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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 2024 were approved by the Board of Directors on 8 April 2025 and will be presented for approval at the Annual General Meeting on 14 May 2025. The material 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 BlueNord ASA have been prepared in accordance with the IFRS \u00ae Accounting Standards, as endorsed by the EU. The Group also provide information required in accordance with the Norwegian Accounting Act and associated NGAAP standards. The preparation of financial statements in accordance with IFRS \u00ae Accounting Standards 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. 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 material accounting policies Amendments to standards Effective January 1, 2024, amendments to IAS 1 Presentation of Financial Statements have resulted in the reclassification of the convertible bond loan as a current liability. BlueNord has a bond loan that comprises a financial liability and an option granted to the holders to convert the bond into shares of the Company at any time before maturity. The conversion option does not meet the definition of an equity instrument and is an embedded derivative recognised separately from the host liability. BlueNord interpreted the previous IAS 1 that the holders\u2019 option to convert at any time did not affect the classification, and the bond loan and related embedded derivatives were classified as non-current as long as it was more than twelve months to maturity. The amended IAS 1 clarified that transfer of a company\u2019s shares is a form of settlement and when a company classifies the host liability as current or non-current, it can ignore only those conversion options that are recognised as equity. As the Company does not have the right to defer settlement for at least twelve months from the reporting dates, the host liability and the related embedded derivatives are reclassified as current. Except for the amendments to IAS 1 mentioned above, there were no material changes in accounting policies in 2024. IFRS 18 Presentation and Disclosure in Financial Statements IFRS 18 will replace IAS 1 Presentation of Financial Statements and applies for annual reporting periods beginning on or after 1 January 2027, provided it is approved by the EU. The new standard introduces the following key new requirements: Classify all income and expenses into five categories in the profit or loss section of the consolidated statement of comprehensive income, namely the operating, investing, financing, discontinued operations and income tax categories. It is also required to present a newly defined operating profit subtotal. Net result will not change. Management-defined performance measures (MPMs) are disclosed in a single note in the financial statements. Enhanced guidance is provided on how to group information in the financial statements. In addition, it is required to use the operating profit subtotal as the starting point for the consolidated statement of cash flows when presenting cash flows from operating activities under the indirect method. The Group has not assessed the impact of the new standard, particularly with respect to the structure of the profit or loss section of the consolidated statement of comprehensive income, the consolidated statement of cash flows and the additional disclosures required for MPMs.
1 Summary of material accounting policies continued
1.2 Consolidation
Subsidiaries
The consolidated financial statements comprise the financial statements of the Company and its
subsidiaries as of 31 December 2024. Subsidiaries are all entities over which the Group has control. Control
is achieved where the Group has the power over the subsidiary, has rights, or is exposed to variable returns
from the subsidiary and has the ability to use its power to affect its returns. All subsidiaries are 100 percent
owned by the Group and there are no non-controlling interests. In January 2024 BlueNord acquired 100
percent of the shares in CarbonCuts A/S, an early-stage CCS company in Denmark.
The Group had the following subsidiaries on 31 December 2024:
Country of Ordinary Ordinary
incorporation shares shares
and place directly held held by the
Name
of business
Nature of business
by parent (%) Group (%)
BlueNord Denmark A/S
Denmark
Intermediate holding company
100%
BlueNord Energy Denmark A/S
Denmark
Exploration and production activity
100%
BlueNord Gas Denmark A/S
Denmark
Exploration and production activity
100%
CarbonCuts A/S
Denmark
Carbon capture and storage
100%
BlueNord Energy 8/06
Netherlands
Exploration and production
100%
Denmark B.V activity
BlueNord Pipeline Denmark Aps Denmark
Infrastructure oil and gas
100%
BlueNord Energy UK Ltd
Great Britain
Exploration activity
100%
BlueNord UK Ltd
Great Britain
Exploration activity
100%
100%
Altinex AS
Norway
Intermediate holding company
100%
100%
BlueNord AS
Norway
Dormant company
100%
100%
Joint arrangements
BlueNord has interests in licenses on the Danish Continental Shelf. A joint arrangement is defined as
an arrangement over which two or more parties have joint control. Joint control is the contractually
agreed sharing of control which exists only when decisions about the relevant activities (being those
that significantly affect the returns of the arrangement) require unanimous consent of the parties
sharing control.
Under IFRS 11 Joint Arrangements, a joint operation is a joint arrangement whereby the parties that
have joint control of the arrangement have rights to the assets and obligations for the liabilities, relating
to the arrangement. BlueNord recognises investments in joint operations (oil and gas production
licences) by reporting its share of related revenues, expenses, assets, liabilities and cash flows, under
the respective items in the Company\u2019s financial statements.
1.3 Segment reporting 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 (\u2018the functional currency\u2019). 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\u2019 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 All currency translation adjustments are recognised in other comprehensive income (OCI). 1.5 Property, plant and equipment Property, plant and equipment include asset under construction, production facilities, pipelines, machinery, and equipment. Items of property, plant and equipment are measured at cost, less accumulated depreciation and accumulated impairment losses. 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. Direct and indirect expenditures related to asset under construction are capitalised. The development phase commences when the licence partners have decided field evaluation. Production facilities are depreciated in accordance with the unit of production (UoP) method based on proven and probable reserves (the ratio between annual production quantity and the reserves). If realisation of probable reserves demands further future investments, these are added to the basis of depreciation. Acquired assets used for extraction and production of petroleum deposits, are depreciated using the UoP method based on proven and probable reserves. Onshore assets are depreciated over the estimated useful life, according to the straight-line method, three to five years. Pipelines are depreciated to the expiry of the licence, according to the straight-line method. Depreciation methods, useful lives, residual values and reserves are reviewed at each reporting date and adjusted if appropriate.
1 Summary of material accounting policies continued
1.6 Intangible assets
Licence rights
Licence rights acquired in a business combination are measured on initial recognition at cost.
Following initial recognition, licence rights are depreciated using the UoP method based on proven and
probable reserves.
1.7 Impairment of non-financial assets
The Group has determined that the smallest identifiable assets or groups of assets that generate cash
inflows independently from other assets or groups are the DUC assets as a whole and the CarbonCuts
business unit. Therefore, the Group has concluded that it has two cash-generating units (CGUs).
If there is any indication that the CGU may be impaired, recoverable amount shall be estimated for the
CGU, and compared to its carrying amount. The recoverable amount is the higher of the fair value less
costs of disposal and the value in use.
In estimating value in use, expected future cash flows are discounted to the net present value applying
a discount rate after tax that reflects the current market valuation of the time value of money and risks
specific to the CGU. The discount rate is derived from a weighted average cost of capital (\u2018WACC\u2019)
for a market participant. For the purpose of impairment testing the lifetime of the field is normally
determined to be the time when the operating cash flows from the field become negative.
If there is any indication that the DUC CGU may be impaired, the Group has relied on its market
capitalisation to arrive at an estimate of the headroom of the DUC CGU.
As the Company\u2019s shares are listed on the Oslo Stock Exchange, the market capitalisation is regarded
as a good approximation of the fair value of the Group\u2019s equity (DUC CGU). The Group\u2019s judgement
is that it can make a reliable estimate of the fair value of its equity and thereby the CGUs, based on its
market capitalisation. Adjusted for any estimated differences between the carrying amounts and fair
value of assets and liabilities not included in the CGUs, the difference between its market capitalisation
and carrying amount of equity is a reliable estimate of the difference between the estimated fair value
and the carrying amount of the CGUs (\u2018headroom\u2019). Adjusted for cost of disposal, if this gives a positive
headroom, it is not necessary to estimate value in use, should an impairment test be required. If not
positive a value in use calculation will be calculated and compared to the carrying value of the CGU.
On the CarbonCuts CGU, the Group has recognised a goodwill from the acquisition of CarbonCuts
and the carrying amounts and recoverable amounts are considered immaterial, therefore no formal
impairment test has been performed as any impairment would be immaterial.
1.8 Financial instruments
The Group has financial instruments at fair value through profit or loss and at amortised cost. See note
19.2 Financial instruments for overview of the categories.
The Group has designated derivatives as cash flow hedging instruments, see note 1.10, with the
change in fair value temporarily to other comprehensive income.
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).
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. 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.
Further details on fair values of financial instruments are provided in note 19 Financial instruments.
1.9 Impairment of financial assets
The Group applies a simplified approach in calculating expected credit losses (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 on future sale of oil and gas. The Group has
elected to apply cash flow hedge accounting designating these derivatives. These derivative financial
instruments 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.
1.11 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.
1.12 Over/under-lifting of hydrocarbons
Over/under-lifting occurs when the Group has lifted and sold more or fewer hydrocarbons from a
producing field than what the Group is entitled to at the time of lifting. When over-lifting occurs, the
Group has recognised more revenue than it is entitled to and for which it has been charged production
costs from the Operator, and consequently the Group recognises an additional expense related to
the over-lift. For under-lifting, the Group has been charged production costs from the Operator related
to production of hydrocarbons that it has not sold, and consequently the Group defers some costs.
Over-lifting of hydrocarbons is presented as other current liabilities, under-lifting of hydrocarbons
is presented as other current assets. The value of over/under-lifting is measured at production cost
including depreciation. Over-lifting and under-lifting of hydrocarbons are presented at gross. Over/
under-lift positions are expected to be settled within 12 months from the reporting date.
1.13 Borrowing costs
The Group capitalise borrowing costs that are directly attributable to the construction of qualifying
assets. The Group identifies qualifying assets as those that necessarily takes 12 months or more
to construct and get ready for its intended use. For the periods presented this is only the Tyra
redevelopment project. No additional borrowing cost capitalised in 2024, as Tyra II started production
21 March 2024 hence the qualifying assets were ready for its intended use early 2024.
The Group calculates an annual weighted average interest rate based on general borrowings and
multiplies with the average carrying amount of assets under construction. The amount of borrowing
costs eligible for capitalisation each year is limited to the actual interest expense before capitalisation
less interest income and gains on extinguishment of bond loans.
Other borrowing costs are included as financial expenses in the consolidated statement of
comprehensive income in the period in which they are incurred.
1.14 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 reporting date in the countries where the Company and its subsidiaries operate and
generate taxable income.
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 \u2018Chapter 2\u2019 tax of 25 percent plus a specific hydrocarbon tax (Chapter 3A) of 52 percent, in which the 25 percent tax payable is deductible in the tax basis. 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 & 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 temporary new rules whereby the Company will have the possibility of increased uplift by 9 percent and accelerated depreciation during the period from 2017 to 2025. At the same time, an additional tax was introduced which will materialise from 2022 through 2037 if the oil price for the year (indexed from 2017) exceeds USD 75.0. The accumulated additional tax in the years 2022 through 2037 cannot exceed the benefit received in previous years related to the increased uplift and accelerated depreciation. The additional tax is accounted for in the year the oil price exceeds the thresholds. 1.15 Pensions The Group only has defined contribution plans as of 31 December 2024 and 31 December 2023. The contributions are recognised as an employee benefit expense for the periods they relate to. 1.16 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 and shares) of the Group. The fair value of the employee services received in exchange for the grant of the options is recognised as an expense with a corresponding amount recognised to equity. 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; and \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 and 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 and shares 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 and shares are considered an integral part of the grant itself, and the charge will be treated as a cash-settled transaction.
1 Summary of material accounting policies continued
1.17 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
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. Payments for decommissioning of oil and gas fields
are included in investing activities in the cash flow statement, as the Group\u2019s judgement is that the
nature of this expenditure is payment for an item of property, plant and equipment.
1.18 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).
See note 1.12 for a description of accounting for over/under lifting of hydrocarbons in the Statement
of Financial Position.
1.19 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.
1.20 Consolidated statement of cash flows
The consolidated statement of cash flows is prepared according to the indirect method. See note 1.11
for the definition of \u2018Cash and cash equivalents\u2019.
Payments for decommissioning of oil and gas fields are included in investing activities, see note 1.17.
For payment of deferred consideration, the Group\u2019s judgement is that amounts that relates to
obtaining control in a business combination is included in investing activities.
", "dimensions": { "concept": "ifrs-full:DisclosureOfMaterialAccountingPolicyInformationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-430": { "value": "
BlueNord ASA (\u2018BlueNord\u2019, \u2018the Company\u2019 of \u2018the Group\u2019) is a public limited liability company registered
in Norway, with headquarters in Oslo (Nedre Vollgate 3, 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 2024 were approved by the Board of Directors on 8 April
2025 and will be presented for approval at the Annual General Meeting on 14 May 2025.
The material 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-2": { "value": "BlueNord ASA", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-427": { "value": "BlueNord ASA", "dimensions": { "concept": "ifrs-full:NameOfUltimateParentOfGroup", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-481": { "value": "BlueNord ASA", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-3": { "value": "public limited liability company", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-4": { "value": "Norway", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-428": { "value": "Norway", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-5": { "value": "Oslo ", "dimensions": { "concept": "ifrs-full:PrincipalPlaceOfBusiness", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-6": { "value": "Nedre Vollgate 3, 0158 Oslo", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-479": { "value": "The consolidated financial statements for 2024 were approved by the Board of Directors on 8 April 2025 and will be presented for approval at the Annual General Meeting on 14 May 2025. ", "dimensions": { "concept": "ifrs-full:DisclosureOfAuthorisationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-431": { "value": "
1.1 Basis of preparation
The consolidated financial statements of BlueNord ASA have been prepared in accordance with the
IFRS
\u00ae
Accounting Standards, as endorsed by the EU. The Group also provide information required in
accordance with the Norwegian Accounting Act and associated NGAAP standards.
The preparation of financial statements in accordance with IFRS
\u00ae
Accounting Standards 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.
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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-480": { "value": "The consolidated financial statements of BlueNord ASA have been prepared in accordance with the IFRS \u00ae Accounting Standards, as endorsed by the EU. The Group also provide information required in accordance with the Norwegian Accounting Act and associated NGAAP standards. ", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-432": { "value": "
1.1.1 Changes in material accounting policies
Amendments to standards
Effective January 1, 2024, amendments to IAS 1 Presentation of Financial Statements have resulted in
the reclassification of the convertible bond loan as a current liability.
BlueNord has a bond loan that comprises a financial liability and an option granted to the holders to
convert the bond into shares of the Company at any time before maturity. The conversion option does
not meet the definition of an equity instrument and is an embedded derivative recognised separately
from the host liability.
BlueNord interpreted the previous IAS 1 that the holders\u2019 option to convert at any time did not affect the
classification, and the bond loan and related embedded derivatives were classified as non-current as
long as it was more than twelve months to maturity.
The amended IAS 1 clarified that transfer of a company\u2019s shares is a form of settlement and when a
company classifies the host liability as current or non-current, it can ignore only those conversion
options that are recognised as equity. As the Company does not have the right to defer settlement for
at least twelve months from the reporting dates, the host liability and the related embedded derivatives
are reclassified as current.
Except for the amendments to IAS 1 mentioned above, there were no material changes in accounting
policies in 2024.
IFRS 18 Presentation and Disclosure in Financial Statements
IFRS 18 will replace IAS 1 Presentation of Financial Statements and applies for annual reporting
periods beginning on or after 1 January 2027, provided it is approved by the EU. The new standard
introduces the following key new requirements:
Classify all income and expenses into five categories in the profit or loss section of the consolidated
statement of comprehensive income, namely the operating, investing, financing, discontinued
operations and income tax categories. It is also required to present a newly defined operating profit
subtotal. Net result will not change. Management-defined performance measures (MPMs) are
disclosed in a single note in the financial statements. Enhanced guidance is provided on how to group
information in the financial statements. In addition, it is required to use the operating profit subtotal
as the starting point for the consolidated statement of cash flows when presenting cash flows from
operating activities under the indirect method. The Group has not assessed the impact of the new
standard, particularly with respect to the structure of the profit or loss section of the consolidated
statement of comprehensive income, the consolidated statement of cash flows and the additional
disclosures required for MPMs.
", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-436": { "value": "1.2 Consolidation Subsidiaries The consolidated financial statements comprise the financial statements of the Company and its subsidiaries as of 31 December 2024. Subsidiaries are all entities over which the Group has control. Control is achieved where the Group has the power over the subsidiary, has rights, or is exposed to variable returns from the subsidiary and has the ability to use its power to affect its returns. All subsidiaries are 100 percent owned by the Group and there are no non-controlling interests. In January 2024 BlueNord acquired 100 percent of the shares in CarbonCuts A/S, an early-stage CCS company in Denmark. The Group had the following subsidiaries on 31 December 2024:
Country of Ordinary Ordinary
incorporation shares shares
and place directly held held by the
Name
of business
Nature of business
by parent (%) Group (%)
BlueNord Denmark A/S
Denmark
Intermediate holding company
100%
BlueNord Energy Denmark A/S
Denmark
Exploration and production activity
100%
BlueNord Gas Denmark A/S
Denmark
Exploration and production activity
100%
CarbonCuts A/S
Denmark
Carbon capture and storage
100%
BlueNord Energy 8/06
Netherlands
Exploration and production
100%
Denmark B.V activity
BlueNord Pipeline Denmark Aps Denmark
Infrastructure oil and gas
100%
BlueNord Energy UK Ltd
Great Britain
Exploration activity
100%
BlueNord UK Ltd
Great Britain
Exploration activity
100%
100%
Altinex AS
Norway
Intermediate holding company
100%
100%
BlueNord AS
Norway
Dormant company
100%
100%
Joint arrangements BlueNord has interests in licenses on the Danish Continental Shelf. A joint arrangement is defined as an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control which exists only when decisions about the relevant activities (being those that significantly affect the returns of the arrangement) require unanimous consent of the parties sharing control. Under IFRS 11 Joint Arrangements, a joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities, relating to the arrangement. BlueNord recognises investments in joint operations (oil and gas production licences) by reporting its share of related revenues, expenses, assets, liabilities and cash flows, under the respective items in the Company\u2019s financial statements. ", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-511": { "value": "Subsidiaries The consolidated financial statements comprise the financial statements of the Company and its subsidiaries as of 31 December 2024. Subsidiaries are all entities over which the Group has control. Control is achieved where the Group has the power over the subsidiary, has rights, or is exposed to variable returns from the subsidiary and has the ability to use its power to affect its returns. All subsidiaries are 100 percent owned by the Group and there are no non-controlling interests. In January 2024 BlueNord acquired 100 percent of the shares in CarbonCuts A/S, an early-stage CCS company in Denmark. The Group had the following subsidiaries on 31 December 2024:
Country of Ordinary Ordinary
incorporation shares shares
and place directly held held by the
Name
of business
Nature of business
by parent (%) Group (%)
BlueNord Denmark A/S
Denmark
Intermediate holding company
100%
BlueNord Energy Denmark A/S
Denmark
Exploration and production activity
100%
BlueNord Gas Denmark A/S
Denmark
Exploration and production activity
100%
CarbonCuts A/S
Denmark
Carbon capture and storage
100%
BlueNord Energy 8/06
Netherlands
Exploration and production
100%
Denmark B.V activity
BlueNord Pipeline Denmark Aps Denmark
Infrastructure oil and gas
100%
BlueNord Energy UK Ltd
Great Britain
Exploration activity
100%
BlueNord UK Ltd
Great Britain
Exploration activity
100%
100%
Altinex AS
Norway
Intermediate holding company
100%
100%
BlueNord AS
Norway
Dormant company
100%
100%
", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-483": { "value": "Subsidiaries The consolidated financial statements comprise the financial statements of the Company and its subsidiaries as of 31 December 2024. Subsidiaries are all entities over which the Group has control. Control is achieved where the Group has the power over the subsidiary, has rights, or is exposed to variable returns from the subsidiary and has the ability to use its power to affect its returns. All subsidiaries are 100 percent owned by the Group and there are no non-controlling interests. In January 2024 BlueNord acquired 100 percent of the shares in CarbonCuts A/S, an early-stage CCS company in Denmark. The Group had the following subsidiaries on 31 December 2024:
Country of Ordinary Ordinary
incorporation shares shares
and place directly held held by the
Name
of business
Nature of business
by parent (%) Group (%)
BlueNord Denmark A/S
Denmark
Intermediate holding company
100%
BlueNord Energy Denmark A/S
Denmark
Exploration and production activity
100%
BlueNord Gas Denmark A/S
Denmark
Exploration and production activity
100%
CarbonCuts A/S
Denmark
Carbon capture and storage
100%
BlueNord Energy 8/06
Netherlands
Exploration and production
100%
Denmark B.V activity
BlueNord Pipeline Denmark Aps Denmark
Infrastructure oil and gas
100%
BlueNord Energy UK Ltd
Great Britain
Exploration activity
100%
BlueNord UK Ltd
Great Britain
Exploration activity
100%
100%
Altinex AS
Norway
Intermediate holding company
100%
100%
BlueNord AS
Norway
Dormant company
100%
100%
Joint arrangements BlueNord has interests in licenses on the Danish Continental Shelf. A joint arrangement is defined as an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control which exists only when decisions about the relevant activities (being those that significantly affect the returns of the arrangement) require unanimous consent of the parties sharing control. Under IFRS 11 Joint Arrangements, a joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities, relating to the arrangement. BlueNord recognises investments in joint operations (oil and gas production licences) by reporting its share of related revenues, expenses, assets, liabilities and cash flows, under the respective items in the Company\u2019s financial statements. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSubsidiariesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-433": { "value": "
1.3 Segment reporting
The whole Group is considered a single operating segment.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSegmentReportingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-434": { "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 (\u2018the functional currency\u2019).
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\u2019 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
All currency translation adjustments are recognised in other comprehensive income (OCI).
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-482": { "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 (\u2018the functional currency\u2019). 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\u2019 functional currency.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-435": { "value": "
1.5 Property, plant and equipment
Property, plant and equipment include asset under construction, production facilities, pipelines,
machinery, and equipment. Items of property, plant and equipment are measured at cost, less
accumulated depreciation and accumulated impairment losses.
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.
Direct and indirect expenditures related to asset under construction are capitalised. The development
phase commences when the licence partners have decided field evaluation.
Production facilities are depreciated in accordance with the unit of production (UoP) method based on
proven and probable reserves (the ratio between annual production quantity and the reserves). If realisation
of probable reserves demands further future investments, these are added to the basis of depreciation.
Acquired assets used for extraction and production of petroleum deposits, are depreciated using
the UoP method based on proven and probable reserves.
Onshore assets are depreciated over the estimated useful life, according to the straight-line
method, three to five years. Pipelines are depreciated to the expiry of the licence, according to the
straight-line method.
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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-523": { "value": "1.5 Property, plant and equipment Property, plant and equipment include asset under construction, production facilities, pipelines, machinery, and equipment. Items of property, plant and equipment are measured at cost, less accumulated depreciation and accumulated impairment losses. 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. Direct and indirect expenditures related to asset under construction are capitalised. The development phase commences when the licence partners have decided field evaluation. Production facilities are depreciated in accordance with the unit of production (UoP) method based on proven and probable reserves (the ratio between annual production quantity and the reserves). If realisation of probable reserves demands further future investments, these are added to the basis of depreciation. Acquired assets used for extraction and production of petroleum deposits, are depreciated using the UoP method based on proven and probable reserves. Onshore assets are depreciated over the estimated useful life, according to the straight-line method, three to five years. Pipelines are depreciated to the expiry of the licence, according to the straight-line method. 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-512": { "value": "1.5 Property, plant and equipment Property, plant and equipment include asset under construction, production facilities, pipelines, machinery, and equipment. Items of property, plant and equipment are measured at cost, less accumulated depreciation and accumulated impairment losses. 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. Direct and indirect expenditures related to asset under construction are capitalised. The development phase commences when the licence partners have decided field evaluation. Production facilities are depreciated in accordance with the unit of production (UoP) method based on proven and probable reserves (the ratio between annual production quantity and the reserves). If realisation of probable reserves demands further future investments, these are added to the basis of depreciation. Acquired assets used for extraction and production of petroleum deposits, are depreciated using the UoP method based on proven and probable reserves. Onshore assets are depreciated over the estimated useful life, according to the straight-line method, three to five years. Pipelines are depreciated to the expiry of the licence, according to the straight-line method. Depreciation methods, useful lives, residual values and reserves are reviewed at each reporting date and adjusted if appropriate.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-484": { "value": "1.5 Property, plant and equipment Property, plant and equipment include asset under construction, production facilities, pipelines, machinery, and equipment. Items of property, plant and equipment are measured at cost, less accumulated depreciation and accumulated impairment losses. 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. Direct and indirect expenditures related to asset under construction are capitalised. The development phase commences when the licence partners have decided field evaluation. Production facilities are depreciated in accordance with the unit of production (UoP) method based on proven and probable reserves (the ratio between annual production quantity and the reserves). If realisation of probable reserves demands further future investments, these are added to the basis of depreciation. Acquired assets used for extraction and production of petroleum deposits, are depreciated using the UoP method based on proven and probable reserves. Onshore assets are depreciated over the estimated useful life, according to the straight-line method, three to five years. Pipelines are depreciated to the expiry of the licence, according to the straight-line method. 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-488": { "value": "1.6 Intangible assets Licence rights Licence rights acquired in a business combination are measured on initial recognition at cost. Following initial recognition, licence rights are depreciated using the UoP method based on proven and probable reserves. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsOtherThanGoodwillExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-437": { "value": "1.7 Impairment of non-financial assets The Group has determined that the smallest identifiable assets or groups of assets that generate cash inflows independently from other assets or groups are the DUC assets as a whole and the CarbonCuts business unit. Therefore, the Group has concluded that it has two cash-generating units (CGUs). If there is any indication that the CGU may be impaired, recoverable amount shall be estimated for the CGU, and compared to its carrying amount. The recoverable amount is the higher of the fair value less costs of disposal and the value in use. In estimating value in use, expected future cash flows are discounted to the net present value applying a discount rate after tax that reflects the current market valuation of the time value of money and risks specific to the CGU. The discount rate is derived from a weighted average cost of capital (\u2018WACC\u2019) for a market participant. For the purpose of impairment testing the lifetime of the field is normally determined to be the time when the operating cash flows from the field become negative. If there is any indication that the DUC CGU may be impaired, the Group has relied on its market capitalisation to arrive at an estimate of the headroom of the DUC CGU. As the Company\u2019s shares are listed on the Oslo Stock Exchange, the market capitalisation is regarded as a good approximation of the fair value of the Group\u2019s equity (DUC CGU). The Group\u2019s judgement is that it can make a reliable estimate of the fair value of its equity and thereby the CGUs, based on its market capitalisation. Adjusted for any estimated differences between the carrying amounts and fair value of assets and liabilities not included in the CGUs, the difference between its market capitalisation and carrying amount of equity is a reliable estimate of the difference between the estimated fair value and the carrying amount of the CGUs (\u2018headroom\u2019). Adjusted for cost of disposal, if this gives a positive headroom, it is not necessary to estimate value in use, should an impairment test be required. If not positive a value in use calculation will be calculated and compared to the carrying value of the CGU. On the CarbonCuts CGU, the Group has recognised a goodwill from the acquisition of CarbonCuts and the carrying amounts and recoverable amounts are considered immaterial, therefore no formal impairment test has been performed as any impairment would be immaterial. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfNonfinancialAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-485": { "value": "1.7 Impairment of non-financial assets The Group has determined that the smallest identifiable assets or groups of assets that generate cash inflows independently from other assets or groups are the DUC assets as a whole and the CarbonCuts business unit. Therefore, the Group has concluded that it has two cash-generating units (CGUs). If there is any indication that the CGU may be impaired, recoverable amount shall be estimated for the CGU, and compared to its carrying amount. The recoverable amount is the higher of the fair value less costs of disposal and the value in use. In estimating value in use, expected future cash flows are discounted to the net present value applying a discount rate after tax that reflects the current market valuation of the time value of money and risks specific to the CGU. The discount rate is derived from a weighted average cost of capital (\u2018WACC\u2019) for a market participant. For the purpose of impairment testing the lifetime of the field is normally determined to be the time when the operating cash flows from the field become negative. If there is any indication that the DUC CGU may be impaired, the Group has relied on its market capitalisation to arrive at an estimate of the headroom of the DUC CGU. As the Company\u2019s shares are listed on the Oslo Stock Exchange, the market capitalisation is regarded as a good approximation of the fair value of the Group\u2019s equity (DUC CGU). The Group\u2019s judgement is that it can make a reliable estimate of the fair value of its equity and thereby the CGUs, based on its market capitalisation. Adjusted for any estimated differences between the carrying amounts and fair value of assets and liabilities not included in the CGUs, the difference between its market capitalisation and carrying amount of equity is a reliable estimate of the difference between the estimated fair value and the carrying amount of the CGUs (\u2018headroom\u2019). Adjusted for cost of disposal, if this gives a positive headroom, it is not necessary to estimate value in use, should an impairment test be required. If not positive a value in use calculation will be calculated and compared to the carrying value of the CGU. On the CarbonCuts CGU, the Group has recognised a goodwill from the acquisition of CarbonCuts and the carrying amounts and recoverable amounts are considered immaterial, therefore no formal impairment test has been performed as any impairment would be immaterial. 1.9 Impairment of financial assets The Group applies a simplified approach in calculating expected credit losses (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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-524": { "value": "1.8 Financial instruments The Group has financial instruments at fair value through profit or loss and at amortised cost. See note 19.2 Financial instruments for overview of the categories. The Group has designated derivatives as cash flow hedging instruments, see note 1.10, with the change in fair value temporarily to other comprehensive income. 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). 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. 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. Further details on fair values of financial instruments are provided in note 19 Financial instruments. 1.9 Impairment of financial assets The Group applies a simplified approach in calculating expected credit losses (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 on future sale of oil and gas. The Group has elected to apply cash flow hedge accounting designating these derivatives. These derivative financial instruments 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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-487": { "value": "1.8 Financial instruments The Group has financial instruments at fair value through profit or loss and at amortised cost. See note 19.2 Financial instruments for overview of the categories. The Group has designated derivatives as cash flow hedging instruments, see note 1.10, with the change in fair value temporarily to other comprehensive income. 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). 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. 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. Further details on fair values of financial instruments are provided in note 19 Financial instruments. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-440": { "value": "1.8 Financial instruments The Group has financial instruments at fair value through profit or loss and at amortised cost. See note 19.2 Financial instruments for overview of the categories. The Group has designated derivatives as cash flow hedging instruments, see note 1.10, with the change in fair value temporarily to other comprehensive income. 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). 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. 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. Further details on fair values of financial instruments are provided in note 19 Financial instruments. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-438": { "value": "1.9 Impairment of financial assets The Group applies a simplified approach in calculating expected credit losses (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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-486": { "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 on future sale of oil and gas. The Group has elected to apply cash flow hedge accounting designating these derivatives. These derivative financial instruments 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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-439": { "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 on future sale of oil and gas. The Group has elected to apply cash flow hedge accounting designating these derivatives. These derivative financial instruments 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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-513": { "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 on future sale of oil and gas. The Group has elected to apply cash flow hedge accounting designating these derivatives. These derivative financial instruments 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. Notes continued", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-446": { "value": "1.11 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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-442": { "value": "1.12 Over/under-lifting of hydrocarbons Over/under-lifting occurs when the Group has lifted and sold more or fewer hydrocarbons from a producing field than what the Group is entitled to at the time of lifting. When over-lifting occurs, the Group has recognised more revenue than it is entitled to and for which it has been charged production costs from the Operator, and consequently the Group recognises an additional expense related to the over-lift. For under-lifting, the Group has been charged production costs from the Operator related to production of hydrocarbons that it has not sold, and consequently the Group defers some costs. Over-lifting of hydrocarbons is presented as other current liabilities, under-lifting of hydrocarbons is presented as other current assets. The value of over/under-lifting is measured at production cost including depreciation. Over-lifting and under-lifting of hydrocarbons are presented at gross. Over/ under-lift positions are expected to be settled within 12 months from the reporting date. ", "dimensions": { "concept": "bluenordasa:DescriptionOfAccountingPolicyForOverUnderLiftingOfHydrocarbons", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-514": { "value": "1.12 Over/under-lifting of hydrocarbons Over/under-lifting occurs when the Group has lifted and sold more or fewer hydrocarbons from a producing field than what the Group is entitled to at the time of lifting. When over-lifting occurs, the Group has recognised more revenue than it is entitled to and for which it has been charged production costs from the Operator, and consequently the Group recognises an additional expense related to the over-lift. For under-lifting, the Group has been charged production costs from the Operator related to production of hydrocarbons that it has not sold, and consequently the Group defers some costs. Over-lifting of hydrocarbons is presented as other current liabilities, under-lifting of hydrocarbons is presented as other current assets. The value of over/under-lifting is measured at production cost including depreciation. Over-lifting and under-lifting of hydrocarbons are presented at gross. Over/ under-lift positions are expected to be settled within 12 months from the reporting date. 1.17 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 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. Payments for decommissioning of oil and gas fields are included in investing activities in the cash flow statement, as the Group\u2019s judgement is that the nature of this expenditure is payment for an item of property, plant and equipment. ", "dimensions": { "concept": "ifrs-full:DescriptionOfOtherAccountingPoliciesRelevantToUnderstandingOfFinancialStatements", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-443": { "value": "1.13 Borrowing costs The Group capitalise borrowing costs that are directly attributable to the construction of qualifying assets. The Group identifies qualifying assets as those that necessarily takes 12 months or more to construct and get ready for its intended use. For the periods presented this is only the Tyra redevelopment project. No additional borrowing cost capitalised in 2024, as Tyra II started production 21 March 2024 hence the qualifying assets were ready for its intended use early 2024. The Group calculates an annual weighted average interest rate based on general borrowings and multiplies with the average carrying amount of assets under construction. The amount of borrowing costs eligible for capitalisation each year is limited to the actual interest expense before capitalisation less interest income and gains on extinguishment of bond loans. Other borrowing costs are included as financial expenses in the consolidated statement of comprehensive income in the period in which they are incurred. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingCostsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-489": { "value": "1.14 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 reporting date in the countries where the Company and its subsidiaries operate and generate taxable income. 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 \u2018Chapter 2\u2019 tax of 25 percent plus a specific hydrocarbon tax (Chapter 3A) of 52 percent, in which the 25 percent tax payable is deductible in the tax basis. 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 & 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 temporary new rules whereby the Company will have the possibility of increased uplift by 9 percent and accelerated depreciation during the period from 2017 to 2025. At the same time, an additional tax was introduced which will materialise from 2022 through 2037 if the oil price for the year (indexed from 2017) exceeds USD 75.0. The accumulated additional tax in the years 2022 through 2037 cannot exceed the benefit received in previous years related to the increased uplift and accelerated depreciation. The additional tax is accounted for in the year the oil price exceeds the thresholds. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-444": { "value": "1.14 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 reporting date in the countries where the Company and its subsidiaries operate and generate taxable income.
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 \u2018Chapter
2\u2019 tax of 25 percent plus a specific hydrocarbon tax (Chapter 3A) of 52 percent, in which the 25 percent
tax payable is deductible in the tax basis. 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 & 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 temporary new
rules whereby the Company will have the possibility of increased uplift by 9 percent and accelerated
depreciation during the period from 2017 to 2025. At the same time, an additional tax was introduced
which will materialise from 2022 through 2037 if the oil price for the year (indexed from 2017) exceeds
USD 75.0. The accumulated additional tax in the years 2022 through 2037 cannot exceed the benefit
received in previous years related to the increased uplift and accelerated depreciation. The additional
tax is accounted for in the year the oil price exceeds the thresholds.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-441": { "value": "
1.15 Pensions
The Group only has defined contribution plans as of 31 December 2024 and 31 December 2023.
The contributions are recognised as an employee benefit expense for the periods they relate to.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-445": { "value": "
1.16 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 and shares)
of the Group. The fair value of the employee services received in exchange for the grant of the options
is recognised as an expense with a corresponding amount recognised to equity. 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; and
\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 and 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 and shares 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 and shares are 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-491": { "value": "1.17 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 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. Payments for decommissioning of oil and gas fields are included in investing activities in the cash flow statement, as the Group\u2019s judgement is that the nature of this expenditure is payment for an item of property, plant and equipment. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-451": { "value": "1.17 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 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. Payments for decommissioning of oil and gas fields are included in investing activities in the cash flow statement, as the Group\u2019s judgement is that the nature of this expenditure is payment for an item of property, plant and equipment. ", "dimensions": { "concept": "bluenordasa:DescriptionOfAccountingPolicyForAssetRetirementObligations", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-447": { "value": "1.18 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). See note 1.12 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-448": { "value": "1.19 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-449": { "value": "1.20 Consolidated statement of cash flows The consolidated statement of cash flows is prepared according to the indirect method. See note 1.11 for the definition of \u2018Cash and cash equivalents\u2019. Payments for decommissioning of oil and gas fields are included in investing activities, see note 1.17. For payment of deferred consideration, the Group\u2019s judgement is that amounts that relates to obtaining control in a business combination is included in investing activities.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForCashFlowsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-450": { "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 reserve-based lending facilities and 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 16 Non-current receivables, trade receivable and other current receivables, note 18 Restricted bank deposits, cash and cash equivalents, note 19 Financial instruments, note 22 Asset retirement obligation, note 23 Borrowings note 24 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
0
45
4
Financial liabilities
0
(4)
(2)
Effect net result/equity
0
49
6
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. With regards to trade receivables and payables, the Company deems the risk to be immaterial. (b) Price risk 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 2024, 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 on 31 December 2024 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
NBV 31.12.24
(26)
(26)
0
Commodity price +10%
(36)
(36)
0
Commodity price -10%
36
36
0
The effect on equity shown in the table would be equal to the change in value of the commodity derivatives after tax. 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 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 1.4 billion (2023: USD 1.2 billion) in interest-bearing debt (carrying amount), the principal amount was USD 1.4 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 (BNOR 16) have a fixed interest rate exposure. The reserve-based lending facility is linked to the SOFR rate as set at the time of the amendment and restatement. A variance of + 1 percent in the SOFR rate would result in an average of USD 7.0 million of interest charges to BlueNord per annum. The Company has hedged this interest rate until 30 June 2024 at a rate of 0.40 percent to protect against any increase in SOFR rate. The Company is actively assessing the need for interest rate hedging, recognising it as a key financial risk. For further information about the Group\u2019s interest-bearing debt, see note 23. All bank deposits (USD 469.4 million) are at floating interest rates. See note 18 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 2024, there are no principal repayments expected 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 (NGL\u2019s) is considered limited, as sales are to major energy companies with considerable financial resources. The counterparty in derivatives are large international banks and insurance companies whose credit risk is considered low. 2.2 Management of capital 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. Both BNOR16 and the RBL facility contains covenants on minimum liquidity and net leverage. The Group\u2019s debt restricts the payment of dividends until the Tyra Redevelopment Project Completion Date has occurred. Under BNOR16, this is subject to an incurrence test and for any dividends made after 1 January 2027, this is limited to 50 percent of the Group\u2019s net profit after tax for the previous year. See further information regarding borrowings and covenants in note 23 ", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-490": { "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 16 Non-current
receivables, trade receivable and other current receivables, note 18 Restricted bank deposits, cash
and cash equivalents, note 19 Financial instruments, note 22 Asset retirement obligation, note 23
Borrowings note 24 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
0
45
4
Financial liabilities
0
(4)
(2)
Effect net result/equity
0
49
6
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. With regards to trade receivables
and payables, the Company deems the risk to be immaterial.
(b) Price risk
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 2024, 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 on 31 December 2024 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
NBV 31.12.24
(26)
(26)
0
Commodity price +10%
(36)
(36)
0
Commodity price -10%
36
36
0
The effect on equity shown in the table would be equal to the change in value of the commodity
derivatives after tax. 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 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 1.4 billion (2023: USD 1.2 billion) in interest-bearing debt (carrying
amount), the principal amount was USD 1.4 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 (BNOR
16) have a fixed interest rate exposure. The reserve-based lending facility is linked to the SOFR rate as
set at the time of the amendment and restatement. A variance of + 1 percent in the SOFR rate would
result in an average of USD 7.0 million of interest charges to BlueNord per annum. The Company has
hedged this interest rate until 30 June 2024 at a rate of 0.40 percent to protect against any increase in
SOFR rate. The Company is actively assessing the need for interest rate hedging, recognising it as a
key financial risk. For further information about the Group\u2019s interest-bearing debt, see note 23.
All bank deposits (USD 469.4 million) are at floating interest rates. See note 18 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-515": { "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 16 Non-current receivables, trade receivable and other current receivables, note 18 Restricted bank deposits, cash and cash equivalents, note 19 Financial instruments, note 22 Asset retirement obligation, note 23 Borrowings note 24 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
0
45
4
Financial liabilities
0
(4)
(2)
Effect net result/equity
0
49
6
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. 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-494": { "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 2024, there are no principal
repayments expected within the next 12 months.
", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-492": { "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 (NGL\u2019s)
is considered limited, as sales are to major energy 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-493": { "value": "2.2 Management of capital 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. Both BNOR16 and the RBL facility contains covenants on minimum liquidity and net leverage. The Group\u2019s debt restricts the payment of dividends until the Tyra Redevelopment Project Completion Date has occurred. Under BNOR16, this is subject to an incurrence test and for any dividends made after 1 January 2027, this is limited to 50 percent of the Group\u2019s net profit after tax for the previous year. See further information regarding borrowings and covenants in note 23 .", "dimensions": { "concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-452": { "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;
\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 is 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:
Sensitivity analysis
Share price
(%)
10%
-10%
Embedded derivatives
USD million
(25)
22
Effect net result/equity
USD million
(25)
22
The embedded derivatives are in jurisdictions where there is tax loss carried forward where no
deferred tax assets are recognised. Therefore, it is concluded that there is no tax effect of the changes
in fair value. See note 19 for fair value hierarchy and further information.
", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-453": { "value": "3 Critical accounting estimates and judgements 3.1 Critical judgements in applying the entity\u2019s accounting policies a) Accounting for convertible bond loan 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 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.
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.
3.2 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 bond 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 more details, see note 2.3 and 19 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. Tax calculations are based on management\u2019s best assessment
and interpretation of tax rules in place guided by industry tax practitioners. If it is expected that a
sustainable tax position may be challenged by the tax authorities due to uncertainty in law interpretation,
a provision is made to account for such uncertainty. Tax authorities can be of a different opinion than the
Company. At each period end the Company provide for expected clawback, if any. See also note 14.
c) Proven and probable oil and gas reserves and depreciation
Proven and probable reserves, along with production volumes and future capex, are used to calculate
the depreciation of oil and gas fields using the unit-of-production method. See note 11 Property, plant
and equipment for depreciation charges.
Oil and gas reserves are estimated by the Company\u2019s experts in accordance with industry standards.
These estimates are based on BlueNord\u2019s assessment of internal information and data received from
the Operator. Proven and probable oil and gas reserves include remaining volumes expected to be
recovered based on reasonable assumptions about future technical, economic, fiscal, and financial
conditions as of the date the estimates are prepared.
Key inputs include estimated commodity prices and CO
2
costs. A set of market price assumptions are
used in these commodity price estimates whereby oil and gas prices, in real terms, are assumed flat
at $65/bbl and EUR 30/MWh (inflated at 2 percent from 2026 onwards). The CO
2
costs include the
CO
2
carbon duty (Danish Government duty defined by the L. 182/2024 with proposed levels until 2030
inflated at 2 percent per annum thereafter) and the EU ETS market price (as per Bloomberg forward
curve for 5 years inflated at 2 percent per annum thereafter).
2025
2026
2027
2028
2029
2030
Brent price, real terms ($/bbl)
65.0
65.0
65.0
65.0
65.0
65.0
Gas price, real terms (EUR/MWh)
30.0
30.0
30.0
30.0
30.0
30.0
EU ETS price, nominal (EUR/mt)
64.9
67.8
69.8
72.1
75.5
80.0
Danish carbon duty, nominal
(DKK/mt)
85.2
153.3
221.4
289.6
357. 8
425.9
USD:DKK
6.60
6.60
6.60
6.60
6.60
6.60
EUR:DKK
7.45
7.45
7.45
7.45
7.45
7.45
USD:EUR
0.89
0.89
0.89
0.89
0.89
0.89
Changes in commodity prices, CO
2
costs and other cost estimates can alter reserve estimates and,
consequently, the economic cut-off, which may impact the timing of decommissioning and removal
activities. Reserve estimates can also change due to updated production and reservoir information.
Future changes to proven and probable oil and gas reserves can significantly affect depreciation,
the life of the field, impairment of licence-related assets and operating results.
There is also an independent assessment of reserves performed by an external party. The difference
between the 2P external reserves disclosed in the \u2018Supplementary oil and gas information\u2019 and those
used for financial reporting purposes relates primarily to projects that are in the category \u2018justified for
development\u2019 as only approved projects are included for financial reporting purposes. The reserves
prepared as at 31 December 2024 form the basis for depreciation for 2025.
d) Asset retirement obligation
The production of oil and gas is subject to statutory requirements for decommissioning and removal
obligations once production ceases. Provisions for these future decommissioning and removal
expenditures must be recognised when the statutory requirement arises. These costs are often
incurred in the future, and there is significant uncertainty regarding the scale and complexity of the
decommissioning and removal process. Additionally, these activities require approval from the
DUC Joint Venture partners and the Danish Energy Agency.
Estimated future costs are based on current costs adjusted for inflation, known decommissioning and removal technology, and the anticipated decommissioning and removal date. These costs are discounted to their present value using a risk-free rate adjusted for credit margin. Changes in one or more of these factors could result in adjustments to the decommissioning and removal liabilities. See note 22 Asset retirement obligations for further details and sensitivities and information on the Group\u2019s assumptions in note 3.2(c). e) Impairment of fixed assets The Group has at 31 December 2024 not identified any impairment indicators. Impairment indicators include internal and external factors such as change in commodity prices, production / cost estimates against actual performance, and climate-related risks impact on costs, among others. The Group has relied on its market capitalisation to arrive at an estimate of the headroom of the DUC CGU should an impairment review be required. If the market capitalisation should decrease materially below its carrying amount of equity, this could give rise to impairment trigger of the DUC CGU. For the CarbonCuts CGU, the Group has recognised a goodwill from the acquisition of CarbonCuts and due to materiality, no impairment test has been performed. If the Group should have to estimate the recoverable amount based on estimated future cash flows, it would have to make significant judgements which could lead to significant estimation uncertainty. Estimation of future cash flows require long-term assumptions concerning a number of often volatile economic factors, including future oil and gas prices, CO 2 taxes, production, commercially depletable reserves, levels of capex and operational costs, currency exchange rates and discount rates. Information on the Group\u2019s assumptions are included in note 3.2 (c). The Group has recognised a goodwill from the acquisition of CarbonCuts. CarbonCuts is in the process of exploring the possibility of establishing a safe and permanent CO 2 storage facility and related costs are to a large extent expensed. We note that after the acquisition, CarbonCuts\u2019 was awarded a licence to explore CO 2 storage possibilities onshore in Denmark and current carrying value and estimated recoverable amount of goodwill of USD 2.1 million are considered immaterial. No impairment was recognised. See also note 1.7 Impairment of non-financial assets and note 12 Impairments related to impairment reviews and note 11 Property, plant and equipment for impairment.", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-495": { "value": "3.1 Critical judgements in applying the entity\u2019s accounting policies a) Accounting for convertible bond loan 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 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. 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. 3.2 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 bond 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 more details, see note 2.3 and 19 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. Tax calculations are based on management\u2019s best assessment and interpretation of tax rules in place guided by industry tax practitioners. If it is expected that a sustainable tax position may be challenged by the tax authorities due to uncertainty in law interpretation, a provision is made to account for such uncertainty. Tax authorities can be of a different opinion than the Company. At each period end the Company provide for expected clawback, if any. See also note 14. c) Proven and probable oil and gas reserves and depreciation Proven and probable reserves, along with production volumes and future capex, are used to calculate the depreciation of oil and gas fields using the unit-of-production method. See note 11 Property, plant and equipment for depreciation charges. Oil and gas reserves are estimated by the Company\u2019s experts in accordance with industry standards. These estimates are based on BlueNord\u2019s assessment of internal information and data received from the Operator. Proven and probable oil and gas reserves include remaining volumes expected to be recovered based on reasonable assumptions about future technical, economic, fiscal, and financial conditions as of the date the estimates are prepared. Key inputs include estimated commodity prices and CO2 costs. A set of market price assumptions are used in these commodity price estimates whereby oil and gas prices, in real terms, are assumed flat at $65/bbl and EUR 30/MWh (inflated at 2 percent from 2026 onwards). The CO 2 costs include the CO2 carbon duty (Danish Government duty defined by the L. 182/2024 with proposed levels until 2030 inflated at 2 percent per annum thereafter) and the EU ETS market price (as per Bloomberg forward curve for 5 years inflated at 2 percent per annum thereafter). 2025 2026 2027 2028 2029 2030 Brent price, real terms ($/bbl) 65.0 65.0 65.0 65.0 65.0 65.0 Gas price, real terms (EUR/MWh) 30.0 30.0 30.0 30.0 30.0 30.0 EU ETS price, nominal (EUR/mt) 64.9 67.8 69.8 72.1 75.5 80.0 Danish carbon duty, nominal (DKK/mt) 85.2 153.3 221.4 289.6 357. 8 425.9 USD:DKK 6.60 6.60 6.60 6.60 6.60 6.60 EUR:DKK 7.45 7.45 7.45 7.45 7.45 7.45 USD:EUR 0.89 0.89 0.89 0.89 0.89 0.89 Changes in commodity prices, CO2 costs and other cost estimates can alter reserve estimates and, consequently, the economic cut-off, which may impact the timing of decommissioning and removal activities. Reserve estimates can also change due to updated production and reservoir information. Future changes to proven and probable oil and gas reserves can significantly affect depreciation, the life of the field, impairment of licence-related assets and operating results. There is also an independent assessment of reserves performed by an external party. The difference between the 2P external reserves disclosed in the \u2018Supplementary oil and gas information\u2019 and those used for financial reporting purposes relates primarily to projects that are in the category \u2018justified for development\u2019 as only approved projects are included for financial reporting purposes. The reserves prepared as at 31 December 2024 form the basis for depreciation for 2025. d) Asset retirement obligation The production of oil and gas is subject to statutory requirements for decommissioning and removal obligations once production ceases. Provisions for these future decommissioning and removal expenditures must be recognised when the statutory requirement arises. These costs are often incurred in the future, and there is significant uncertainty regarding the scale and complexity of the decommissioning and removal process. Additionally, these activities require approval from the DUC Joint Venture partners and the Danish Energy Agency. Estimated future costs are based on current costs adjusted for inflation, known decommissioning and removal technology, and the anticipated decommissioning and removal date. These costs are discounted to their present value using a risk-free rate adjusted for credit margin. Changes in one or more of these factors could result in adjustments to the decommissioning and removal liabilities. See note 22 Asset retirement obligations for further details and sensitivities and information on the Group\u2019s assumptions in note 3.2(c). e) Impairment of fixed assets The Group has at 31 December 2024 not identified any impairment indicators. Impairment indicators include internal and external factors such as change in commodity prices, production / cost estimates against actual performance, and climate-related risks impact on costs, among others. The Group has relied on its market capitalisation to arrive at an estimate of the headroom of the DUC CGU should an impairment review be required. If the market capitalisation should decrease materially below its carrying amount of equity, this could give rise to impairment trigger of the DUC CGU. For the CarbonCuts CGU, the Group has recognised a goodwill from the acquisition of CarbonCuts and due to materiality, no impairment test has been performed. If the Group should have to estimate the recoverable amount based on estimated future cash flows, it would have to make significant judgements which could lead to significant estimation uncertainty. Estimation of future cash flows require long-term assumptions concerning a number of often volatile economic factors, including future oil and gas prices, CO 2 taxes, production, commercially depletable reserves, levels of capex and operational costs, currency exchange rates and discount rates. Information on the Group\u2019s assumptions are included in note 3.2 (c). The Group has recognised a goodwill from the acquisition of CarbonCuts. CarbonCuts is in the process of exploring the possibility of establishing a safe and permanent CO 2 storage facility and related costs are to a large extent expensed. We note that after the acquisition, CarbonCuts\u2019 was awarded a licence to explore CO 2 storage possibilities onshore in Denmark and current carrying value and estimated recoverable amount of goodwill of USD 2.1 million are considered immaterial. No impairment was recognised. See also note 1.7 Impairment of non-financial assets and note 12 Impairments related to impairment reviews and note 11 Property, plant and equipment for impairment.", "dimensions": { "concept": "ifrs-full:ExplanationOfAssumptionAboutFutureWithSignificantRiskOfResultingInMaterialAdjustments", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-454": { "value": "4 Climate risk management 4.1 Climate risk factors As an oil and gas company, BlueNord acknowledge the growing significance of climate-related risks on BlueNord\u2019s operations within the DUC. The regulatory landscape in which the DUC operates is evolving, with increased emphasis on reducing greenhouse gas (GHG) emissions. Denmark is committed to achieving carbon neutrality by 2050 (phasing out of oil and gas), aligning with the European Union\u2019s Green Deal and international climate agreements. BlueNord\u2019s licence in the DUC sole concession will expire in 2042.
The Company recognises that climate-related risks and the global transition towards a low-carbon
economy presents both challenges and opportunities that could impact our financial performance,
asset valuation and future strategy. As part of the risk management framework, the Company
assesses climate risks under two categories:
\u2022 Transition risk \u2013 risk arising from the shift to lower carbon economy, which includes regulatory
changes, market shifts and evolving stakeholder expectations.
\u2022 Physical risk \u2013 risk arising from climate change impacts which could affect BlueNord\u2019s production
and infrastructure and value chain.
The Company integrates climate scenario analysis into its financial planning using frameworks such as
the Task Force on Climate-related Financial Disclosures (TCFD).
Transition risk
Policy and regulatory changes
Denmark has one of the most ambitious climate policies in Europe. BlueNord\u2019s oil and gas operations
are subject to the EU Emission Trading System (EU ETS). The EU ETS is based on a \u2018cap and trade\u2019
principle whereby the cap (expressed in emissions allowances) refers to the limit set on the maximum
amount of GHG emissions that can be emitted. As a non-operator and a JV partner within the DUC,
BlueNord relies on the Operator (TotalEnergies) to purchase and manage EU ETS allowances for the
emissions relating to BlueNord\u2019s share of the DUC operations. Although BlueNord is permitted to self-
manage the purchase of its net allowances, these purchases are still to be handed over to the Operator
who will manage the surrendering of allowances every September of the following year for emissions
reported in the current year.
As part of the Green Tax Reform agreed in 2022, Denmark has also introduced a carbon tax (phased
in from 2025 to 2030) on GHG emissions from activities covered by the EU ETS Directive. This
CO\u2082 tax is calculated based on the number of emission allowances surrendered each year. The
introduction of this CO\u2082 tax on offshore oil and gas production and participation in addition to the costs
incurred under the EU ETS scheme will significantly increase compliance costs which directly affects
operational expenses and therefore impact profitability.
Additionally, the Danish Climate Act and the North Sea Agreement may impose stricter regulatory
compliance. Stricter environmental laws, such as limitations on offshore drilling, methane emissions
regulations, and potential fossil fuel phase-out policies may impact the Company\u2019s asset valuation and
future investment plans. This may also influence borrowing terms.
In 2024, the Net-Zero Industry Act (NZIA) was adopted by the European Parliament and Council,
establishing a framework of measures for strengthening Europe\u2019s net-zero technology ecosystem. Article
23 of the Act establishes a contribution in CO
2
injection capacity in a storage site located in an EU member
state countries for oil and gas producers in proportion to their production level over the period 1 January
2020 to 31st December 2023. While injection capacity contribution has not yet been specified by the EU
Commissions, BlueNord will likely be in scope for contributing to the EU\u2019s ambition of an annual injection
capacity of 50 million tonnes of CO
2
by 2030. BlueNord, via its wholly-owned subsidiary CarbonCuts,
is currently undergoing an exploration programme in the onshore Danish Ruby CCS licence following
exploration licence award in 2024. The development of the Ruby CO
2
store could form part of the NZIA
conformance plan for BlueNord. Until the project is declared feasible and commercially viable, project\u2019s
costs are expensed to the income statement and minimal asset value is attributed to the project now.
BlueNord will continue to monitor the development of the requirements under NZIA regulation such as
clarity on injection contribution, to allow us to better analyse its impact on the Company going forward.
Market demand shifts and transition to lower emissions technology
The accelerating transition to renewable energy sources may reduce long-term demand for oil and
gas, affecting our revenue forecasts and asset valuations. Denmark and the EU are shifting towards
renewable energy sources, such as offshore wind, solar, and biofuels while reducing reliance on fossil
fuels. This trend could reduce long-term demand for oil and gas production from the Danish North Sea,
which could affect reserves and resources estimation.
The rapid advancement of carbon capture, utilisation, and storage (CCUS), green hydrogen, and
offshore wind projects could accelerate the transition away from fossil fuels. Denmark\u2019s Energy Island
initiative and investments in Power-to-X technology further reinforce this trend.
Stakeholder expectations and reputational risks
Investors, lenders and regulators are increasingly integrating Environmental, Social, and Governance
(ESG) factors into financing decisions. Additionally, climate litigation risks are growing, particularly
regarding environmental responsibilities under Danish and EU law.
Mitigation actions
\u2022 Proactive engagement with the government and regulatory bodies ensuring compliance with new
climate requirements.
\u2022 Continuous assessment on emission reduction initiatives and other potential renewable projects
within the DUC partnership.
\u2022 Perform internal sensitivity analysis and scenario testing, taking into account climate risk factors, at
a company and project level.
\u2022 Include climate risk considerations within investment decisions and working closely within the DUC
partnership to align the DUC operations with evolving policies.
\u2022 Diversifying the Company\u2019s portfolio by investing in Carbon, Capture and Storage (CCS) projects
through its wholly-owned subsidiary CarbonCuts.
\u2022 Strengthening ESG disclosures to maintain investor confidence and access to sustainable financing.
Physical risk
Acute and chronic physical risk
Denmark sometimes unfavourable weather conditions could disrupt onshore and offshore operations,
impact infrastructure integrity, and cause supply chain logistics and production downtime. Longer-
term shifts in climate patterns like changing frequency of chronic heat waves or cold waves, sea level
rise, and increased water stress could impact operations in Denmark and in the value chain.
Mitigating actions \u2022 Active engagement and monitoring on Health, Safety and Environmental (HSE) related topics within the DUC operations \u2022 Integrating sustainability consideration within project planning Financial impact and reporting considerations These climate-related risks may have financial implications across the Company\u2019s asset valuation, operational costs and other financial obligations. The Company integrates climate risk into its financial reporting and performs climate risk assessments on the below financial reporting elements: \u2022 Production expenses on environmental liabilities (Note 6): Carbon costs are accounted for under production expenses. Changes in carbon regulations are continuously monitored to ensure compliance. There is also an option for the Company to reduce its exposure to volatile carbon prices by actively purchasing carbon allowances. This has not been exercised for the 2024 obligations where BlueNord still relies on the Operator to manage its share as part of the DUC JV partnership. \u2022 Impairments (note 12): Climate factors are among the triggers considered during impairment testing. This includes consideration of the carbon price volatility and impact from potential introduction of new carbon regulations that could lead to higher incurred operational expenses. \u2022 Financial income and expense (Note 13): The Company\u2019s current RBL financing terms include a link to ESG performance affecting debt pricing however the impact is considered immaterial. Other climate related risks are integrated into interest rate sensitivity analysis for the Company\u2019s debt obligations such as a potential increase in financing costs for oil and gas financing as the industry shifts towards stricter green targets. While this does not apply in the short-term due to the fixed rates on existing debt, it offers insights into potential increased interest exposure over the longer-term. \u2022 Asset retirement obligations (Note 22): Climate factors may influence costs estimates and regulatory developments affecting decommissioning obligations. The impact on provisioning has been disclosed related to the impact of a five-year acceleration of cease of production of fields within the DUC hubs, due to low economics driven by higher climate-related costs. \u2022 Reserves estimates (Note 3 and Supplementary Note): Denmark\u2019s commitment to achieving carbon neutrality by 2050 may have an impact on reserves estimates, driven by earlier cessation of production. For context, the DUC licence expires in 2042, and Denmark has committed to stopping oil and gas production by 2050 under the Danish North Sea Agreement (NSA). This suggests a reduced risk of early production shutdown when seen in the light of the various possible scenarios for oil and gas demand in the future as the energy transition takes place and offers greater flexibility to adjust to evolving market conditions or shifts in global energy demand. Given this, further climate risk sensitivity analysis is not considered necessary by the Company in this case. As stated earlier in note 3.2(c), changes in commodity prices, CO 2 costs and other cost estimates can also alter reserve estimates and, consequently, the economic cut-off, which may impact the timing of decommissioning and removal activities and as such future changes to proven and probable oil and gas reserves can significantly affect depreciation, the life of the field, impairment of licence-related assets, and operating results.", "dimensions": { "concept": "bluenordasa:DisclosureOfClimateRiskManagement", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-455": { "value": "5 Revenue
USD million
2024
2023
Sale of oil
507.3
485.6
Sale of gas and NGL
191.4
306.0
Other income
3.6
3.5
Total revenue
702.3
795.0
Oil \u2013 lifted volumes (mmbbl)
6.82
7.16
Effective oil price USD/bbl
74.4
67.8
Gas \u2013 lifted volumes (mmboe)
2.58
2.20
Effective gas price EUR/MWh
40.4
75.7
Effective gas price USD/boe
74.2
139.1
In 2024 sale of oil amounted to USD 507.3 million and sale of gas amounted to USD 191.4 million, realised prices were USD 74.4 per bbl of oil and USD 74.2 per boe gas lifted during the year, adjusted for settlement of price hedges in place with financial institutions. During 2024, 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. For the year 2024 only a minor part of the price hedges exceeded the physical sale of oil and were recognised as financial cost.
Revenue per customer
2024
2023
Shell Trading International
69.4%
75.8%
\u00d8rsted Salg & Service AS
18.6%
17.4%
Shell Energy Europe Limited
3.4%
3.2%
BP Oil International
9.1%
\u2013
Macquarie Bank Europe
2.4%
2.1%
Deutsche Bank
0.3%
\u2013
BNP Paribas
0.2%
2.4%
ING
1)
-3.4%
\u2013
Natixis
\u2013
6.4%
Crossbridge Energy A/S
\u2013
0.2%
Lloyds Bank Corporate Markets PLC
1)
\u2013
-2.2%
SEB Skandinaviska Enskilda Banken AB
1)
\u2013
-2.3%
Commonwealth Bank
1)
\u2013
-3.0%
Total revenue
100.0%
100.0%
1) Settlement of commodity hedges in place with financial institutions.", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-456": { "value": "
6 Production expenses
USD million
2024
2023
Direct field opex
(200.4)
(232.4)
Tariff and transportation expenses
(46.3)
(34.9)
Environmental costs
1)
(12.6)
(11.8)
Production general and administrative
(14.7)
(16.8)
Field operating cost
(274.1)
(295.9)
Total produced volumes (mmboe)
9.2
9.1
In USD per boe
(29.9)
(32.5)
Adjustments for:
Concept studies
(1.2)
(6.2)
Change in inventory position
(1.3)
(6.7)
Over/under-lift of oil and NGL
(8.9)
(6.3)
Insurance and other
(22.6)
(21.9)
Stock scrap
(2.4)
(3.0)
Production expenses
(310.4)
(340.1)
1) Includes cost for CO
2
allowances under the EU ETS scheme. See also note 4 Climate Risk Management.
Production expenses for the year directly attributable to the lifting and transportation to market of
BlueNord\u2019s oil and gas production is in total USD 274.1 million, which equates to USD 29.9 per boe
produced during 2024 (2023: USD 32.5 per boe produced). During 2024 BlueNord has observed
that the result of conducting the \u2018Well & Reservoir Optimization Management\u2019 (WROM) increases
the reserves which has led to the conclusion that this cost should be capitalised. This has no cash
effect but has decreased the direct field opex for 2024. Due to the start-up of Tyra, transportation cost
has increased compared to previous year. Due to uncertainties related to production forecast, cost
is further influenced by increased penalties as gas nomination has been challenging. Penalties are
imposed if actual production deviates from nominated volumes.
", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-496": { "value": "6 Production expenses
USD million
2024
2023
Direct field opex
(200.4)
(232.4)
Tariff and transportation expenses
(46.3)
(34.9)
Environmental costs
1)
(12.6)
(11.8)
Production general and administrative
(14.7)
(16.8)
Field operating cost
(274.1)
(295.9)
Total produced volumes (mmboe)
9.2
9.1
In USD per boe
(29.9)
(32.5)
Adjustments for:
Concept studies
(1.2)
(6.2)
Change in inventory position
(1.3)
(6.7)
Over/under-lift of oil and NGL
(8.9)
(6.3)
Insurance and other
(22.6)
(21.9)
Stock scrap
(2.4)
(3.0)
Production expenses
(310.4)
(340.1)
1) Includes cost for CO 2 allowances under the EU ETS scheme. See also note 4 Climate Risk Management. Production expenses for the year directly attributable to the lifting and transportation to market of BlueNord\u2019s oil and gas production is in total USD 274.1 million, which equates to USD 29.9 per boe produced during 2024 (2023: USD 32.5 per boe produced). During 2024 BlueNord has observed that the result of conducting the \u2018Well & Reservoir Optimization Management\u2019 (WROM) increases the reserves which has led to the conclusion that this cost should be capitalised. This has no cash effect but has decreased the direct field opex for 2024. Due to the start-up of Tyra, transportation cost has increased compared to previous year. Due to uncertainties related to production forecast, cost is further influenced by increased penalties as gas nomination has been challenging. Penalties are imposed if actual production deviates from nominated volumes.", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesByNatureExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-457": { "value": "7 Exploration and evaluation expenses
USD million
2024
2023
Acquisition of seismic data, analysis and general G&G costs
(5.8)
\u2013
Other exploration and evaluation expenses
(0.1)
(1.4)
Total exploration and evaluation expenses
(5.9)
(1.4)
", "dimensions": { "concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-458": { "value": "
8 Personnel expenses
USD million
Note
2024
2023
Salaries
(13.0)
(10.3)
Social security tax
(4.0)
(1.4)
Pension costs
21
(0.7)
(0.7)
Costs relating to share-based payments
(1.6)
(5.2)
Other personnel expenses
(0.4)
(0.4)
Total personnel expenses
(19.7)
(18.0)
Average FTE
40.2
36.2
Average number of employees
43.3
38.3
Long-term performance share programme
In 2022, an annual long-term performance share programme was implemented with effect from
1 January 2022, replacing the Share Option Programme as BlueNord\u2019s LTI plan for executives and
employees. The programme applies to all permanent employees. More details on the long-term
performance share programme see the Executive Remuneration Report for 2024.
Key management personnel compensation
Key management personnel compensation comprises the following:
USD 1 000
2024
2023
Short-term employee benefits
3,160
2,239
Post-employment benefits
122
98
Share-based payments
830
787
Total remuneration to key management
4,112
3,124
Please see the Executive Remuneration Report 2024 for compensation to key management and
Board of Directors in the period 2020-2024.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutEmployeesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-516": { "value": "8 Personnel expenses
USD million
Note
2024
2023
Salaries
(13.0)
(10.3)
Social security tax
(4.0)
(1.4)
Pension costs
21
(0.7)
(0.7)
Costs relating to share-based payments
(1.6)
(5.2)
Other personnel expenses
(0.4)
(0.4)
Total personnel expenses
(19.7)
(18.0)
Average FTE
40.2
36.2
Average number of employees
43.3
38.3
Long-term performance share programme In 2022, an annual long-term performance share programme was implemented with effect from 1 January 2022, replacing the Share Option Programme as BlueNord\u2019s LTI plan for executives and employees. The programme applies to all permanent employees. More details on the long-term performance share programme see the Executive Remuneration Report for 2024. Key management personnel compensation Key management personnel compensation comprises the following:
USD 1 000
2024
2023
Short-term employee benefits
3,160
2,239
Post-employment benefits
122
98
Share-based payments
830
787
Total remuneration to key management
4,112
3,124
Please see the Executive Remuneration Report 2024 for compensation to key management and Board of Directors in the period 2020-2024. 21 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 684.4 thousand for 2024. For 2023, the corresponding costs were USD 732.2 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 (\u2018obligatorisk tjenestepensjon\u2019). Correspondingly, the affiliates in Denmark and the United Kingdom comply with the requirement for mandatory occupational pension by local legislation.", "dimensions": { "concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-497": { "value": "8 Personnel expenses
USD million
Note
2024
2023
Salaries
(13.0)
(10.3)
Social security tax
(4.0)
(1.4)
Pension costs
21
(0.7)
(0.7)
Costs relating to share-based payments
(1.6)
(5.2)
Other personnel expenses
(0.4)
(0.4)
Total personnel expenses
(19.7)
(18.0)
Average FTE
40.2
36.2
Average number of employees
43.3
38.3
Long-term performance share programme In 2022, an annual long-term performance share programme was implemented with effect from 1 January 2022, replacing the Share Option Programme as BlueNord\u2019s LTI plan for executives and employees. The programme applies to all permanent employees. More details on the long-term performance share programme see the Executive Remuneration Report for 2024. Key management personnel compensation Key management personnel compensation comprises the following:
USD 1 000
2024
2023
Short-term employee benefits
3,160
2,239
Post-employment benefits
122
98
Share-based payments
830
787
Total remuneration to key management
4,112
3,124
Please see the Executive Remuneration Report 2024 for compensation to key management and Board of Directors in the period 2020-2024. ", "dimensions": { "concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-525": { "value": "Key management personnel compensation Key management personnel compensation comprises the following:
USD 1 000
2024
2023
Short-term employee benefits
3,160
2,239
Post-employment benefits
122
98
Share-based payments
830
787
Total remuneration to key management
4,112
3,124
Please see the Executive Remuneration Report 2024 for compensation to key management and Board of Directors in the period 2020-2024. ", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-459": { "value": "9 Other operating expenses
USD million
2024
2023
Consultant fees
(8.4)
(9.4)
Other operating expenses
(4.0)
(4.7)
Total other operating expenses
(12.4)
(14.1)
USD
100
0, excl. VAT
2024
2023
Auditor\u2019s fees
(590.4)
(580.0)
Other assurance service
\u2013
(6.9)
Other service
(93.1)
(86.1)
Total audit fees
(683.6)
(673.0)
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-498": { "value": "
USD
100
0, excl. VAT
2024
2023
Auditor\u2019s fees
(590.4)
(580.0)
Other assurance service
\u2013
(6.9)
Other service
(93.1)
(86.1)
Total audit fees
(683.6)
(673.0)
", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-460": { "value": "
10 Goodwill and intangible assets
Goodwill and intangible assets at 31 December 2024
Capitalised
exploration
USD million
expenditures
Licence
Goodwill
Total
Book value 31.12.23
1.9
149.7
\u2013
151.6
Acquisition costs 31.12.23
1.9
186.0
\u2013
187.9
Additions
\u2013
\u2013
2.2
2.2
Currency translation adjustment
\u2013
\u2013
(0.1)
(0.1)
Acquisition costs 31.12.24
1.9
186.0
2.1
190.1
Accumulated depreciation, amortisation and
write-down 31.12.23
\u2013
(36.3)
\u2013
(36.3)
Depreciation/amortisation
\u2013
(6.7)
\u2013
(6.7)
Accumulated depreciation, amortisation and
write-down 31.12.24
\u2013
(43.0)
\u2013
(43.0)
Book value 31.12.24
1.9
143.0
2.1
147.0
Goodwill and intangible assets at 31 December 2023
Capitalised
exploration Conceptual
USD million expenditures
studies
Licence
Total
Book value 31.12.22
1.8
1.9
156.6
160.4
Acquisition costs 31.12.22
1.8
1.9
186.0
189.8
Additions
0.1
\u2013
\u2013
0.1
Reclassified to operating expenses
\u2013
(1.9)
\u2013
(1.9)
Acquisition costs 31.12.23
1.9
\u2013
186.0
187.9
Accumulated depreciation and write-downs
31.12.22
\u2013
\u2013
(29.4)
(29.4)
Depreciation/amortisation
\u2013
\u2013
(6.9)
(6.9)
Accumulated depreciation and write-downs
31.12.23
\u2013
\u2013
(36.3)
(36.3)
Book value 31.12.23
1.9
\u2013
149.7
151.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-499": { "value": "10 Goodwill and intangible assets Goodwill and intangible assets at 31 December 2024
Capitalised
exploration
USD million
expenditures
Licence
Goodwill
Total
Book value 31.12.23
1.9
149.7
\u2013
151.6
Acquisition costs 31.12.23
1.9
186.0
\u2013
187.9
Additions
\u2013
\u2013
2.2
2.2
Currency translation adjustment
\u2013
\u2013
(0.1)
(0.1)
Acquisition costs 31.12.24
1.9
186.0
2.1
190.1
Accumulated depreciation, amortisation and
write-down 31.12.23
\u2013
(36.3)
\u2013
(36.3)
Depreciation/amortisation
\u2013
(6.7)
\u2013
(6.7)
Accumulated depreciation, amortisation and
write-down 31.12.24
\u2013
(43.0)
\u2013
(43.0)
Book value 31.12.24
1.9
143.0
2.1
147.0
Goodwill and intangible assets at 31 December 2023
Capitalised
exploration Conceptual
USD million expenditures
studies
Licence
Total
Book value 31.12.22
1.8
1.9
156.6
160.4
Acquisition costs 31.12.22
1.8
1.9
186.0
189.8
Additions
0.1
\u2013
\u2013
0.1
Reclassified to operating expenses
\u2013
(1.9)
\u2013
(1.9)
Acquisition costs 31.12.23
1.9
\u2013
186.0
187.9
Accumulated depreciation and write-downs
31.12.22
\u2013
\u2013
(29.4)
(29.4)
Depreciation/amortisation
\u2013
\u2013
(6.9)
(6.9)
Accumulated depreciation and write-downs
31.12.23
\u2013
\u2013
(36.3)
(36.3)
Book value 31.12.23
1.9
\u2013
149.7
151.6
11 Property, plant and equipment Property, plant and equipment at 31 December 2024
Asset under Production Other
USD million construction facilities
assets
Total
Book value 31.12.23
1,422.8
1,003.7
1.4
2,427.9
Acquisition costs 31.12.23
1,422.8
1,491.5
3.1
2,917.4
Reclassification from AUC to production facilities
1)
(1,401.5)
1,401.5
\u2013
0.0
Additions
31.3
185.5
0.1
216.9
Acquisition of subsidiary
\u2013
\u2013
0.0
0.0
Sale of asset
\u2013
19.4
(0.0)
19.4
Revaluation abandonment assets
\u2013
37.1
\u2013
37.1
Disposals
\u2013
\u2013
(0.0)
(0.0)
Currency translation adjustment
\u2013
(0.1)
(0.1)
(0.2)
Acquisition costs 31.12.24
52.6
3,135.0
3.1
3,190.7
Depreciation and write-downs 31.12.23
\u2013
(487.9)
(1.7)
(489.5)
Depreciation
\u2013
(127.0)
(0.2)
(127.2)
Depreciation of capitalised borrowing cost
\u2013
(1.1)
\u2013
(1.1)
Sale of asset, reversal depreciation
\u2013
\u2013
0.0
0.0
Acquisition of subsidiary
\u2013
\u2013
(0.0)
(0.0)
Disposals
\u2013
\u2013
0.0
0.0
Currency translation adjustment
\u2013
0.0
0.0
0.1
Depreciation and write-downs 31.12.24
\u2013
(615.9)
(1.9)
(617.7)
Book value 31.12.24
52.6
2,519.1
1.3
2,573.0
1) Mainly related to Tyra. Property, plant and equipment at 31 December 2023
Asset under Production
USD million construction
facilities
Other assets
Total
Book value 31.12.22
1,222.3
859.6
1.4
2,083.3
Acquisition costs 31.12.22
1,222.3
1,252.5
3.1
2,47
7. 9
Sale of assets
\u2013
\u2013
(0.0)
(0.0)
Additions
322.7
65.9
0.4
388.9
Reclassification from AUC to production facilities
(122.2)
122.2
\u2013
\u2013
Reclassification from capex to opex
\u2013
1.5
\u2013
1.5
Revaluation abandonment asset
\u2013
49.4
\u2013
49.4
Disposal
\u2013
\u2013
(0.3)
(0.3)
Currency translation adjustment
\u2013
0.1
0.0
0.1
Acquisition costs 31.12.23
1,422.8
1,491.5
3.1
2,917.4
Accumulated depreciation and write-downs
31.12.2022
\u2013
(392.9)
(1.7)
(394.6)
Sale of asset, reversal depreciation
\u2013
\u2013
0.0
0.0
Depreciation
\u2013
(94.9)
(0.2)
(95.1)
Disposals
\u2013
\u2013
0.2
0.2
Currency translation adjustment
\u2013
(0.0)
(0.0)
(0.0)
Accumulated depreciation and write-downs
31.12.23
\u2013
(487.9)
(1.7)
(489.5)
Book value 31.12.23
1,422.8
1,003.7
1.4
2,427.9
", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-461": { "value": "
11 Property, plant and equipment
Property, plant and equipment at 31 December 2024
Asset under Production Other
USD million construction facilities
assets
Total
Book value 31.12.23
1,422.8
1,003.7
1.4
2,427.9
Acquisition costs 31.12.23
1,422.8
1,491.5
3.1
2,917.4
Reclassification from AUC to production facilities
1)
(1,401.5)
1,401.5
\u2013
0.0
Additions
31.3
185.5
0.1
216.9
Acquisition of subsidiary
\u2013
\u2013
0.0
0.0
Sale of asset
\u2013
19.4
(0.0)
19.4
Revaluation abandonment assets
\u2013
37.1
\u2013
37.1
Disposals
\u2013
\u2013
(0.0)
(0.0)
Currency translation adjustment
\u2013
(0.1)
(0.1)
(0.2)
Acquisition costs 31.12.24
52.6
3,135.0
3.1
3,190.7
Depreciation and write-downs 31.12.23
\u2013
(487.9)
(1.7)
(489.5)
Depreciation
\u2013
(127.0)
(0.2)
(127.2)
Depreciation of capitalised borrowing cost
\u2013
(1.1)
\u2013
(1.1)
Sale of asset, reversal depreciation
\u2013
\u2013
0.0
0.0
Acquisition of subsidiary
\u2013
\u2013
(0.0)
(0.0)
Disposals
\u2013
\u2013
0.0
0.0
Currency translation adjustment
\u2013
0.0
0.0
0.1
Depreciation and write-downs 31.12.24
\u2013
(615.9)
(1.9)
(617.7)
Book value 31.12.24
52.6
2,519.1
1.3
2,573.0
1) Mainly related to Tyra.
Property, plant and equipment at 31 December 2023
Asset under Production
USD million construction
facilities
Other assets
Total
Book value 31.12.22
1,222.3
859.6
1.4
2,083.3
Acquisition costs 31.12.22
1,222.3
1,252.5
3.1
2,47
7. 9
Sale of assets
\u2013
\u2013
(0.0)
(0.0)
Additions
322.7
65.9
0.4
388.9
Reclassification from AUC to production facilities
(122.2)
122.2
\u2013
\u2013
Reclassification from capex to opex
\u2013
1.5
\u2013
1.5
Revaluation abandonment asset
\u2013
49.4
\u2013
49.4
Disposal
\u2013
\u2013
(0.3)
(0.3)
Currency translation adjustment
\u2013
0.1
0.0
0.1
Acquisition costs 31.12.23
1,422.8
1,491.5
3.1
2,917.4
Accumulated depreciation and write-downs
31.12.2022
\u2013
(392.9)
(1.7)
(394.6)
Sale of asset, reversal depreciation
\u2013
\u2013
0.0
0.0
Depreciation
\u2013
(94.9)
(0.2)
(95.1)
Disposals
\u2013
\u2013
0.2
0.2
Currency translation adjustment
\u2013
(0.0)
(0.0)
(0.0)
Accumulated depreciation and write-downs
31.12.23
\u2013
(487.9)
(1.7)
(489.5)
Book value 31.12.23
1,422.8
1,003.7
1.4
2,427.9
", "dimensions": { "concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-462": { "value": " 12 Impairments Impairment reviews See note 1.7 for the accounting policies and note 3.2 (de) for the accounting estimates / assumptions related to impairment of non-financial assets. The Group has determined that it has two cash-generating units (CGUs): one for the DUC assets and one for CarbonCuts. The Group believes that the market capitalisation is primarily attributable to the DC assets. No impairment triggers were identified in 2024, and therefore, no impairment tests were required to be done on the DUUC CGU. Should the market capitalisation materially decrease below the carrying amount of equity, this could indicate potential impairment trigger of the DUC CGU. If not positive a value in use calculation will be calculated and compared to the carrying value of the CGU to determine if there is an impairment of the DUC CGU. Although no impairment test was required due to the absence of triggers, the Group is reassured by the market capitalisation, which continues to show significant headroom as of 31 December 2024 and 2023. The market capitalisation was USD 1,532.5 million and USD 1,281.6 million on 31 December 2024 and 2023, respectively, based on the exchange rates for the US dollar and Norwegian kroner rates at those times. The carrying amount of equity, was USD 691.8 million and USD 813.6 million on December 31, 2024, and 2023, respectively. The Group has recognised a goodwill from the acquisition of CarbonCuts. CarbonCuts is in the process of exploring the possibility of establishing a safe and permanent CO 2 storage facility and related costs are to a large extent expensed. We note that after the acquisition, CarbonCuts\u2019 was awarded a licence to explore CO 2 storage possibilities onshore in Denmark and current carrying value and estimated recoverable amount are considered immaterial and as such no impairment test was performed. The carrying value of goodwill is USD 2.1 million. No impairment was recognised.", "dimensions": { "concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-463": { "value": "
13 Financial income and expenses
Financial income
USD million
2024
2023
Total interest income
15.8
17. 8
Value adjustment foreign exchange contract
0.7
\u2013
Volume protection true-up
\u2013
0.6
Extinguishment of bond loans
\u2013
1.0
Foreign exchange gains
9.5
3.7
Total other financial income
10.2
5.3
Financial expenses
USD million
2024
2023
Interest expenses current liabilities
(0.5)
\u2013
Interest expense from bond loans
(56.2)
(44.9)
Interest expense from bank debt
1)
(76.8)
(51.9)
Less capitalised borrowing cost
\u2013
78.0
Total interest expenses
(133.0)
(18.9)
Value adjustment of embedded derivatives
2)
(32.1)
(14.1)
Value adjustment interest swap RBL, ineffective part
(0.1)
(0.7)
Value adjustment amortised cost RBL
(5.6)
\u2013
Utilisation of derivatives, ineffective part
(0.7)
(0.1)
Accretion expense related to asset retirement obligations
(54.3)
(49.3)
Extinguishment of bond loans
(22.3)
\u2013
Foreign exchange losses
(5.5)
(12.3)
Other financial expenses
(2.6)
(3.0)
Total other financial expenses
(123.2)
(79.5)
Net financial items
(230.2)
(75.2)
1) Net of the effective part of the realised interest swap, related to RBL facility.
2) Fair value adjustment of the embedded derivatives of the convertible bonds.
3) Change in net present value due to amendment and restatement of the RBL.
Climate-related risk
A sensitivity analysis has been conducted considering the impact of climate-related risks on debt
financing margins. The margin on existing debt balances is fixed, so this risk relates to the potential
impact of an increase in margins upon refinancing in the future. The Company has estimated the
impact of a one-percentage point sensitivity increase (as a proxy of a potential shift in margins) in credit
spreads on outstanding debt balances as of 31 December 2024. This analysis indicates that such an
increase would result in additional interest expense of USD 60 million .
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-533": { "value": "13 Financial income and expenses Financial income
USD million
2024
2023
Total interest income
15.8
17. 8
Value adjustment foreign exchange contract
0.7
\u2013
Volume protection true-up
\u2013
0.6
Extinguishment of bond loans
\u2013
1.0
Foreign exchange gains
9.5
3.7
Total other financial income
10.2
5.3
Financial expenses
USD million
2024
2023
Interest expenses current liabilities
(0.5)
\u2013
Interest expense from bond loans
(56.2)
(44.9)
Interest expense from bank debt
1)
(76.8)
(51.9)
Less capitalised borrowing cost
\u2013
78.0
Total interest expenses
(133.0)
(18.9)
Value adjustment of embedded derivatives
2)
(32.1)
(14.1)
Value adjustment interest swap RBL, ineffective part
(0.1)
(0.7)
Value adjustment amortised cost RBL
(5.6)
\u2013
Utilisation of derivatives, ineffective part
(0.7)
(0.1)
Accretion expense related to asset retirement obligations
(54.3)
(49.3)
Extinguishment of bond loans
(22.3)
\u2013
Foreign exchange losses
(5.5)
(12.3)
Other financial expenses
(2.6)
(3.0)
Total other financial expenses
(123.2)
(79.5)
Net financial items
(230.2)
(75.2)
1) Net of the effective part of the realised interest swap, related to RBL facility. 2) Fair value adjustment of the embedded derivatives of the convertible bonds. 3) Change in net present value due to amendment and restatement of the RBL. Climate-related risk A sensitivity analysis has been conducted considering the impact of climate-related risks on debt financing margins. The margin on existing debt balances is fixed, so this risk relates to the potential impact of an increase in margins upon refinancing in the future. The Company has estimated the impact of a one-percentage point sensitivity increase (as a proxy of a potential shift in margins) in credit spreads on outstanding debt balances as of 31 December 2024. This analysis indicates that such an increase would result in additional interest expense of USD 60 million .", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-531": { "value": "13 Financial income and expenses Financial income
USD million
2024
2023
Total interest income
15.8
17. 8
Value adjustment foreign exchange contract
0.7
\u2013
Volume protection true-up
\u2013
0.6
Extinguishment of bond loans
\u2013
1.0
Foreign exchange gains
9.5
3.7
Total other financial income
10.2
5.3
Financial expenses
USD million
2024
2023
Interest expenses current liabilities
(0.5)
\u2013
Interest expense from bond loans
(56.2)
(44.9)
Interest expense from bank debt
1)
(76.8)
(51.9)
Less capitalised borrowing cost
\u2013
78.0
Total interest expenses
(133.0)
(18.9)
Value adjustment of embedded derivatives
2)
(32.1)
(14.1)
Value adjustment interest swap RBL, ineffective part
(0.1)
(0.7)
Value adjustment amortised cost RBL
(5.6)
\u2013
Utilisation of derivatives, ineffective part
(0.7)
(0.1)
Accretion expense related to asset retirement obligations
(54.3)
(49.3)
Extinguishment of bond loans
(22.3)
\u2013
Foreign exchange losses
(5.5)
(12.3)
Other financial expenses
(2.6)
(3.0)
Total other financial expenses
(123.2)
(79.5)
Net financial items
(230.2)
(75.2)
1) Net of the effective part of the realised interest swap, related to RBL facility. 2) Fair value adjustment of the embedded derivatives of the convertible bonds. 3) Change in net present value due to amendment and restatement of the RBL. Climate-related risk A sensitivity analysis has been conducted considering the impact of climate-related risks on debt financing margins. The margin on existing debt balances is fixed, so this risk relates to the potential impact of an increase in margins upon refinancing in the future. The Company has estimated the impact of a one-percentage point sensitivity increase (as a proxy of a potential shift in margins) in credit spreads on outstanding debt balances as of 31 December 2024. This analysis indicates that such an increase would result in additional interest expense of USD 60 million ", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-526": { "value": "13 Financial income and expenses Financial income
USD million
2024
2023
Total interest income
15.8
17. 8
Value adjustment foreign exchange contract
0.7
\u2013
Volume protection true-up
\u2013
0.6
Extinguishment of bond loans
\u2013
1.0
Foreign exchange gains
9.5
3.7
Total other financial income
10.2
5.3
Financial expenses
USD million
2024
2023
Interest expenses current liabilities
(0.5)
\u2013
Interest expense from bond loans
(56.2)
(44.9)
Interest expense from bank debt
1)
(76.8)
(51.9)
Less capitalised borrowing cost
\u2013
78.0
Total interest expenses
(133.0)
(18.9)
Value adjustment of embedded derivatives
2)
(32.1)
(14.1)
Value adjustment interest swap RBL, ineffective part
(0.1)
(0.7)
Value adjustment amortised cost RBL
(5.6)
\u2013
Utilisation of derivatives, ineffective part
(0.7)
(0.1)
Accretion expense related to asset retirement obligations
(54.3)
(49.3)
Extinguishment of bond loans
(22.3)
\u2013
Foreign exchange losses
(5.5)
(12.3)
Other financial expenses
(2.6)
(3.0)
Total other financial expenses
(123.2)
(79.5)
Net financial items
(230.2)
(75.2)
1) Net of the effective part of the realised interest swap, related to RBL facility. 2) Fair value adjustment of the embedded derivatives of the convertible bonds. 3) Change in net present value due to amendment and restatement of the RBL. Climate-related risk A sensitivity analysis has been conducted considering the impact of climate-related risks on debt financing margins. The margin on existing debt balances is fixed, so this risk relates to the potential impact of an increase in margins upon refinancing in the future. The Company has estimated the impact of a one-percentage point sensitivity increase (as a proxy of a potential shift in margins) in credit spreads on outstanding debt balances as of 31 December 2024. This analysis indicates that such an increase would result in additional interest expense of USD 60 million .", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-517": { "value": "13 Financial income and expenses Financial income
USD million
2024
2023
Total interest income
15.8
17. 8
Value adjustment foreign exchange contract
0.7
\u2013
Volume protection true-up
\u2013
0.6
Extinguishment of bond loans
\u2013
1.0
Foreign exchange gains
9.5
3.7
Total other financial income
10.2
5.3
Financial expenses
USD million
2024
2023
Interest expenses current liabilities
(0.5)
\u2013
Interest expense from bond loans
(56.2)
(44.9)
Interest expense from bank debt
1)
(76.8)
(51.9)
Less capitalised borrowing cost
\u2013
78.0
Total interest expenses
(133.0)
(18.9)
Value adjustment of embedded derivatives
2)
(32.1)
(14.1)
Value adjustment interest swap RBL, ineffective part
(0.1)
(0.7)
Value adjustment amortised cost RBL
(5.6)
\u2013
Utilisation of derivatives, ineffective part
(0.7)
(0.1)
Accretion expense related to asset retirement obligations
(54.3)
(49.3)
Extinguishment of bond loans
(22.3)
\u2013
Foreign exchange losses
(5.5)
(12.3)
Other financial expenses
(2.6)
(3.0)
Total other financial expenses
(123.2)
(79.5)
Net financial items
(230.2)
(75.2)
1) Net of the effective part of the realised interest swap, related to RBL facility. 2) Fair value adjustment of the embedded derivatives of the convertible bonds. 3) Change in net present value due to amendment and restatement of the RBL. Climate-related risk A sensitivity analysis has been conducted considering the impact of climate-related risks on debt financing margins. The margin on existing debt balances is fixed, so this risk relates to the potential impact of an increase in margins upon refinancing in the future. The Company has estimated the impact of a one-percentage point sensitivity increase (as a proxy of a potential shift in margins) in credit spreads on outstanding debt balances as of 31 December 2024. This analysis indicates that such an increase would result in additional interest expense of USD 60 million .", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-500": { "value": "13 Financial income and expenses Financial income
USD million
2024
2023
Total interest income
15.8
17. 8
Value adjustment foreign exchange contract
0.7
\u2013
Volume protection true-up
\u2013
0.6
Extinguishment of bond loans
\u2013
1.0
Foreign exchange gains
9.5
3.7
Total other financial income
10.2
5.3
Financial expenses
USD million
2024
2023
Interest expenses current liabilities
(0.5)
\u2013
Interest expense from bond loans
(56.2)
(44.9)
Interest expense from bank debt
1)
(76.8)
(51.9)
Less capitalised borrowing cost
\u2013
78.0
Total interest expenses
(133.0)
(18.9)
Value adjustment of embedded derivatives
2)
(32.1)
(14.1)
Value adjustment interest swap RBL, ineffective part
(0.1)
(0.7)
Value adjustment amortised cost RBL
(5.6)
\u2013
Utilisation of derivatives, ineffective part
(0.7)
(0.1)
Accretion expense related to asset retirement obligations
(54.3)
(49.3)
Extinguishment of bond loans
(22.3)
\u2013
Foreign exchange losses
(5.5)
(12.3)
Other financial expenses
(2.6)
(3.0)
Total other financial expenses
(123.2)
(79.5)
Net financial items
(230.2)
(75.2)
1) Net of the effective part of the realised interest swap, related to RBL facility. 2) Fair value adjustment of the embedded derivatives of the convertible bonds. 3) Change in net present value due to amendment and restatement of the RBL. Climate-related risk A sensitivity analysis has been conducted considering the impact of climate-related risks on debt financing margins. The margin on existing debt balances is fixed, so this risk relates to the potential impact of an increase in margins upon refinancing in the future. The Company has estimated the impact of a one-percentage point sensitivity increase (as a proxy of a potential shift in margins) in credit spreads on outstanding debt balances as of 31 December 2024. This analysis indicates that such an increase would result in additional interest expense of USD 60 million .", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-464": { "value": "
14 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 \u2018Chapter
2\u2019 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 the 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)
2024
2023
Current tax
(5.4)
(63.3)
Solidarity contribution, current
1)
\u2013
(72.2)
Current tax, prior year
2)
68.1
(10.1)
Current tax
62.7
(145.5)
Deferred tax
(53.2)
(65.8)
Solidarity contribution, deferred
1)
\u2013
70.5
Deferred tax, prior year
2)
(68.1)
7.1
Deferred tax
(121.4)
11.8
Tax (expense)/income
(58.7)
(133.7)
1) The current tax accrual includes 33 percent \u2018solidarity contribution\u2019, the EU-regulated temporary tax to be levied on fossil fuel
companies in 2023 in Denmark. As this contribution may be offset against hydrocarbon tax, the charge does not lead to an increase in
the overall tax percentage applied.
2) Mainly related to tax depreciation of Tyra II included in the tax return for 2023.
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
2024
2023
Cash flow hedges
67.2
(47.7)
Tax (expense)/income related to OCI
67.2
(47.7)
Income tax on OCI is related to the derivatives designated in cash flow hedges. To the extent
derivatives are associated with the sale of oil and gas, result from cash flow hedges is subject to
64 percent hydrocarbon tax.
Hydrocarbon tax 64%
Corporate tax 22%
Reconciliation of nominal to actual tax rate
2024
2024
In total
Result before tax
67.6
(79.6)
(12.1)
Expected tax on profit before tax
43.2
64%
(17.5)
22%
25.7
Tax effect of:
Prior year adjustment
0.5
1%
(0.4)
1%
0.1
Currency changes to tax losses carried
forward in DKK
1)
53.0
78%
\u2013
0%
53.0
Investment uplift on capex projects
2)
(51.3)
-76%
\u2013
0%
(51.3)
Permanent differences
3)
\u2013
0%
7.1
-9%
7.1
Interest limitation
11.5
17%
\u2013
0%
11.5
No recognition of tax assets in Norway
and UK
\u2013
0%
12.7
-16%
12.7
Tax expense (income) in profit/loss
56.9
84%
1.8
-2%
58.7
1) Impact of changes in USD/DKK exchange rate on loss carried forward as the tax losses are carried forward in DKK.
2) The tax cost in the hydrocarbon tax regime is positively impacted by the 39 percent investment uplift on the Tyra redevelopment project.
3) Mainly related to fair value adjustment of embedded derivatives.
Hydrocarbon tax 64%
Corporate tax 22%
Reconciliation of nominal to actual tax rate, continues
2023
2022
In total
Result before tax
237.2
6.3
243.6
Expected tax on profit before tax
151.8
64%
1.4
22%
153.2
Tax effect of:
Prior year adjustment
4.2
2%
(1.3)
-20%
2.9
Currency changes to tax losses carried
forward in DKK
1)
(24.6)
-10%
\u2013
0%
(24.6)
Investment uplift on capex projects
2)
(42.6)
-18%
\u2013
0%
(42.6)
Permanent differences
3)
37.9
16%
3.0
48%
40.9
No recognition of tax assets in Norway
and UK
\u2013
0%
3.8
61%
3.8
Tax expense (income) in profit/loss
126.8
53%
7.0
110%
133.7
1) Impact of changes in USD/DKK exchange rate on loss carried forward as the tax losses are carried forward in DKK.
2) The tax cost in the hydrocarbon tax regime is positively impacted by the 39 percent investment uplift on the Tyra redevelopment project.
3) This is related to the portion of interest cost not deductible under the Danish interest limitation rules.
Hydrocarbon tax 64%
Corporate tax 22%
2024
2024
In total
OCI before tax
(98.1)
(23.4)
-121.5
Expected tax on OCI before tax
62.8
64%
5.2
22%
67.9
Tax effect of:
Non-taxable currency translation adjustment
\u2013
-0.7
-0.7
Tax in OCI
62.8
64%
4.5
22%
67.2
Hydrocarbon tax 64%
Corporate tax 22%
2023
2023
In total
OCI before tax
82.8
(22.7)
60.1
Expected tax on OCI before tax
(53.0)
64%
5.0
22%
(48.0)
Tax effect of:
Non-taxable currency translation adjustment
\u2013
0.3
0.3
Tax in OCI
(53.0)
64%
5.3
22%
(47.7)
Current income tax receivables/(payables)
2024
2023
Corporate tax 22% (Denmark)
(0.8)
(4.6)
Hydrocarbon tax (Denmark)
11.5
(73.7)
Hydrocarbon tax for prior years (Denmark)
(8.6)
(12.9)
Solidarity contribution
\u2013
(48.8)
Tax receivables/(payables)
2.2
(140.0)
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 receivables of USD 2.2 million, which includes USD 11.5 million actual cash receivables to be paid in 2025 and USD 9.4 million in provision for uncertain tax positions
Deferred tax
Deferred tax is 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 is allocated to the following balance sheet items, all pertaining to
the Group\u2019s activities on the Danish continental shelf:
Effect
recognised Effect
USD million in profit/ recognised
Deferred tax and deferred tax asset
31.12.2023
loss
in OCI
31.12.2024
Property, plant and equipment
812.9
248.3
\u2013
1,061.2
Intangible assets, licences
29.4
(14.8)
\u2013
14.7
Inventories and receivables
33.8
(1.3)
\u2013
32.5
Asset retirement obligation (ARO)
(623.9)
(47.1)
\u2013
(671.1)
Other assets and liabilities
(2.9)
(2.7)
\u2013
(5.6)
Tax loss carryforward, corporate tax (22%)
\u2013
\u2013
\u2013
\u2013
Tax loss carryforward, chapter 2 tax (25%)
(0.1)
(31.2)
\u2013
(31.3)
Tax loss carryforward, chapter 3a tax (52%)
(467.7)
(29.7)
(62.8)
(560.2)
Deferred tax asset, net
(218.5)
121.4
(62.8)
(159.8)
Effect Effect
USD million recognised in recognised
Deferred tax and deferred tax asset
31.12.2022
profit/loss
in OCI
31.12.2023
Property, plant and equipment
745.9
67.0
\u2013
812.8
Intangible assets, licenses
25.1
4.3
\u2013
29.4
Inventories and receivables
29.3
4.6
\u2013
33.8
Asset retirement obligation (ARO) provision
(564.5)
(59.5)
\u2013
(623.9)
Other assets and liabilities
(2.8)
(0.1)
\u2013
(2.9)
Tax loss carryforward, corporate tax (22%)
\u2013
\u2013
\u2013
\u2013
Tax loss carryforward, Chapter 2 tax (25%)
(0.1)
0.1
\u2013
\u2013
Tax loss carryforward, Chapter 3a tax (52%)
(471.9)
(28.1)
32.3
(467.7)
Deferred tax asset, net
(239.1)
(11.7)
32.3
(218.5)
Tax loss carryforwards
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 pound.
Tax losses carried forward, Denmark. In million DKK
2024
2023
Corporate tax (22%)
\u2013
\u2013
Chapter 2 Hydrocarbon tax (25%)
890.7
\u2013
Chapter 3a Hydrocarbon tax (52%)
7,488.1
5,523.2
Tax losses carried forward, Norway. In million NOK
2024
2023
Corporate tax Norway (22%)
1,208.3
1,204.2
Tax losses carried forward, UK. In million GPB/USD
2024
1)
2023
Trade losses, UK (hydrocarbon s 330 (2)), USD
78.0
78.0
Trade losses, UK (hydrocarbon), USD
100.1
100.1
Pre-trading revenue expenditure, UK (hydrocarbon), GBP
1.3
1.3
Pre-trading capital expenditure, UK (hydrocarbon), GBP
40.2
40.2
1) The amounts are based on the latest tax return for income year 2022.
", "dimensions": { "concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-518": { "value": "14 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 \u2018Chapter 2\u2019 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 the 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)
2024
2023
Current tax
(5.4)
(63.3)
Solidarity contribution, current
1)
\u2013
(72.2)
Current tax, prior year
2)
68.1
(10.1)
Current tax
62.7
(145.5)
Deferred tax
(53.2)
(65.8)
Solidarity contribution, deferred
1)
\u2013
70.5
Deferred tax, prior year
2)
(68.1)
7.1
Deferred tax
(121.4)
11.8
Tax (expense)/income
(58.7)
(133.7)
1) The current tax accrual includes 33 percent \u2018solidarity contribution\u2019, the EU-regulated temporary tax to be levied on fossil fuel companies in 2023 in Denmark. As this contribution may be offset against hydrocarbon tax, the charge does not lead to an increase in the overall tax percentage applied. 2) Mainly related to tax depreciation of Tyra II included in the tax return for 2023. 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
2024
2023
Cash flow hedges
67.2
(47.7)
Tax (expense)/income related to OCI
67.2
(47.7)
Income tax on OCI is related to the derivatives designated in cash flow hedges. To the extent derivatives are associated with the sale of oil and gas, result from cash flow hedges is subject to 64 percent hydrocarbon tax.
Hydrocarbon tax 64%
Corporate tax 22%
Reconciliation of nominal to actual tax rate
2024
2024
In total
Result before tax
67.6
(79.6)
(12.1)
Expected tax on profit before tax
43.2
64%
(17.5)
22%
25.7
Tax effect of:
Prior year adjustment
0.5
1%
(0.4)
1%
0.1
Currency changes to tax losses carried
forward in DKK
1)
53.0
78%
\u2013
0%
53.0
Investment uplift on capex projects
2)
(51.3)
-76%
\u2013
0%
(51.3)
Permanent differences
3)
\u2013
0%
7.1
-9%
7.1
Interest limitation
11.5
17%
\u2013
0%
11.5
No recognition of tax assets in Norway
and UK
\u2013
0%
12.7
-16%
12.7
Tax expense (income) in profit/loss
56.9
84%
1.8
-2%
58.7
1) Impact of changes in USD/DKK exchange rate on loss carried forward as the tax losses are carried forward in DKK. 2) The tax cost in the hydrocarbon tax regime is positively impacted by the 39 percent investment uplift on the Tyra redevelopment project. 3) Mainly related to fair value adjustment of embedded derivatives.
Hydrocarbon tax 64%
Corporate tax 22%
Reconciliation of nominal to actual tax rate, continues
2023
2022
In total
Result before tax
237.2
6.3
243.6
Expected tax on profit before tax
151.8
64%
1.4
22%
153.2
Tax effect of:
Prior year adjustment
4.2
2%
(1.3)
-20%
2.9
Currency changes to tax losses carried
forward in DKK
1)
(24.6)
-10%
\u2013
0%
(24.6)
Investment uplift on capex projects
2)
(42.6)
-18%
\u2013
0%
(42.6)
Permanent differences
3)
37.9
16%
3.0
48%
40.9
No recognition of tax assets in Norway
and UK
\u2013
0%
3.8
61%
3.8
Tax expense (income) in profit/loss
126.8
53%
7.0
110%
133.7
1) Impact of changes in USD/DKK exchange rate on loss carried forward as the tax losses are carried forward in DKK. 2) The tax cost in the hydrocarbon tax regime is positively impacted by the 39 percent investment uplift on the Tyra redevelopment project. 3) This is related to the portion of interest cost not deductible under the Danish interest limitation rules.
Hydrocarbon tax 64%
Corporate tax 22%
2024
2024
In total
OCI before tax
(98.1)
(23.4)
-121.5
Expected tax on OCI before tax
62.8
64%
5.2
22%
67.9
Tax effect of:
Non-taxable currency translation adjustment
\u2013
-0.7
-0.7
Tax in OCI
62.8
64%
4.5
22%
67.2
Hydrocarbon tax 64%
Corporate tax 22%
2023
2023
In total
OCI before tax
82.8
(22.7)
60.1
Expected tax on OCI before tax
(53.0)
64%
5.0
22%
(48.0)
Tax effect of:
Non-taxable currency translation adjustment
\u2013
0.3
0.3
Tax in OCI
(53.0)
64%
5.3
22%
(47.7)
Current income tax receivables/(payables)
2024
2023
Corporate tax 22% (Denmark)
(0.8)
(4.6)
Hydrocarbon tax (Denmark)
11.5
(73.7)
Hydrocarbon tax for prior years (Denmark)
(8.6)
(12.9)
Solidarity contribution
\u2013
(48.8)
Tax receivables/(payables)
2.2
(140.0)
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 receivables of USD 2.2 million, which includes USD 11.5 million actual cash receivables to be paid in 2025 and USD 9.4 million in provision for uncertain tax positions . Deferred tax Deferred tax is 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 is allocated to the following balance sheet items, all pertaining to the Group\u2019s activities on the Danish continental shelf:
Effect
recognised Effect
USD million in profit/ recognised
Deferred tax and deferred tax asset
31.12.2023
loss
in OCI
31.12.2024
Property, plant and equipment
812.9
248.3
\u2013
1,061.2
Intangible assets, licences
29.4
(14.8)
\u2013
14.7
Inventories and receivables
33.8
(1.3)
\u2013
32.5
Asset retirement obligation (ARO)
(623.9)
(47.1)
\u2013
(671.1)
Other assets and liabilities
(2.9)
(2.7)
\u2013
(5.6)
Tax loss carryforward, corporate tax (22%)
\u2013
\u2013
\u2013
\u2013
Tax loss carryforward, chapter 2 tax (25%)
(0.1)
(31.2)
\u2013
(31.3)
Tax loss carryforward, chapter 3a tax (52%)
(467.7)
(29.7)
(62.8)
(560.2)
Deferred tax asset, net
(218.5)
121.4
(62.8)
(159.8)
Effect Effect
USD million recognised in recognised
Deferred tax and deferred tax asset
31.12.2022
profit/loss
in OCI
31.12.2023
Property, plant and equipment
745.9
67.0
\u2013
812.8
Intangible assets, licenses
25.1
4.3
\u2013
29.4
Inventories and receivables
29.3
4.6
\u2013
33.8
Asset retirement obligation (ARO) provision
(564.5)
(59.5)
\u2013
(623.9)
Other assets and liabilities
(2.8)
(0.1)
\u2013
(2.9)
Tax loss carryforward, corporate tax (22%)
\u2013
\u2013
\u2013
\u2013
Tax loss carryforward, Chapter 2 tax (25%)
(0.1)
0.1
\u2013
\u2013
Tax loss carryforward, Chapter 3a tax (52%)
(471.9)
(28.1)
32.3
(467.7)
Deferred tax asset, net
(239.1)
(11.7)
32.3
(218.5)
Tax loss carryforwards 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 pound.
Tax losses carried forward, Denmark. In million DKK
2024
2023
Corporate tax (22%)
\u2013
\u2013
Chapter 2 Hydrocarbon tax (25%)
890.7
\u2013
Chapter 3a Hydrocarbon tax (52%)
7,488.1
5,523.2
Tax losses carried forward, Norway. In million NOK
2024
2023
Corporate tax Norway (22%)
1,208.3
1,204.2
Tax losses carried forward, UK. In million GPB/USD
2024
1)
2023
Trade losses, UK (hydrocarbon s 330 (2)), USD
78.0
78.0
Trade losses, UK (hydrocarbon), USD
100.1
100.1
Pre-trading revenue expenditure, UK (hydrocarbon), GBP
1.3
1.3
Pre-trading capital expenditure, UK (hydrocarbon), GBP
40.2
40.2
1) The amounts are based on the latest tax return for income year 2022.", "dimensions": { "concept": "ifrs-full:DisclosureOfTaxReceivablesAndPayablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-501": { "value": "14 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 \u2018Chapter 2\u2019 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 the 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)
2024
2023
Current tax
(5.4)
(63.3)
Solidarity contribution, current
1)
\u2013
(72.2)
Current tax, prior year
2)
68.1
(10.1)
Current tax
62.7
(145.5)
Deferred tax
(53.2)
(65.8)
Solidarity contribution, deferred
1)
\u2013
70.5
Deferred tax, prior year
2)
(68.1)
7.1
Deferred tax
(121.4)
11.8
Tax (expense)/income
(58.7)
(133.7)
1) The current tax accrual includes 33 percent \u2018solidarity contribution\u2019, the EU-regulated temporary tax to be levied on fossil fuel companies in 2023 in Denmark. As this contribution may be offset against hydrocarbon tax, the charge does not lead to an increase in the overall tax percentage applied. 2) Mainly related to tax depreciation of Tyra II included in the tax return for 2023. 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
2024
2023
Cash flow hedges
67.2
(47.7)
Tax (expense)/income related to OCI
67.2
(47.7)
Income tax on OCI is related to the derivatives designated in cash flow hedges. To the extent derivatives are associated with the sale of oil and gas, result from cash flow hedges is subject to 64 percent hydrocarbon tax.
Hydrocarbon tax 64%
Corporate tax 22%
Reconciliation of nominal to actual tax rate
2024
2024
In total
Result before tax
67.6
(79.6)
(12.1)
Expected tax on profit before tax
43.2
64%
(17.5)
22%
25.7
Tax effect of:
Prior year adjustment
0.5
1%
(0.4)
1%
0.1
Currency changes to tax losses carried
forward in DKK
1)
53.0
78%
\u2013
0%
53.0
Investment uplift on capex projects
2)
(51.3)
-76%
\u2013
0%
(51.3)
Permanent differences
3)
\u2013
0%
7.1
-9%
7.1
Interest limitation
11.5
17%
\u2013
0%
11.5
No recognition of tax assets in Norway
and UK
\u2013
0%
12.7
-16%
12.7
Tax expense (income) in profit/loss
56.9
84%
1.8
-2%
58.7
1) Impact of changes in USD/DKK exchange rate on loss carried forward as the tax losses are carried forward in DKK. 2) The tax cost in the hydrocarbon tax regime is positively impacted by the 39 percent investment uplift on the Tyra redevelopment project. 3) Mainly related to fair value adjustment of embedded derivatives.
Hydrocarbon tax 64%
Corporate tax 22%
Reconciliation of nominal to actual tax rate, continues
2023
2022
In total
Result before tax
237.2
6.3
243.6
Expected tax on profit before tax
151.8
64%
1.4
22%
153.2
Tax effect of:
Prior year adjustment
4.2
2%
(1.3)
-20%
2.9
Currency changes to tax losses carried
forward in DKK
1)
(24.6)
-10%
\u2013
0%
(24.6)
Investment uplift on capex projects
2)
(42.6)
-18%
\u2013
0%
(42.6)
Permanent differences
3)
37.9
16%
3.0
48%
40.9
No recognition of tax assets in Norway
and UK
\u2013
0%
3.8
61%
3.8
Tax expense (income) in profit/loss
126.8
53%
7.0
110%
133.7
1) Impact of changes in USD/DKK exchange rate on loss carried forward as the tax losses are carried forward in DKK. 2) The tax cost in the hydrocarbon tax regime is positively impacted by the 39 percent investment uplift on the Tyra redevelopment project. 3) This is related to the portion of interest cost not deductible under the Danish interest limitation rules.
Hydrocarbon tax 64%
Corporate tax 22%
2024
2024
In total
OCI before tax
(98.1)
(23.4)
-121.5
Expected tax on OCI before tax
62.8
64%
5.2
22%
67.9
Tax effect of:
Non-taxable currency translation adjustment
\u2013
-0.7
-0.7
Tax in OCI
62.8
64%
4.5
22%
67.2
Hydrocarbon tax 64%
Corporate tax 22%
2023
2023
In total
OCI before tax
82.8
(22.7)
60.1
Expected tax on OCI before tax
(53.0)
64%
5.0
22%
(48.0)
Tax effect of:
Non-taxable currency translation adjustment
\u2013
0.3
0.3
Tax in OCI
(53.0)
64%
5.3
22%
(47.7)
Current income tax receivables/(payables)
2024
2023
Corporate tax 22% (Denmark)
(0.8)
(4.6)
Hydrocarbon tax (Denmark)
11.5
(73.7)
Hydrocarbon tax for prior years (Denmark)
(8.6)
(12.9)
Solidarity contribution
\u2013
(48.8)
Tax receivables/(payables)
2.2
(140.0)
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 receivables of USD 2.2 million, which includes USD 11.5 million actual cash
receivables to be paid in 2025 and USD 9.4 million in provision for uncertain tax positions .
Deferred tax Deferred tax is 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 is allocated to the following balance sheet items, all pertaining to the Group\u2019s activities on the Danish continental shelf:
Effect
recognised Effect
USD million in profit/ recognised
Deferred tax and deferred tax asset
31.12.2023
loss
in OCI
31.12.2024
Property, plant and equipment
812.9
248.3
\u2013
1,061.2
Intangible assets, licences
29.4
(14.8)
\u2013
14.7
Inventories and receivables
33.8
(1.3)
\u2013
32.5
Asset retirement obligation (ARO)
(623.9)
(47.1)
\u2013
(671.1)
Other assets and liabilities
(2.9)
(2.7)
\u2013
(5.6)
Tax loss carryforward, corporate tax (22%)
\u2013
\u2013
\u2013
\u2013
Tax loss carryforward, chapter 2 tax (25%)
(0.1)
(31.2)
\u2013
(31.3)
Tax loss carryforward, chapter 3a tax (52%)
(467.7)
(29.7)
(62.8)
(560.2)
Deferred tax asset, net
(218.5)
121.4
(62.8)
(159.8)
Effect Effect
USD million recognised in recognised
Deferred tax and deferred tax asset
31.12.2022
profit/loss
in OCI
31.12.2023
Property, plant and equipment
745.9
67.0
\u2013
812.8
Intangible assets, licenses
25.1
4.3
\u2013
29.4
Inventories and receivables
29.3
4.6
\u2013
33.8
Asset retirement obligation (ARO) provision
(564.5)
(59.5)
\u2013
(623.9)
Other assets and liabilities
(2.8)
(0.1)
\u2013
(2.9)
Tax loss carryforward, corporate tax (22%)
\u2013
\u2013
\u2013
\u2013
Tax loss carryforward, Chapter 2 tax (25%)
(0.1)
0.1
\u2013
\u2013
Tax loss carryforward, Chapter 3a tax (52%)
(471.9)
(28.1)
32.3
(467.7)
Deferred tax asset, net
(239.1)
(11.7)
32.3
(218.5)
Tax loss carryforwards 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 pound.
Tax losses carried forward, Denmark. In million DKK
2024
2023
Corporate tax (22%)
\u2013
\u2013
Chapter 2 Hydrocarbon tax (25%)
890.7
\u2013
Chapter 3a Hydrocarbon tax (52%)
7,488.1
5,523.2
Tax losses carried forward, Norway. In million NOK
2024
2023
Corporate tax Norway (22%)
1,208.3
1,204.2
Tax losses carried forward, UK. In million GPB/USD
2024
1)
2023
Trade losses, UK (hydrocarbon s 330 (2)), USD
78.0
78.0
Trade losses, UK (hydrocarbon), USD
100.1
100.1
Pre-trading revenue expenditure, UK (hydrocarbon), GBP
1.3
1.3
Pre-trading capital expenditure, UK (hydrocarbon), GBP
40.2
40.2
1) The amounts are based on the latest tax return for income year 2022.", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-466": { "value": "15 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
2024
2023
Profit (loss) attributable to ordinary shareholders
from operations
(70.8)
109.8
Adjustment amortisation convertible bond loans
31.3
27.0
Adjustment fair value embedded derivatives
32.1
14.1
Profit (loss) basis for fully diluted shareholders
from operations
(7.3)
150.9
Number of shares outstanding at the beginning of the year
26,105,328
25,571,262
Issue of new share
292,791
\u2013
Sale of treasury shares
100,521
36,641
Conversion part of convertible bond
\u2013
497,425
Number of shares outstanding at the end of the year
26,498,640
26,105,328
Weighted average number of shares (basic)
26,318,827
26,043,859
Adjustment convertible bond loan
1)
4,803,885
4,
8
09
,74 3
Adjustment option schemes
\u2013
378,868
Weighted average number of shares (diluted)
31,122,712
31,232,470
Earnings per share in USD
(2.7)
4.2
Earnings per share in USD diluted
(2.7)
4.2
1) The BNOR15 convertible bond loan is converted to number of shares by dividing the principal amount at year end (USD 247.1 million, 2023: USD 228,4 million) with the strike price as this is less favourable (51.4 USD/share, 2023 converted by the conversion price as this was less favourable: 47.5 USD/share). The conversion price is 99 percent of the volume-weighted average price (VWAP) for the last 20 days (606.5 NOK/share, 2023: 483.1 NOK/share) converted to USD by using the closing rate at year end (11.35 NOK/USD, 2023: 10.17 NOK/USD).", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-467": { "value": "
16 Non-current receivables, trade receivables and other current assets
USD million
2024
2023
Non-current assets
Convertible loan CarbonCuts
\u2013
1.1
Loan CarbonCuts
\u2013
2.6
Total non-current receivables
\u2013
3.7
Current assets
Trade receivables
27.9
59.9
Under-lift of oil/NGL
\u2013
2.6
Prepayments
9.5
24.8
Other receivables
1.6
1.4
Total trade receivables and other current receivables
39.0
88.7
Aging analysis of trade receivables on 31 December 2024
Past due
USD million
Total
Not past due
> 30 days
30-60 days
61-90 days
91-120 days
> 120 days
Trade receivables
27.9
27.9
\u2013
\u2013
\u2013
\u2013
\u2013
Total
27.9
27.9
\u2013
\u2013
\u2013
\u2013
\u2013
Aging analysis of trade receivables on 31 December 2023
Past due
USD million
Tot al
Not past due
> 30 days
30-60 days
61-90 days
91-120 days
> 120 days
Trade receivables
59.9
59.9
\u2013
\u2013
\u2013
\u2013
\u2013
Total
59.9
59.9
\u2013
\u2013
\u2013
\u2013
\u2013
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-519": { "value": "16 Non-current receivables, trade receivables and other current assets
USD million
2024
2023
Non-current assets
Convertible loan CarbonCuts
\u2013
1.1
Loan CarbonCuts
\u2013
2.6
Total non-current receivables
\u2013
3.7
Current assets
Trade receivables
27.9
59.9
Under-lift of oil/NGL
\u2013
2.6
Prepayments
9.5
24.8
Other receivables
1.6
1.4
Total trade receivables and other current receivables
39.0
88.7
Aging analysis of trade receivables on 31 December 2024
Past due
USD million
Total
Not past due
> 30 days
30-60 days
61-90 days
91-120 days
> 120 days
Trade receivables
27.9
27.9
\u2013
\u2013
\u2013
\u2013
\u2013
Total
27.9
27.9
\u2013
\u2013
\u2013
\u2013
\u2013
Aging analysis of trade receivables on 31 December 2023
Past due
USD million
Tot al
Not past due
> 30 days
30-60 days
61-90 days
91-120 days
> 120 days
Trade receivables
59.9
59.9
\u2013
\u2013
\u2013
\u2013
\u2013
Total
59.9
59.9
\u2013
\u2013
\u2013
\u2013
\u2013
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-527": { "value": "16 Non-current receivables, trade receivables and other current assets
USD million
2024
2023
Non-current assets
Convertible loan CarbonCuts
\u2013
1.1
Loan CarbonCuts
\u2013
2.6
Total non-current receivables
\u2013
3.7
Current assets
Trade receivables
27.9
59.9
Under-lift of oil/NGL
\u2013
2.6
Prepayments
9.5
24.8
Other receivables
1.6
1.4
Total trade receivables and other current receivables
39.0
88.7
Aging analysis of trade receivables on 31 December 2024
Past due
USD million
Total
Not past due
> 30 days
30-60 days
61-90 days
91-120 days
> 120 days
Trade receivables
27.9
27.9
\u2013
\u2013
\u2013
\u2013
\u2013
Total
27.9
27.9
\u2013
\u2013
\u2013
\u2013
\u2013
Aging analysis of trade receivables on 31 December 2023
Past due
USD million
Tot al
Not past due
> 30 days
30-60 days
61-90 days
91-120 days
> 120 days
Trade receivables
59.9
59.9
\u2013
\u2013
\u2013
\u2013
\u2013
Total
59.9
59.9
\u2013
\u2013
\u2013
\u2013
\u2013
", "dimensions": { "concept": "ifrs-full:DisclosureOfPrepaymentsAndOtherAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-502": { "value": "16 Non-current receivables, trade receivables and other current assets
USD million
2024
2023
Non-current assets
Convertible loan CarbonCuts
\u2013
1.1
Loan CarbonCuts
\u2013
2.6
Total non-current receivables
\u2013
3.7
Current assets
Trade receivables
27.9
59.9
Under-lift of oil/NGL
\u2013
2.6
Prepayments
9.5
24.8
Other receivables
1.6
1.4
Total trade receivables and other current receivables
39.0
88.7
Aging analysis of trade receivables on 31 December 2024
Past due
USD million
Total
Not past due
> 30 days
30-60 days
61-90 days
91-120 days
> 120 days
Trade receivables
27.9
27.9
\u2013
\u2013
\u2013
\u2013
\u2013
Total
27.9
27.9
\u2013
\u2013
\u2013
\u2013
\u2013
Aging analysis of trade receivables on 31 December 2023
Past due
USD million
Tot al
Not past due
> 30 days
30-60 days
61-90 days
91-120 days
> 120 days
Trade receivables
59.9
59.9
\u2013
\u2013
\u2013
\u2013
\u2013
Total
59.9
59.9
\u2013
\u2013
\u2013
\u2013
\u2013
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-465": { "value": "17 Inventories
USD million
2024
2023
Product inventory, oil
13.7
15.0
Other stock (spares and consumables)
1)
42.1
39.7
Total inventories
55.8
54.7
1) As of 31 December 2024 there is no provision for obsolete stock.", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-468": { "value": "
18 Restricted bank deposits, cash and cash equivalents
USD million
2024
2023
Non-current assets
Restricted bank deposits pledged as security for abandonment obligation
related to Nini/Cecilie
61.5
64.3
Restricted bank deposits pledged as security for cash call obligations towards
TotalEnergies
1)
\u2013
149.6
Total non-current restricted bank deposits
61.5
213.9
Current assets
Unrestricted cash and cash equivalents
250.6
166.7
Restricted bank deposits pledged as security for cash call obligations towards
TotalEnergies
1)
157. 2
\u2013
Restricted bank deposits
2)
0.1
0.1
Total current cash and cash equivalents
407.9
166.9
Total bank deposits
469.4
380.7
1) BlueNord has made a USD 140 million bank deposit into a security account to secure future requests for anticipated payments related to
capital and operating expenditures in accordance with the security agreement with TotalEnergies E&P Denmark A/S as Operator of the
DUC. No further transfer to the security account will be made, except that interest earned will be accrued in the account.
2) Tax Withholding Account.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRestrictedCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-503": { "value": "18 Restricted bank deposits, cash and cash equivalents
USD million
2024
2023
Non-current assets
Restricted bank deposits pledged as security for abandonment obligation
related to Nini/Cecilie
61.5
64.3
Restricted bank deposits pledged as security for cash call obligations towards
TotalEnergies
1)
\u2013
149.6
Total non-current restricted bank deposits
61.5
213.9
Current assets
Unrestricted cash and cash equivalents
250.6
166.7
Restricted bank deposits pledged as security for cash call obligations towards
TotalEnergies
1)
157. 2
\u2013
Restricted bank deposits
2)
0.1
0.1
Total current cash and cash equivalents
407.9
166.9
Total bank deposits
469.4
380.7
1) BlueNord has made a USD 140 million bank deposit into a security account to secure future requests for anticipated payments related to capital and operating expenditures in accordance with the security agreement with TotalEnergies E&P Denmark A/S as Operator of the DUC. No further transfer to the security account will be made, except that interest earned will be accrued in the account. 2) Tax Withholding Account.", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-469": { "value": "
19 Financial instruments
19.1 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 31.12.2024
USD million
Level 1
Level 2
Level 3
Total
Assets
Financial assets at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
14.2
\u2013
14.2
Total assets
\u2013
14.2
\u2013
14.2
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
1
\u2013
\u2013
85.1
85.1
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
87.4
\u2013
87.4
Total liabilities
\u2013
87.4
85.1
172.5
1) For more information see section 18.2, 18.3 and note 2.3
On 31.12.2023
USD million
Level 1
Level 2
Level 3
Tot al
Assets
Financial assets at fair value through profit or loss
\u2013 Derivative instruments interest swap, ineffective part
\u2013
1.2
\u2013
1.2
Financial assets at fair value hedging instruments
\u2013 Derivative instruments interest swap
\u2013
20.4
\u2013
20.4
\u2013 Derivative instruments price hedge
\u2013
64.1
\u2013
64.1
Total assets
\u2013
85.7
\u2013
85.7
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
\u2013
\u2013
53.0
53.0
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
39.2
\u2013
39.2
Total liabilities
\u2013
39.2
53.0
92.2
19.2 Financial instruments by category
On 31.12.24
Assets
Financial at fair value
assets at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Assets
Derivative instruments price hedge
\u2013
\u2013
14.2
14.2
Trade receivables and other current assets
39.0
\u2013
\u2013
39.0
Restricted bank deposits
218.8
\u2013
\u2013
218.8
Cash and cash equivalents
250.6
\u2013
\u2013
250.6
Total
508.4
\u2013
14.2
522.6
Liabilities
Financial at fair value
liabilities at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
87.4
87.4
Embedded derivatives convertible bond BNOR15
1)
\u2013
85.1
\u2013
85.1
Convertible bond loan
233.1
\u2013
\u2013
233.1
Senior unsecured bond loan
303.5
\u2013
\u2013
303.5
Reserve-based lending facility
834.3
\u2013
\u2013
834.3
Trade payables and other current liabilities
99.4
\u2013
\u2013
99.4
Total
1,470.4
85.1
87.4
1,642.9
1) For more information see section 18.1, 18.3 and note 2.3.
On 31.12.23
Financial Assets
assets at at fair value Hedging
amortised through instruments
USD million on 31.12.23 cost profit or loss
at fair value
Total
Assets
Convertible loan CarbonCuts
1.1
\u2013
\u2013
1.1
Loan CarbonCuts
2.6
\u2013
\u2013
2.6
Derivative instruments interest swap
\u2013
\u2013
21.6
21.6
Derivative instruments price hedge
\u2013
\u2013
64.1
64.1
Trade receivables and other current assets
88.7
\u2013
\u2013
88.7
Restricted bank deposits
214.0
\u2013
\u2013
214.0
Cash and cash equivalents
166.7
\u2013
\u2013
166.7
Total
473.1
\u2013
85.7
558.8
Financial Liabilities
liabilities at at fair value Hedging
amortised through instruments
USD million cost profit or loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
39.2
39.2
Embedded derivatives convertible bond BNOR15
\u2013
53.0
\u2013
53.0
Convertible bond loans
201.7
\u2013
\u2013
201.7
Senior unsecured bond loan
169.1
\u2013
\u2013
169.1
Reserve-based lending facility
820.8
\u2013
\u2013
820.8
Trade payables and other current liabilities
125.3
\u2013
\u2013
125.3
Total
1,316.9
53.0
39.2
1,409.1
The tables below show the payment structure for the Company\u2019s financial commitments, based on undiscounted contractual payments:
Less than
31.12.24
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
28.5
28.5
385.5
\u2013
442.5
Reserve-based lending facility
83.8
86.2
1,036.3
\u2013
1,206.3
Trade creditors and other liabilities
99.4
\u2013
\u2013
\u2013
99.4
Derivative financial liabilities:
\u2013
Derivatives
1)
64.3
22.0
1.0
\u2013
87.4
Total as at 31.12.24
276.1
136.7
1,422.9
\u2013
1,835.6
Less than
31.12.23
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
\u2013
\u2013
175.0
\u2013
175.0
Reserve-based lending facility
125.0
275.0
450.0
\u2013
850.0
Trade creditors and other liabilities
125.3
\u2013
\u2013
\u2013
125.3
Derivative financial liabilities:
\u2013
Derivatives
1)
35.9
3.2
\u2013
\u2013
39.2
Total as at 31.12.24
286.2
278.2
625.0
\u2013
1,189.4
1) Any redemption and repurchase of bonds are acted by BlueNord as Issuer. The Bondholders will have the right of a mandatory redemption but only in a case of a Change of Control event (which will be notified by BlueNord). In the table it is assumed that it will be no cash payments on BNOR15 and the related embedded derivative
19.3 Financial instruments \u2014 fair values
Set out below is a comparison of the carrying amounts and fair value of financial instruments on
31 December 2024:
Total amount Carrying Fair
USD million
outstanding
1)
amount value
Financial assets
Derivative instruments price hedge
14.2
14.2
Trade receivables and other current assets
39.0
39.0
Restricted bank deposits
218.8
218.8
Cash and cash equivalents
250.6
250.6
Total
522.6
522.6
Financial liabilities
Derivative instruments price hedge
87.4
87.4
Embedded derivative convertible bond BNOR15
2)
85.1
85.1
Convertible bond loans
247.1
233.1
162.0
Senior unsecured bond loan
300.0
303.5
300.0
Reserve-based lending facility
880.0
834.3
880.0
Trade payables and other current liabilities
99.4
99.4
Total
1,427.1
1,642.9
1,613.9
1) Total amount outstanding on the bonds and under the RBL facility.
2) For more information see section 19.1, 19.2 and note 2.3.
The RBL facility is measured at amortised cost. 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 capital outstanding is USD 880 million on 31 December 2024.
The senior unsecured bond loan is measured at amortised cost; a total of USD 11.5 million in
transaction costs are deducted from the amount initially recognised.
The BNOR15 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, transaction costs are included in the amortised cost.
The embedded derivative is valued on an option valuation basis, the carrying value as on 31 December
2024 was USD 85.1 million. The assumptions in establishing the option value as on 31 December 2024
are shown below.
The following table list the inputs to the model used to calculate the fair value of the embedded derivatives:
BNOR15
2024
Valuation date
(date)
31 Dec 24
Agreement execution date
(date)
30 Dec 22
Par value of bonds
(USD) 247,067,145
Reference share price at time of agreement
(NOK)
413
Share price at 31.12.2024
(NOK)
657
Fair value at grant date
(USD)
38,928,552
Fair value at 31.12.2024
(USD)
85,139,366
PIK interest rate
(%)
8.00%
Expected remaining life
(years)
1.0
Number of options
(#)
4,803,885
Conversion price
(NOK)
537
Fixed FX rate of agreement
(USD:NOK)
10.440
Risk-free rate (based on government bonds)
(%)
3.87%
Expected volatility
(%)
42.62%
Model used
Black \u2013 Scholes \u2013 Merton
19.4 Hedging
The Group actively seeks to reduce the market-related risks it is exposed to including, (i) commodity
prices, (ii) market-linked floating interest rates and (iii) foreign exchange rates.
The Company has a rolling hedge requirement under its newly refinanced RBL facility based on a
minimum level of production corresponding to the RBL\u2019s production forecast. The requirement is for
the following volumes and time periods: (i) Oil: Year 1 at 50 percent and Year 2 at 40 percent; (ii) Gas:
Season 1 at 50 percent, Season 2 at 50 percent, Season 3 at 40 percent and Season 4 at 20 percent
(seasons being the ensuing six-month seasons, with a season being October to March or April to
September). The Company\u2019s hedges are compliant with this requirement. Currently all the Company\u2019s
commodity price hedging arrangements are a mixture of swaps and options.
The Company entered 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 01 November 2021 to 30 June 2024. As a
result, the Company paid interest on its RBL cash drawings equal to 0.4041 percent plus the applicable
margin until the expiry of the hedge contracts. As the hedge terminated in June 2024, there were no
further interest hedge in place as per 31 December 2024.
In 2024 the Company entered foreign exchange hedges to secure fixed USD to DKK exchange
rates at a nominal amount of USD 71.5 million equivalent to DKK 495 million, for selected payments in
relation to taxes in 2024, VAT and cash calls related to the Company\u2019s forecast cash-flows. All foreign
exchange hedges entered into in 2024 have all now matured as at 31 December 2024.
Hedge accounting is applied to all the Company\u2019s hedging arrangements. To the extent more than 100 percent of the market-related risk is hedged, the portion above 100 percent is considered ineffective, and the value adjustment is treated as a financial item in the Income Statement. In 2024, most of the Company\u2019s arrangements in relation to commodity prices were effective, the part that exceeded the physical sale of oil was recognised as a financial cost. Time value related to commodity hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value. During Q2 2024, the Company\u2019s interest rate hedge above the drawn amount of the RBL at the time (USD 880 million drawn against the hedged transaction value at USD 900 million) was considered ineffective and the value adjustment was treated as a financial item in the Income Statement. No part of the foreign exchange hedge was considered ineffective.
Maturity
Less than 1 to 3 3 to 6 6 to 9 9 to 12 More than
As at 31.12.2024 1 month months months months months 12 months
Commodity forward sales
contracts oil:
Notional quantity (in mbbl)
\u2013
929.0
929.0
915.0
915.0
1,500.0
Notional amount (in USD million
per bbl)
\u2013
67.8
67.7
67.5
67.5
110.2
Average hedged sales price
(in USD per bbl)
\u2013
73.0
72.9
73.8
73.8
73.5
Commodity forward sales
contracts gas:
Notional quantity (in mMWh)
\u2013
840.0
1,350.0
1,350.0
1,065.0
2,805.0
Notional amount (in EUR million
per MWh)
\u2013
36.3
49.9
49.9
38.7
96.0
Average hedged sales price
(in EUR per MWh)
\u2013
43.2
36.9
36.9
36.4
34.2
Commodity zero cost collar
contracts oil:
Notional quantity gas (in mbbl)
\u2013
135.0
135.0
60.0
60.0
1,200.0
Average hedged price \u2013 floor
(in USD per bbl)
\u2013
66.1
66.1
67.5
67.5
65.0
Average hedged price \u2013 ceiling
(in USD per bbl)
\u2013
82.7
82.7
77.4
77.4
77.4
Commodity zero cost collar
contracts gas:
Notional quantity gas (in mMWh)
\u2013
285.0
240.0
240.0
300.0
1,260.0
Average hedged price \u2013 floor
(in EUR per MWh)
\u2013
36.3
34.4
34.4
35.0
31.2
Average hedged price \u2013 ceiling
(in EUR per MWh)
\u2013
56.2
49.4
49.4
54.5
45.6
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 01.01.2023
13.9
Realised cash flow hedge on revenue
(19.7)
Realised cash flow hedge on financial items
(29.3)
Related tax \u2013 realised cash flow hedge
19.1
Changes in fair value cash flow hedge revenue
102.5
Changes in fair value cash flow hedge financial items
5.2
Related tax \u2013 changes in fair value cash flow hedge
(66.8)
Balance as of 31.12.2023
24.9
Realised cash flow hedge on revenue
1.6
Realised cash flow hedge on financial items
(20.2)
Related tax \u2013 realised cash flow hedge
3.1
Changes in fair value cash flow hedge revenue
(100.4)
Changes in fair value cash flow hedge financial items
0.6
Related tax \u2013 changes in fair value cash flow hedge
64.1
Balance as of 31.12.2024
(26.3)
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-520": { "value": "19 Financial instruments 19.1 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 31.12.2024
USD million
Level 1
Level 2
Level 3
Total
Assets
Financial assets at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
14.2
\u2013
14.2
Total assets
\u2013
14.2
\u2013
14.2
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
1
\u2013
\u2013
85.1
85.1
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
87.4
\u2013
87.4
Total liabilities
\u2013
87.4
85.1
172.5
1) For more information see section 18.2, 18.3 and note 2.3 On 31.12.2023
USD million
Level 1
Level 2
Level 3
Tot al
Assets
Financial assets at fair value through profit or loss
\u2013 Derivative instruments interest swap, ineffective part
\u2013
1.2
\u2013
1.2
Financial assets at fair value hedging instruments
\u2013 Derivative instruments interest swap
\u2013
20.4
\u2013
20.4
\u2013 Derivative instruments price hedge
\u2013
64.1
\u2013
64.1
Total assets
\u2013
85.7
\u2013
85.7
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
\u2013
\u2013
53.0
53.0
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
39.2
\u2013
39.2
Total liabilities
\u2013
39.2
53.0
92.2
19.2 Financial instruments by category On 31.12.24
Assets
Financial at fair value
assets at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Assets
Derivative instruments price hedge
\u2013
\u2013
14.2
14.2
Trade receivables and other current assets
39.0
\u2013
\u2013
39.0
Restricted bank deposits
218.8
\u2013
\u2013
218.8
Cash and cash equivalents
250.6
\u2013
\u2013
250.6
Total
508.4
\u2013
14.2
522.6
Liabilities
Financial at fair value
liabilities at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
87.4
87.4
Embedded derivatives convertible bond BNOR15
1)
\u2013
85.1
\u2013
85.1
Convertible bond loan
233.1
\u2013
\u2013
233.1
Senior unsecured bond loan
303.5
\u2013
\u2013
303.5
Reserve-based lending facility
834.3
\u2013
\u2013
834.3
Trade payables and other current liabilities
99.4
\u2013
\u2013
99.4
Total
1,470.4
85.1
87.4
1,642.9
1) For more information see section 18.1, 18.3 and note 2.3. On 31.12.23
Financial Assets
assets at at fair value Hedging
amortised through instruments
USD million on 31.12.23 cost profit or loss
at fair value
Total
Assets
Convertible loan CarbonCuts
1.1
\u2013
\u2013
1.1
Loan CarbonCuts
2.6
\u2013
\u2013
2.6
Derivative instruments interest swap
\u2013
\u2013
21.6
21.6
Derivative instruments price hedge
\u2013
\u2013
64.1
64.1
Trade receivables and other current assets
88.7
\u2013
\u2013
88.7
Restricted bank deposits
214.0
\u2013
\u2013
214.0
Cash and cash equivalents
166.7
\u2013
\u2013
166.7
Total
473.1
\u2013
85.7
558.8
Financial Liabilities
liabilities at at fair value Hedging
amortised through instruments
USD million cost profit or loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
39.2
39.2
Embedded derivatives convertible bond BNOR15
\u2013
53.0
\u2013
53.0
Convertible bond loans
201.7
\u2013
\u2013
201.7
Senior unsecured bond loan
169.1
\u2013
\u2013
169.1
Reserve-based lending facility
820.8
\u2013
\u2013
820.8
Trade payables and other current liabilities
125.3
\u2013
\u2013
125.3
Total
1,316.9
53.0
39.2
1,409.1
The tables below show the payment structure for the Company\u2019s financial commitments, based on undiscounted contractual payments:
Less than
31.12.24
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
28.5
28.5
385.5
\u2013
442.5
Reserve-based lending facility
83.8
86.2
1,036.3
\u2013
1,206.3
Trade creditors and other liabilities
99.4
\u2013
\u2013
\u2013
99.4
Derivative financial liabilities:
\u2013
Derivatives
1)
64.3
22.0
1.0
\u2013
87.4
Total as at 31.12.24
276.1
136.7
1,422.9
\u2013
1,835.6
Less than
31.12.23
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
\u2013
\u2013
175.0
\u2013
175.0
Reserve-based lending facility
125.0
275.0
450.0
\u2013
850.0
Trade creditors and other liabilities
125.3
\u2013
\u2013
\u2013
125.3
Derivative financial liabilities:
\u2013
Derivatives
1)
35.9
3.2
\u2013
\u2013
39.2
Total as at 31.12.24
286.2
278.2
625.0
\u2013
1,189.4
1) Any redemption and repurchase of bonds are acted by BlueNord as Issuer. The Bondholders will have the right of a mandatory redemption but only in a case of a Change of Control event (which will be notified by BlueNord). In the table it is assumed that it will be no cash payments on BNOR15 and the related embedded derivative. 19.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments on 31 December 2024:
Total amount Carrying Fair
USD million
outstanding
1)
amount value
Financial assets
Derivative instruments price hedge
14.2
14.2
Trade receivables and other current assets
39.0
39.0
Restricted bank deposits
218.8
218.8
Cash and cash equivalents
250.6
250.6
Total
522.6
522.6
Financial liabilities
Derivative instruments price hedge
87.4
87.4
Embedded derivative convertible bond BNOR15
2)
85.1
85.1
Convertible bond loans
247.1
233.1
162.0
Senior unsecured bond loan
300.0
303.5
300.0
Reserve-based lending facility
880.0
834.3
880.0
Trade payables and other current liabilities
99.4
99.4
Total
1,427.1
1,642.9
1,613.9
1) Total amount outstanding on the bonds and under the RBL facility. 2) For more information see section 19.1, 19.2 and note 2.3. The RBL facility is measured at amortised cost. 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 capital outstanding is USD 880 million on 31 December 2024. The senior unsecured bond loan is measured at amortised cost; a total of USD 11.5 million in transaction costs are deducted from the amount initially recognised. The BNOR15 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, transaction costs are included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as on 31 December 2024 was USD 85.1 million. The assumptions in establishing the option value as on 31 December 2024 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives:
BNOR15
2024
Valuation date
(date)
31 Dec 24
Agreement execution date
(date)
30 Dec 22
Par value of bonds
(USD) 247,067,145
Reference share price at time of agreement
(NOK)
413
Share price at 31.12.2024
(NOK)
657
Fair value at grant date
(USD)
38,928,552
Fair value at 31.12.2024
(USD)
85,139,366
PIK interest rate
(%)
8.00%
Expected remaining life
(years)
1.0
Number of options
(#)
4,803,885
Conversion price
(NOK)
537
Fixed FX rate of agreement
(USD:NOK)
10.440
Risk-free rate (based on government bonds)
(%)
3.87%
Expected volatility
(%)
42.62%
Model used
Black \u2013 Scholes \u2013 Merton
19.4 Hedging The Group actively seeks to reduce the market-related risks it is exposed to including, (i) commodity prices, (ii) market-linked floating interest rates and (iii) foreign exchange rates. The Company has a rolling hedge requirement under its newly refinanced RBL facility based on a minimum level of production corresponding to the RBL\u2019s production forecast. The requirement is for the following volumes and time periods: (i) Oil: Year 1 at 50 percent and Year 2 at 40 percent; (ii) Gas: Season 1 at 50 percent, Season 2 at 50 percent, Season 3 at 40 percent and Season 4 at 20 percent (seasons being the ensuing six-month seasons, with a season being October to March or April to September). The Company\u2019s hedges are compliant with this requirement. Currently all the Company\u2019s commodity price hedging arrangements are a mixture of swaps and options. The Company entered 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 01 November 2021 to 30 June 2024. As a result, the Company paid interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin until the expiry of the hedge contracts. As the hedge terminated in June 2024, there were no further interest hedge in place as per 31 December 2024. In 2024 the Company entered foreign exchange hedges to secure fixed USD to DKK exchange rates at a nominal amount of USD 71.5 million equivalent to DKK 495 million, for selected payments in relation to taxes in 2024, VAT and cash calls related to the Company\u2019s forecast cash-flows. All foreign exchange hedges entered into in 2024 have all now matured as at 31 December 2024.
Hedge accounting is applied to all the Company\u2019s hedging arrangements. To the extent more than 100
percent of the market-related risk is hedged, the portion above 100 percent is considered ineffective,
and the value adjustment is treated as a financial item in the Income Statement. In 2024, most of the
Company\u2019s arrangements in relation to commodity prices were effective, the part that exceeded
the physical sale of oil was recognised as a financial cost. Time value related to commodity hedging
arrangements is considered insignificant and generally the valuation of the instruments do not take
into consideration the time value. During Q2 2024, the Company\u2019s interest rate hedge above the drawn
amount of the RBL at the time (USD 880 million drawn against the hedged transaction value at USD
900 million) was considered ineffective and the value adjustment was treated as a financial item in the
Income Statement. No part of the foreign exchange hedge was considered ineffective.
Maturity
Less than 1 to 3 3 to 6 6 to 9 9 to 12 More than
As at 31.12.2024 1 month months months months months 12 months
Commodity forward sales
contracts oil:
Notional quantity (in mbbl)
\u2013
929.0
929.0
915.0
915.0
1,500.0
Notional amount (in USD million
per bbl)
\u2013
67.8
67.7
67.5
67.5
110.2
Average hedged sales price
(in USD per bbl)
\u2013
73.0
72.9
73.8
73.8
73.5
Commodity forward sales
contracts gas:
Notional quantity (in mMWh)
\u2013
840.0
1,350.0
1,350.0
1,065.0
2,805.0
Notional amount (in EUR million
per MWh)
\u2013
36.3
49.9
49.9
38.7
96.0
Average hedged sales price
(in EUR per MWh)
\u2013
43.2
36.9
36.9
36.4
34.2
Commodity zero cost collar
contracts oil:
Notional quantity gas (in mbbl)
\u2013
135.0
135.0
60.0
60.0
1,200.0
Average hedged price \u2013 floor
(in USD per bbl)
\u2013
66.1
66.1
67.5
67.5
65.0
Average hedged price \u2013 ceiling
(in USD per bbl)
\u2013
82.7
82.7
77.4
77.4
77.4
Commodity zero cost collar
contracts gas:
Notional quantity gas (in mMWh)
\u2013
285.0
240.0
240.0
300.0
1,260.0
Average hedged price \u2013 floor
(in EUR per MWh)
\u2013
36.3
34.4
34.4
35.0
31.2
Average hedged price \u2013 ceiling
(in EUR per MWh)
\u2013
56.2
49.4
49.4
54.5
45.6
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 01.01.2023
13.9
Realised cash flow hedge on revenue
(19.7)
Realised cash flow hedge on financial items
(29.3)
Related tax \u2013 realised cash flow hedge
19.1
Changes in fair value cash flow hedge revenue
102.5
Changes in fair value cash flow hedge financial items
5.2
Related tax \u2013 changes in fair value cash flow hedge
(66.8)
Balance as of 31.12.2023
24.9
Realised cash flow hedge on revenue
1.6
Realised cash flow hedge on financial items
(20.2)
Related tax \u2013 realised cash flow hedge
3.1
Changes in fair value cash flow hedge revenue
(100.4)
Changes in fair value cash flow hedge financial items
0.6
Related tax \u2013 changes in fair value cash flow hedge
64.1
Balance as of 31.12.2024
(26.3)
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialAssetsHeldForTradingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-535": { "value": "19 Financial instruments 19.1 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 31.12.2024
USD million
Level 1
Level 2
Level 3
Total
Assets
Financial assets at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
14.2
\u2013
14.2
Total assets
\u2013
14.2
\u2013
14.2
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
1
\u2013
\u2013
85.1
85.1
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
87.4
\u2013
87.4
Total liabilities
\u2013
87.4
85.1
172.5
1) For more information see section 18.2, 18.3 and note 2.3 On 31.12.2023
USD million
Level 1
Level 2
Level 3
Tot al
Assets
Financial assets at fair value through profit or loss
\u2013 Derivative instruments interest swap, ineffective part
\u2013
1.2
\u2013
1.2
Financial assets at fair value hedging instruments
\u2013 Derivative instruments interest swap
\u2013
20.4
\u2013
20.4
\u2013 Derivative instruments price hedge
\u2013
64.1
\u2013
64.1
Total assets
\u2013
85.7
\u2013
85.7
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
\u2013
\u2013
53.0
53.0
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
39.2
\u2013
39.2
Total liabilities
\u2013
39.2
53.0
92.2
19.2 Financial instruments by category On 31.12.24
Assets
Financial at fair value
assets at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Assets
Derivative instruments price hedge
\u2013
\u2013
14.2
14.2
Trade receivables and other current assets
39.0
\u2013
\u2013
39.0
Restricted bank deposits
218.8
\u2013
\u2013
218.8
Cash and cash equivalents
250.6
\u2013
\u2013
250.6
Total
508.4
\u2013
14.2
522.6
Liabilities
Financial at fair value
liabilities at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
87.4
87.4
Embedded derivatives convertible bond BNOR15
1)
\u2013
85.1
\u2013
85.1
Convertible bond loan
233.1
\u2013
\u2013
233.1
Senior unsecured bond loan
303.5
\u2013
\u2013
303.5
Reserve-based lending facility
834.3
\u2013
\u2013
834.3
Trade payables and other current liabilities
99.4
\u2013
\u2013
99.4
Total
1,470.4
85.1
87.4
1,642.9
1) For more information see section 18.1, 18.3 and note 2.3. On 31.12.23
Financial Assets
assets at at fair value Hedging
amortised through instruments
USD million on 31.12.23 cost profit or loss
at fair value
Total
Assets
Convertible loan CarbonCuts
1.1
\u2013
\u2013
1.1
Loan CarbonCuts
2.6
\u2013
\u2013
2.6
Derivative instruments interest swap
\u2013
\u2013
21.6
21.6
Derivative instruments price hedge
\u2013
\u2013
64.1
64.1
Trade receivables and other current assets
88.7
\u2013
\u2013
88.7
Restricted bank deposits
214.0
\u2013
\u2013
214.0
Cash and cash equivalents
166.7
\u2013
\u2013
166.7
Total
473.1
\u2013
85.7
558.8
Financial Liabilities
liabilities at at fair value Hedging
amortised through instruments
USD million cost profit or loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
39.2
39.2
Embedded derivatives convertible bond BNOR15
\u2013
53.0
\u2013
53.0
Convertible bond loans
201.7
\u2013
\u2013
201.7
Senior unsecured bond loan
169.1
\u2013
\u2013
169.1
Reserve-based lending facility
820.8
\u2013
\u2013
820.8
Trade payables and other current liabilities
125.3
\u2013
\u2013
125.3
Total
1,316.9
53.0
39.2
1,409.1
The tables below show the payment structure for the Company\u2019s financial commitments, based on undiscounted contractual payments:
Less than
31.12.24
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
28.5
28.5
385.5
\u2013
442.5
Reserve-based lending facility
83.8
86.2
1,036.3
\u2013
1,206.3
Trade creditors and other liabilities
99.4
\u2013
\u2013
\u2013
99.4
Derivative financial liabilities:
\u2013
Derivatives
1)
64.3
22.0
1.0
\u2013
87.4
Total as at 31.12.24
276.1
136.7
1,422.9
\u2013
1,835.6
Less than
31.12.23
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
\u2013
\u2013
175.0
\u2013
175.0
Reserve-based lending facility
125.0
275.0
450.0
\u2013
850.0
Trade creditors and other liabilities
125.3
\u2013
\u2013
\u2013
125.3
Derivative financial liabilities:
\u2013
Derivatives
1)
35.9
3.2
\u2013
\u2013
39.2
Total as at 31.12.24
286.2
278.2
625.0
\u2013
1,189.4
1) Any redemption and repurchase of bonds are acted by BlueNord as Issuer. The Bondholders will have the right of a mandatory redemption but only in a case of a Change of Control event (which will be notified by BlueNord). In the table it is assumed that it will be no cash payments on BNOR15 and the related embedded derivative. 19.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments on 31 December 2024:
Total amount Carrying Fair
USD million
outstanding
1)
amount value
Financial assets
Derivative instruments price hedge
14.2
14.2
Trade receivables and other current assets
39.0
39.0
Restricted bank deposits
218.8
218.8
Cash and cash equivalents
250.6
250.6
Total
522.6
522.6
Financial liabilities
Derivative instruments price hedge
87.4
87.4
Embedded derivative convertible bond BNOR15
2)
85.1
85.1
Convertible bond loans
247.1
233.1
162.0
Senior unsecured bond loan
300.0
303.5
300.0
Reserve-based lending facility
880.0
834.3
880.0
Trade payables and other current liabilities
99.4
99.4
Total
1,427.1
1,642.9
1,613.9
1) Total amount outstanding on the bonds and under the RBL facility. 2) For more information see section 19.1, 19.2 and note 2.3. The RBL facility is measured at amortised cost. 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 capital outstanding is USD 880 million on 31 December 2024. The senior unsecured bond loan is measured at amortised cost; a total of USD 11.5 million in transaction costs are deducted from the amount initially recognised. The BNOR15 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, transaction costs are included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as on 31 December 2024 was USD 85.1 million. The assumptions in establishing the option value as on 31 December 2024 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives:
BNOR15
2024
Valuation date
(date)
31 Dec 24
Agreement execution date
(date)
30 Dec 22
Par value of bonds
(USD) 247,067,145
Reference share price at time of agreement
(NOK)
413
Share price at 31.12.2024
(NOK)
657
Fair value at grant date
(USD)
38,928,552
Fair value at 31.12.2024
(USD)
85,139,366
PIK interest rate
(%)
8.00%
Expected remaining life
(years)
1.0
Number of options
(#)
4,803,885
Conversion price
(NOK)
537
Fixed FX rate of agreement
(USD:NOK)
10.440
Risk-free rate (based on government bonds)
(%)
3.87%
Expected volatility
(%)
42.62%
Model used
Black \u2013 Scholes \u2013 Merton
19.4 Hedging The Group actively seeks to reduce the market-related risks it is exposed to including, (i) commodity prices, (ii) market-linked floating interest rates and (iii) foreign exchange rates. The Company has a rolling hedge requirement under its newly refinanced RBL facility based on a minimum level of production corresponding to the RBL\u2019s production forecast. The requirement is for the following volumes and time periods: (i) Oil: Year 1 at 50 percent and Year 2 at 40 percent; (ii) Gas: Season 1 at 50 percent, Season 2 at 50 percent, Season 3 at 40 percent and Season 4 at 20 percent (seasons being the ensuing six-month seasons, with a season being October to March or April to September). The Company\u2019s hedges are compliant with this requirement. Currently all the Company\u2019s commodity price hedging arrangements are a mixture of swaps and options. The Company entered 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 01 November 2021 to 30 June 2024. As a result, the Company paid interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin until the expiry of the hedge contracts. As the hedge terminated in June 2024, there were no further interest hedge in place as per 31 December 2024. In 2024 the Company entered foreign exchange hedges to secure fixed USD to DKK exchange rates at a nominal amount of USD 71.5 million equivalent to DKK 495 million, for selected payments in relation to taxes in 2024, VAT and cash calls related to the Company\u2019s forecast cash-flows. All foreign exchange hedges entered into in 2024 have all now matured as at 31 December 2024. Hedge accounting is applied to all the Company\u2019s hedging arrangements. To the extent more than 100 percent of the market-related risk is hedged, the portion above 100 percent is considered ineffective, and the value adjustment is treated as a financial item in the Income Statement. In 2024, most of the Company\u2019s arrangements in relation to commodity prices were effective, the part that exceeded the physical sale of oil was recognised as a financial cost. Time value related to commodity hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value. During Q2 2024, the Company\u2019s interest rate hedge above the drawn amount of the RBL at the time (USD 880 million drawn against the hedged transaction value at USD 900 million) was considered ineffective and the value adjustment was treated as a financial item in the Income Statement. No part of the foreign exchange hedge was considered ineffective.
Maturity
Less than 1 to 3 3 to 6 6 to 9 9 to 12 More than
As at 31.12.2024 1 month months months months months 12 months
Commodity forward sales
contracts oil:
Notional quantity (in mbbl)
\u2013
929.0
929.0
915.0
915.0
1,500.0
Notional amount (in USD million
per bbl)
\u2013
67.8
67.7
67.5
67.5
110.2
Average hedged sales price
(in USD per bbl)
\u2013
73.0
72.9
73.8
73.8
73.5
Commodity forward sales
contracts gas:
Notional quantity (in mMWh)
\u2013
840.0
1,350.0
1,350.0
1,065.0
2,805.0
Notional amount (in EUR million
per MWh)
\u2013
36.3
49.9
49.9
38.7
96.0
Average hedged sales price
(in EUR per MWh)
\u2013
43.2
36.9
36.9
36.4
34.2
Commodity zero cost collar
contracts oil:
Notional quantity gas (in mbbl)
\u2013
135.0
135.0
60.0
60.0
1,200.0
Average hedged price \u2013 floor
(in USD per bbl)
\u2013
66.1
66.1
67.5
67.5
65.0
Average hedged price \u2013 ceiling
(in USD per bbl)
\u2013
82.7
82.7
77.4
77.4
77.4
Commodity zero cost collar
contracts gas:
Notional quantity gas (in mMWh)
\u2013
285.0
240.0
240.0
300.0
1,260.0
Average hedged price \u2013 floor
(in EUR per MWh)
\u2013
36.3
34.4
34.4
35.0
31.2
Average hedged price \u2013 ceiling
(in EUR per MWh)
\u2013
56.2
49.4
49.4
54.5
45.6
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 01.01.2023
13.9
Realised cash flow hedge on revenue
(19.7)
Realised cash flow hedge on financial items
(29.3)
Related tax \u2013 realised cash flow hedge
19.1
Changes in fair value cash flow hedge revenue
102.5
Changes in fair value cash flow hedge financial items
5.2
Related tax \u2013 changes in fair value cash flow hedge
(66.8)
Balance as of 31.12.2023
24.9
Realised cash flow hedge on revenue
1.6
Realised cash flow hedge on financial items
(20.2)
Related tax \u2013 realised cash flow hedge
3.1
Changes in fair value cash flow hedge revenue
(100.4)
Changes in fair value cash flow hedge financial items
0.6
Related tax \u2013 changes in fair value cash flow hedge
64.1
Balance as of 31.12.2024
(26.3)
", "dimensions": { "concept": "ifrs-full:DisclosureOfDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-528": { "value": "19 Financial instruments 19.1 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 31.12.2024
USD million
Level 1
Level 2
Level 3
Total
Assets
Financial assets at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
14.2
\u2013
14.2
Total assets
\u2013
14.2
\u2013
14.2
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
1
\u2013
\u2013
85.1
85.1
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
87.4
\u2013
87.4
Total liabilities
\u2013
87.4
85.1
172.5
1) For more information see section 18.2, 18.3 and note 2.3 On 31.12.2023
USD million
Level 1
Level 2
Level 3
Tot al
Assets
Financial assets at fair value through profit or loss
\u2013 Derivative instruments interest swap, ineffective part
\u2013
1.2
\u2013
1.2
Financial assets at fair value hedging instruments
\u2013 Derivative instruments interest swap
\u2013
20.4
\u2013
20.4
\u2013 Derivative instruments price hedge
\u2013
64.1
\u2013
64.1
Total assets
\u2013
85.7
\u2013
85.7
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
\u2013
\u2013
53.0
53.0
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
39.2
\u2013
39.2
Total liabilities
\u2013
39.2
53.0
92.2
19.2 Financial instruments by category On 31.12.24
Assets
Financial at fair value
assets at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Assets
Derivative instruments price hedge
\u2013
\u2013
14.2
14.2
Trade receivables and other current assets
39.0
\u2013
\u2013
39.0
Restricted bank deposits
218.8
\u2013
\u2013
218.8
Cash and cash equivalents
250.6
\u2013
\u2013
250.6
Total
508.4
\u2013
14.2
522.6
Liabilities
Financial at fair value
liabilities at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
87.4
87.4
Embedded derivatives convertible bond BNOR15
1)
\u2013
85.1
\u2013
85.1
Convertible bond loan
233.1
\u2013
\u2013
233.1
Senior unsecured bond loan
303.5
\u2013
\u2013
303.5
Reserve-based lending facility
834.3
\u2013
\u2013
834.3
Trade payables and other current liabilities
99.4
\u2013
\u2013
99.4
Total
1,470.4
85.1
87.4
1,642.9
1) For more information see section 18.1, 18.3 and note 2.3. On 31.12.23
Financial Assets
assets at at fair value Hedging
amortised through instruments
USD million on 31.12.23 cost profit or loss
at fair value
Total
Assets
Convertible loan CarbonCuts
1.1
\u2013
\u2013
1.1
Loan CarbonCuts
2.6
\u2013
\u2013
2.6
Derivative instruments interest swap
\u2013
\u2013
21.6
21.6
Derivative instruments price hedge
\u2013
\u2013
64.1
64.1
Trade receivables and other current assets
88.7
\u2013
\u2013
88.7
Restricted bank deposits
214.0
\u2013
\u2013
214.0
Cash and cash equivalents
166.7
\u2013
\u2013
166.7
Total
473.1
\u2013
85.7
558.8
Financial Liabilities
liabilities at at fair value Hedging
amortised through instruments
USD million cost profit or loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
39.2
39.2
Embedded derivatives convertible bond BNOR15
\u2013
53.0
\u2013
53.0
Convertible bond loans
201.7
\u2013
\u2013
201.7
Senior unsecured bond loan
169.1
\u2013
\u2013
169.1
Reserve-based lending facility
820.8
\u2013
\u2013
820.8
Trade payables and other current liabilities
125.3
\u2013
\u2013
125.3
Total
1,316.9
53.0
39.2
1,409.1
The tables below show the payment structure for the Company\u2019s financial commitments, based on undiscounted contractual payments:
Less than
31.12.24
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
28.5
28.5
385.5
\u2013
442.5
Reserve-based lending facility
83.8
86.2
1,036.3
\u2013
1,206.3
Trade creditors and other liabilities
99.4
\u2013
\u2013
\u2013
99.4
Derivative financial liabilities:
\u2013
Derivatives
1)
64.3
22.0
1.0
\u2013
87.4
Total as at 31.12.24
276.1
136.7
1,422.9
\u2013
1,835.6
Less than
31.12.23
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
\u2013
\u2013
175.0
\u2013
175.0
Reserve-based lending facility
125.0
275.0
450.0
\u2013
850.0
Trade creditors and other liabilities
125.3
\u2013
\u2013
\u2013
125.3
Derivative financial liabilities:
\u2013
Derivatives
1)
35.9
3.2
\u2013
\u2013
39.2
Total as at 31.12.24
286.2
278.2
625.0
\u2013
1,189.4
1) Any redemption and repurchase of bonds are acted by BlueNord as Issuer. The Bondholders will have the right of a mandatory redemption but only in a case of a Change of Control event (which will be notified by BlueNord). In the table it is assumed that it will be no cash payments on BNOR15 and the related embedded derivative. 19.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments on 31 December 2024:
Total amount Carrying Fair
USD million
outstanding
1)
amount value
Financial assets
Derivative instruments price hedge
14.2
14.2
Trade receivables and other current assets
39.0
39.0
Restricted bank deposits
218.8
218.8
Cash and cash equivalents
250.6
250.6
Total
522.6
522.6
Financial liabilities
Derivative instruments price hedge
87.4
87.4
Embedded derivative convertible bond BNOR15
2)
85.1
85.1
Convertible bond loans
247.1
233.1
162.0
Senior unsecured bond loan
300.0
303.5
300.0
Reserve-based lending facility
880.0
834.3
880.0
Trade payables and other current liabilities
99.4
99.4
Total
1,427.1
1,642.9
1,613.9
1) Total amount outstanding on the bonds and under the RBL facility. 2) For more information see section 19.1, 19.2 and note 2.3. The RBL facility is measured at amortised cost. 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 capital outstanding is USD 880 million on 31 December 2024. The senior unsecured bond loan is measured at amortised cost; a total of USD 11.5 million in transaction costs are deducted from the amount initially recognised. The BNOR15 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, transaction costs are included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as on 31 December 2024 was USD 85.1 million. The assumptions in establishing the option value as on 31 December 2024 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives:
BNOR15
2024
Valuation date
(date)
31 Dec 24
Agreement execution date
(date)
30 Dec 22
Par value of bonds
(USD) 247,067,145
Reference share price at time of agreement
(NOK)
413
Share price at 31.12.2024
(NOK)
657
Fair value at grant date
(USD)
38,928,552
Fair value at 31.12.2024
(USD)
85,139,366
PIK interest rate
(%)
8.00%
Expected remaining life
(years)
1.0
Number of options
(#)
4,803,885
Conversion price
(NOK)
537
Fixed FX rate of agreement
(USD:NOK)
10.440
Risk-free rate (based on government bonds)
(%)
3.87%
Expected volatility
(%)
42.62%
Model used
Black \u2013 Scholes \u2013 Merton
19.4 Hedging The Group actively seeks to reduce the market-related risks it is exposed to including, (i) commodity prices, (ii) market-linked floating interest rates and (iii) foreign exchange rates. The Company has a rolling hedge requirement under its newly refinanced RBL facility based on a minimum level of production corresponding to the RBL\u2019s production forecast. The requirement is for the following volumes and time periods: (i) Oil: Year 1 at 50 percent and Year 2 at 40 percent; (ii) Gas: Season 1 at 50 percent, Season 2 at 50 percent, Season 3 at 40 percent and Season 4 at 20 percent (seasons being the ensuing six-month seasons, with a season being October to March or April to September). The Company\u2019s hedges are compliant with this requirement. Currently all the Company\u2019s commodity price hedging arrangements are a mixture of swaps and options. The Company entered 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 01 November 2021 to 30 June 2024. As a result, the Company paid interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin until the expiry of the hedge contracts. As the hedge terminated in June 2024, there were no further interest hedge in place as per 31 December 2024. In 2024 the Company entered foreign exchange hedges to secure fixed USD to DKK exchange rates at a nominal amount of USD 71.5 million equivalent to DKK 495 million, for selected payments in relation to taxes in 2024, VAT and cash calls related to the Company\u2019s forecast cash-flows. All foreign exchange hedges entered into in 2024 have all now matured as at 31 December 2024. Hedge accounting is applied to all the Company\u2019s hedging arrangements. To the extent more than 100 percent of the market-related risk is hedged, the portion above 100 percent is considered ineffective, and the value adjustment is treated as a financial item in the Income Statement. In 2024, most of the Company\u2019s arrangements in relation to commodity prices were effective, the part that exceeded the physical sale of oil was recognised as a financial cost. Time value related to commodity hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value. During Q2 2024, the Company\u2019s interest rate hedge above the drawn amount of the RBL at the time (USD 880 million drawn against the hedged transaction value at USD 900 million) was considered ineffective and the value adjustment was treated as a financial item in the Income Statement. No part of the foreign exchange hedge was considered ineffective.
Maturity
Less than 1 to 3 3 to 6 6 to 9 9 to 12 More than
As at 31.12.2024 1 month months months months months 12 months
Commodity forward sales
contracts oil:
Notional quantity (in mbbl)
\u2013
929.0
929.0
915.0
915.0
1,500.0
Notional amount (in USD million
per bbl)
\u2013
67.8
67.7
67.5
67.5
110.2
Average hedged sales price
(in USD per bbl)
\u2013
73.0
72.9
73.8
73.8
73.5
Commodity forward sales
contracts gas:
Notional quantity (in mMWh)
\u2013
840.0
1,350.0
1,350.0
1,065.0
2,805.0
Notional amount (in EUR million
per MWh)
\u2013
36.3
49.9
49.9
38.7
96.0
Average hedged sales price
(in EUR per MWh)
\u2013
43.2
36.9
36.9
36.4
34.2
Commodity zero cost collar
contracts oil:
Notional quantity gas (in mbbl)
\u2013
135.0
135.0
60.0
60.0
1,200.0
Average hedged price \u2013 floor
(in USD per bbl)
\u2013
66.1
66.1
67.5
67.5
65.0
Average hedged price \u2013 ceiling
(in USD per bbl)
\u2013
82.7
82.7
77.4
77.4
77.4
Commodity zero cost collar
contracts gas:
Notional quantity gas (in mMWh)
\u2013
285.0
240.0
240.0
300.0
1,260.0
Average hedged price \u2013 floor
(in EUR per MWh)
\u2013
36.3
34.4
34.4
35.0
31.2
Average hedged price \u2013 ceiling
(in EUR per MWh)
\u2013
56.2
49.4
49.4
54.5
45.6
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 01.01.2023
13.9
Realised cash flow hedge on revenue
(19.7)
Realised cash flow hedge on financial items
(29.3)
Related tax \u2013 realised cash flow hedge
19.1
Changes in fair value cash flow hedge revenue
102.5
Changes in fair value cash flow hedge financial items
5.2
Related tax \u2013 changes in fair value cash flow hedge
(66.8)
Balance as of 31.12.2023
24.9
Realised cash flow hedge on revenue
1.6
Realised cash flow hedge on financial items
(20.2)
Related tax \u2013 realised cash flow hedge
3.1
Changes in fair value cash flow hedge revenue
(100.4)
Changes in fair value cash flow hedge financial items
0.6
Related tax \u2013 changes in fair value cash flow hedge
64.1
Balance as of 31.12.2024
(26.3)
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-534": { "value": "19.1 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 31.12.2024
USD million
Level 1
Level 2
Level 3
Total
Assets
Financial assets at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
14.2
\u2013
14.2
Total assets
\u2013
14.2
\u2013
14.2
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
1
\u2013
\u2013
85.1
85.1
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
87.4
\u2013
87.4
Total liabilities
\u2013
87.4
85.1
172.5
1) For more information see section 18.2, 18.3 and note 2.3 On 31.12.2023
USD million
Level 1
Level 2
Level 3
Tot al
Assets
Financial assets at fair value through profit or loss
\u2013 Derivative instruments interest swap, ineffective part
\u2013
1.2
\u2013
1.2
Financial assets at fair value hedging instruments
\u2013 Derivative instruments interest swap
\u2013
20.4
\u2013
20.4
\u2013 Derivative instruments price hedge
\u2013
64.1
\u2013
64.1
Total assets
\u2013
85.7
\u2013
85.7
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
\u2013
\u2013
53.0
53.0
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
39.2
\u2013
39.2
Total liabilities
\u2013
39.2
53.0
92.2
19.2 Financial instruments by category On 31.12.24
Assets
Financial at fair value
assets at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Assets
Derivative instruments price hedge
\u2013
\u2013
14.2
14.2
Trade receivables and other current assets
39.0
\u2013
\u2013
39.0
Restricted bank deposits
218.8
\u2013
\u2013
218.8
Cash and cash equivalents
250.6
\u2013
\u2013
250.6
Total
508.4
\u2013
14.2
522.6
Liabilities
Financial at fair value
liabilities at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
87.4
87.4
Embedded derivatives convertible bond BNOR15
1)
\u2013
85.1
\u2013
85.1
Convertible bond loan
233.1
\u2013
\u2013
233.1
Senior unsecured bond loan
303.5
\u2013
\u2013
303.5
Reserve-based lending facility
834.3
\u2013
\u2013
834.3
Trade payables and other current liabilities
99.4
\u2013
\u2013
99.4
Total
1,470.4
85.1
87.4
1,642.9
1) For more information see section 18.1, 18.3 and note 2.3. On 31.12.23
Financial Assets
assets at at fair value Hedging
amortised through instruments
USD million on 31.12.23 cost profit or loss
at fair value
Total
Assets
Convertible loan CarbonCuts
1.1
\u2013
\u2013
1.1
Loan CarbonCuts
2.6
\u2013
\u2013
2.6
Derivative instruments interest swap
\u2013
\u2013
21.6
21.6
Derivative instruments price hedge
\u2013
\u2013
64.1
64.1
Trade receivables and other current assets
88.7
\u2013
\u2013
88.7
Restricted bank deposits
214.0
\u2013
\u2013
214.0
Cash and cash equivalents
166.7
\u2013
\u2013
166.7
Total
473.1
\u2013
85.7
558.8
Financial Liabilities
liabilities at at fair value Hedging
amortised through instruments
USD million cost profit or loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
39.2
39.2
Embedded derivatives convertible bond BNOR15
\u2013
53.0
\u2013
53.0
Convertible bond loans
201.7
\u2013
\u2013
201.7
Senior unsecured bond loan
169.1
\u2013
\u2013
169.1
Reserve-based lending facility
820.8
\u2013
\u2013
820.8
Trade payables and other current liabilities
125.3
\u2013
\u2013
125.3
Total
1,316.9
53.0
39.2
1,409.1
The tables below show the payment structure for the Company\u2019s financial commitments, based on undiscounted contractual payments:
Less than
31.12.24
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
28.5
28.5
385.5
\u2013
442.5
Reserve-based lending facility
83.8
86.2
1,036.3
\u2013
1,206.3
Trade creditors and other liabilities
99.4
\u2013
\u2013
\u2013
99.4
Derivative financial liabilities:
\u2013
Derivatives
1)
64.3
22.0
1.0
\u2013
87.4
Total as at 31.12.24
276.1
136.7
1,422.9
\u2013
1,835.6
Less than
31.12.23
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
\u2013
\u2013
175.0
\u2013
175.0
Reserve-based lending facility
125.0
275.0
450.0
\u2013
850.0
Trade creditors and other liabilities
125.3
\u2013
\u2013
\u2013
125.3
Derivative financial liabilities:
\u2013
Derivatives
1)
35.9
3.2
\u2013
\u2013
39.2
Total as at 31.12.24
286.2
278.2
625.0
\u2013
1,189.4
1) Any redemption and repurchase of bonds are acted by BlueNord as Issuer. The Bondholders will have the right of a mandatory redemption but only in a case of a Change of Control event (which will be notified by BlueNord). In the table it is assumed that it will be no cash payments on BNOR15 and the related embedded derivative. 19.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments on 31 December 2024:
Total amount Carrying Fair
USD million
outstanding
1)
amount value
Financial assets
Derivative instruments price hedge
14.2
14.2
Trade receivables and other current assets
39.0
39.0
Restricted bank deposits
218.8
218.8
Cash and cash equivalents
250.6
250.6
Total
522.6
522.6
Financial liabilities
Derivative instruments price hedge
87.4
87.4
Embedded derivative convertible bond BNOR15
2)
85.1
85.1
Convertible bond loans
247.1
233.1
162.0
Senior unsecured bond loan
300.0
303.5
300.0
Reserve-based lending facility
880.0
834.3
880.0
Trade payables and other current liabilities
99.4
99.4
Total
1,427.1
1,642.9
1,613.9
1) Total amount outstanding on the bonds and under the RBL facility. 2) For more information see section 19.1, 19.2 and note 2.3. The RBL facility is measured at amortised cost. 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 capital outstanding is USD 880 million on 31 December 2024. The senior unsecured bond loan is measured at amortised cost; a total of USD 11.5 million in transaction costs are deducted from the amount initially recognised. The BNOR15 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, transaction costs are included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as on 31 December 2024 was USD 85.1 million. The assumptions in establishing the option value as on 31 December 2024 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives:
BNOR15
2024
Valuation date
(date)
31 Dec 24
Agreement execution date
(date)
30 Dec 22
Par value of bonds
(USD) 247,067,145
Reference share price at time of agreement
(NOK)
413
Share price at 31.12.2024
(NOK)
657
Fair value at grant date
(USD)
38,928,552
Fair value at 31.12.2024
(USD)
85,139,366
PIK interest rate
(%)
8.00%
Expected remaining life
(years)
1.0
Number of options
(#)
4,803,885
Conversion price
(NOK)
537
Fixed FX rate of agreement
(USD:NOK)
10.440
Risk-free rate (based on government bonds)
(%)
3.87%
Expected volatility
(%)
42.62%
Model used
Black \u2013 Scholes \u2013 Merton
19.4 Hedging The Group actively seeks to reduce the market-related risks it is exposed to including, (i) commodity prices, (ii) market-linked floating interest rates and (iii) foreign exchange rates. The Company has a rolling hedge requirement under its newly refinanced RBL facility based on a minimum level of production corresponding to the RBL\u2019s production forecast. The requirement is for the following volumes and time periods: (i) Oil: Year 1 at 50 percent and Year 2 at 40 percent; (ii) Gas: Season 1 at 50 percent, Season 2 at 50 percent, Season 3 at 40 percent and Season 4 at 20 percent (seasons being the ensuing six-month seasons, with a season being October to March or April to September). The Company\u2019s hedges are compliant with this requirement. Currently all the Company\u2019s commodity price hedging arrangements are a mixture of swaps and options. The Company entered 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 01 November 2021 to 30 June 2024. As a result, the Company paid interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin until the expiry of the hedge contracts. As the hedge terminated in June 2024, there were no further interest hedge in place as per 31 December 2024. In 2024 the Company entered foreign exchange hedges to secure fixed USD to DKK exchange rates at a nominal amount of USD 71.5 million equivalent to DKK 495 million, for selected payments in relation to taxes in 2024, VAT and cash calls related to the Company\u2019s forecast cash-flows. All foreign exchange hedges entered into in 2024 have all now matured as at 31 December 2024. Hedge accounting is applied to all the Company\u2019s hedging arrangements. To the extent more than 100 percent of the market-related risk is hedged, the portion above 100 percent is considered ineffective, and the value adjustment is treated as a financial item in the Income Statement. In 2024, most of the Company\u2019s arrangements in relation to commodity prices were effective, the part that exceeded the physical sale of oil was recognised as a financial cost. Time value related to commodity hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value. During Q2 2024, the Company\u2019s interest rate hedge above the drawn amount of the RBL at the time (USD 880 million drawn against the hedged transaction value at USD 900 million) was considered ineffective and the value adjustment was treated as a financial item in the Income Statement. No part of the foreign exchange hedge was considered ineffective.
Maturity
Less than 1 to 3 3 to 6 6 to 9 9 to 12 More than
As at 31.12.2024 1 month months months months months 12 months
Commodity forward sales
contracts oil:
Notional quantity (in mbbl)
\u2013
929.0
929.0
915.0
915.0
1,500.0
Notional amount (in USD million
per bbl)
\u2013
67.8
67.7
67.5
67.5
110.2
Average hedged sales price
(in USD per bbl)
\u2013
73.0
72.9
73.8
73.8
73.5
Commodity forward sales
contracts gas:
Notional quantity (in mMWh)
\u2013
840.0
1,350.0
1,350.0
1,065.0
2,805.0
Notional amount (in EUR million
per MWh)
\u2013
36.3
49.9
49.9
38.7
96.0
Average hedged sales price
(in EUR per MWh)
\u2013
43.2
36.9
36.9
36.4
34.2
Commodity zero cost collar
contracts oil:
Notional quantity gas (in mbbl)
\u2013
135.0
135.0
60.0
60.0
1,200.0
Average hedged price \u2013 floor
(in USD per bbl)
\u2013
66.1
66.1
67.5
67.5
65.0
Average hedged price \u2013 ceiling
(in USD per bbl)
\u2013
82.7
82.7
77.4
77.4
77.4
Commodity zero cost collar
contracts gas:
Notional quantity gas (in mMWh)
\u2013
285.0
240.0
240.0
300.0
1,260.0
Average hedged price \u2013 floor
(in EUR per MWh)
\u2013
36.3
34.4
34.4
35.0
31.2
Average hedged price \u2013 ceiling
(in EUR per MWh)
\u2013
56.2
49.4
49.4
54.5
45.6
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 01.01.2023
13.9
Realised cash flow hedge on revenue
(19.7)
Realised cash flow hedge on financial items
(29.3)
Related tax \u2013 realised cash flow hedge
19.1
Changes in fair value cash flow hedge revenue
102.5
Changes in fair value cash flow hedge financial items
5.2
Related tax \u2013 changes in fair value cash flow hedge
(66.8)
Balance as of 31.12.2023
24.9
Realised cash flow hedge on revenue
1.6
Realised cash flow hedge on financial items
(20.2)
Related tax \u2013 realised cash flow hedge
3.1
Changes in fair value cash flow hedge revenue
(100.4)
Changes in fair value cash flow hedge financial items
0.6
Related tax \u2013 changes in fair value cash flow hedge
64.1
Balance as of 31.12.2024
(26.3)
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsHeldForTradingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-532": { "value": "19.1 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 31.12.2024
USD million
Level 1
Level 2
Level 3
Total
Assets
Financial assets at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
14.2
\u2013
14.2
Total assets
\u2013
14.2
\u2013
14.2
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
1
\u2013
\u2013
85.1
85.1
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
87.4
\u2013
87.4
Total liabilities
\u2013
87.4
85.1
172.5
1) For more information see section 18.2, 18.3 and note 2.3 On 31.12.2023
USD million
Level 1
Level 2
Level 3
Tot al
Assets
Financial assets at fair value through profit or loss
\u2013 Derivative instruments interest swap, ineffective part
\u2013
1.2
\u2013
1.2
Financial assets at fair value hedging instruments
\u2013 Derivative instruments interest swap
\u2013
20.4
\u2013
20.4
\u2013 Derivative instruments price hedge
\u2013
64.1
\u2013
64.1
Total assets
\u2013
85.7
\u2013
85.7
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
\u2013
\u2013
53.0
53.0
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
39.2
\u2013
39.2
Total liabilities
\u2013
39.2
53.0
92.2
19.2 Financial instruments by category On 31.12.24
Assets
Financial at fair value
assets at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Assets
Derivative instruments price hedge
\u2013
\u2013
14.2
14.2
Trade receivables and other current assets
39.0
\u2013
\u2013
39.0
Restricted bank deposits
218.8
\u2013
\u2013
218.8
Cash and cash equivalents
250.6
\u2013
\u2013
250.6
Total
508.4
\u2013
14.2
522.6
Liabilities
Financial at fair value
liabilities at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
87.4
87.4
Embedded derivatives convertible bond BNOR15
1)
\u2013
85.1
\u2013
85.1
Convertible bond loan
233.1
\u2013
\u2013
233.1
Senior unsecured bond loan
303.5
\u2013
\u2013
303.5
Reserve-based lending facility
834.3
\u2013
\u2013
834.3
Trade payables and other current liabilities
99.4
\u2013
\u2013
99.4
Total
1,470.4
85.1
87.4
1,642.9
1) For more information see section 18.1, 18.3 and note 2.3. On 31.12.23
Financial Assets
assets at at fair value Hedging
amortised through instruments
USD million on 31.12.23 cost profit or loss
at fair value
Total
Assets
Convertible loan CarbonCuts
1.1
\u2013
\u2013
1.1
Loan CarbonCuts
2.6
\u2013
\u2013
2.6
Derivative instruments interest swap
\u2013
\u2013
21.6
21.6
Derivative instruments price hedge
\u2013
\u2013
64.1
64.1
Trade receivables and other current assets
88.7
\u2013
\u2013
88.7
Restricted bank deposits
214.0
\u2013
\u2013
214.0
Cash and cash equivalents
166.7
\u2013
\u2013
166.7
Total
473.1
\u2013
85.7
558.8
Financial Liabilities
liabilities at at fair value Hedging
amortised through instruments
USD million cost profit or loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
39.2
39.2
Embedded derivatives convertible bond BNOR15
\u2013
53.0
\u2013
53.0
Convertible bond loans
201.7
\u2013
\u2013
201.7
Senior unsecured bond loan
169.1
\u2013
\u2013
169.1
Reserve-based lending facility
820.8
\u2013
\u2013
820.8
Trade payables and other current liabilities
125.3
\u2013
\u2013
125.3
Total
1,316.9
53.0
39.2
1,409.1
The tables below show the payment structure for the Company\u2019s financial commitments, based on undiscounted contractual payments:
Less than
31.12.24
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
28.5
28.5
385.5
\u2013
442.5
Reserve-based lending facility
83.8
86.2
1,036.3
\u2013
1,206.3
Trade creditors and other liabilities
99.4
\u2013
\u2013
\u2013
99.4
Derivative financial liabilities:
\u2013
Derivatives
1)
64.3
22.0
1.0
\u2013
87.4
Total as at 31.12.24
276.1
136.7
1,422.9
\u2013
1,835.6
Less than
31.12.23
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
\u2013
\u2013
175.0
\u2013
175.0
Reserve-based lending facility
125.0
275.0
450.0
\u2013
850.0
Trade creditors and other liabilities
125.3
\u2013
\u2013
\u2013
125.3
Derivative financial liabilities:
\u2013
Derivatives
1)
35.9
3.2
\u2013
\u2013
39.2
Total as at 31.12.24
286.2
278.2
625.0
\u2013
1,189.4
1) Any redemption and repurchase of bonds are acted by BlueNord as Issuer. The Bondholders will have the right of a mandatory redemption but only in a case of a Change of Control event (which will be notified by BlueNord). In the table it is assumed that it will be no cash payments on BNOR15 and the related embedded derivative. 19.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments on 31 December 2024:
Total amount Carrying Fair
USD million
outstanding
1)
amount value
Financial assets
Derivative instruments price hedge
14.2
14.2
Trade receivables and other current assets
39.0
39.0
Restricted bank deposits
218.8
218.8
Cash and cash equivalents
250.6
250.6
Total
522.6
522.6
Financial liabilities
Derivative instruments price hedge
87.4
87.4
Embedded derivative convertible bond BNOR15
2)
85.1
85.1
Convertible bond loans
247.1
233.1
162.0
Senior unsecured bond loan
300.0
303.5
300.0
Reserve-based lending facility
880.0
834.3
880.0
Trade payables and other current liabilities
99.4
99.4
Total
1,427.1
1,642.9
1,613.9
1) Total amount outstanding on the bonds and under the RBL facility. 2) For more information see section 19.1, 19.2 and note 2.3. The RBL facility is measured at amortised cost. 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 capital outstanding is USD 880 million on 31 December 2024. The senior unsecured bond loan is measured at amortised cost; a total of USD 11.5 million in transaction costs are deducted from the amount initially recognised. The BNOR15 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, transaction costs are included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as on 31 December 2024 was USD 85.1 million. The assumptions in establishing the option value as on 31 December 2024 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives:
BNOR15
2024
Valuation date
(date)
31 Dec 24
Agreement execution date
(date)
30 Dec 22
Par value of bonds
(USD) 247,067,145
Reference share price at time of agreement
(NOK)
413
Share price at 31.12.2024
(NOK)
657
Fair value at grant date
(USD)
38,928,552
Fair value at 31.12.2024
(USD)
85,139,366
PIK interest rate
(%)
8.00%
Expected remaining life
(years)
1.0
Number of options
(#)
4,803,885
Conversion price
(NOK)
537
Fixed FX rate of agreement
(USD:NOK)
10.440
Risk-free rate (based on government bonds)
(%)
3.87%
Expected volatility
(%)
42.62%
Model used
Black \u2013 Scholes \u2013 Merton
19.4 Hedging The Group actively seeks to reduce the market-related risks it is exposed to including, (i) commodity prices, (ii) market-linked floating interest rates and (iii) foreign exchange rates. The Company has a rolling hedge requirement under its newly refinanced RBL facility based on a minimum level of production corresponding to the RBL\u2019s production forecast. The requirement is for the following volumes and time periods: (i) Oil: Year 1 at 50 percent and Year 2 at 40 percent; (ii) Gas: Season 1 at 50 percent, Season 2 at 50 percent, Season 3 at 40 percent and Season 4 at 20 percent (seasons being the ensuing six-month seasons, with a season being October to March or April to September). The Company\u2019s hedges are compliant with this requirement. Currently all the Company\u2019s commodity price hedging arrangements are a mixture of swaps and options. The Company entered 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 01 November 2021 to 30 June 2024. As a result, the Company paid interest on its RBL cash drawings equal to 0.4041 percent plus the applicable margin until the expiry of the hedge contracts. As the hedge terminated in June 2024, there were no further interest hedge in place as per 31 December 2024. In 2024 the Company entered foreign exchange hedges to secure fixed USD to DKK exchange rates at a nominal amount of USD 71.5 million equivalent to DKK 495 million, for selected payments in relation to taxes in 2024, VAT and cash calls related to the Company\u2019s forecast cash-flows. All foreign exchange hedges entered into in 2024 have all now matured as at 31 December 2024. Hedge accounting is applied to all the Company\u2019s hedging arrangements. To the extent more than 100 percent of the market-related risk is hedged, the portion above 100 percent is considered ineffective, and the value adjustment is treated as a financial item in the Income Statement. In 2024, most of the Company\u2019s arrangements in relation to commodity prices were effective, the part that exceeded the physical sale of oil was recognised as a financial cost. Time value related to commodity hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value. During Q2 2024, the Company\u2019s interest rate hedge above the drawn amount of the RBL at the time (USD 880 million drawn against the hedged transaction value at USD 900 million) was considered ineffective and the value adjustment was treated as a financial item in the Income Statement. No part of the foreign exchange hedge was considered ineffective.
Maturity
Less than 1 to 3 3 to 6 6 to 9 9 to 12 More than
As at 31.12.2024 1 month months months months months 12 months
Commodity forward sales
contracts oil:
Notional quantity (in mbbl)
\u2013
929.0
929.0
915.0
915.0
1,500.0
Notional amount (in USD million
per bbl)
\u2013
67.8
67.7
67.5
67.5
110.2
Average hedged sales price
(in USD per bbl)
\u2013
73.0
72.9
73.8
73.8
73.5
Commodity forward sales
contracts gas:
Notional quantity (in mMWh)
\u2013
840.0
1,350.0
1,350.0
1,065.0
2,805.0
Notional amount (in EUR million
per MWh)
\u2013
36.3
49.9
49.9
38.7
96.0
Average hedged sales price
(in EUR per MWh)
\u2013
43.2
36.9
36.9
36.4
34.2
Commodity zero cost collar
contracts oil:
Notional quantity gas (in mbbl)
\u2013
135.0
135.0
60.0
60.0
1,200.0
Average hedged price \u2013 floor
(in USD per bbl)
\u2013
66.1
66.1
67.5
67.5
65.0
Average hedged price \u2013 ceiling
(in USD per bbl)
\u2013
82.7
82.7
77.4
77.4
77.4
Commodity zero cost collar
contracts gas:
Notional quantity gas (in mMWh)
\u2013
285.0
240.0
240.0
300.0
1,260.0
Average hedged price \u2013 floor
(in EUR per MWh)
\u2013
36.3
34.4
34.4
35.0
31.2
Average hedged price \u2013 ceiling
(in EUR per MWh)
\u2013
56.2
49.4
49.4
54.5
45.6
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 01.01.2023
13.9
Realised cash flow hedge on revenue
(19.7)
Realised cash flow hedge on financial items
(29.3)
Related tax \u2013 realised cash flow hedge
19.1
Changes in fair value cash flow hedge revenue
102.5
Changes in fair value cash flow hedge financial items
5.2
Related tax \u2013 changes in fair value cash flow hedge
(66.8)
Balance as of 31.12.2023
24.9
Realised cash flow hedge on revenue
1.6
Realised cash flow hedge on financial items
(20.2)
Related tax \u2013 realised cash flow hedge
3.1
Changes in fair value cash flow hedge revenue
(100.4)
Changes in fair value cash flow hedge financial items
0.6
Related tax \u2013 changes in fair value cash flow hedge
64.1
Balance as of 31.12.2024
(26.3)
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialLiabilitiesHeldForTradingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-504": { "value": "19.1 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 31.12.2024
USD million
Level 1
Level 2
Level 3
Total
Assets
Financial assets at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
14.2
\u2013
14.2
Total assets
\u2013
14.2
\u2013
14.2
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
1
\u2013
\u2013
85.1
85.1
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
87.4
\u2013
87.4
Total liabilities
\u2013
87.4
85.1
172.5
1) For more information see section 18.2, 18.3 and note 2.3 On 31.12.2023
USD million
Level 1
Level 2
Level 3
Tot al
Assets
Financial assets at fair value through profit or loss
\u2013 Derivative instruments interest swap, ineffective part
\u2013
1.2
\u2013
1.2
Financial assets at fair value hedging instruments
\u2013 Derivative instruments interest swap
\u2013
20.4
\u2013
20.4
\u2013 Derivative instruments price hedge
\u2013
64.1
\u2013
64.1
Total assets
\u2013
85.7
\u2013
85.7
Liabilities
Financial liabilities at fair value through profit or loss
\u2013 Embedded derivatives convertible bond BNOR15
\u2013
\u2013
53.0
53.0
Financial liabilities at fair value hedging instruments
\u2013 Derivative instruments price hedge
\u2013
39.2
\u2013
39.2
Total liabilities
\u2013
39.2
53.0
92.2
19.2 Financial instruments by category On 31.12.24
Assets
Financial at fair value
assets at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Assets
Derivative instruments price hedge
\u2013
\u2013
14.2
14.2
Trade receivables and other current assets
39.0
\u2013
\u2013
39.0
Restricted bank deposits
218.8
\u2013
\u2013
218.8
Cash and cash equivalents
250.6
\u2013
\u2013
250.6
Total
508.4
\u2013
14.2
522.6
Liabilities
Financial at fair value
liabilities at through Hedging
amortised profit or instruments
USD million cost loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
87.4
87.4
Embedded derivatives convertible bond BNOR15
1)
\u2013
85.1
\u2013
85.1
Convertible bond loan
233.1
\u2013
\u2013
233.1
Senior unsecured bond loan
303.5
\u2013
\u2013
303.5
Reserve-based lending facility
834.3
\u2013
\u2013
834.3
Trade payables and other current liabilities
99.4
\u2013
\u2013
99.4
Total
1,470.4
85.1
87.4
1,642.9
1) For more information see section 18.1, 18.3 and note 2.3. On 31.12.23
Financial Assets
assets at at fair value Hedging
amortised through instruments
USD million on 31.12.23 cost profit or loss
at fair value
Total
Assets
Convertible loan CarbonCuts
1.1
\u2013
\u2013
1.1
Loan CarbonCuts
2.6
\u2013
\u2013
2.6
Derivative instruments interest swap
\u2013
\u2013
21.6
21.6
Derivative instruments price hedge
\u2013
\u2013
64.1
64.1
Trade receivables and other current assets
88.7
\u2013
\u2013
88.7
Restricted bank deposits
214.0
\u2013
\u2013
214.0
Cash and cash equivalents
166.7
\u2013
\u2013
166.7
Total
473.1
\u2013
85.7
558.8
Financial Liabilities
liabilities at at fair value Hedging
amortised through instruments
USD million cost profit or loss
at fair value
Total
Liabilities
Derivative instruments price hedge
\u2013
\u2013
39.2
39.2
Embedded derivatives convertible bond BNOR15
\u2013
53.0
\u2013
53.0
Convertible bond loans
201.7
\u2013
\u2013
201.7
Senior unsecured bond loan
169.1
\u2013
\u2013
169.1
Reserve-based lending facility
820.8
\u2013
\u2013
820.8
Trade payables and other current liabilities
125.3
\u2013
\u2013
125.3
Total
1,316.9
53.0
39.2
1,409.1
The tables below show the payment structure for the Company\u2019s financial commitments,
based on undiscounted contractual payments:
Less than
31.12.24
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
28.5
28.5
385.5
\u2013
442.5
Reserve-based lending facility
83.8
86.2
1,036.3
\u2013
1,206.3
Trade creditors and other liabilities
99.4
\u2013
\u2013
\u2013
99.4
Derivative financial liabilities:
\u2013
Derivatives
1)
64.3
22.0
1.0
\u2013
87.4
Total as at 31.12.24
276.1
136.7
1,422.9
\u2013
1,835.6
Less than
31.12.23
1 year
1-2 years
2-5 years
Over 5 years
Tot al
Non-derivative financial liabilities:
BNOR15
1)
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR16
\u2013
\u2013
175.0
\u2013
175.0
Reserve-based lending facility
125.0
275.0
450.0
\u2013
850.0
Trade creditors and other liabilities
125.3
\u2013
\u2013
\u2013
125.3
Derivative financial liabilities:
\u2013
Derivatives
1)
35.9
3.2
\u2013
\u2013
39.2
Total as at 31.12.24
286.2
278.2
625.0
\u2013
1,189.4
1) Any redemption and repurchase of bonds are acted by BlueNord as Issuer. The Bondholders will have the right of a mandatory
redemption but only in a case of a Change of Control event (which will be notified by BlueNord). In the table it is assumed that it will
be no cash payments on BNOR15 and the related embedded derivative.
19.3 Financial instruments \u2014 fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments on 31 December 2024:
Total amount Carrying Fair
USD million
outstanding
1)
amount value
Financial assets
Derivative instruments price hedge
14.2
14.2
Trade receivables and other current assets
39.0
39.0
Restricted bank deposits
218.8
218.8
Cash and cash equivalents
250.6
250.6
Total
522.6
522.6
Financial liabilities
Derivative instruments price hedge
87.4
87.4
Embedded derivative convertible bond BNOR15
2)
85.1
85.1
Convertible bond loans
247.1
233.1
162.0
Senior unsecured bond loan
300.0
303.5
300.0
Reserve-based lending facility
880.0
834.3
880.0
Trade payables and other current liabilities
99.4
99.4
Total
1,427.1
1,642.9
1,613.9
1) Total amount outstanding on the bonds and under the RBL facility. 2) For more information see section 19.1, 19.2 and note 2.3. The RBL facility is measured at amortised cost. 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 capital outstanding is USD 880 million on 31 December 2024. The senior unsecured bond loan is measured at amortised cost; a total of USD 11.5 million in transaction costs are deducted from the amount initially recognised. The BNOR15 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, transaction costs are included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as on 31 December 2024 was USD 85.1 million. The assumptions in establishing the option value as on 31 December 2024 are shown below. The following table list the inputs to the model used to calculate the fair value of the embedded derivatives:
BNOR15
2024
Valuation date
(date)
31 Dec 24
Agreement execution date
(date)
30 Dec 22
Par value of bonds
(USD) 247,067,145
Reference share price at time of agreement
(NOK)
413
Share price at 31.12.2024
(NOK)
657
Fair value at grant date
(USD)
38,928,552
Fair value at 31.12.2024
(USD)
85,139,366
PIK interest rate
(%)
8.00%
Expected remaining life
(years)
1.0
Number of options
(#)
4,803,885
Conversion price
(NOK)
537
Fixed FX rate of agreement
(USD:NOK)
10.440
Risk-free rate (based on government bonds)
(%)
3.87%
Expected volatility
(%)
42.62%
Model used
Black \u2013 Scholes \u2013 Merton
", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-470": { "value": "
20 Share capital
There is only one single class of shares in the Company and 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 01 January 2023
25,708,424
1.7
Issue of shares
497,425
0.0
Number of shares and share capital as of 31 December 2023
26,205,849
1.7
Issue of shares
292,791
0.0
Number of shares and share capital as of 31 December 2024
26,498,640
1.7
Treasury share
No. of shares reserve*
Number of treasury shares and treasury share reserve as of
01 January 2023
(137,162)
(0.1)
Sale of treasury shares
36,641
0.0
Number of treasury shares and treasury share reserve as of
31 December 2023
(100,521)
(0.1)
Sale of treasury shares
100,521
0.1
Number of treasury shares and treasury share reserve as of
31 December 2024
\u2013
\u2013
* In USD million.
Changes in 2024
During 2024 the Company issued 292.791 shares in relation to exercise of share options held by former
members of the Board and second award of the Long-Term Incentive (LTI) programme.
The Company sold 100,521 of its own shares in relation to exercise of share options held by former
members of the Board.
Changes in 2023
The Company received conversion notice from bondholders holding BNOR13 and BNOR15 bonds
for total principal amount of USD 14.6 million in 2023, which pursuant to the bond terms are convertible
into 497,425 new shares in the Company. The BNOR13 conversion in January had a conversion
price of USD 28.9734, the following conversions had a conversion price of USD 51.4307 according
to the new bond terms. Following such conversions, the share capital is increased with NOK 268.5/
USD 32.7 thousands.
The Company sold 36,641 of its own shares during the year, of which 23,641 shares was related to first
award of the Long-Term Incentive (LTI) programme. The shares price at transfer date was 475 NOK/
share. In addition, 13,000 shares were sold to cover exercise of options held by former employees at
strike price 160 NOK/share.
Overview of shareholders at 31 March 2025:
Shareholder*
Shareholding
Ownership share
Voting share
Euroclear Bank S.A./N.V.
6,872,158
25.9 %
25.9 %
Goldman Sachs International
5,123,261
19.3 %
19.3 %
The Bank of New York Mellon SA/NV
2,279,864
8.6 %
8.6 %
SOBER AS
1,850,000
7.0 %
7.0 %
J.P. Morgan Securities LLC
1,482,181
5.6 %
5.6 %
J.P. Morgan Chase Bank, N.A., London
816,890
3.1 %
3.1 %
State Street Bank and Trust Comp
787,902
3.0 %
3.0 %
Citibank, N.A.
489,581
1.8 %
1.8 %
BARCLAYS CAPITAL LUXEMBOURG SARL
450,000
1.7 %
1.7 %
UBS Switzerland AG
448,391
1.7 %
1.7 %
Sbakkejord AS
417,058
1.6 %
1.6 %
J.P. Morgan SE
349,569
1.3 %
1.3 %
FINSNES INVEST AS
316,000
1.2 %
1.2 %
FJORD & ATOLL SOSYFR AS
308,070
1.2 %
1.2 %
HANASAND
292,412
1.1 %
1.1 %
VELDE HOLDING AS
245,000
0.9 %
0.9 %
ALTO HOLDING AS
244,700
0.9 %
0.9 %
CLEARSTREAM BANKING S.A.
198,115
0.7 %
0.7 %
Caceis Bank
186,695
0.7 %
0.7 %
The Bank of New York Mellon
186,210
0.7 %
0.7 %
Total
23,344,057
88.1 %
88.1 %
Other owners (ownership <0,53%)
3,154,583
11.9 %
11.9 %
Total number of shares at 31 March 2025
26,498,640
100.0 %
100.0 %
* Nominee holder.", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-529": { "value": "20 Share capital There is only one single class of shares in the Company and 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 01 January 2023
25,708,424
1.7
Issue of shares
497,425
0.0
Number of shares and share capital as of 31 December 2023
26,205,849
1.7
Issue of shares
292,791
0.0
Number of shares and share capital as of 31 December 2024
26,498,640
1.7
Treasury share
No. of shares reserve*
Number of treasury shares and treasury share reserve as of
01 January 2023
(137,162)
(0.1)
Sale of treasury shares
36,641
0.0
Number of treasury shares and treasury share reserve as of
31 December 2023
(100,521)
(0.1)
Sale of treasury shares
100,521
0.1
Number of treasury shares and treasury share reserve as of
31 December 2024
\u2013
\u2013
* In USD million. Changes in 2024 During 2024 the Company issued 292.791 shares in relation to exercise of share options held by former members of the Board and second award of the Long-Term Incentive (LTI) programme. The Company sold 100,521 of its own shares in relation to exercise of share options held by former members of the Board. Changes in 2023 The Company received conversion notice from bondholders holding BNOR13 and BNOR15 bonds for total principal amount of USD 14.6 million in 2023, which pursuant to the bond terms are convertible into 497,425 new shares in the Company. The BNOR13 conversion in January had a conversion price of USD 28.9734, the following conversions had a conversion price of USD 51.4307 according to the new bond terms. Following such conversions, the share capital is increased with NOK 268.5/ USD 32.7 thousands. The Company sold 36,641 of its own shares during the year, of which 23,641 shares was related to first award of the Long-Term Incentive (LTI) programme. The shares price at transfer date was 475 NOK/ share. In addition, 13,000 shares were sold to cover exercise of options held by former employees at strike price 160 NOK/share. Overview of shareholders at 31 March 2025:
Shareholder*
Shareholding
Ownership share
Voting share
Euroclear Bank S.A./N.V.
6,872,158
25.9 %
25.9 %
Goldman Sachs International
5,123,261
19.3 %
19.3 %
The Bank of New York Mellon SA/NV
2,279,864
8.6 %
8.6 %
SOBER AS
1,850,000
7.0 %
7.0 %
J.P. Morgan Securities LLC
1,482,181
5.6 %
5.6 %
J.P. Morgan Chase Bank, N.A., London
816,890
3.1 %
3.1 %
State Street Bank and Trust Comp
787,902
3.0 %
3.0 %
Citibank, N.A.
489,581
1.8 %
1.8 %
BARCLAYS CAPITAL LUXEMBOURG SARL
450,000
1.7 %
1.7 %
UBS Switzerland AG
448,391
1.7 %
1.7 %
Sbakkejord AS
417,058
1.6 %
1.6 %
J.P. Morgan SE
349,569
1.3 %
1.3 %
FINSNES INVEST AS
316,000
1.2 %
1.2 %
FJORD & ATOLL SOSYFR AS
308,070
1.2 %
1.2 %
HANASAND
292,412
1.1 %
1.1 %
VELDE HOLDING AS
245,000
0.9 %
0.9 %
ALTO HOLDING AS
244,700
0.9 %
0.9 %
CLEARSTREAM BANKING S.A.
198,115
0.7 %
0.7 %
Caceis Bank
186,695
0.7 %
0.7 %
The Bank of New York Mellon
186,210
0.7 %
0.7 %
Total
23,344,057
88.1 %
88.1 %
Other owners (ownership <0,53%)
3,154,583
11.9 %
11.9 %
Total number of shares at 31 March 2025
26,498,640
100.0 %
100.0 %
* Nominee holder.", "dimensions": { "concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-505": { "value": "20 Share capital There is only one single class of shares in the Company and 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 01 January 2023
25,708,424
1.7
Issue of shares
497,425
0.0
Number of shares and share capital as of 31 December 2023
26,205,849
1.7
Issue of shares
292,791
0.0
Number of shares and share capital as of 31 December 2024
26,498,640
1.7
Treasury share
No. of shares reserve*
Number of treasury shares and treasury share reserve as of
01 January 2023
(137,162)
(0.1)
Sale of treasury shares
36,641
0.0
Number of treasury shares and treasury share reserve as of
31 December 2023
(100,521)
(0.1)
Sale of treasury shares
100,521
0.1
Number of treasury shares and treasury share reserve as of
31 December 2024
\u2013
\u2013
* In USD million. Changes in 2024 During 2024 the Company issued 292.791 shares in relation to exercise of share options held by former members of the Board and second award of the Long-Term Incentive (LTI) programme. The Company sold 100,521 of its own shares in relation to exercise of share options held by former members of the Board. Changes in 2023 The Company received conversion notice from bondholders holding BNOR13 and BNOR15 bonds for total principal amount of USD 14.6 million in 2023, which pursuant to the bond terms are convertible into 497,425 new shares in the Company. The BNOR13 conversion in January had a conversion price of USD 28.9734, the following conversions had a conversion price of USD 51.4307 according to the new bond terms. Following such conversions, the share capital is increased with NOK 268.5/ USD 32.7 thousands. The Company sold 36,641 of its own shares during the year, of which 23,641 shares was related to first award of the Long-Term Incentive (LTI) programme. The shares price at transfer date was 475 NOK/ share. In addition, 13,000 shares were sold to cover exercise of options held by former employees at strike price 160 NOK/share.
Overview of shareholders at 31 March 2025:
Shareholder*
Shareholding
Ownership share
Voting share
Euroclear Bank S.A./N.V.
6,872,158
25.9 %
25.9 %
Goldman Sachs International
5,123,261
19.3 %
19.3 %
The Bank of New York Mellon SA/NV
2,279,864
8.6 %
8.6 %
SOBER AS
1,850,000
7.0 %
7.0 %
J.P. Morgan Securities LLC
1,482,181
5.6 %
5.6 %
J.P. Morgan Chase Bank, N.A., London
816,890
3.1 %
3.1 %
State Street Bank and Trust Comp
787,902
3.0 %
3.0 %
Citibank, N.A.
489,581
1.8 %
1.8 %
BARCLAYS CAPITAL LUXEMBOURG SARL
450,000
1.7 %
1.7 %
UBS Switzerland AG
448,391
1.7 %
1.7 %
Sbakkejord AS
417,058
1.6 %
1.6 %
J.P. Morgan SE
349,569
1.3 %
1.3 %
FINSNES INVEST AS
316,000
1.2 %
1.2 %
FJORD & ATOLL SOSYFR AS
308,070
1.2 %
1.2 %
HANASAND
292,412
1.1 %
1.1 %
VELDE HOLDING AS
245,000
0.9 %
0.9 %
ALTO HOLDING AS
244,700
0.9 %
0.9 %
CLEARSTREAM BANKING S.A.
198,115
0.7 %
0.7 %
Caceis Bank
186,695
0.7 %
0.7 %
The Bank of New York Mellon
186,210
0.7 %
0.7 %
Total
23,344,057
88.1 %
88.1 %
Other owners (ownership <0,53%)
3,154,583
11.9 %
11.9 %
Total number of shares at 31 March 2025
26,498,640
100.0 %
100.0 %
* Nominee holder.
", "dimensions": { "concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-506": { "value": "
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 684.4 thousand for 2024. For 2023, the corresponding
costs were USD 732.2 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 (\u2018obligatorisk tjenestepensjon\u2019).
Correspondingly, the affiliates in Denmark and the United Kingdom comply with the requirement for
mandatory occupational pension by local legislation.
", "dimensions": { "concept": "ifrs-full:DisclosureOfDefinedContributionPlansExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-471": { "value": "22 Asset retirement obligations
USD million
31.12.2024
31.12.2023
Balance on 01.01.
1,049.0
955.8
Provisions and change of estimates made during the year
34.5
52.6
Accretion expense
54.2
49.2
Incurred cost removal
(15.5)
(8.7)
Currency translation adjustment
(0.1)
0.1
Total provision made for asset retirement obligations
1,122.1
1,049.0
Breakdown of short-term and long-term asset retirement obligations
Short-term
11.4
15.4
Long-term
1,110.6
1,033.7
Total provision for asset retirement obligations
1,122.1
1,049.0
See note 1.17 for the accounting policies and note 3.2 (c) for the accounting estimates / assumptions related to asset retirement obligations. BlueNord has a legal and contractual obligation under the DUC Joint Venture (JV) partnership to decommission its oil and gas assets at the end of their useful life. The lifetime estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The timing estimates of the abandonment provision is calculated based on the assessment of when the remaining oil and gas reserves reaches its economic cut-off. The abandonment cost is estimated by the Operator and forms the basis for the ARO calculation. The obligations are measured at net present value, assuming an inflation rate of 2.0 percent (2023: 2.0 percent) and a nominal credit-adjusted discount rate before tax of 5.0 percent (2023: 5.5 percent). The credit margin included in the discount rate is 2.1 percent (2023: 2.9 percent). 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. To note, the timing and costs have not yet been agreed within the partnership and may deviate from the licence partners\u2019 estimates. The change in estimate during the year includes an increase of USD 69 million due to change in discount rate and a decrease of USD 15 million due to change in expected timing of close in of production from Gorm and phasing of the abandonment activities. Further, the asset retirement estimate from the Operator includes both US dollar and Danish kroner costs and as a result there is a decrease of USD 19 million due to the strengthening of USD to DKK. To date, BlueNord is not required to post any security in respect of its abandonment obligations
As part of the overall restructuring in 2015, an agreement was reached that entails that the partners
took over BlueNord\u2019s share of the Nini/Cecilie licences, however, 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 61.5 million/DKK 444.1 million.
The balance as per 31.12.2024 is USD 1,057.2 million for DUC, USD 61.5 million for Nini/Cecilie, USD 1.3
million for Lulita (non-DUC share) and USD 2.1 million for Tyra F-3 pipeline.
Expected timing of Asset Retirement Obligation
USD million
Un-discounted
Discounted
2025-2029
42.8
39.0
2030-2034
492.6
330.4
2035-2039
61.1
36.6
2040+
1)
1,589.1
654.6
At 31.12.2024
2)
2,185.6
1,060.6
1) The DUC licence expires in 2042.
2) Excluding Nini/Cecilie as the provision is secured through an escrow account, see note 18.
Sensitivity analysis
The table below shows how the asset retirement obligation for the DUC would be affected by changes
in the various assumptions, given that the remaining assumptions are constant. This includes sensitivities
accounting for climate risk related factors which can impact cost estimates, increase discount rate
and / or accelerate the timing of abandonment due to tighter regulatory standards.
ARO Change in
Sensitivity ($\u2019mm) provision
Abandonment cost estimate
1,057.5
Abandonment cost estimate increase +40%
1,480.5
40.0%
Abandonment cost estimate increase +10%
1,163.3
10.0%
Abandonment cost estimate decrease -10%
951.8
-10.0%
Abandonment cost estimate decrease -30%
740.3
-30.0%
Discount rate +1.0%
925.4
-13.0%
Discount rate -1.0%
1,213.2
15.0%
Inflation rate +1.0%
1,210.5
15.0%
Inflation rate -1.0%
925.2
-13.0%
Cessation Of Production (by hubs) accelerated by 5 years
1,216.6
15.0%
", "dimensions": { "concept": "bluenordasa:DisclosureOfAssetRetirementObligations", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-507": { "value": "22 Asset retirement obligations
USD million
31.12.2024
31.12.2023
Balance on 01.01.
1,049.0
955.8
Provisions and change of estimates made during the year
34.5
52.6
Accretion expense
54.2
49.2
Incurred cost removal
(15.5)
(8.7)
Currency translation adjustment
(0.1)
0.1
Total provision made for asset retirement obligations
1,122.1
1,049.0
Breakdown of short-term and long-term asset retirement obligations
Short-term
11.4
15.4
Long-term
1,110.6
1,033.7
Total provision for asset retirement obligations
1,122.1
1,049.0
See note 1.17 for the accounting policies and note 3.2 (c) for the accounting estimates / assumptions related to asset retirement obligations. BlueNord has a legal and contractual obligation under the DUC Joint Venture (JV) partnership to decommission its oil and gas assets at the end of their useful life. The lifetime estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The timing estimates of the abandonment provision is calculated based on the assessment of when the remaining oil and gas reserves reaches its economic cut-off. The abandonment cost is estimated by the Operator and forms the basis for the ARO calculation. The obligations are measured at net present value, assuming an inflation rate of 2.0 percent (2023: 2.0 percent) and a nominal credit-adjusted discount rate before tax of 5.0 percent (2023: 5.5 percent). The credit margin included in the discount rate is 2.1 percent (2023: 2.9 percent). 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. To note, the timing and costs have not yet been agreed within the partnership and may deviate from the licence partners\u2019 estimates. The change in estimate during the year includes an increase of USD 69 million due to change in discount rate and a decrease of USD 15 million due to change in expected timing of close in of production from Gorm and phasing of the abandonment activities. Further, the asset retirement estimate from the Operator includes both US dollar and Danish kroner costs and as a result there is a decrease of USD 19 million due to the strengthening of USD to DKK. To date, BlueNord is not required to post any security in respect of its abandonment obligations . As part of the overall restructuring in 2015, an agreement was reached that entails that the partners took over BlueNord\u2019s share of the Nini/Cecilie licences, however, 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 61.5 million/DKK 444.1 million. The balance as per 31.12.2024 is USD 1,057.2 million for DUC, USD 61.5 million for Nini/Cecilie, USD 1.3 million for Lulita (non-DUC share) and USD 2.1 million for Tyra F-3 pipeline. Expected timing of Asset Retirement Obligation
USD million
Un-discounted
Discounted
2025-2029
42.8
39.0
2030-2034
492.6
330.4
2035-2039
61.1
36.6
2040+
1)
1,589.1
654.6
At 31.12.2024
2)
2,185.6
1,060.6
1) The DUC licence expires in 2042. 2) Excluding Nini/Cecilie as the provision is secured through an escrow account, see note 18. Sensitivity analysis The table below shows how the asset retirement obligation for the DUC would be affected by changes in the various assumptions, given that the remaining assumptions are constant. This includes sensitivities accounting for climate risk related factors which can impact cost estimates, increase discount rate and / or accelerate the timing of abandonment due to tighter regulatory standards.
ARO Change in
Sensitivity ($\u2019mm) provision
Abandonment cost estimate
1,057.5
Abandonment cost estimate increase +40%
1,480.5
40.0%
Abandonment cost estimate increase +10%
1,163.3
10.0%
Abandonment cost estimate decrease -10%
951.8
-10.0%
Abandonment cost estimate decrease -30%
740.3
-30.0%
Discount rate +1.0%
925.4
-13.0%
Discount rate -1.0%
1,213.2
15.0%
Inflation rate +1.0%
1,210.5
15.0%
Inflation rate -1.0%
925.2
-13.0%
Cessation Of Production (by hubs) accelerated by 5 years
1,216.6
15.0%
", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-472": { "value": " 23 Borrowings 23.1 Summary of borrowings
31.12.2024
31.12.2023
Principal Book Principal Book
USD million amount value amount value
BNOR14 Senior Unsecured Bond
1)
\u2013
\u2013
175.0
169.1
BNOR16 Senior Unsecured Bond
2)
300.0
303.5
\u2013
\u2013
Reserve-based lending facility
3)
880.0
834.3
725.0
695.8
Total non-current debt
1,180.0
1,137.9
900.0
864.9
Reserve-based lending facility
3)
\u2013
\u2013
125.0
125.0
BNOR15 Convertible Bond
4)
247.1
233.1
228.4
201.7
Total current debt
247.1
233.1
353.4
326.7
Total borrowings
1,427.1
1,370.9
1,253.4
1,191.6
Note: Book values reported on the basis of amortised cost for BNOR16 (BNOR14 called upon in June 2024), the reserve-based lending facility and the convertible bond loan element of BNOR13 and BNOR15. 1) As at 14 June 2024, the Company exercised the call option to redeem all of BNOR14 at 110.00131 percent (plus accrued unpaid interests on the redeemed amount) on 02 July 2024. 2) The Company issued a senior unsecured bond of USD 300 million 2 July 2024, with a maturity in July 2029. The bond carries an interest of 9.5 percent p.a., payable semi-annually. The BNOR16 bond has been used to redeem the BNOR14 bond and for other general corporate purposes. 3) The Company completed the amendment and restatement of its USD 1.1 billion reserve-based lending facility and entered into an increased reserve-based lending Facility in Q2 2024. The facility has a five and a half-year tenor with a total facility amount of USD 1.4 billion (an increase of USD 300 million), with a maximum of USD 1.15 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 4.0 percent per annum. The current capital outstanding is USD 880 million at 2024. 4) The Company issued a convertible bond loan of USD 207.6 million in December 2022, with a five-year tenor and a conversion to equity or cash settlement after three years (31 December 2025). BNOR15 is made up of a transfer from BNOR13 of USD 151.4 million plus additional compensation bonds of USD 56.2 million. In the same way as BNOR13, 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. Conversion price of USD 51.4307 per share. In 2023, USD 0.1 million was converted into equity. No other capital movements were recorded in 2024. For more information on the bond terms see www.bluenord.com/debt. BlueNord has exercised the clean up call option to redeem all of BNOR13 outstandings in accordance with the bond terms and as at January 2025, BNOR13 has been fully repaid.
Cash flows
Non-cash changes
Receipts/ Interest and Conversion to Move from
Movements in interest-bearing liabilities
31.12.23
payments financing cost shares
LT to ST
Amortisation
31.12.24
BNOR13 Convertible Bond
\u2013
\u2013
\u2013
\u2013
\u2013
\u2013
\u2013
BNOR15 Convertible Bond
201.7
\u2013
\u2013
\u2013
(233.1)
31.3
\u2013
BNOR16 Senior Unsecured Bond
\u2013
300.0
(11.5)
\u2013
\u2013
15.1
303.5
BNOR14 Senior Unsecured Bond
169.1
(175.0)
(25.4)
22.3
\u2013
9.0
\u2013
Reserve-based lending facility
1)
695.8
30.0
(96.8)
\u2013
125.0
80.4
834.3
Total movement non-current interest-bearing liabilities
1,066.6
155.0
(133.7)
22.3
(108.1)
135.8
1,137.9
Reserve-based lending facility
125.0
\u2013
\u2013
\u2013
(125.0)
\u2013
\u2013
BNOR15 Convertible Bond
\u2013
\u2013
\u2013
\u2013
233.1
\u2013
233.1
Total movement in current interest-bearing liabilities
125.0
\u2013
\u2013
\u2013
108.1
\u2013
233.1
Total movement in interest-bearing liabilities
1,191.6
155.0
(133.7)
22.3
\u2013
135.8
1,370.9
1) The cash outflow from interest and financing cost of USD 96.8 million (2023: USD 37.9 million) and the change in amortisation of USD
80.4 million (2023: USD 44.6 million) on the reserve-based lending facility is net of realised gain on interest swap of USD 21.3 million
(2023: USD 46.4 million).
Cash flows
Non-cash changes
Receipts/ Interest and Conversion to Conversion
Movements in interest-bearing liabilities
31.12.22
payments financing cost shares
BNOR15
Amortisation
31.12.23
BNOR13 Convertible Bond
13.1
\u2013
\u2013
(13.2)
\u2013
0.1
(0.0)
BNOR15 Convertible Bond
175.7
\u2013
\u2013
(0.1)
\u2013
26.2
201.7
BNOR14 Senior Unsecured Bond
166.9
\u2013
(15.8)
\u2013
\u2013
17.9
169.1
Reserve-based lending facility
1)
764.0
50.0
(37.9)
\u2013
(125.0)
44.6
695.8
Total movement non-current interest-bearing liabilities
1,119.6
50.0
(53.6)
(13.3)
(125.0)
88.9
1,066.6
Reserve-based lending facility
\u2013
\u2013
\u2013
\u2013
125.0
\u2013
125.0
Deferred Consideration
25.0
(25.0)
\u2013
\u2013
\u2013
\u2013
\u2013
Total movement current interest-bearing liabilities
25.0
(25.0)
\u2013
\u2013
125.0
\u2013
125.0
Total movement in interest-bearing liabilities
1,144.6
25.0
(53.6)
(13.3)
\u2013
88.9
1,191.6
23.2 Details on borrowing Details on borrowings outstanding on 31 December 2024 Reserve-based lending facility In June 2024, BlueNord amended and extended its existing senior secured reserve-based credit facility to commit to a five-and-a-half-year senior reserve-based credit facility of USD 1.4 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 2024 amounted to USD 1,362 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, BlueNord Denmark A/S, BlueNord Energy Denmark A/S, BlueNord Gas Denmark A/S by BlueNord ASA. BNOR15 In December 2022, BlueNord launched an exchange offer for the BNOR13 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 majority of the BNOR13 convertible was transferred into the BNOR15 convertible. The Company issued a total of 207,641,201 new BNOR15 bonds, each with a nominal value of USD 1. The BNOR13 bond has been fully repaid in January 2025. The BNOR15 bond terms mirror the amendments of the previous BNOR13 bond except that inter alia a tap issue mechanism has been included. Interest is at 8 percent p.a. on a PIK basis, with an alternative option to pay cash interest at 6 percent p.a., payable semi-annually. BNOR16 In July 2024, BlueNord successfully completed the issue of a USD 300 million unsecured bond. The proceeds have been used to redeem the previous BNOR14 bond and also utilised for general corporate purposes. The bond carries an interest of 9.5 percent p.a., payable semi-annually, with a five-year tenor 23.3 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 3.0:1.0. Each test is carried out on the audited full year financial statements of BlueNord ASA. BlueNord must also demonstrate minimum liquidity on a look forward basis of USD 50 million during the relevant period, which is the latest of completion of the Tyra redevelopment project and following 12-month period. 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. BlueNord has been in compliance with all covenants requirements during 2023 and 2024 and at 31 December 2024. BNOR16 The USD 300 million unsecured bond contains a financial covenant that the ratio of net debt to EBITDAX (earnings before interest, tax, depreciation, amortisation, and exploration) shall be less than 3.0:1.0. There is also a minimum liquidity covenant requirement of USD 50 million unrestricted cash, bank deposits and cash equivalents. BlueNord is in compliance with the covenants at the end of 2024. 23.4 Payment structure Payment structure (USD million) at 31.12.2024:
Year
BNOR15
1)
BNOR16
RBL Facility
Total
2025
\u2013
\u2013
\u2013
\u2013
2026
\u2013
\u2013
\u2013
\u2013
2027
\u2013
\u2013
223.0
223.0
2028
\u2013
\u2013
328.5
328.5
2029
\u2013
300.0
328.5
628.5
Total
\u2013
300.0
880.0
1,180.0
1) Any redemption and repurchase of bonds are acted by BlueNord as Issuer. The Bondholders will have the right of a mandatory redemption but only in a case of a Change of Control event (which will be notified by BlueNord). In the table it is assumed that it will be no cash payments on BNOR15
Interest payments (USD million) at 31.12.2024:
Year
BNOR16
1)
RBL Facility
2)
Total
Interest rate
3)
9.5%
SOFR**
2025
28.5
83.8
112.3
2026
28.5
86.2
114.7
2027
28.5
80.4
108.9
2028
28.5
53.3
81.8
2029
28.5
22.6
51.1
Total
142.5
326.3
468.8
1) BNOR16 carries an interest rate of 9.50 per annum, payable semi-annually.
2) RBL interest payment include drawn, undrawn and letter of credit utilisation fees. There are no active interest rate hedges to date.
3) BNOR15 carries an interest charge of: (i) 6 percent per annum in cash, payable semi-annually, or; (ii) 8 percent per annum payment in kind
(\u2018PIK\u2019) cumulative interest, rolled up semi-annually, to add to BNOR15 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 BNOR15 in the above table.
See also note 19.2 Financial Instruments by Category for payment structure that includes all financial liabilities.
23.5 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
2024
2023
BlueNord ASA shares in Altinex AS
398.5
396.8
Altinex AS shares in BlueNord Energy 8/06 Denmark B.V and
other companies
614.7
614.7
Loans from Parent to subsidiaries
348.6
343.2
Total net book value
1,361.8
1,354.7
", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-473": { "value": "
24 Trade payables and other payables
USD million
2024
2023
Trade payable
4.4
17. 5
Liabilities to operators relating to joint venture licences
31.1
70.9
Over-lift of oil/NGL
6.3
\u2013
Accrued interest
3.4
1.3
Salary accruals
2.3
2.4
Public duties payable
33.7
12.8
Other current liabilities
18.2
20.3
Total trade payables and other current liabilities
99.4
125.3
Trade and other payables held in currency
USD million
2024
2023
USD
51.7
40.2
DKK
29.8
70.3
EUR
16.0
12.3
GBP
0.7
0.8
NOK
1.2
1.7
Total
99.4
125.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-530": { "value": "24 Trade payables and other payables
USD million
2024
2023
Trade payable
4.4
17. 5
Liabilities to operators relating to joint venture licences
31.1
70.9
Over-lift of oil/NGL
6.3
\u2013
Accrued interest
3.4
1.3
Salary accruals
2.3
2.4
Public duties payable
33.7
12.8
Other current liabilities
18.2
20.3
Total trade payables and other current liabilities
99.4
125.3
Trade and other payables held in currency
USD million
2024
2023
USD
51.7
40.2
DKK
29.8
70.3
EUR
16.0
12.3
GBP
0.7
0.8
NOK
1.2
1.7
Total
99.4
125.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-521": { "value": "24 Trade payables and other payables
USD million
2024
2023
Trade payable
4.4
17. 5
Liabilities to operators relating to joint venture licences
31.1
70.9
Over-lift of oil/NGL
6.3
\u2013
Accrued interest
3.4
1.3
Salary accruals
2.3
2.4
Public duties payable
33.7
12.8
Other current liabilities
18.2
20.3
Total trade payables and other current liabilities
99.4
125.3
Trade and other payables held in currency
USD million
2024
2023
USD
51.7
40.2
DKK
29.8
70.3
EUR
16.0
12.3
GBP
0.7
0.8
NOK
1.2
1.7
Total
99.4
125.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-508": { "value": "24 Trade payables and other payables
USD million
2024
2023
Trade payable
4.4
17. 5
Liabilities to operators relating to joint venture licences
31.1
70.9
Over-lift of oil/NGL
6.3
\u2013
Accrued interest
3.4
1.3
Salary accruals
2.3
2.4
Public duties payable
33.7
12.8
Other current liabilities
18.2
20.3
Total trade payables and other current liabilities
99.4
125.3
Trade and other payables held in currency
USD million
2024
2023
USD
51.7
40.2
DKK
29.8
70.3
EUR
16.0
12.3
GBP
0.7
0.8
NOK
1.2
1.7
Total
99.4
125.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-474": { "value": "25 Guarantees Overview of issued guarantees on 31 December 2024 The parent company of the Group, BlueNord ASA (\u2018BlueNord\u2019), has issued a parent company guarantee to the Danish Ministry of Climate, Energy and Utilities on behalf of its subsidiary BlueNord Energy Denmark A/S, BlueNord Gas Denmark A/S and CarbonCuts A/S. 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 Danish continental shelf, including 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 1.4 billion reserve-based lending facility and customary obligations/guarantees under joint operating agreements. BlueNord has also provided a parent company guarantee to Shell Energy Europe Limited in relation to its subsidiary BlueNord Energy Denmark A/S\u2019s obligations under a gas offtake and transportation agreement capped at EUR 30 mill. Furthermore, the Company has provided a parent company guarantee to Total E&P Denmark A/S for its obligations under the JOA together with a guarantee from Shell. BlueNord has provided standby letters of credit of USD 100 million, issued under the LC tranche of the USD 1.4 billion RBL facility for the benefit of Shell in connection with this guarantee.
In relation to BlueNord\u2019s historic operations in the UK North Sea, the Company has issued a parent
company guarantee on behalf of its subsidiaries BlueNord UK Ltd and BlueNord Energy UK Limited.
On 31 December 2012, BlueNord issued a parent company guarantee on behalf of its subsidiary
Noreco Norway AS. 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, 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 December 2024, the guarantee has not been withdrawn.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutLiquidityArrangementsGuaranteesOrOtherCommitmentsWithThirdPartiesThatMayAffectFairValueOrRiskOfInterestsInStructuredEntitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-476": { "value": " 26 Investments in jointly-owned assets Investments in jointly own assets are included in the accounts by recognising the Group\u2019s share of the assets, liabilities, revenues and expenses related to the joint operation. The Group holds the following licence equities on 31 December 2024:
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
Denmark
36.8%
", "dimensions": { "concept": "ifrs-full:DisclosureOfJointVenturesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-477": { "value": "
27 Contingencies and commitments
Financial commitments
As a partner in the 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 for BlueNord is expected to be around USD 290 million per year. Capital and
abandonment expenditure for individual projects are approved separately.
BlueNord\u2019s capital commitments are related to the drilling of one infill well on Halfdan, with a gross
DUC budget of DKK 388 million.
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 21 million per year (2024: USD 20 million)
BlueNord share.
In addition to the above and in order to obtain the consent of TotalEnergies EP Danmark A/S to the
acquisition, BlueNord Energy Denmark A/S agreed to deposit cash in a secured cash call security
account in favour of TotalEnergies EP Danmark A/S (the concessionaire in respect of the Sole
Concession). On 31 December 2024, the escrow account was USD 157 million. As a result of the Tyra
redevelopment project being completed the cash call security amount has in January 2025 reduced
to USD 100 million 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, 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 BlueNord, but the liability is in any and all circumstances limited to a
maximum amount equal to the restricted cash account of USD 61.5 million (DKK 441.3 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, 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.
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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-522": { "value": "27 Contingencies and commitments Financial commitments As a partner in the 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 for BlueNord is expected to be around USD 290 million per year. Capital and abandonment expenditure for individual projects are approved separately. BlueNord\u2019s capital commitments are related to the drilling of one infill well on Halfdan, with a gross DUC budget of DKK 388 million. 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 21 million per year (2024: USD 20 million) BlueNord share. In addition to the above and in order to obtain the consent of TotalEnergies EP Danmark A/S to the acquisition, BlueNord Energy Denmark A/S agreed to deposit cash in a secured cash call security account in favour of TotalEnergies EP Danmark A/S (the concessionaire in respect of the Sole Concession). On 31 December 2024, the escrow account was USD 157 million. As a result of the Tyra redevelopment project being completed the cash call security amount has in January 2025 reduced to USD 100 million 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, 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 BlueNord, but the liability is in any and all circumstances limited to a maximum amount equal to the restricted cash account of USD 61.5 million (DKK 441.3 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, 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. 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-510": { "value": "27 Contingencies and commitments Financial commitments As a partner in the 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 for BlueNord is expected to be around USD 290 million per year. Capital and abandonment expenditure for individual projects are approved separately. BlueNord\u2019s capital commitments are related to the drilling of one infill well on Halfdan, with a gross DUC budget of DKK 388 million. 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 21 million per year (2024: USD 20 million) BlueNord share. In addition to the above and in order to obtain the consent of TotalEnergies EP Danmark A/S to the acquisition, BlueNord Energy Denmark A/S agreed to deposit cash in a secured cash call security account in favour of TotalEnergies EP Danmark A/S (the concessionaire in respect of the Sole Concession). On 31 December 2024, the escrow account was USD 157 million. As a result of the Tyra redevelopment project being completed the cash call security amount has in January 2025 reduced to USD 100 million 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, 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 BlueNord, but the liability is in any and all circumstances limited to a maximum amount equal to the restricted cash account of USD 61.5 million (DKK 441.3 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, 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. 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-475": { "value": "
28 Related party transactions
Other than fees to Directors of the Board the Group did not have any transactions with related parties
during 2024.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-509": { "value": "28 Related party transactions Other than fees to Directors of the Board the Group did not have any transactions with related parties during 2024. ", "dimensions": { "concept": "ifrs-full:DisclosureOfTransactionsBetweenRelatedPartiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-478": { "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. ", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXGE3C16", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } } } }