 0.6 Derivative instruments interest swap 55.7 55.7 Derivative instruments price hedge 108.9 108.9 Trade receivables and other current assets 128.6 128.6 Restricted cash 203.7 203.7 Bank deposits, cash, cash equivalents and quoted shares 268.4 268.4 Total 766.1 766.1 Financial liabilities Derivative instruments price hedge 166.8 166.8 Embedded derivative convertible bond NOR13 10.0 10.0 Embedded derivative convertible bond NOR15 38.9 38.9 Convertible bond loans 221.5 188.7 211.5 Senior unsecured bond loan 175.0 166.9 175.0 Reserve-based lending facility 800.0 764.0 800.0 Deferred consideration 25.0 25.0 Trade payables and other current liabilities 115.6 115.6 Total 1,196.5 1,476.0 1,542.8 * Total amount outstanding on the bonds and under the RBL facility. The NOR13 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 10.0 million due to the majority of the NOR13 instrument being converted into the new NOR15 instrument. On 13 January 2022, the majority of the remaining NOR13 convertible instrument was converted into equity, leaving only USD 0.2 million which will be subject to the NOR13 amendments as proposed by the company in November 2022. The NOR15 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost, a total of USD 4.4 million in transaction cost is included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 38.9 million. The assumptions in establishing the option value as of 31 December 2022 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives: NOR13 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 24 Jul 19 Par value of bonds (USD) 13,810,094 Reference share price at time of agreement (NOK) 232 Fair value at grant date (USD) 53,942,754 PIK interest rate (%) 8.00% Expected life (years) 0.9 Number of options (#) 476,648 Conversion price (NOK) 238 Fixed FX rate of agreement (USD:NOK) 8.180 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton NOR15 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 30 Dec 22 Par value of bonds (USD) 207,641,201 Reference share price at time of agreement (NOK) 395 Fair value at grant date (USD) 38,928,552 PIK interest rate (%) 8.00% Expected life (years) 3.0 Number of options (#) 4,037,301 Conversion price (NOK) 537 Fixed FX rate of agreement (USD:NOK) 10.440 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton The RBL facility is measured at amortised cost, in addition a total of USD 53 million in transaction cost has been capitalised. Transaction costs are deducted from the amount initially recognised and are expensed over the period during which the debt is outstanding under the effective interest method. The senior unsecured bond loan is measured at amortised cost; a total of USD 7.6 million in transaction costs are deducted from the amount initially recognised. 18.4 Hedging The Group actively seeks to reduce the risk it is exposed to regarding fluctuating commodity prices through the establishment of hedging arrangements. To the extent more than 100 percent of the projected production is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. In 2022 no part of the hedging instruments was considered ineffective. Time value related to hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value. Currently, all the Company\u2019s commodity price hedging arrangements is executed solely in the market through forward contracts. Under its RBL facility, Norwegian Energy Company ASA (BlueNord) has a rolling hedge requirement based on a minimum level of production corresponding to the RBL banking case forecast. The Company has entered into a USD 1.0 billion swap transaction with a group of banks to fix the Company\u2019s floating interest rate exposure under its RBL facility from 1 November 2021 until 30 June 2024. Norwegian Energy Company ASA (BlueNord) will as a result pay interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin. Norwegian Energy Company ASA (BlueNord) applies hedge accounting to the Company\u2019s hedging arrangements. To the extent more than 100 percent of the Company\u2019s interest under its RBL facility is hedged any value adjustments to the instruments covering in excess of 100 percent are considered ineffective and the value adjustment is treated as a financial item in the income statement. The ineffective amount in 2022 charged to financial items in the income statement were an income of USD 10.2 million. As at 31 December 2022 Maturity Less than one month One to three months Three to six months Six to nine months Nine to 12 months More than 12 months Commodity forward sales contracts: Notional quantity (in mboe) \u2013 1,448 1,350 990 937 3,391 Notional amount (in USD million) \u2013 134 104 88 76 246 Average hedged sales price (in USD per boe) \u2013 92 77 89 81 72 Hedge reserve movement The table below shows the movement in the hedge reserve from changes in the cash flow hedges. USD million Hedge reserve Balance as of 1 January 2022 (67.5) Realised cash flow hedge 242.2 Related tax \u2013 realised cash flow hedge (155.0) Changes in fair value (57.9) Related tax \u2013 changes in fair value 52.1 Balance as of 31 December 2022 13.9 ", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialAssetsHeldForTradingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-443": { "value": "18.1 Fair value hierarchy The table below analyses financial instruments carried at fair value, by valuation method. The different levels have been defined as follows: Level 1 Quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 Inputs for the asset or liability that are not based on observable market data. On 31 December 2022 USD million Level 1 Level 2 Level 3 Total Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 11.1 \u2013 11.1 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 44.6 \u2013 44.6 - Derivative instruments price hedge \u2013 108.9 \u2013 108.9 Total assets \u2013 164.6 \u2013 164.6 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 10.0 10.0 - Embedded derivatives convertible bond NOR15 \u2013 \u2013 38.9 38. 9 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 166.8 \u2013 166.8 Total liabilities \u2013 166.8 48.9 215.7 On 31 December 2021 USD million Level 1 Level 2 Level 3 Tota l Assets Financial assets at fair value through profit or loss - Derivative instruments interest swap \u2013 1.0 \u2013 1.0 Financial assets at fair value hedging instruments - Derivative instruments interest swap \u2013 8.8 \u2013 8. 8 Total assets \u2013 9.7 \u2013 9.7 Liabilities Financial liabilities at fair value through profit or loss - Embedded derivatives convertible bond NOR13 \u2013 \u2013 12.1 12.1 Financial liabilities at fair value hedging instruments - Derivative instruments price hedge \u2013 205.1 \u2013 205.1 Total liabilities \u2013 205.1 12.1 217.2 18.2 Financial instruments by category On 31 December 2022 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Total Assets Convertible loan CarbonCuts 0.2 \u2013 \u2013 0.2 Loan CarbonCuts 0.6 \u2013 \u2013 0.6 Derivative instruments interest swap \u2013 \u2013 55.7 55.7 Derivative instruments price hedge \u2013 \u2013 108.9 108.9 Trade receivables and other current assets 128.6 \u2013 \u2013 128.6 Restricted cash 203.7 \u2013 \u2013 203.7 Bank deposits, cash and cash equivalents 268.4 \u2013 \u2013 268.4 Total 601.5 \u2013 164.6 766.1 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Total Liabilities Derivative instruments price hedge \u2013 \u2013 166.8 166.8 Embedded derivatives convertible bond NOR13 \u2013 10.0 \u2013 10.0 Embedded derivatives convertible bond NOR15 \u2013 38.9 \u2013 38.9 Convertible bond loans 188.7 \u2013 \u2013 188.7 Senior unsecured bond loan 166.9 \u2013 \u2013 166.9 Reserve-based lending facility 764.0 \u2013 \u2013 764.0 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 115.6 \u2013 \u2013 115.6 Total 1,260.2 48.9 166.8 1,476.0 On 31 December 2021 USD million Financial assets at amortised cost Assets at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Assets Derivative instruments price hedge \u2013 \u2013 9.7 9.7 Trade receivables and other current assets 108.9 \u2013 \u2013 108.9 Restricted cash 205.5 \u2013 \u2013 205.5 Bank deposits, cash and cash equivalents 122.7 \u2013 \u2013 122.7 Total 437.0 \u2013 9.7 446.8 USD million Financial liabilities at amortised cost Liabilities at fair value through profit or loss Fair value \u2013 hedging instruments Tot al Liabilities Derivative instruments price hedge \u2013 \u2013 205.1 205.1 Embedded derivatives convertible bond NOR13 \u2013 12.1 \u2013 12.1 Convertible bond loans 157.1 \u2013 \u2013 157.1 Senior unsecured bond loan 164.9 \u2013 \u2013 164.9 Reserve-based lending facility 857.3 \u2013 \u2013 857.3 Deferred consideration 25.0 \u2013 \u2013 25.0 Trade payables and other current liabilities 130.5 \u2013 \u2013 130.5 Total 1,334.8 12.1 205.1 1,552.1 18.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments as at 31 December 2022: USD million Total amount outstanding* Carrying amount Fair value Financial assets Convertible loan CarbonCuts 0.2 0.2 Loan CarbonCuts 0.6 0.6 Derivative instruments interest swap 55.7 55.7 Derivative instruments price hedge 108.9 108.9 Trade receivables and other current assets 128.6 128.6 Restricted cash 203.7 203.7 Bank deposits, cash, cash equivalents and quoted shares 268.4 268.4 Total 766.1 766.1 Financial liabilities Derivative instruments price hedge 166.8 166.8 Embedded derivative convertible bond NOR13 10.0 10.0 Embedded derivative convertible bond NOR15 38.9 38.9 Convertible bond loans 221.5 188.7 211.5 Senior unsecured bond loan 175.0 166.9 175.0 Reserve-based lending facility 800.0 764.0 800.0 Deferred consideration 25.0 25.0 Trade payables and other current liabilities 115.6 115.6 Total 1,196.5 1,476.0 1,542.8 * Total amount outstanding on the bonds and under the RBL facility. The NOR13 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 10.0 million due to the majority of the NOR13 instrument being converted into the new NOR15 instrument. On 13 January 2022, the majority of the remaining NOR13 convertible instrument was converted into equity, leaving only USD 0.2 million which will be subject to the NOR13 amendments as proposed by the company in November 2022. The NOR15 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost, a total of USD 4.4 million in transaction cost is included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as of 31 December 2022 was USD 38.9 million. The assumptions in establishing the option value as of 31 December 2022 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives: NOR13 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 24 Jul 19 Par value of bonds (USD) 13,810,094 Reference share price at time of agreement (NOK) 232 Fair value at grant date (USD) 53,942,754 PIK interest rate (%) 8.00% Expected life (years) 0.9 Number of options (#) 476,648 Conversion price (NOK) 238 Fixed FX rate of agreement (USD:NOK) 8.180 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton NOR15 2022 Valuation date (date) 31 Dec 22 Agreement execution date (date) 30 Dec 22 Par value of bonds (USD) 207,641,201 Reference share price at time of agreement (NOK) 395 Fair value at grant date (USD) 38,928,552 PIK interest rate (%) 8.00% Expected life (years) 3.0 Number of options (#) 4,037,301 Conversion price (NOK) 537 Fixed FX rate of agreement (USD:NOK) 10.440 Risk-free rate (based on government bonds) (%) 3.18% Expected volatility (%) 48.31% Model used Black-Scholes-Merton The RBL facility is measured at amortised cost, in addition a total of USD 53 million in transaction cost has been capitalised. Transaction costs are deducted from the amount initially recognised and are expensed over the period during which the debt is outstanding under the effective interest method. The senior unsecured bond loan is measured at amortised cost; a total of USD 7.6 million in transaction costs are deducted from the amount initially recognised. ", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-467": { "value": "19 Share capital Norwegian Energy Company ASA (BlueNord) owns 137.162 of its own shares. All shares have equal rights. All shares are fully paid. Changes in number of shares and share capital: No. of shares Share capital* Number of shares and share capital as of 1 January 2021 24,549,013 29.5 Number of shares and share capital as of 31 December 2021 24,549,013 29.5 Issue of shares 1,159,411 1.4 Capital reduction, approved and registered \u2013 (29.3) Number of shares and share capital as of 31 December 2022 25,708,424 1.7 No. of shares Treasury share reserve* Number of treasury shares and treasury share reserve as of 1 January 2021 (438,161) (0.5) Number of treasury shares and treasury share reserve as of 31 December 2021 (438,161) (0.5) Sale of treasury shares 300,999 0.3 Number of treasury shares and treasury share reserve as of 31 December 2022 (137,162) (0.1) * In USD million. Changes in 2022 The Company received conversion notice from bondholders holding NOR13 Bonds for USD 33.6 million, which pursuant to the bond term are convertible into 1,159,411 new shares in the Company at a conversion price of USD 28.9734. Following such conversions the share capital is increased with NOK 11.6/USD 1.4 million. The share capital is reduced with NOK 243.2/USD 29.3 million by reducing the nominal value of the shares. The reduction amount was transferred to share premium fund. The share capital reduction has been registered in the Norwegian Registry of Business Enterprises on 28 December 2022. Following the share capital reduction, the Company\u2019s share capital is NOK 13.9/USD 1.7 million divided on 25.708.424 shares, each with a nominal value of NOK 0.5398295. The Company sold 300.999 of its own shares in relation to exercise of options held by former Director of the Board and former members of the Executive Team. Overview of shareholders at 28 March 2023: Shareholder* Shareholding Ownership share Voting share Euroclear Bank S.A./N.V. 6,243,331 23.8% 23.8% Goldman Sachs International 5,189,939 19.8% 19.8% SOBER AS 1,850,000 7.1% 7.1% Barclays Bank PLC 1,540,368 5.9% 5.9% J.P. Morgan Securities LLC 1,435,010 5.5% 5.5% Bank of America 774,408 3.0% 3.0% J.P. Morgan Securities LLC 588,649 2.7% 2.7% BNP Paribas 585,000 2.2% 2.2% Sbakkejord AS 341,262 2.2% 2.2% CLEARSTREAM BANKING S.A. 586,202 2.2% 2.2% SOSYFR INVEST AS 268,368 1.6% 1.6% Soci\u00e9t\u00e9 G\u00e9n\u00e9rale 425,000 1.3% 1.3% Morgan Stanley & Co. Int. Plc. 300,225 1.2% 1.2% FINSNES INVEST AS 318,000 1.1% 1.1% VELDE HOLDING AS 222,222 1.0% 1.0% Barclays Bank PLC 700,216 1.0% 1.0% Goldman Sachs & Co. LLC 203,349 0.9% 0.9% DNB BANK ASA 257,969 0.8% 0.8% The Bank of New York Mellon SA/NV 228,149 0.8% 0.8% OUSDAL AS 200,000 0.8% 0.8% Total 22,257,667 85% 85% Other owners (ownership <0,42%) 3,944,377 15.1% 15.1% Total number of shares at 28 March 2023 26,202,044 100% 100% *Nominee holder. ", "dimensions": { "concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-444": { "value": "19 Share capital Norwegian Energy Company ASA (BlueNord) owns 137.162 of its own shares. All shares have equal rights. All shares are fully paid. Changes in number of shares and share capital: No. of shares Share capital* Number of shares and share capital as of 1 January 2021 24,549,013 29.5 Number of shares and share capital as of 31 December 2021 24,549,013 29.5 Issue of shares 1,159,411 1.4 Capital reduction, approved and registered \u2013 (29.3) Number of shares and share capital as of 31 December 2022 25,708,424 1.7 No. of shares Treasury share reserve* Number of treasury shares and treasury share reserve as of 1 January 2021 (438,161) (0.5) Number of treasury shares and treasury share reserve as of 31 December 2021 (438,161) (0.5) Sale of treasury shares 300,999 0.3 Number of treasury shares and treasury share reserve as of 31 December 2022 (137,162) (0.1) * In USD million. Changes in 2022 The Company received conversion notice from bondholders holding NOR13 Bonds for USD 33.6 million, which pursuant to the bond term are convertible into 1,159,411 new shares in the Company at a conversion price of USD 28.9734. Following such conversions the share capital is increased with NOK 11.6/USD 1.4 million. The share capital is reduced with NOK 243.2/USD 29.3 million by reducing the nominal value of the shares. The reduction amount was transferred to share premium fund. The share capital reduction has been registered in the Norwegian Registry of Business Enterprises on 28 December 2022. Following the share capital reduction, the Company\u2019s share capital is NOK 13.9/USD 1.7 million divided on 25.708.424 shares, each with a nominal value of NOK 0.5398295. The Company sold 300.999 of its own shares in relation to exercise of options held by former Director of the Board and former members of the Executive Team. Overview of shareholders at 28 March 2023: Shareholder* Shareholding Ownership share Voting share Euroclear Bank S.A./N.V. 6,243,331 23.8% 23.8% Goldman Sachs International 5,189,939 19.8% 19.8% SOBER AS 1,850,000 7.1% 7.1% Barclays Bank PLC 1,540,368 5.9% 5.9% J.P. Morgan Securities LLC 1,435,010 5.5% 5.5% Bank of America 774,408 3.0% 3.0% J.P. Morgan Securities LLC 588,649 2.7% 2.7% BNP Paribas 585,000 2.2% 2.2% Sbakkejord AS 341,262 2.2% 2.2% CLEARSTREAM BANKING S.A. 586,202 2.2% 2.2% SOSYFR INVEST AS 268,368 1.6% 1.6% Soci\u00e9t\u00e9 G\u00e9n\u00e9rale 425,000 1.3% 1.3% Morgan Stanley & Co. Int. Plc. 300,225 1.2% 1.2% FINSNES INVEST AS 318,000 1.1% 1.1% VELDE HOLDING AS 222,222 1.0% 1.0% Barclays Bank PLC 700,216 1.0% 1.0% Goldman Sachs & Co. LLC 203,349 0.9% 0.9% DNB BANK ASA 257,969 0.8% 0.8% The Bank of New York Mellon SA/NV 228,149 0.8% 0.8% OUSDAL AS 200,000 0.8% 0.8% Total 22,257,667 85% 85% Other owners (ownership <0,42%) 3,944,377 15.1% 15.1% Total number of shares at 28 March 2023 26,202,044 100% 100% *Nominee holder. ", "dimensions": { "concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-409": { "value": "19 Share capital Norwegian Energy Company ASA (BlueNord) owns 137.162 of its own shares. All shares have equal rights. All shares are fully paid. Changes in number of shares and share capital: No. of shares Share capital* Number of shares and share capital as of 1 January 2021 24,549,013 29.5 Number of shares and share capital as of 31 December 2021 24,549,013 29.5 Issue of shares 1,159,411 1.4 Capital reduction, approved and registered \u2013 (29.3) Number of shares and share capital as of 31 December 2022 25,708,424 1.7 No. of shares Treasury share reserve* Number of treasury shares and treasury share reserve as of 1 January 2021 (438,161) (0.5) Number of treasury shares and treasury share reserve as of 31 December 2021 (438,161) (0.5) Sale of treasury shares 300,999 0.3 Number of treasury shares and treasury share reserve as of 31 December 2022 (137,162) (0.1) * In USD million. Changes in 2022 The Company received conversion notice from bondholders holding NOR13 Bonds for USD 33.6 million, which pursuant to the bond term are convertible into 1,159,411 new shares in the Company at a conversion price of USD 28.9734. Following such conversions the share capital is increased with NOK 11.6/USD 1.4 million. The share capital is reduced with NOK 243.2/USD 29.3 million by reducing the nominal value of the shares. The reduction amount was transferred to share premium fund. The share capital reduction has been registered in the Norwegian Registry of Business Enterprises on 28 December 2022. Following the share capital reduction, the Company\u2019s share capital is NOK 13.9/USD 1.7 million divided on 25.708.424 shares, each with a nominal value of NOK 0.5398295. The Company sold 300.999 of its own shares in relation to exercise of options held by former Director of the Board and former members of the Executive Team. Overview of shareholders at 28 March 2023: Shareholder* Shareholding Ownership share Voting share Euroclear Bank S.A./N.V. 6,243,331 23.8% 23.8% Goldman Sachs International 5,189,939 19.8% 19.8% SOBER AS 1,850,000 7.1% 7.1% Barclays Bank PLC 1,540,368 5.9% 5.9% J.P. Morgan Securities LLC 1,435,010 5.5% 5.5% Bank of America 774,408 3.0% 3.0% J.P. Morgan Securities LLC 588,649 2.7% 2.7% BNP Paribas 585,000 2.2% 2.2% Sbakkejord AS 341,262 2.2% 2.2% CLEARSTREAM BANKING S.A. 586,202 2.2% 2.2% SOSYFR INVEST AS 268,368 1.6% 1.6% Soci\u00e9t\u00e9 G\u00e9n\u00e9rale 425,000 1.3% 1.3% Morgan Stanley & Co. Int. Plc. 300,225 1.2% 1.2% FINSNES INVEST AS 318,000 1.1% 1.1% VELDE HOLDING AS 222,222 1.0% 1.0% Barclays Bank PLC 700,216 1.0% 1.0% Goldman Sachs & Co. LLC 203,349 0.9% 0.9% DNB BANK ASA 257,969 0.8% 0.8% The Bank of New York Mellon SA/NV 228,149 0.8% 0.8% OUSDAL AS 200,000 0.8% 0.8% Total 22,257,667 85% 85% Other owners (ownership <0,42%) 3,944,377 15.1% 15.1% Total number of shares at 28 March 2023 26,202,044 100% 100% *Nominee holder. ", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-445": { "value": "20 Post-employment benefits Defined contribution plan The Group has defined contribution plans for its employees. Pension costs related to the Company\u2019s defined contribution plan amounts to USD 513 thousand for 2022. For 2021, the corresponding costs were USD 558 thousand. The Norwegian companies are obliged to have occupational pension in accordance with the Norwegian act related to mandatory occupational pension. All Norwegian companies meet the Norwegian requirements for mandatory occupational pension (\u201cobligatorisk tjenestepensjon\u201d). Correspondingly, the affiliates in Denmark and United Kingdom comply with the requirement for mandatory occupational pension by local legislation ", "dimensions": { "concept": "ifrs-full:DisclosureOfDefinedContributionPlansExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-446": { "value": "21 Asset retirement obligations USD million 31.12.2022 31.12.2021 Balance on 01.01. 1,029.2 950.3 Provisions and change of estimates made during the year (107.0) 64.9 Accretion expense 48.1 35.2 Incurred cost removal (14.4) (21.0) Currency translation adjustment (0.1) (0.2) Total provision made for asset retirement obligations 955.8 1,029.2 Break down of short-term and long-term asset retirement obligations Short-term 9.8 26.2 Long-term 946.1 1,003.0 Total provision for asset retirement obligations 955.8 1,029.2 Estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The obligations are measured at net present value, assuming an inflation rate of 2.0 percent (2021: 2.0 percent) and a nominal discount rate before tax of 5.5 percent (2021: 5 percent). The credit margin included in the discount rate is 2.5 percent. The change in estimate during the year includes a decrease of USD 70 million as a result of the discount rate increasing by 0.5 percent. The asset retirement estimate from the operator includes both USD and DKK costs and as a result there is a further decrease of USD 39 million due to the weakening of DKK to USD. The net remaining change in estimate is due to more minor impacts on cost estimates, additional provision for Tyra II installations offset by a change in expected timing of costs being incurred. Most of the removal activities are expected to be executed many years into the future. This makes the ultimate asset retirement costs and timing highly uncertain. Costs and timing can be affected by changes in regulations, technology, estimated reserves, economic cut-off date etc. The provision at the reporting date represents management\u2019s best estimate of the present value of the future asset retirement costs required. As part of the overall restructuring in 2015, an agreement was reached that entails that the partners took over Norwegian Energy Company ASA (BlueNord)\u2019s share of the Nini/Cecilie licences, however Norwegian Energy Company ASA (BlueNord) remains liable for the asset retirement obligation towards the licence partners. The liability related to Nini/Cecilie is capped at the escrow amount, which is currently USD 61.1 million/ DKK 426.0 million. The balance as per 31.12.2022 is USD 890.8 million for DUC, USD 61.1 million for Nini/Cecilie, USD 2.3 million for Lulita (non-DUC share) and USD 1.6 million for Tyra F-3 pipeline. Sensitivity analysis The table below shows how the asset retirement obligation would be affected by changes in the various assumptions, given that the remaining assumptions are constant. Sensitivity ARO ($\u2019mm) Change in provision Abandonment Cost Estimate increase +10% 979.2 10.0 % Abandonment Cost Estimate decrease -10% 807.0 -10.0 % Discount rate +1.0% 768.2 -14.0 % Discount rate -1.0% 1,042.7 17.0 % Inflation rate +1.0% 1,041.3 17.0 % Inflation rate -1.0% 767.1 -14.0 % ", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-410": { "value": "21 Asset retirement obligations USD million 31.12.2022 31.12.2021 Balance on 01.01. 1,029.2 950.3 Provisions and change of estimates made during the year (107.0) 64.9 Accretion expense 48.1 35.2 Incurred cost removal (14.4) (21.0) Currency translation adjustment (0.1) (0.2) Total provision made for asset retirement obligations 955.8 1,029.2 Break down of short-term and long-term asset retirement obligations Short-term 9.8 26.2 Long-term 946.1 1,003.0 Total provision for asset retirement obligations 955.8 1,029.2 Estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The obligations are measured at net present value, assuming an inflation rate of 2.0 percent (2021: 2.0 percent) and a nominal discount rate before tax of 5.5 percent (2021: 5 percent). The credit margin included in the discount rate is 2.5 percent. The change in estimate during the year includes a decrease of USD 70 million as a result of the discount rate increasing by 0.5 percent. The asset retirement estimate from the operator includes both USD and DKK costs and as a result there is a further decrease of USD 39 million due to the weakening of DKK to USD. The net remaining change in estimate is due to more minor impacts on cost estimates, additional provision for Tyra II installations offset by a change in expected timing of costs being incurred. Most of the removal activities are expected to be executed many years into the future. This makes the ultimate asset retirement costs and timing highly uncertain. Costs and timing can be affected by changes in regulations, technology, estimated reserves, economic cut-off date etc. The provision at the reporting date represents management\u2019s best estimate of the present value of the future asset retirement costs required. As part of the overall restructuring in 2015, an agreement was reached that entails that the partners took over Norwegian Energy Company ASA (BlueNord)\u2019s share of the Nini/Cecilie licences, however Norwegian Energy Company ASA (BlueNord) remains liable for the asset retirement obligation towards the licence partners. The liability related to Nini/Cecilie is capped at the escrow amount, which is currently USD 61.1 million/ DKK 426.0 million. The balance as per 31.12.2022 is USD 890.8 million for DUC, USD 61.1 million for Nini/Cecilie, USD 2.3 million for Lulita (non-DUC share) and USD 1.6 million for Tyra F-3 pipeline. Sensitivity analysis The table below shows how the asset retirement obligation would be affected by changes in the various assumptions, given that the remaining assumptions are constant. Sensitivity ARO ($\u2019mm) Change in provision Abandonment Cost Estimate increase +10% 979.2 10.0 % Abandonment Cost Estimate decrease -10% 807.0 -10.0 % Discount rate +1.0% 768.2 -14.0 % Discount rate -1.0% 1,042.7 17.0 % Inflation rate +1.0% 1,041.3 17.0 % Inflation rate -1.0% 767.1 -14.0 % ", "dimensions": { "concept": "norwegianenergy:DisclosureOfAssetRetirementObligations", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-411": { "value": "22 Borrowings 22.1 Summary of borrowings 31.12.2022 31.12.2021 USD million Principal amount Book value Principal amount Book value NOR13 Convertible Bond 13.8 13.1 185.0 157.1 NOR15 Convertible Bond2) 207.6 175.7 \u2013 \u2013 NOR14 Senior Unsecured Bond3) 175.0 166.9 175.0 164.9 Total non-current bonds 396.5 355.6 360.0 322.1 Reserve-based lending facility 3) 800.0 764.0 900.0 857.3 Deferred Consideration4) \u2013 \u2013 25.0 25.0 Total non-current debt 800.0 764.0 925.0 882.3 Deferred Consideration4) 25.0 25.0 \u2013 \u2013 Total current debt 25.0 25.0 \u2013 \u2013 Total borrowings 1,221.5 1,144.6 1,285.0 1,204.3 Cash flows Non-cash changes Movements in interest-bearing liabilities 31.12.21 Receipts/ payments Conversion to shares Conversion NOR15 PI K*/ Amortisation 31.12.22 NOR13 Convertible Bond 157.1 \u2013 (29.6) (143.3) 28.8 13.1 NOR15 Convertible Bond \u2013 (4.4) \u2013 168.7 11.4 175.7 NOR14 Senior Unsecured Bond 164.9 (15.8) \u2013 \u2013 17.7 166.9 Reserve-based lending facility 857.3 (100.0) \u2013 \u2013 6.7 764.0 Deferred Consideration 25.0 \u2013 \u2013 \u2013 \u2013 25.0 Total movement non-current interest-bearing liabilities 1,204.3 (120.2) (29.6) 25.5 64.7 1,144.6 Total movement in interest-bearing liabilities 1,204.3 (120.2) (29.6) 25.5 64.7 1,144.6 * PIK = Payment In Kind. Note: Book values reported on the basis of amortised cost for NOR14, the reserve-based lending facility and the convertible bond loan element of NOR13 and NOR15. 1) The Company issued a convertible bond loan of USD 158 million in 2019 where the lender was granted a right to convert the loan into new shares in the Company by way of set-off against the claim on the Company. The loan carries an interest of 8 percent p.a. on a PIK basis, with an alternative option to pay cash interest at 6 percent p.a., payable semi-annually. In 2022, four conversions with a carrying amount of USD 36.6 million took place and USD 29.6 million of amortised cost was derecognised from the financial liability to equity. In December 2022, USD 143.3 million was transferred into the new convertible instrument NOR15. The principal amount transferred was USD 151.4 million. Of the remaining USD 13.8 million outstanding on 31 December 2022, USD 13.6 million was converted into equity by 13 January. The remaining balance of USD 0.2 million was subject to the NOR13 amendments as proposed by the Company in November 2022 on 19 January 2023. 2) The Company issued a convertible bond loan of USD 207.6 million in December 2022, made up of a transfer from NOR13 of USD 151.4 million plus additional compensation bonds of USD 56.2 million. Similarly, to NOR13, the lender was granted a right to convert the loan into new shares in the Company by way of set-off against the claim on the Company. The loan carries an interest of 8 percent p.a. on a PIK basis, with an alternative option to pay cash interest at 6 percent p.a., payable semi-annually. 3) The Company entered into an increased reserve-based lending facility in Q2 2021. The facility has a seven-year tenor with a maximum limit of USD 1.1 billion, with a maximum of USD 1.0 billion available for cash drawdown by the Company. Interest is accrued on the drawn amount with an interest rate comprising the aggregate of SOFR and 4 percent per annum, 4.5 percent per annum from February 2023. The amount drawn on 30 September was USD 800 million, Norwegian Energy Company ASA (BlueNord) made a USD 100 million repayment in July 2022. 4) In accordance with the Sales Purchase Agreement USD 25 million of the consideration is due the earliest of March 2023 or finalising Tyra Redevelopment. 22.2 Details on borrowing Details on borrowings outstanding on 31 December 2022 Reserve-based lending facility In April 2021, Norwegian Energy Company ASA (BlueNord) amended its existing senior secured reserve-based credit facility to commit to a seven-year senior reserve-based credit facility of USD 1.1 billion. The facility is a reserve-based credit facility secured against certain cash flows generated by the Group. The amount available under the facility is recalculated every six months based upon the calculated cash flow generated by certain producing fields and fields under development at an oil price and economic assumptions agreed with the banking syndicate providing the facility. The facility is secured by a pledge over the shares of certain Group companies, a pledge over the Company\u2019s working interest in its share of the DUC licence and security over insurances, hedging contracts, project accounts, intercompany loans and material contracts. The pledged assets on 31 December 2022 amounted to USD 1 ,323 million and represented the carrying value of the pledge of the Group companies whose shares are pledged as described in the section 5 below (Assets pledged as security for interest-bearing debt). Pledge value: carrying value of shares held in Altinex AS, Noreco Denmark A/S, Noreco Oil Denmark A/S, Noreco Petroleum Denmark A/S by Norwegian Energy Company ASA (BlueNord). NOR13 In July 2019, Norwegian Energy Company ASA (BlueNord) issued a subordinated convertible bond loan of USD 158 million with a tenor of eight years where the lender was granted a right to convert the loan into new shares in the Company at a conversion price of NOK 240 (USD 29.3) per share by way of set-off against the claim on the Company. The loan has a mandatory conversion to equity after five years and carries an interest of 8 percent p.a. on a PIK basis, with an alternative option to pay cash interest at 6 percent p.a., payable semi-annually. Should the instrument be in place beyond the five-year conversion period, the interest rate on NOR13 will be reduced to 0.0 percent for the remaining term of the loan. In November 2022, Norwegian Energy Company ASA (BlueNord) proposed for some amendments to the NOR13 bond which included a two-year delay in the mandatory conversion date (8 November 2023 to 31 December 2025) and an inclusion of a call option to allow the Company to redeem the NOR13 bond with cash in December 2025. To reflect the premium of the then share price relative to the NOR13 previous conversion price, the principal amount was updated from approximately USD 165 million to approximately USD 227 million by way of issuance of compensation bonds. Conversion price was reset to USD 51.4307 per share and interest rate remains unchanged. Following the proposed amendments, a claim arose from two minority NOR13 bondholders in which Norwegian Energy Company ASA (BlueNord) received a temporary injunction from the Oslo District Court that restricted the NOR13 amendments from being implemented (the \u201cRuling\u201d). To allow the NOR13 bondholders who wanted to benefit from the commercial position represented by the amendments, Norwegian Energy Company ASA (BlueNord) proposed a new NOR15 subordinated convertible bond for the bondholders to exchange their holdings of NOR13 for NOR15 (see note below). In December 2022, the Oslo District Court confirmed that the temporary injunction was withdrawn, and the Ruling is no longer in effect. The exchange offer for NOR15 continued as planned, with 91.6 percent of the outstanding NOR13 bonds exchanged to the new NOR15 bonds, and the remainder converted to equity or remained subject to the NOR13 amendments. The value of the NOR13 convertible bond at year end is USD 13.8 million of which USD 13.6 million converted in January 2023. NOR14 In December 2019, Norwegian Energy Company ASA (BlueNord) successfully completed the issue of a USD 175 million unsecured bond. The proceeds are utilised for general corporate purposes and the bond carries an interest of 9 percent p.a., payable semi-annually, with a six and a half-year tenor. NOR15 In December 2022, Norwegian Energy Company ASA (BlueNord) launched an exchange offer for the NOR13 bondholders in exchange for a new subordinated convertible bond of USD 208 million, with revised terms and a later and more flexible conversion date in 2025. The Company issued a total of 207,641,201 new NOR15 bonds, each with a nominal value of USD 1. The NOR15 bond terms mirror the amendments of the NOR13 bond except that inter alia a tap issue mechanism has been included. Interest payments are on similar terms with NOR13, which is an interest of 8 percent p.a. on a PIK basis, with an alternative option to pay cash interest at six percent p.a., payable semi-annually. 22.3 Covenants Covenants relating to interest-bearing debt Reserve-based lending facility The reserve-based credit facility constitutes senior debt of the Company and is secured on a first priority basis against certain of the Company\u2019s subsidiaries and their assets. The reserve-based credit facility agreement contains a financial covenant that the ratio of Net Debt to EBITDAX (earnings before interest, tax, depreciation, amortisation and exploration) shall be: less than 6.0:1.0 at the end of financial years 2021 and 2022; less than 3.5:1.0 at the end of financial year 2023; and less than 3.0:1.0 at the end of financial year 2024 onwards until the expiry of the facility. Each test is carried out on the audited full year financial statements of Norwegian Energy Company ASA (BlueNord). Norwegian Energy Company ASA (BlueNord) must also demonstrate minimum liquidity on a look forward basis of USD 50 million during the relevant period, which is currently to the completion of the Tyra redevelopment project. The agreement also includes special covenants which, among other, restrict the Company from taking on additional secured debt, provide parameters for minimum and maximum hedging requirements and restrict declaration of dividends or other distributions. Norwegian Energy Company ASA (BlueNord) is in compliance with these covenants at the end of 2022. NOR14 In July 2021, Norwegian Energy Company ASA (BlueNord)\u2019s written resolution regarding the addition of further headroom under the Leverage Ratio covenant through to the end of 2023 was resolved and approved by the Company\u2019s NOR14 bondholders. Based on this written resolution, the maximum Leverage Ratio has been amended to 7.0x (from 5.0x) during the Tyra Redevelopment Period ending Q2 2023, 6.0x (from 3.0x) during Q3 2023 and 5.0x (from 3.0x) during Q4 2023. From Q1 2024 onwards, the maximum Leverage Ratio will revert to 3.0x per the original bond terms. In addition to the change in maximum permitted leverage, Norwegian Energy Company ASA (BlueNord)\u2019s minimum liquidity threshold has increased to USD 75 million until the end of 2023 (from USD 50 million until end Q2 2023 and USD 25 million during Q3 and Q4 2023). Norwegian Energy Company ASA (BlueNord) is in compliance with the covenants at the end of 2022. 22.4 Payment structure Payment structure (USD million) Year NOR13 NOR14 NOR15 Reserve-based lending facility Deferred consideration Total 2023 \u2013 \u2013 \u2013 \u2013 25.0 25.0 2024 \u2013 \u2013 \u2013 75.0 \u2013 75.0 2025 \u2013 \u2013 \u2013 275.0 \u2013 275.0 2026 \u2013 175.0 \u2013 275.0 \u2013 450.0 2027 \u2013 \u2013 \u2013 138.0 \u2013 138.0 2028 \u2013 \u2013 \u2013 38.0 \u2013 38.0 Total \u2013 175.0 \u2013 800.0 25.0 1,000.0 Interest payments (USD million): Year NOR13* NOR14 NOR15* Reserve-based lending facility Deferred consideration Total Interest rate 9.0% \u2013 SOFR** 4.0% 2023 \u2013 15.8 \u2013 76.7 1.0 93.7 2024 \u2013 15.8 \u2013 75.8 \u2013 91.6 2025 \u2013 15.8 \u2013 58.7 \u2013 74. 5 2026 \u2013 7.9 \u2013 33.4 \u2013 41.3 2027 \u2013 \u2013 \u2013 8.9 \u2013 8.9 2028 \u2013 \u2013 \u2013 0.3 \u2013 0.3 Total \u2013 55.3 \u2013 253.9 1.0 310.2 * NOR13/NOR15 carries a variable interest charge of: (i) 6 percent per annum in cash, payable semi-annually, or; (ii) 8 percent per annum PIK cumulative interest, rolled up semi-annually, to add to NOR13/NOR15 capital on conversion at expiry of the bond. Currently, the Company has elected the PIK interest of 8 percent and is therefore forecasting no cash interest payments on NOR13/NOR15 in the above table. ** In Q3 2021, the Company entered a USD 1.0 billion swap transaction with a group of banks to fix the Company\u2019s floating interest rate (LIBOR/SOFR from 1 November 2021) exposure under its Reserve Lending Facility from November 2021 until 30 June 2024. Norwegian Energy Company ASA (BlueNord) will, as a result, pay interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin. 22.5 Assets pledged as security for interest-bearing debt Net book value in the separate financial statements of assets pledged as securities The Group has the following pledged assets for the reserve-based lending facility: USD million 2022 2021 BlueNord shares in Altinex AS 393.5 392.6 Altinex AS shares in Noreco Olie-og Gasutvinding Danmark B.V and other companies 621.5 1,371.5 Loans from Parent to subsidiaries 308.3 300.1 Total net book value 1,323.3 2,064.3 ", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-468": { "value": "23 Trade payables and other payables USD million 2022 2021 Trade payable 17.0 5.4 Liabilities to operators relating to joint venture licences 66.8 73.4 Accrued interest 3.3 2.5 Salary accruals 2.5 2.1 Public duties payable 8.3 14.0 Deferred consideration 25.0 \u2013 Other current liabilities 17.7 33.1 Total trade payables and other current liabilities 140.6 130.5 Trade and other payables held in currency USD million 2022 2021 USD 54.7 82.9 DKK 71.2 22.5 EUR 11.3 21.7 GBP 0.8 1.9 NOK 2.6 1.4 Total 140.6 130.5 ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-460": { "value": "23 Trade payables and other payables USD million 2022 2021 Trade payable 17.0 5.4 Liabilities to operators relating to joint venture licences 66.8 73.4 Accrued interest 3.3 2.5 Salary accruals 2.5 2.1 Public duties payable 8.3 14.0 Deferred consideration 25.0 \u2013 Other current liabilities 17.7 33.1 Total trade payables and other current liabilities 140.6 130.5 Trade and other payables held in currency USD million 2022 2021 USD 54.7 82.9 DKK 71.2 22.5 EUR 11.3 21.7 GBP 0.8 1.9 NOK 2.6 1.4 Total 140.6 130.5 ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-447": { "value": "23 Trade payables and other payables USD million 2022 2021 Trade payable 17.0 5.4 Liabilities to operators relating to joint venture licences 66.8 73.4 Accrued interest 3.3 2.5 Salary accruals 2.5 2.1 Public duties payable 8.3 14.0 Deferred consideration 25.0 \u2013 Other current liabilities 17.7 33.1 Total trade payables and other current liabilities 140.6 130.5 Trade and other payables held in currency USD million 2022 2021 USD 54.7 82.9 DKK 71.2 22.5 EUR 11.3 21.7 GBP 0.8 1.9 NOK 2.6 1.4 Total 140.6 130.5 ", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-412": { "value": "23 Trade payables and other payables USD million 2022 2021 Trade payable 17.0 5.4 Liabilities to operators relating to joint venture licences 66.8 73.4 Accrued interest 3.3 2.5 Salary accruals 2.5 2.1 Public duties payable 8.3 14.0 Deferred consideration 25.0 \u2013 Other current liabilities 17.7 33.1 Total trade payables and other current liabilities 140.6 130.5 Trade and other payables held in currency USD million 2022 2021 USD 54.7 82.9 DKK 71.2 22.5 EUR 11.3 21.7 GBP 0.8 1.9 NOK 2.6 1.4 Total 140.6 130.5 ", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-413": { "value": "24 Share-based compensation Please see the Executive Remuneration Report 2022 for more details on long-term incentive scheme to key management and Board of Directors in the period 2018 \u2013 2022. Number of Share options Retention shares Performance shares Total share options outstanding as at 1 January 2021 983,868 \u2013 \u2013 Share options relinquished in 2021 (235,000) \u2013 \u2013 Outstanding at 31 December 2021 748 ,868 \u2013 \u2013 Granted in 2022 122,000 112,825 188,935 Exercised in 2022 (301,000) \u2013 \u2013 Translated in 2022 (178,000) \u2013 \u2013 Outstanding at 31 December 2022 391,868 112,825 188,935 The expense recognised during the year is shown in the following table: USD million 2022 2021 Expense arising from equity-settled share-based payment transactions 0.0 0.3 Expense arising from Retention shares and Performance shares 1.4 \u2013 Total expense arising from long-term incentive schemes 1.4 0.3 The following table list the inputs to the model used: Weighted averages 2022 Fair value of options at valuation date (NOK) 83 Share price at valuation date (NOK) 143 Exercise price (NOK) 160 Expected volatility 57.49% Expected life (years) 2.7 Expected dividends n/a Risk-free rate (based on government bonds) 0.35% ", "dimensions": { "concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-415": { "value": "25 Guarantees Overview of issued guarantees on 31 December 2022 The parent company of the Group, Norwegian Energy Company ASA (BlueNord) has issued a parent company guarantee on behalf of its subsidiary Norwegian Energy Company UK Ltd and Noreco Oil (UK) Limited. Norwegian Energy Company ASA (BlueNord) guarantees that, if any amounts become payable by Norwegian Energy Company UK Ltd or by Noreco Oil (UK) Limited to the UK Secretary of State under the terms of the licence and the company does not repay those amounts on first demand, Norwegian Energy Company ASA (BlueNord) shall pay to the UK Secretary of State on demand an amount equal to all such amounts. Under the forfeiture agreement Premier assumes this risk as between Premier and Norwegian Energy Company ASA (BlueNord) so, while this contingent liability to the Secretary of State would need to be recognised in any future sale of the company, Noreco Oil (UK) Limited does have recourse against Premier if it defaults in its performance. On 6 December 2007, Norwegian Energy Company ASA (BlueNord) issued a parent company guarantee to the Danish Ministry of Climate, Energy and Building on behalf of its subsidiary Noreco Oil Denmark A/S and Noreco Petroleum Denmark A/S. On 31 December 2012, Norwegian Energy Company ASA (BlueNord) issued a parent company guarantee on behalf of its subsidiary Noreco Norway AS. Norwegian Energy Company ASA (BlueNord) guarantees that, if any amounts become payable by Noreco Norway AS to the Norwegian Secretary of State under the terms of the licences and the company does not repay those amounts on first demand, Norwegian Energy Company ASA (BlueNord) shall pay to the Norwegian Secretary of State on demand an amount equal to all such amounts. Noreco Norway AS was liquidated in 2018, however as per 31.12.2022, the guarantee has not been withdrawn. The Company has provided a parent company guarantee to the Danish Ministry of Climate, Energy and Utilities related to the Group\u2019s activities on the DCS, including Norwegian Energy Company ASA (BlueNord)\u2019s participation in the Tyra West Pipeline and the Lulita licence. The Company has also provided a parent company guarantee towards the lenders in relation to the Company\u2019s USD 1.1 billion reserve-based lending facility and customary obligations/guarantees under joint operating agreements. Norwegian Energy Company ASA (BlueNord) has also provided a parent company guarantee to Shell Energy Europe Limited in relation to its subsidiary Noreco Oil Denmark A/S\u2019s obligations under a gas offtake and transportation agreement capped at EUR 30 million. Furthermore, the Company has provided a parent company guarantee to TotalEnergies EP Danmark A/S for its obligations under the JOA together with a guarantee from Shell. Norwegian Energy Company ASA (BlueNord) has provided standby letters of credit of USD 100 million, issued under the USD 100 million sub-limit of the RBL facility for the benefit of Shell in connection with this guarantee. In relation to Norwegian Energy Company ASA (BlueNord)\u2019s historic operations in the UK North Sea, the Company has issued a parent company guarantee on behalf of its subsidiaries Norwegian Energy Company UK Ltd and BlueNord Oil (UK) Limited. ", "dimensions": { "concept": "norwegianenergy:DisclosureOfGuarantees", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-414": { "value": "26 Investments in jointly owned assets Investments in jointly own assets are included in the accounts by recognising the Groups share of the assets, liabilities, revenues and expenses related to the joint operation. The Group holds the following licence equities on 31 December 2022: Licence Field Country Ownership share DUC DUC Denmark 36.8 % 1/90 Lulita Part Denmark 20.0 % 7/86 Lulita Part Denmark 20.0 % 8/06B \u2013 Denmark 36.8 % ", "dimensions": { "concept": "ifrs-full:DisclosureOfJointVenturesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-461": { "value": "27 Contingencies and commitments Financial commitments As a partner in DUC, the Company has commitment to fund its proportional share of the budget and work programmes of the DUC. In December each year, the operating budget (which includes operating expenditures, capital expenditure related to production, exploration and abandonment) for the following year, is agreed amongst the DUC partners. For the coming four years, the average operating budget is expected to be around USD 230 million per year. Capital and abandonment expenditure for individual projects, such as Tyra, are approved separately. Norwegian Energy Company ASA (BlueNord)\u2019s capital commitments are principally related to the ongoing Tyra redevelopment project. The gross capital and abandonment expenditure budget for the Tyra redevelopment project at the time of the investment decision was DKK 21 billion which in 2022 was increased to DKK 26.3 billion and DKK 20.6 billion had been incurred by the end of 2022. Based on the current project schedule, Norwegian Energy Company ASA (BlueNord) will be required to fund its proportional share of this remaining expenditure over the next two years with Tyra to restart production by end of 2023. Further, Norwegian Energy Company ASA (BlueNord) has capital commitments to infill wells planned for Halfdan in 2023 with a gross DUC budget of DKK 0.6 billion. The DUC is obliged to use the specially constructed oil trunk line, pumps and terminal facilities and to contribute to the construction and financing costs thereof as a result of an agreement entered into with the Danish government. This obligation is approximately USD 18 million per year (2022: USD 16 million gross). In addition to the above and in order to obtain the consent of TotalEnergies EP Danmark A/S to the acquisition, Noreco Oil Denmark A/S agreed to deposit cash in a secured cash call security account in favour of Total E&P Danmark A/S (the concessionaire in respect of the Sole Concession). On 31 December 2022, the escrow account was USD 143 million. All payment obligations from Norwegian Energy Company ASA (BlueNord) to the cash call security account have been made and there will be no further increase. The cash call security amount will then decrease to USD 100 million at the end of the year in which the Tyra redevelopment project is completed and can, on certain terms and conditions, be replaced with a letter of credit or other type of security. Contingent liabilities In relation to the Nini and Cecilie fields, Norwegian Energy Company ASA (BlueNord) was in 2015 prevented from making payments for its share of production costs and was consequently in breach of the licence agreements. In accordance with the JOAs, the Nini and Cecilie licences were forfeitured and the licences were taken over by the partners, whereas the debt remained with Norwegian Energy Company ASA (BlueNord). Norwegian Energy Company ASA (BlueNord) and representatives from the bondholders reached an agreement during 2015 which entails that the Danish Norwegian Energy Company ASA (BlueNord) entity remains liable for the abandonment obligation, but the liability is in any and all circumstances limited to a maximum amount equal to the restricted cash account of USD 61 million (DKK 427 million), adjusted for interest. The total provision made for the asset retirement obligations reflects this. The Company has received a claim regarding the level of \u00d8rsted pipeline tariffs charged since 2013. As the relevant authority (Forsyningstilsynet) is currently reassessing their view, Norwegian Energy Company ASA (BlueNord) believes that there is no basis for this claim prior to a new ruling setting the appropriate level of these tariffs. Given the outcome of this and any consequent liability is not yet known, the Company has not recognised a provision for this claim. During the normal course of its business, the Company may be involved in disputes, including tax disputes. The Company has not made accruals for possible liabilities related to litigation and claims based on management\u2019s best judgement. Norwegian Energy Company ASA (BlueNord) has unlimited liability for damage in relation to its participation in the DUC. The Company has insured its pro rata liability in line with standard market practice. Apart from the issues discussed above, the Group is not involved in claims from public authorities, legal claims or arbitrations that could have a significant negative impact on the Company\u2019s financial position or results. ", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-448": { "value": "27 Contingencies and commitments Financial commitments As a partner in DUC, the Company has commitment to fund its proportional share of the budget and work programmes of the DUC. In December each year, the operating budget (which includes operating expenditures, capital expenditure related to production, exploration and abandonment) for the following year, is agreed amongst the DUC partners. For the coming four years, the average operating budget is expected to be around USD 230 million per year. Capital and abandonment expenditure for individual projects, such as Tyra, are approved separately. Norwegian Energy Company ASA (BlueNord)\u2019s capital commitments are principally related to the ongoing Tyra redevelopment project. The gross capital and abandonment expenditure budget for the Tyra redevelopment project at the time of the investment decision was DKK 21 billion which in 2022 was increased to DKK 26.3 billion and DKK 20.6 billion had been incurred by the end of 2022. Based on the current project schedule, Norwegian Energy Company ASA (BlueNord) will be required to fund its proportional share of this remaining expenditure over the next two years with Tyra to restart production by end of 2023. Further, Norwegian Energy Company ASA (BlueNord) has capital commitments to infill wells planned for Halfdan in 2023 with a gross DUC budget of DKK 0.6 billion. The DUC is obliged to use the specially constructed oil trunk line, pumps and terminal facilities and to contribute to the construction and financing costs thereof as a result of an agreement entered into with the Danish government. This obligation is approximately USD 18 million per year (2022: USD 16 million gross). In addition to the above and in order to obtain the consent of TotalEnergies EP Danmark A/S to the acquisition, Noreco Oil Denmark A/S agreed to deposit cash in a secured cash call security account in favour of Total E&P Danmark A/S (the concessionaire in respect of the Sole Concession). On 31 December 2022, the escrow account was USD 143 million. All payment obligations from Norwegian Energy Company ASA (BlueNord) to the cash call security account have been made and there will be no further increase. The cash call security amount will then decrease to USD 100 million at the end of the year in which the Tyra redevelopment project is completed and can, on certain terms and conditions, be replaced with a letter of credit or other type of security. Contingent liabilities In relation to the Nini and Cecilie fields, Norwegian Energy Company ASA (BlueNord) was in 2015 prevented from making payments for its share of production costs and was consequently in breach of the licence agreements. In accordance with the JOAs, the Nini and Cecilie licences were forfeitured and the licences were taken over by the partners, whereas the debt remained with Norwegian Energy Company ASA (BlueNord). Norwegian Energy Company ASA (BlueNord) and representatives from the bondholders reached an agreement during 2015 which entails that the Danish Norwegian Energy Company ASA (BlueNord) entity remains liable for the abandonment obligation, but the liability is in any and all circumstances limited to a maximum amount equal to the restricted cash account of USD 61 million (DKK 427 million), adjusted for interest. The total provision made for the asset retirement obligations reflects this. The Company has received a claim regarding the level of \u00d8rsted pipeline tariffs charged since 2013. As the relevant authority (Forsyningstilsynet) is currently reassessing their view, Norwegian Energy Company ASA (BlueNord) believes that there is no basis for this claim prior to a new ruling setting the appropriate level of these tariffs. Given the outcome of this and any consequent liability is not yet known, the Company has not recognised a provision for this claim. During the normal course of its business, the Company may be involved in disputes, including tax disputes. The Company has not made accruals for possible liabilities related to litigation and claims based on management\u2019s best judgement. Norwegian Energy Company ASA (BlueNord) has unlimited liability for damage in relation to its participation in the DUC. The Company has insured its pro rata liability in line with standard market practice. Apart from the issues discussed above, the Group is not involved in claims from public authorities, legal claims or arbitrations that could have a significant negative impact on the Company\u2019s financial position or results. ", "dimensions": { "concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-416": { "value": "27 Contingencies and commitments Financial commitments As a partner in DUC, the Company has commitment to fund its proportional share of the budget and work programmes of the DUC. In December each year, the operating budget (which includes operating expenditures, capital expenditure related to production, exploration and abandonment) for the following year, is agreed amongst the DUC partners. For the coming four years, the average operating budget is expected to be around USD 230 million per year. Capital and abandonment expenditure for individual projects, such as Tyra, are approved separately. Norwegian Energy Company ASA (BlueNord)\u2019s capital commitments are principally related to the ongoing Tyra redevelopment project. The gross capital and abandonment expenditure budget for the Tyra redevelopment project at the time of the investment decision was DKK 21 billion which in 2022 was increased to DKK 26.3 billion and DKK 20.6 billion had been incurred by the end of 2022. Based on the current project schedule, Norwegian Energy Company ASA (BlueNord) will be required to fund its proportional share of this remaining expenditure over the next two years with Tyra to restart production by end of 2023. Further, Norwegian Energy Company ASA (BlueNord) has capital commitments to infill wells planned for Halfdan in 2023 with a gross DUC budget of DKK 0.6 billion. The DUC is obliged to use the specially constructed oil trunk line, pumps and terminal facilities and to contribute to the construction and financing costs thereof as a result of an agreement entered into with the Danish government. This obligation is approximately USD 18 million per year (2022: USD 16 million gross). In addition to the above and in order to obtain the consent of TotalEnergies EP Danmark A/S to the acquisition, Noreco Oil Denmark A/S agreed to deposit cash in a secured cash call security account in favour of Total E&P Danmark A/S (the concessionaire in respect of the Sole Concession). On 31 December 2022, the escrow account was USD 143 million. All payment obligations from Norwegian Energy Company ASA (BlueNord) to the cash call security account have been made and there will be no further increase. The cash call security amount will then decrease to USD 100 million at the end of the year in which the Tyra redevelopment project is completed and can, on certain terms and conditions, be replaced with a letter of credit or other type of security. Contingent liabilities In relation to the Nini and Cecilie fields, Norwegian Energy Company ASA (BlueNord) was in 2015 prevented from making payments for its share of production costs and was consequently in breach of the licence agreements. In accordance with the JOAs, the Nini and Cecilie licences were forfeitured and the licences were taken over by the partners, whereas the debt remained with Norwegian Energy Company ASA (BlueNord). Norwegian Energy Company ASA (BlueNord) and representatives from the bondholders reached an agreement during 2015 which entails that the Danish Norwegian Energy Company ASA (BlueNord) entity remains liable for the abandonment obligation, but the liability is in any and all circumstances limited to a maximum amount equal to the restricted cash account of USD 61 million (DKK 427 million), adjusted for interest. The total provision made for the asset retirement obligations reflects this. The Company has received a claim regarding the level of \u00d8rsted pipeline tariffs charged since 2013. As the relevant authority (Forsyningstilsynet) is currently reassessing their view, Norwegian Energy Company ASA (BlueNord) believes that there is no basis for this claim prior to a new ruling setting the appropriate level of these tariffs. Given the outcome of this and any consequent liability is not yet known, the Company has not recognised a provision for this claim. During the normal course of its business, the Company may be involved in disputes, including tax disputes. The Company has not made accruals for possible liabilities related to litigation and claims based on management\u2019s best judgement. Norwegian Energy Company ASA (BlueNord) has unlimited liability for damage in relation to its participation in the DUC. The Company has insured its pro rata liability in line with standard market practice. Apart from the issues discussed above, the Group is not involved in claims from public authorities, legal claims or arbitrations that could have a significant negative impact on the Company\u2019s financial position or results. ", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-449": { "value": "28 Related party transactions Other than fees to directors of the board the group did not have any transactions with related parties during 2022. ", "dimensions": { "concept": "ifrs-full:DisclosureOfTransactionsBetweenRelatedPartiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-417": { "value": "28 Related party transactions Other than fees to directors of the board the group did not have any transactions with related parties during 2022. ", "dimensions": { "concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-418": { "value": "29 Subsequent events There are no events with significant accounting impacts that have occurred between the end of the reporting period and the date of this report. The Company monitors the Russia-Ukraine war closely and has not identified any negative impact on the Company\u2019s assets or income. ", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-3": { "value": "Norway", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-4": { "value": "Norway", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-5": { "value": "Nedre Vollgate 1, 0158 Oslo, Norway", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-6": { "value": "Oslo", "dimensions": { "concept": "ifrs-full:PrincipalPlaceOfBusiness", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-7": { "value": "Oil and gas", "dimensions": { "concept": "ifrs-full:DescriptionOfNatureOfEntitysOperationsAndPrincipalActivities", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-8": { "value": "Norwegian Energy Company ASA", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } }, "fact-9": { "value": "Norwegian Energy Company ASA", "dimensions": { "concept": "ifrs-full:NameOfUltimateParentOfGroup", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00" } } } }