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Going concern
The Company regularly evaluates its financial
\u00a0
position, cash
flow forecasts and its compliance with financial covenants
\u00a0
by
considering multiple combinations of oil and gas prices,
production volumes, and operational spend scenarios.
\u00a0
As required under the Norwegian Accounting Act,
\u00a0
the
Company\u2019s Board of Directors conducted a review of
\u00a0
the going
concern assumption considering all relevant information
available up to the date the DNO consolidated and
\u00a0
Company
accounts are issued and taking into account all
\u00a0
available
information about the future covering at least 12 months
\u00a0
from
the end of the reporting period. The Board of
\u00a0
Directors\u2019 review
included, in particular,
\u00a0
assessment of the Group\u2019s projected
cash reserves and access to financing arrangements,
\u00a0
debt
maturities, operational outlook and work programs,
\u00a0
while
maintaining appropriate headroom in respect of sound
\u00a0
equity,
liquidity and financial covenant compliance throughout
\u00a0
the
assessment period.
\u00a0
Following its review, the Board of Directors confirmed, pursuant
to the Norwegian Accounting Act section 3-3a, that
\u00a0
the
requirements of the going concern assumption are
\u00a0
met and that
these financial statements have been prepared on
\u00a0
that basis.
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"ifrs-full:DividendsPaid", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:SharePremiumMember", "unit": "iso4217:USD" } }, "ID_295": { "value": "0.0", "decimals": -6, "dimensions": { "concept": "ifrs-full:DividendsPaid", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:ReserveOfExchangeDifferencesOnTranslationMember", "unit": "iso4217:USD" } }, "ID_296": { "value": "101900000.0", "decimals": -5, "dimensions": { "concept": "ifrs-full:DividendsPaid", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:RetainedEarningsMember", "unit": "iso4217:USD" } }, "ID_297": { "value": "101900000.0", "decimals": -5, "dimensions": { "concept": "ifrs-full:DividendsPaid", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ID_303": { "value": "0.0", "decimals": -6, "dimensions": { "concept": "ifrs-full:IncreaseDecreaseThroughTransactionsWithOwners", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:IssuedCapitalMember", "unit": "iso4217:USD" } }, "ID_304": { "value": "0.0", "decimals": -6, "dimensions": { "concept": "ifrs-full:IncreaseDecreaseThroughTransactionsWithOwners", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:SharePremiumMember", "unit": "iso4217:USD" } }, "ID_305": { "value": "0.0", "decimals": -6, "dimensions": { "concept": "ifrs-full:IncreaseDecreaseThroughTransactionsWithOwners", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:ReserveOfExchangeDifferencesOnTranslationMember", "unit": "iso4217:USD" } }, "ID_306": { "value": "-101900000.0", "decimals": -5, "dimensions": { "concept": "ifrs-full:IncreaseDecreaseThroughTransactionsWithOwners", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:RetainedEarningsMember", "unit": "iso4217:USD" } }, "ID_307": { "value": "-101900000.0", "decimals": -5, "dimensions": { "concept": "ifrs-full:IncreaseDecreaseThroughTransactionsWithOwners", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ID_245A": { "value": "32900000.0", "decimals": -5, "dimensions": { "concept": "ifrs-full:Equity", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2025-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:IssuedCapitalMember", "unit": "iso4217:USD" } }, "ID_246A": { "value": "343600000.0", "decimals": -5, "dimensions": { "concept": "ifrs-full:Equity", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2025-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:SharePremiumMember", "unit": "iso4217:USD" } }, "ID_247A": { "value": "-65700000.0", "decimals": -5, "dimensions": { "concept": "ifrs-full:Equity", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2025-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:ReserveOfExchangeDifferencesOnTranslationMember", "unit": "iso4217:USD" } }, "ID_248A": { "value": "769300000.0", "decimals": -5, "dimensions": { "concept": "ifrs-full:Equity", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2025-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:RetainedEarningsMember", "unit": "iso4217:USD" } }, "ID_155AA": { "value": "1080000000.0", "decimals": -5, "dimensions": { "concept": "ifrs-full:Equity", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2025-01-01T00:00:00", "unit": "iso4217:USD" } }, "ID_2": { "value": "
Note 1
Accounting principles
Statement of compliance
The consolidated financial statements of DNO ASA have
\u00a0
been
prepared in accordance with IFRS Accounting
\u00a0
Standards as
adopted by the EU and additional disclosure requirements
\u00a0
in the
Norwegian Accounting Act, effective as of 31 December 2024.
The consolidated financial statements were approved
\u00a0
by the
Board of Directors on 2 April 2025.
Basis for preparation
The consolidated financial statements have been prepared
\u00a0
on a
historical cost basis.
As permitted by International Accounting
Standard (IAS) 1
Presentation of Financial Statements
\u00a0
and in
conformity with industry practice,
\u00a0
the expenses in the
consolidated statements of comprehensive income are presented
as a combination of nature and function as this gives
\u00a0
the most
relevant and reliable presentation for the Group.
Due to rounding, the figures in one or more rows
\u00a0
or columns
included in the financial statements
\u00a0
and notes may not add up to
the subtotals or totals of that row or column.
", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_3": { "value": "
Note 1
Accounting principles
Significant accounting estimates and assumptions
The preparation of the Group\u2019s financial statements requires
management to make judgments, estimates and assumptions
\u00a0
that
affect the reported amounts of revenues and expenses, assets
and liabilities, the accompanying disclosures, and the
\u00a0
disclosure
of contingent liabilities at the reporting date. Estimates
\u00a0
and
assumptions are based on management\u2019s best knowledge
\u00a0
and
experience and various other factors that are believed
\u00a0
to be
reasonable under the circumstances. Uncertainty about
\u00a0
these
estimates and assumptions could result in outcomes
\u00a0
that require
a material adjustment to the carrying amount of
\u00a0
assets or
liabilities affected in future periods.
\u00a0
The key assumptions concerning the future and
\u00a0
other key sources
of estimation uncertainty at the reporting date
\u00a0
that have a
significant risk of causing a material adjustment to
\u00a0
the carrying
amounts of assets and liabilities within the next
\u00a0
financial year are
described in the relevant notes throughout this report,
\u00a0
see below
for references to notes. The Group based its assumptions
\u00a0
and
estimates on parameters available when the Group
\u00a0
financial
statements were prepared. However, existing circumstances and
assumptions about future developments may change due
\u00a0
to
market changes or circumstances arising beyond the
\u00a0
control of
the Group. Such changes are reflected in the assumptions
\u00a0
when
they occur.
\u25a0
Estimates and assumptions
The key assumptions and key sources of estimation
\u00a0
uncertainty
\u00a0
for the Group are described in each of the following
\u00a0
notes:
\u2022 Entitlement risk associated with operating in
\u00a0
Kurdistan (Note 3
and 15);
\u2022 Notional corporate income tax/deferred taxation in
\u00a0
Kurdistan
(Note 8);
\u2022 Impairment assessment of capitalized exploration
\u00a0
expenditures
(Note 9);
\u2022 Impairment/reversal of oil and gas assets (Note
\u00a0
11);
\u2022 Application of the acquisition method for business
\u00a0
combinations
(Note 12);
\u2022 Estimation of the cost for decommissioning (Note
\u00a0
20);
\u2022 Reserves and resources estimates (Note 27).
\u00a0
\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Entitlement risk associated with operating in Kurdistan
DNO has interests in two licenses in Kurdistan
\u00a0
through Production Sharing Contracts (PSCs) and
\u00a0
has based its entitlement
calculations on the terms of these PSCs.
\u00a0
The Company notes from public reports that on 15
\u00a0
February 2022, the Federal Supreme Court
\u00a0
of Iraq (FSCI) ruled on two matters,
one stemming back to 2012 and another related
\u00a0
matter dating back to 2019. Reportedly, the FSCI found amongst other
\u00a0
things that
the Kurdistan Oil and Gas Law No. 27/2007 (KOGL)
\u00a0
is unconstitutional, that the KRG is to hand over
\u00a0
all oil production from areas
located in the Kurdistan region of Iraq (KRI) to the
\u00a0
Federal Government of Iraq (FGI) and that
\u00a0
the FGI has the right to pursue
\u00a0
the
nullity of the oil contracts concluded by the KRG.
\u00a0
DNO was not a party to these proceedings.
\u00a0
Further, DNO learned via media reports
that on 4 July 2022, the Karkh commercial court
\u00a0
in Baghdad ruled that PSCs signed between
\u00a0
the KRG and four international oil
companies (including DNO) should be voided. Similar
\u00a0
cases were reported as regards four other international
\u00a0
oil companies over the
ensuing weeks. Media then reported that on 21
\u00a0
August 2022, the KRG filed third party objections
\u00a0
to the reported 2022 Baghdad court
rulings including those understood to concern DNO.
\u00a0
On 18 December 2024, it was reported
\u00a0
that the Karkh Court of Appeal ruled in
favor of inter alia the KRG, confirming that the
\u00a0
PSCs in question were valid. That ruling was
\u00a0
also reported appealed by the FGI,
however, on 22 January 2025, DNO learnt, again from media reports,
\u00a0
that the Court of Cassation dismissed the
\u00a0
FGI\u2019s appeal and
thus confirmed that the PSCs are valid. On 27 February 2025,
\u00a0
there were reports that the FGI had requested
\u00a0
a correction of the
rulings of the Court of Cassation. The Company
\u00a0
notes reports that this process does not allow
\u00a0
the FGI to introduce new evidence or
arguments; it merely seeks to correct perceived
\u00a0
errors in the Court of Cassation\u2019s ruling.
\u00a0
As far as the Company is aware, that
process is still pending. Throughout the period
\u00a0
when these cases were pending, the KRG
\u00a0
issued repeated assurances that the PSCs
remain valid and there were also several rulings
\u00a0
in Erbil courts affirming the validity of the PSCs. In
\u00a0
2014, the FGI initiated an
arbitration case against the Government of T\u00fcrkiye and
\u00a0
its state-owned pipeline operator BOTAS relating to the ITP. Following an
arbitration ruling which became publicly known on
\u00a0
or around 24 March 2023, and which
\u00a0
were in parts in favor of Iraq, the ITP was
closed on 25 March 2023. As of the reporting
\u00a0
date, the ITP remains closed, despite T\u00fcrkiye\u2019s announcement
\u00a0
in October 2023 that
the ITP is ready to resume operations. Timing of export
\u00a0
resumption is uncertain. Consequently, DNO initiated cost reduction
measures in Kurdistan and commenced local sales on
\u00a0
a cash and carry basis, where the oil
\u00a0
is transported by traders by road tanker
or pipelined to local refineries. The contractor
\u00a0
entities\u2019 entitlement is sold by DNO. Varying by contract, local selling prices were
\u00a0
in the
mid USD 30s per barrel during 2024, significantly
\u00a0
lower than the international prices previously
\u00a0
achieved through pipeline export.
However, all local deliveries are prepaid by the buyers directly to
\u00a0
DNO, eliminating counterparty credit risk.
\u00a0
The FGI\u2019s 2023-2025 Federal Iraqi Budget Law (Budget
\u00a0
Law) entered into force in June 2023. The details
\u00a0
of FGI-KRG budget
allocations, implementation of the Budget Law and
\u00a0
the monetary size of the budget transfers to the
\u00a0
KRG are not clear to DNO. DNO
notes however that on 2 February 2025, the
\u00a0
Iraqi Parliament approved amendments of the Budget
\u00a0
Law. There have been several
media reports that indicate that the Budget Law
\u00a0
amendment may enable restart of export of Kurdish
\u00a0
oil through the ITP. DNO and
other member companies of the Association of the
\u00a0
Petroleum Industry of Kurdistan (APIKUR ) have
\u00a0
repeatedly stated that they are
prepared to resume exports, contingent upon reaching
\u00a0
agreements that provide for payment surety for
\u00a0
past and future exports, direct
payment and preservation of the legal, commercial and
\u00a0
economic terms of their production sharing contracts (Conditions).
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
It is unclear to the Company how implementation
\u00a0
of the amended Budget Law can facilitate satisfaction
\u00a0
of the Conditions. It is also
not clear how the KRG and the FGI will address
\u00a0
these matters beyond 2025. To date, DNO continues its operations in Kurdistan, and
developments are closely monitored.
\u00a0
Due to the disagreements between the FGI and
\u00a0
the KRG, economic conditions in Kurdistan and
\u00a0
limited oil export channels, DNO has
historically faced constraints in fully monetizing the oil
\u00a0
it produces in Kurdistan. There is no guarantee
\u00a0
that oil can be exported or sold
locally in sufficient quantities or at prices required to
\u00a0
sustain DNO\u2019s operations and investment plans or
\u00a0
that the Group will promptly
receive its full entitlement payments for any oil it delivers
\u00a0
for export if the ITP reopens. Export sales have
\u00a0
not always followed the
PSC terms. Furthermore, there has also previously
\u00a0
been uncertainty related to receipt of payments
\u00a0
for oil sold to the KRG but
notwithstanding sometimes lengthy delays, payments
\u00a0
have ultimately been received by DNO.
At yearend 2024, the Company was owed a total
\u00a0
of USD 298.1 million, excluding any interest,
\u00a0
by the KRG mainly related to export
oil sales to the KRG for the months October 2022
\u00a0
through March 2023. These receivables are past
\u00a0
due (see Note 15). The KRG has
repeatedly stated that it is and remains committed
\u00a0
to its PSCs. Timing of export resumption and payments for previous
\u00a0
oil sales by
the KRG is uncertain. The Company continues to engage
\u00a0
with the KRG regarding recovery of the
\u00a0
arrears and payment terms and
conditions for any future oil exports.
The Company\u2019s PSCs include rights for the host
\u00a0
government to audit the PSC accounts which
\u00a0
may impact the Company\u2019s recovery
of costs and financial results. During 2024 in
\u00a0
Kurdistan, such audits were carried out with respect
\u00a0
to the Baeshiqa 2018-2019
Accounts and the Tawke 2021 Accounts.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Notional corporate income tax/deferred
\u00a0
taxation in Kurdistan
DNO\u2019s PSCs in Kurdistan provide that the corporate income tax
\u00a0
to which the contractor is subject is deemed
\u00a0
to have been paid to the
government as part of the payment of profit
\u00a0
oil to the government or its representatives.
\u00a0
Current and deferred taxation arising from
such notional corporate income tax is not calculated
\u00a0
for Kurdistan, as there is uncertainty related to
\u00a0
the tax laws of the KRG and
there is currently no well-established tax regime
\u00a0
for international oil companies. As such, it has
\u00a0
not been possible to reliably measure
such notional corporate income taxes deemed to have
\u00a0
been paid on behalf of the Company\u2019s subsidiary, DNO Iraq AS. For
accounting purposes, if such notional income
\u00a0
tax is to be classified as income tax in accordance
\u00a0
with IAS 12
Income Taxes
, the
Group would present this as an income tax expense
\u00a0
with a corresponding increase in revenues.
\u00a0
Furthermore, it would be assessed
whether any deferred tax asset or liability is required
\u00a0
to be recognized equal to the difference between
\u00a0
book values and the tax
values of the qualifying assets and liabilities,
\u00a0
multiplied by the applicable tax rate.
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment assessment of
\u00a0
capitalized exploration expenditures
\u00a0
The Group\u2019s accounting policy is to temporarily capitalize
\u00a0
drilling expenditures related to exploration wells,
\u00a0
pending an evaluation of
potential oil and gas discoveries. If resources are
\u00a0
not discovered, or if recovery of the resources
\u00a0
is not considered technically or
commercially viable, the costs of the exploration wells
\u00a0
are expensed in the income statement. Decisions
\u00a0
as to whether an exploration
well should remain capitalized or expensed during
\u00a0
the period may have a material effect on the financial
\u00a0
results for the period.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment/reversal of impairment
\u00a0
of oil and gas assets
The estimation of the recoverable amount for the
\u00a0
oil and gas assets includes assessments of
\u00a0
expected future cash flows and future
market conditions, including entitlement production,
\u00a0
future oil and gas prices, cost profiles, country
\u00a0
risk factors (i.e., discount rate)
and the date of expiration of the licenses.
\u00a0
The fair value of an asset or a liability is
\u00a0
measured using the assumptions that market participants
\u00a0
would use when pricing the asset
or liability, including assumptions about risk, assuming that market participants
\u00a0
act in their economic best interest. The Group
\u00a0
uses
valuation techniques that are appropriate in
\u00a0
the circumstances and for which sufficient data are available
\u00a0
to measure fair value. The
fair value of oil and gas assets is normally
\u00a0
based on discounted cash flow models (income
\u00a0
approach), where the determination of
different inputs in the model requires significant judgment
\u00a0
from management, as described in the section
\u00a0
above regarding
impairment.
Climate considerations in impairment assessments
Certain climate considerations are factored into
\u00a0
the Group\u2019s estimation of cash flows that are applied in
\u00a0
the calculation of recoverable
amount. This includes factoring in current legislation
\u00a0
(e.g., environmental taxes/fees) and estimation
\u00a0
of future levels of environmental
taxes/fees. For DNO\u2019s oil and gas assets on the NCS,
\u00a0
carbon pricing is in line with current legislation and
\u00a0
reflects the operators
forecasts for individual assets. As proposed in the Norwegian
\u00a0
Government\u2019s Climate Plan for 2021-2030, a steady increase
\u00a0
in the
total carbon price (quota plus CO2 tax) to
\u00a0
NOK 2,000 per tonnes (in 2020 real terms) is
\u00a0
expected by 2030. In Kurdistan, the KRG
introduced in 2021 a requirement for oil companies
\u00a0
to put plans in place to curb gas flaring
\u00a0
to reduce emissions. The Company has
run sensitivities for its Kurdistan oil assets with the
\u00a0
CO2 tax assumptions as described in the scenarios
\u00a0
described by the International
Energy Agency (IEA).
An energy transition is likely to impact future oil
\u00a0
and gas prices which in turn may affect
\u00a0
the recoverable amount of the oil and gas
assets. Indirectly, climate considerations are also assessed in the forecasting of
\u00a0
oil and gas prices where supply and demand
\u00a0
are
considered.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty
The Group applies the acquisition method for transactions
\u00a0
involving business combinations and applies the principles
\u00a0
of the
acquisition method when an interest or an additional
\u00a0
interest is acquired in a joint operation
\u00a0
which constitutes a business. Application
of the acquisition method may require significant judgement
\u00a0
in, among other matters, determining and
\u00a0
measuring the fair value of the
transaction consideration including contingent consideration
\u00a0
elements, identifying all assets acquired and
\u00a0
liabilities assumed,
establishing their fair values, determining deferred taxes,
\u00a0
and allocating the purchase price accordingly, including measurement
\u00a0
and
allocation of goodwill.
\u00a0
The assets acquired through business combinations are
\u00a0
recognized at fair values and, as such, are
\u00a0
sensitive to adverse changes in
a number of often volatile economic factors, including
\u00a0
future oil and gas prices and the underlying
\u00a0
performance of the assets.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Estimation of the cost for
\u00a0
decommissioning
Estimation of the costs for decommissioning is complex
\u00a0
and requires judgement as these estimates
\u00a0
are based on currently
applicable laws, regulations and technology. Decommissioning activities will normally
\u00a0
take place in the distant future, and the
technology, regulatory requirements and related costs may change. The energy transition
\u00a0
may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated decommissioning provisions. Based
\u00a0
on various scenario analysis
performed by the Company, management does not expect any reasonable
\u00a0
change in the expected timeframe to have a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost estimates (i.e., cash flows) remain unchanged.
\u00a0
The estimates
cover expected removal concepts based on known technology
\u00a0
and, in the case of offshore decommissioning, estimated
\u00a0
costs of
maritime operations, hiring of heavy-lift barges and
\u00a0
drilling rigs. As a result, the initial recognition
\u00a0
of the liability and the capitalized
cost associated with decommissioning obligations,
\u00a0
and the subsequent adjustment of these balance
\u00a0
sheet items, involve the
application of significant judgement. Based on
\u00a0
the described uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
\u00a0
\n
\u00a0
\n
Estimation uncertainty
The assessment of the existence and potential quantum
\u00a0
of contingencies inherently involves the exercise
\u00a0
of significant judgment and
the use of estimates regarding the outcome of
\u00a0
future events. Management uses its judgment, and
\u00a0
if necessary also external legal
experts to evaluate certain provisions and legal
\u00a0
disputes in order to ensure the correct accounting
\u00a0
treatment.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Contingencies, provisions
\u00a0
and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or more uncertain future event
\u00a0
occurs or fails to occur. The
assessment of the existence and potential quantum of
\u00a0
contingencies inherently involves the exercise of
\u00a0
significant judgment and the
use of estimates regarding the outcome of future
\u00a0
events. Management uses its judgment to evaluate
\u00a0
certain provisions and legal
disputes in order to ensure the correct accounting
\u00a0
treatment.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Reserves and resources estimates
\u00a0
DNO\u2019s reserves and contingent resources are estimated
\u00a0
and classified by the Company in accordance
\u00a0
with the rules and guidelines
of the Society of Petroleum Engineers (SPE) and are
\u00a0
in conformity with requirements from the Oslo Stock
\u00a0
Exchange for the reporting
of reserves and resources. All estimates of reserves
\u00a0
and resources involve uncertainty.
Important factors that could cause actual results to
\u00a0
differ from the estimates include, but are not limited
\u00a0
to: technical, geological and
geotechnical conditions; economic and market conditions; oil
\u00a0
and gas prices; changes in government regulations;
\u00a0
political
developments; interest rates; and currency exchange
\u00a0
rates. Specific parameters of uncertainty related
\u00a0
to the field/reservoir include
but are not limited to: reservoir pressure and
\u00a0
porosity; recovery factors; water cut development;
\u00a0
production decline rates; gas/oil
ratios; and oil properties.
\u00a0
Changes in commodity prices and costs may impact economic
\u00a0
cut-off and remaining reserves, which may change the
\u00a0
timing of any
decommissioning activities. Future changes to estimated
\u00a0
reserves can also have a material effect on depreciation,
\u00a0
impairment of oil
and gas fields and operating results. The Group
\u00a0
may also not be able to commercially develop
\u00a0
its contingent resources that are used
in impairment assessments or acquisition accounting
\u00a0
where the fair value approach is applied.
", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_4": { "value": "
Principal activities and corporate information
The principal activities of the Group are
international oil and gas
exploration, development and production operations.
DNO\u2019s
activities are mainly undertaken in the Middle East, the North Sea
and West Africa.
DNO ASA
\u00a0
is a Norwegian
public limited liability
\u00a0
company
organized and existing under the laws of
Norway
\u00a0
pursuant to the
Norwegian Public Limited Liability Companies Act
(\u201callmennaksjeloven\u201d). The Company was incorporated
\u00a0
on 6
August 1971 and its registration number is 921
\u00a0
526 121. The
shares in the Company have been listed on the
\u00a0
Oslo Stock
Exchange since 1981, currently under the ticker \"DNO\".
\u00a0
The
Company's registered office is located at
Dokkveien 1, 0250 Oslo,
Norway
.
\u00a0
\u25a0
Statement of compliance
The consolidated financial statements of DNO ASA have
\u00a0
been
prepared in accordance with IFRS Accounting
\u00a0
Standards as
adopted by the EU and additional disclosure requirements
\u00a0
in the
Norwegian Accounting Act, effective as of 31 December 2024.
The consolidated financial statements were approved
\u00a0
by the
Board of Directors on 2 April 2025.
\u25a0
Basis for preparation
The consolidated financial statements have been prepared
\u00a0
on a
historical cost basis.
As permitted by International Accounting
Standard (IAS) 1
Presentation of Financial Statements
\u00a0
and in
conformity with industry practice,
\u00a0
the expenses in the
consolidated statements of comprehensive income are presented
as a combination of nature and function as this gives
\u00a0
the most
relevant and reliable presentation for the Group.
Due to rounding, the figures in one or more rows
\u00a0
or columns
included in the financial statements
\u00a0
and notes may not add up to
the subtotals or totals of that row or column.
\u25a0
Significant accounting estimates and assumptions
The preparation of the Group\u2019s financial statements requires
management to make judgments, estimates and assumptions
\u00a0
that
affect the reported amounts of revenues and expenses, assets
and liabilities, the accompanying disclosures, and the
\u00a0
disclosure
of contingent liabilities at the reporting date. Estimates
\u00a0
and
assumptions are based on management\u2019s best knowledge
\u00a0
and
experience and various other factors that are believed
\u00a0
to be
reasonable under the circumstances. Uncertainty about
\u00a0
these
estimates and assumptions could result in outcomes
\u00a0
that require
a material adjustment to the carrying amount of
\u00a0
assets or
liabilities affected in future periods.
\u00a0
The key assumptions concerning the future and
\u00a0
other key sources
of estimation uncertainty at the reporting date
\u00a0
that have a
significant risk of causing a material adjustment to
\u00a0
the carrying
amounts of assets and liabilities within the next
\u00a0
financial year are
described in the relevant notes throughout this report,
\u00a0
see below
for references to notes. The Group based its assumptions
\u00a0
and
estimates on parameters available when the Group
\u00a0
financial
statements were prepared. However, existing circumstances and
assumptions about future developments may change due
\u00a0
to
market changes or circumstances arising beyond the
\u00a0
control of
the Group. Such changes are reflected in the assumptions
\u00a0
when
they occur.
\u25a0
Estimates and assumptions
The key assumptions and key sources of estimation
\u00a0
uncertainty
\u00a0
for the Group are described in each of the following
\u00a0
notes:
\u2022 Entitlement risk associated with operating in
\u00a0
Kurdistan (Note 3
and 15);
\u2022 Notional corporate income tax/deferred taxation in
\u00a0
Kurdistan
(Note 8);
\u2022 Impairment assessment of capitalized exploration
\u00a0
expenditures
(Note 9);
\u2022 Impairment/reversal of oil and gas assets (Note
\u00a0
11);
\u2022 Application of the acquisition method for business
\u00a0
combinations
(Note 12);
\u2022 Estimation of the cost for decommissioning (Note
\u00a0
20);
\u2022 Reserves and resources estimates (Note 27).
\u25a0
Group accounting and consolidation principles
Basis for consolidation
The consolidated financial statements include the financial
statements of DNO ASA and its subsidiaries. The Company
currently holds a 100 percent interest in all
\u00a0
of its subsidiaries.
\u25a0
Functional and presentational currency
The consolidated financial statements are presented
\u00a0
in USD,
\u00a0
which is also DNO ASA\u2019s functional currency and presentation
currency.
\u00a0
Statements of comprehensive income and statements of
\u00a0
cash
flows of subsidiaries and joint operations that have
\u00a0
a functional
currency different from the parent company are translated
\u00a0
into the
presentation currency at average exchange rates
\u00a0
each month.
Statements of financial position items are translated using
\u00a0
the
exchange rate at the reporting date, with the
\u00a0
translation
differences taken directly to other comprehensive income.
\u25a0
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO
\u00a0
holds a long-term
interest which is jointly controlled by DNO and
\u00a0
one or more other
parties under a contractual arrangement in which
\u00a0
decisions about
the relevant activities require the unanimous
\u00a0
consent of the
parties sharing control. Such joint arrangements are classified
\u00a0
as
either joint operations or joint ventures.
\u00a0
Joint operations
DNO recognizes its investments in joint operations
\u00a0
by reporting its
share of related revenues, expenses, assets, liabilities
\u00a0
and cash
flows under the respective items in the Group's
\u00a0
financial
statements.
\u00a0
Joint ventures
The Group\u2019s investments in a joint venture are accounted
\u00a0
for
using the equity method in accordance with
IAS 28 Investments in
Associates and Joint Ventures
.
\u00a0
\u25a0
License acquisitions, farm-in/out and swaps
Individual assessment is made whether the acquisition
\u00a0
of an oil
and gas license should be treated as a business combination
\u00a0
or
as an asset purchase. Generally, purchase of a license in
development or production phase is regarded as
\u00a0
a business
combination, while purchase of a license in the exploration
\u00a0
phase
is regarded as an asset purchase.
A farm-in or farm-out of an oil and gas license
\u00a0
takes place when
the owner of a working interest (the farmor)
\u00a0
transfers all or a
portion of its working interest to another party
\u00a0
(the farmee) in
return for an agreed upon consideration and/or
\u00a0
action, such as
conducting subsurface studies, drilling wells or developing
\u00a0
the
asset. Any cash consideration received directly from
\u00a0
the farmee is
credited against costs previously capitalized in relation
\u00a0
to the
whole interest with any excess accounted for by
\u00a0
the farmor as a
gain on disposal.
\u00a0
In the development or production phase, a farm-in/farm-out
agreement will be treated as a transaction recorded
\u00a0
at fair value
as represented by the costs carried by the farmee.
\u00a0
Any gain or
loss arising from the farm-in/farm-out is recognized
\u00a0
in the
statements of comprehensive income.
\u00a0
License swaps are measured at the fair value of
\u00a0
the asset being
exchanged, unless the transaction lacks commercial substance,
or neither the fair value of the asset received, nor
\u00a0
divested, can
be reliably measured. In the exploration phase,
\u00a0
the Group
normally recognizes license swaps based on historical
\u00a0
cost basis.
\u25a0
Changes in accounting policies
The accounting policies adopted are consistent with
\u00a0
those of the
previous financial year.
\u00a0
Other amendments and interpretations may apply
\u00a0
for the first time
in 2024 but are not considered to have any material
\u00a0
impact on the
Group\u2019s financial statements.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Segment information
DNO\u2019s operating segments correspond to its reportable
\u00a0
segments. The Company identifies and reports
\u00a0
its segments based on the
nature of the risk and return within its business
\u00a0
and by the geographical location of the Group\u2019s
\u00a0
assets and operations. The segment
information is provided to the senior management
\u00a0
and the Board of Directors who are considered
\u00a0
to collectively be the Chief
Operating Decision Maker and is used as the basis
\u00a0
for allocation of resources and decision
\u00a0
making.
The accounting policies of the reporting segments
\u00a0
equal those described in these consolidated
\u00a0
financial statements. Transfer pricing
between the segments and companies is set using
\u00a0
the arm\u2019s length principle in a manner similar to transactions
\u00a0
with third parties and
are eliminated at the consolidated level. Segment profit/loss
\u00a0
includes profit/loss from inter-segment sales.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Revenues
Revenues presented in the consolidated statements
\u00a0
of comprehensive income consist of Revenue
\u00a0
from contracts with customers.
Revenue from contracts with customers is recognized
\u00a0
when the customer obtains control of the oil
\u00a0
and gas, which normally will be
when title passes at the point of delivery, based on the contractual terms of
\u00a0
the agreements.
In general, the revenues from the Group\u2019s production of oil
\u00a0
and gas are recognized on the basis of
\u00a0
volumes lifted and sold to
customers during the period (the sales method).
Tariff income from processing of oil and gas is related to the North Sea segment and is
\u00a0
recognized as earned.
Revenue recognition in Kurdistan
\u00a0
During 2024 and most of 2023, revenues in
\u00a0
Kurdistan were generated from local sales and recognized
\u00a0
on the basis of volumes lifted
and sold to customers during the period. Local deliveries
\u00a0
are prepaid by the buyers directly to DNO.
Export revenues in Kurdistan were in the first three
\u00a0
months of 2023 generated through the sale of oil
\u00a0
produced from the Tawke and
the Baeshiqa licenses which was exported by
\u00a0
the pipeline through T\u00fcrkiye. Title to the oil was considered
\u00a0
to have passed on delivery
of oil to the export pipeline at Fish Khabur
\u00a0
terminal. Revenues generated from export sales
\u00a0
were recognized on the basis of invoiced
oil sales following monthly deliveries to the KRG.
\u00a0
Based on business practice, the KRG was
\u00a0
responsible for exporting the oil
produced in Kurdistan and it is assessed that
\u00a0
DNO has a customer relationship with
\u00a0
the KRG. The price for export oil deliveries to
the KRG was based on Brent prices with
\u00a0
adjustments for oil quality and transportation
\u00a0
fees.
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Entitlement risk associated with operating in Kurdistan
DNO has interests in two licenses in Kurdistan
\u00a0
through Production Sharing Contracts (PSCs) and
\u00a0
has based its entitlement
calculations on the terms of these PSCs.
\u00a0
The Company notes from public reports that on 15
\u00a0
February 2022, the Federal Supreme Court
\u00a0
of Iraq (FSCI) ruled on two matters,
one stemming back to 2012 and another related
\u00a0
matter dating back to 2019. Reportedly, the FSCI found amongst other
\u00a0
things that
the Kurdistan Oil and Gas Law No. 27/2007 (KOGL)
\u00a0
is unconstitutional, that the KRG is to hand over
\u00a0
all oil production from areas
located in the Kurdistan region of Iraq (KRI) to the
\u00a0
Federal Government of Iraq (FGI) and that
\u00a0
the FGI has the right to pursue
\u00a0
the
nullity of the oil contracts concluded by the KRG.
\u00a0
DNO was not a party to these proceedings.
\u00a0
Further, DNO learned via media reports
that on 4 July 2022, the Karkh commercial court
\u00a0
in Baghdad ruled that PSCs signed between
\u00a0
the KRG and four international oil
companies (including DNO) should be voided. Similar
\u00a0
cases were reported as regards four other international
\u00a0
oil companies over the
ensuing weeks. Media then reported that on 21
\u00a0
August 2022, the KRG filed third party objections
\u00a0
to the reported 2022 Baghdad court
rulings including those understood to concern DNO.
\u00a0
On 18 December 2024, it was reported
\u00a0
that the Karkh Court of Appeal ruled in
favor of inter alia the KRG, confirming that the
\u00a0
PSCs in question were valid. That ruling was
\u00a0
also reported appealed by the FGI,
however, on 22 January 2025, DNO learnt, again from media reports,
\u00a0
that the Court of Cassation dismissed the
\u00a0
FGI\u2019s appeal and
thus confirmed that the PSCs are valid. On 27 February 2025,
\u00a0
there were reports that the FGI had requested
\u00a0
a correction of the
rulings of the Court of Cassation. The Company
\u00a0
notes reports that this process does not allow
\u00a0
the FGI to introduce new evidence or
arguments; it merely seeks to correct perceived
\u00a0
errors in the Court of Cassation\u2019s ruling.
\u00a0
As far as the Company is aware, that
process is still pending. Throughout the period
\u00a0
when these cases were pending, the KRG
\u00a0
issued repeated assurances that the PSCs
remain valid and there were also several rulings
\u00a0
in Erbil courts affirming the validity of the PSCs. In
\u00a0
2014, the FGI initiated an
arbitration case against the Government of T\u00fcrkiye and
\u00a0
its state-owned pipeline operator BOTAS relating to the ITP. Following an
arbitration ruling which became publicly known on
\u00a0
or around 24 March 2023, and which
\u00a0
were in parts in favor of Iraq, the ITP was
closed on 25 March 2023. As of the reporting
\u00a0
date, the ITP remains closed, despite T\u00fcrkiye\u2019s announcement
\u00a0
in October 2023 that
the ITP is ready to resume operations. Timing of export
\u00a0
resumption is uncertain. Consequently, DNO initiated cost reduction
measures in Kurdistan and commenced local sales on
\u00a0
a cash and carry basis, where the oil
\u00a0
is transported by traders by road tanker
or pipelined to local refineries. The contractor
\u00a0
entities\u2019 entitlement is sold by DNO. Varying by contract, local selling prices were
\u00a0
in the
mid USD 30s per barrel during 2024, significantly
\u00a0
lower than the international prices previously
\u00a0
achieved through pipeline export.
However, all local deliveries are prepaid by the buyers directly to
\u00a0
DNO, eliminating counterparty credit risk.
\u00a0
The FGI\u2019s 2023-2025 Federal Iraqi Budget Law (Budget
\u00a0
Law) entered into force in June 2023. The details
\u00a0
of FGI-KRG budget
allocations, implementation of the Budget Law and
\u00a0
the monetary size of the budget transfers to the
\u00a0
KRG are not clear to DNO. DNO
notes however that on 2 February 2025, the
\u00a0
Iraqi Parliament approved amendments of the Budget
\u00a0
Law. There have been several
media reports that indicate that the Budget Law
\u00a0
amendment may enable restart of export of Kurdish
\u00a0
oil through the ITP. DNO and
other member companies of the Association of the
\u00a0
Petroleum Industry of Kurdistan (APIKUR ) have
\u00a0
repeatedly stated that they are
prepared to resume exports, contingent upon reaching
\u00a0
agreements that provide for payment surety for
\u00a0
past and future exports, direct
payment and preservation of the legal, commercial and
\u00a0
economic terms of their production sharing contracts (Conditions).
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
It is unclear to the Company how implementation
\u00a0
of the amended Budget Law can facilitate satisfaction
\u00a0
of the Conditions. It is also
not clear how the KRG and the FGI will address
\u00a0
these matters beyond 2025. To date, DNO continues its operations in Kurdistan, and
developments are closely monitored.
\u00a0
Due to the disagreements between the FGI and
\u00a0
the KRG, economic conditions in Kurdistan and
\u00a0
limited oil export channels, DNO has
historically faced constraints in fully monetizing the oil
\u00a0
it produces in Kurdistan. There is no guarantee
\u00a0
that oil can be exported or sold
locally in sufficient quantities or at prices required to
\u00a0
sustain DNO\u2019s operations and investment plans or
\u00a0
that the Group will promptly
receive its full entitlement payments for any oil it delivers
\u00a0
for export if the ITP reopens. Export sales have
\u00a0
not always followed the
PSC terms. Furthermore, there has also previously
\u00a0
been uncertainty related to receipt of payments
\u00a0
for oil sold to the KRG but
notwithstanding sometimes lengthy delays, payments
\u00a0
have ultimately been received by DNO.
At yearend 2024, the Company was owed a total
\u00a0
of USD 298.1 million, excluding any interest,
\u00a0
by the KRG mainly related to export
oil sales to the KRG for the months October 2022
\u00a0
through March 2023. These receivables are past
\u00a0
due (see Note 15). The KRG has
repeatedly stated that it is and remains committed
\u00a0
to its PSCs. Timing of export resumption and payments for previous
\u00a0
oil sales by
the KRG is uncertain. The Company continues to engage
\u00a0
with the KRG regarding recovery of the
\u00a0
arrears and payment terms and
conditions for any future oil exports.
The Company\u2019s PSCs include rights for the host
\u00a0
government to audit the PSC accounts which
\u00a0
may impact the Company\u2019s recovery
of costs and financial results. During 2024 in
\u00a0
Kurdistan, such audits were carried out with respect
\u00a0
to the Baeshiqa 2018-2019
Accounts and the Tawke 2021 Accounts.
\u00a0
\n
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\n
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Cost of goods sold
Lifting costs and Tariff and transportation expenses
Lifting costs consist of expenses related to the production
\u00a0
of oil and gas, including operation and maintenance
\u00a0
of installations, well
intervention activities and insurances. Tariff and transportation expenses consist of charges
\u00a0
incurred by the Group in the North Sea
for the use of infrastructure owned by other
\u00a0
companies. Lifting costs and Tariff and transportation expenses are recognized based on
the Group\u2019s paying interest in the oil and gas licenses.
\u00a0
Movement in overlift/underlift
A liability (overlift, see Note 22) arises when the
\u00a0
Group sells more than its share of the oil and
\u00a0
gas production. Similarly, an asset
(underlift, see Note 15) arises when the sale
\u00a0
is less than the Group\u2019s share of the oil and gas production.
\u00a0
In general, the
overlift/underlift balances are valued at production
\u00a0
cost including depreciation (the sales method). The
\u00a0
movements in overlift/underlift
are presented as an adjustment to Cost of
\u00a0
goods sold.
\u00a0
Depreciation, depletion and amortization
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the unit-of-production (UoP) method. See
\u00a0
Note 10 for more details.
\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Pensions and share-based payments
Pensions
The Group\u2019s pension obligations in Norway are limited
\u00a0
to certain defined contribution plans which are
\u00a0
paid to pension insurance
plans and charged to profit or loss in the period
\u00a0
in which they are incurred. Once the contributions
\u00a0
are paid there are no further
obligations.
Share-based payments
Cash-settled share-based payments are recognized in
\u00a0
the income statement as expenses during the
\u00a0
vesting period and as a liability.
The liability is measured at fair value and revaluated
\u00a0
using the Black & Scholes pricing model at each balance
\u00a0
sheet date and at the
date of settlement, with any change in the fair
\u00a0
value recognized in the income statement for
\u00a0
the period.
\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Exploration expenses
The Group uses the successful efforts method to account for
\u00a0
its exploration and evaluation assets. All
\u00a0
exploration costs (including
purchase of seismic, geological and geophysical
\u00a0
costs and general and administrative costs),
\u00a0
except for acquisition costs of licenses
and drilling costs of exploration wells, are expensed
\u00a0
as incurred.
\u00a0
Acquisition costs of licenses and drilling costs
\u00a0
of exploration wells are temporarily capitalized
\u00a0
pending the determination of oil and
gas resources. These costs include directly attributable
\u00a0
employee remuneration, materials and fuel used,
\u00a0
rig costs and payments to
contractors. Continued capitalization of such costs is
\u00a0
assessed for impairment at each reporting
\u00a0
date. The main criterion is that there
must be plans for future activity in the license or
\u00a0
that a development decision is expected in
\u00a0
the near future. If reserves or resources
are not found, or if discoveries are assessed
\u00a0
not technically or commercially recoverable,
\u00a0
the costs of exploration wells and licenses
are expensed. Furthermore, 3D seismic cost over
\u00a0
a discovery area is capitalized when the
\u00a0
objective is to learn more about the
reservoir and to support the determination of new
\u00a0
well locations within the discovery area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Financial income and expenses
Accretion expenses from unwinding of the discount
\u00a0
related to the ARO provision and lease
\u00a0
liability are further detailed in Notes 19
and Note 20. Accounting effects from IFRS 9 (expected
\u00a0
credit loss model) assessment related to the
\u00a0
KRG arrears is further detailed
in Note 15.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Income taxes
Tax income/expense consists of taxes receivable/payable and changes in deferred taxes. Taxes receivable/payable are based on
the amount receivable from or payable to the tax
\u00a0
authorities. Deferred tax liability is calculated
\u00a0
on all taxable temporary differences
unless there is a recognition exception. A deferred
\u00a0
tax asset is recognized only to the extent
\u00a0
that it is probable that the future taxable
income will be available against which the asset
\u00a0
can be utilized. Unrecognized deferred tax assets
\u00a0
are reassessed at each reporting
date and are recognized to the extent that it has
\u00a0
become probable that future taxable profits will
\u00a0
allow the deferred tax asset to be
recovered. Deferred tax assets and deferred
\u00a0
tax liabilities are recognized at their nominal
\u00a0
value and classified as non-current
assets/liabilities in the statements of financial position.
\u00a0
Tax payable and deferred tax are recognized directly in the equity to the
extent that they relate to items charged directly to equity.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Notional corporate income tax/deferred
\u00a0
taxation in Kurdistan
DNO\u2019s PSCs in Kurdistan provide that the corporate income tax
\u00a0
to which the contractor is subject is deemed
\u00a0
to have been paid to the
government as part of the payment of profit
\u00a0
oil to the government or its representatives.
\u00a0
Current and deferred taxation arising from
such notional corporate income tax is not calculated
\u00a0
for Kurdistan, as there is uncertainty related to
\u00a0
the tax laws of the KRG and
there is currently no well-established tax regime
\u00a0
for international oil companies. As such, it has
\u00a0
not been possible to reliably measure
such notional corporate income taxes deemed to have
\u00a0
been paid on behalf of the Company\u2019s subsidiary, DNO Iraq AS. For
accounting purposes, if such notional income
\u00a0
tax is to be classified as income tax in accordance
\u00a0
with IAS 12
Income Taxes
, the
Group would present this as an income tax expense
\u00a0
with a corresponding increase in revenues.
\u00a0
Furthermore, it would be assessed
whether any deferred tax asset or liability is required
\u00a0
to be recognized equal to the difference between
\u00a0
book values and the tax
values of the qualifying assets and liabilities,
\u00a0
multiplied by the applicable tax rate.
\u00a0
\n
\u00a0
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\n
\u00a0
\n
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\u00a0
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\u00a0
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\u00a0
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\u00a0
\n
\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
Intangible assets
General
Intangible assets are stated at cost, less accumulated
\u00a0
amortization and accumulated impairment charges.
\u00a0
Intangible assets include
acquisition costs for oil and gas licenses, expenditures
\u00a0
on the exploration for oil and gas resources,
\u00a0
technical goodwill and other
intangible assets. Goodwill is not depreciated.
\u00a0
The useful lives of intangible assets are assessed
\u00a0
as either finite or infinite. Amortization of
\u00a0
intangible assets is based on the
expected useful economic life and assessed for
\u00a0
impairment whenever there is an indication that the intangible
\u00a0
asset might be
impaired. The impairment assessment of intangible assets
\u00a0
with infinite lives is undertaken annually or
\u00a0
more often if indicators exist.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Goodwill
The goodwill that is recognized by the Group is related
\u00a0
to technical goodwill and is recognized
\u00a0
due to the requirement to recognize
deferred tax for the difference between the assigned fair
\u00a0
values and the related tax base. Although not
\u00a0
an IFRS term, \u201ctechnical
goodwill\u201d is commonly used in the oil and gas
\u00a0
industry to describe a category of goodwill
\u00a0
arising as an offsetting amount to deferred
tax recognized in business combinations. There are
\u00a0
no specific IFRS guidelines about the allocation
\u00a0
of technical goodwill, and the
Group has therefore applied the general guidelines
\u00a0
for allocating goodwill. In general, technical goodwill
\u00a0
is allocated to a cash-
generating unit (CGU) or group of CGUs that give
\u00a0
rise to the technical goodwill, while any residual
\u00a0
goodwill may be allocated across
all CGUs based on facts and circumstances in
\u00a0
the business combination.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its exploration and evaluation assets. Acquisition
\u00a0
costs of licenses and
drilling costs of exploration wells are temporarily
\u00a0
capitalized pending the determination of oil and
\u00a0
gas resources. These costs include
directly attributable employee remuneration, materials
\u00a0
and fuel used, rig costs and payments to contractors.
\u00a0
Continued capitalization
of such costs is assessed for impairment at each
\u00a0
reporting date. The main criterion is that there
\u00a0
must be plans for future activity in
the license or that a development decision is expected
\u00a0
in the near future. If reserves or resources
\u00a0
are not found, or if discoveries are
assessed not technically or commercially recoverable,
\u00a0
the costs of exploration wells and licenses are
\u00a0
expensed. Furthermore, 3D
seismic costs over a discovery area is capitalized
\u00a0
when the objective is to learn more about
\u00a0
the reservoir and to support the
determination of new well locations within the discovery
\u00a0
area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment assessment of
\u00a0
capitalized exploration expenditures
\u00a0
The Group\u2019s accounting policy is to temporarily capitalize
\u00a0
drilling expenditures related to exploration wells,
\u00a0
pending an evaluation of
potential oil and gas discoveries. If resources are
\u00a0
not discovered, or if recovery of the resources
\u00a0
is not considered technically or
commercially viable, the costs of the exploration wells
\u00a0
are expensed in the income statement. Decisions
\u00a0
as to whether an exploration
well should remain capitalized or expensed during
\u00a0
the period may have a material effect on the financial
\u00a0
results for the period.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Property, plant and equipment (PP&E)
General
PP&E are recognized at historical cost and adjusted
\u00a0
for depreciation, depletion and amortization
\u00a0
(DD&A) and impairment charges.
\u00a0
Depreciation of PP&E other than oil and gas assets
\u00a0
are generally depreciated on a straight-line basis
\u00a0
over expected useful lives,
normally varying from three to seven years. Expected
\u00a0
useful lives are reviewed at each balance
\u00a0
sheet date and, where there are
changes in estimates, depreciation periods are changed
\u00a0
accordingly.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Exploration and development costs
\u00a0
Capitalized exploration expenditures are classified as
\u00a0
intangible assets and reclassified to tangible
\u00a0
assets (i.e., PP&E) at the start of
the development. For accounting purposes, an oil
\u00a0
and gas field is considered to enter the development
\u00a0
phase when the technical
feasibility and commercial viability of extracting oil and
\u00a0
gas from the field are demonstrable. All
\u00a0
costs of developing commercial oil
and gas fields are capitalized, including indirect
\u00a0
costs. Capitalized development costs are classified
\u00a0
as tangible assets.
\u00a0
Acquired license rights are recognized as intangible
\u00a0
assets at the time of acquisition. Acquired
\u00a0
license rights related to fields in the
exploration phase remain as intangible assets when
\u00a0
the related fields enter the development or
\u00a0
production phase. Furthermore, 3D
seismic cost over a discovery area is capitalized
\u00a0
when the objective is to learn more about
\u00a0
the reservoir and to support the
determination of new well locations within the discovery
\u00a0
area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Oil and gas assets in production
\u00a0
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the UoP method. The rate of depreciation
\u00a0
is equal to the ratio of oil
and gas production for the period over the estimated
\u00a0
remaining 2P reserves at the beginning of
\u00a0
the period. The future development
expenditures necessary to bring those reserves into
\u00a0
production are included in the basis for depreciation
\u00a0
and are estimated by the
management based on current period end un-escalated
\u00a0
price levels. The reserve basis used for depreciation
\u00a0
purposes is updated at
least once a year. Any changes in the reserves affecting UoP calculations
\u00a0
are reflected prospectively. Reserves and resources,
along with associated estimation uncertainty, are described in detail in Note
\u00a0
27.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Right-of-use (RoU) asset
s
\u00a0
The RoU assets in the balance sheet are mainly
\u00a0
related to office rent and are measured to cost, less
\u00a0
any accumulated depreciation
and impairment losses, and adjusted for any remeasurement
\u00a0
of lease liabilities. The RoU assets are depreciated
\u00a0
linearly over the
lifetime of the related lease contract. For measurement
\u00a0
of lease liabilities, see Note 19. In the
\u00a0
consolidated statements of
comprehensive income, operating lease costs, relating
\u00a0
to contracts that contain a lease, are replaced
\u00a0
by depreciation and interest
expense.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Impairments
At the end of each reporting period, the Group
\u00a0
assesses whether there is any indication that an
\u00a0
asset may be impaired. If an
impairment indicator is concluded to exist, an impairment
\u00a0
test is performed.
\u00a0
Indications of impairment may include a decline
\u00a0
in the long-term oil and gas price (or short-term
\u00a0
oil and gas price for late-life oil and
gas fields), changes in future investments or significant
\u00a0
downward revision of reserve and resource
\u00a0
estimates. For the purposes of
impairment assessment, assets are grouped at the
\u00a0
lowest levels for which there are separable identifiable
\u00a0
cash inflows. For oil and
gas assets, a CGU may be individual oil and
\u00a0
gas fields, or a group of oil and gas fields
\u00a0
that are connected to the same
infrastructure/production facilities, or a license.
\u00a0
An impairment loss is recognized when the carrying
\u00a0
amount exceeds the recoverable amount of an
\u00a0
asset. The recoverable amount is
the higher of the asset\u2019s fair value less costs to sell
\u00a0
and its value in use. Fair value less costs
\u00a0
to sell determined through either the
discounted cash flow method (income approach) or
\u00a0
the market transactions method (market approach).
\u00a0
The value in use can only be
determined through the discounted cash flow method.
Technical goodwill
\u00a0
Technical goodwill is tested for impairment annually or more frequently when there are
\u00a0
impairment indicators. Those indicators may
be specific to an individual CGU or groups of
\u00a0
CGUs to which the technical goodwill is
\u00a0
related. Goodwill is not depreciated and hence,
impairment of technical goodwill is expected on
\u00a0
a recurring basis, unless there are positive
\u00a0
changes in underlying assumptions that
more than offset the production from the CGU (or
\u00a0
groups of CGUs).
\u00a0
When performing the impairment test for technical
\u00a0
goodwill, deferred tax recognized in relation to
\u00a0
the acquired assets in a business
combination reduces the net carrying value prior
\u00a0
to the impairment charges. After initial recognition,
\u00a0
depreciation of values calculated
in the purchase price allocations from business
\u00a0
combinations will result in decreased deferred tax
\u00a0
liability. When deferred tax from
the initial recognition decreases, more goodwill is exposed
\u00a0
for impairment.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment/reversal of impairment
\u00a0
of oil and gas assets
The estimation of the recoverable amount for the
\u00a0
oil and gas assets includes assessments of
\u00a0
expected future cash flows and future
market conditions, including entitlement production,
\u00a0
future oil and gas prices, cost profiles, country
\u00a0
risk factors (i.e., discount rate)
and the date of expiration of the licenses.
\u00a0
The fair value of an asset or a liability is
\u00a0
measured using the assumptions that market participants
\u00a0
would use when pricing the asset
or liability, including assumptions about risk, assuming that market participants
\u00a0
act in their economic best interest. The Group
\u00a0
uses
valuation techniques that are appropriate in
\u00a0
the circumstances and for which sufficient data are available
\u00a0
to measure fair value. The
fair value of oil and gas assets is normally
\u00a0
based on discounted cash flow models (income
\u00a0
approach), where the determination of
different inputs in the model requires significant judgment
\u00a0
from management, as described in the section
\u00a0
above regarding
impairment.
Climate considerations in impairment assessments
Certain climate considerations are factored into
\u00a0
the Group\u2019s estimation of cash flows that are applied in
\u00a0
the calculation of recoverable
amount. This includes factoring in current legislation
\u00a0
(e.g., environmental taxes/fees) and estimation
\u00a0
of future levels of environmental
taxes/fees. For DNO\u2019s oil and gas assets on the NCS,
\u00a0
carbon pricing is in line with current legislation and
\u00a0
reflects the operators
forecasts for individual assets. As proposed in the Norwegian
\u00a0
Government\u2019s Climate Plan for 2021-2030, a steady increase
\u00a0
in the
total carbon price (quota plus CO2 tax) to
\u00a0
NOK 2,000 per tonnes (in 2020 real terms) is
\u00a0
expected by 2030. In Kurdistan, the KRG
introduced in 2021 a requirement for oil companies
\u00a0
to put plans in place to curb gas flaring
\u00a0
to reduce emissions. The Company has
run sensitivities for its Kurdistan oil assets with the
\u00a0
CO2 tax assumptions as described in the scenarios
\u00a0
described by the International
Energy Agency (IEA).
An energy transition is likely to impact future oil
\u00a0
and gas prices which in turn may affect
\u00a0
the recoverable amount of the oil and gas
assets. Indirectly, climate considerations are also assessed in the forecasting of
\u00a0
oil and gas prices where supply and demand
\u00a0
are
considered.
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Business combinations
In accordance with IFRS 3 Business Combinations,
\u00a0
an acquisition is considered a business combination,
\u00a0
when the acquired asset or
groups of assets constitute a business (i.e., an integrated
\u00a0
set of operations and assets conducted and
\u00a0
managed for the purpose of
providing a return to the investors).
Acquired businesses are included in the financial statements
\u00a0
from the transaction date. The transaction date
\u00a0
is defined as the date
on which the Group achieves control over the
\u00a0
financial and operating assets. This date may
\u00a0
differ from the actual date on which the
assets are transferred.
For accounting purposes, the acquisition method is used
\u00a0
in connection with the purchase of businesses.
\u00a0
Acquisition cost equals the
fair value of the assets used as consideration, including
\u00a0
contingent consideration, equity instruments issued
\u00a0
and liabilities assumed
in connection with the transfer of control. Acquisition
\u00a0
cost is measured against the fair value of the acquired
\u00a0
assets and assumed
liabilities. Identifiable intangible assets are included
\u00a0
in connection with acquisitions if they can be
\u00a0
separated from other assets or
meet the legal contractual criteria. If the acquisition
\u00a0
cost at the time of the acquisition exceeds
\u00a0
the fair value of the acquired net
assets (when the acquiring entity achieves control
\u00a0
of the transferring entity), goodwill arises. If the
\u00a0
fair value of the acquired net
assets exceeds the acquisition cost on the acquisition
\u00a0
date, the excess amount is taken to profit
\u00a0
or loss immediately.
\u00a0
Goodwill is allocated to the CGUs or groups of
\u00a0
CGUs that are expected to benefit from
\u00a0
synergy effects of the acquisition. The
allocation of goodwill may vary depending on the
\u00a0
basis of its initial recognition.
The goodwill that is recognized by the Group is related
\u00a0
to technical goodwill and is recognized
\u00a0
due to the requirement to recognize
deferred tax for the difference between the assigned fair
\u00a0
values and the related tax base. The fair
\u00a0
values of the Group\u2019s licenses in
the North Sea are based on cash flows after tax. This
\u00a0
is because these licenses are sold only on
\u00a0
an after-tax basis. The purchaser is
therefore not entitled to a tax deduction for the
\u00a0
consideration paid above the seller\u2019s tax
\u00a0
values. In accordance with IAS 12, a
provision is made for deferred tax corresponding
\u00a0
to the tax rate multiplied by the difference between
\u00a0
the fair values of the acquired
assets and the transferred tax depreciation basis.
\u00a0
The offsetting entry to this deferred tax is goodwill. Hence,
\u00a0
goodwill arises as a
technical effect of deferred tax. Technical goodwill is tested for impairment separately for each CGU
\u00a0
which gives rise to the technical
goodwill. A CGU may be individual oil fields, or a
\u00a0
group of oil fields that are connected to
\u00a0
the same infrastructure/production facilities,
or a license.
The estimation of fair value may be adjusted up
\u00a0
to 12 months after the acquisition date if new
\u00a0
information emerges about facts and
circumstances that existed at the time of the
\u00a0
takeover and which, had they been known, would
\u00a0
have affected the calculation of the
amounts that were included from that date.
Acquisition-related costs, except costs to issue debt
\u00a0
or equity securities, are expensed as incurred.
\u00a0
Taxes payable and deferred
taxes are recognized directly in the equity to
\u00a0
the extent that they relate to items charged
\u00a0
directly to the equity.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty
The Group applies the acquisition method for transactions
\u00a0
involving business combinations and applies the principles
\u00a0
of the
acquisition method when an interest or an additional
\u00a0
interest is acquired in a joint operation
\u00a0
which constitutes a business. Application
of the acquisition method may require significant judgement
\u00a0
in, among other matters, determining and
\u00a0
measuring the fair value of the
transaction consideration including contingent consideration
\u00a0
elements, identifying all assets acquired and
\u00a0
liabilities assumed,
establishing their fair values, determining deferred taxes,
\u00a0
and allocating the purchase price accordingly, including measurement
\u00a0
and
allocation of goodwill.
\u00a0
The assets acquired through business combinations are
\u00a0
recognized at fair values and, as such, are
\u00a0
sensitive to adverse changes in
a number of often volatile economic factors, including
\u00a0
future oil and gas prices and the underlying
\u00a0
performance of the assets.
\u00a0
\n
\u00a0
\n
\u00a0
\n
Joint Venture
The Group\u2019s investments in a joint venture are accounted
\u00a0
for using the equity method. The income statement
\u00a0
reflects the Group\u2019s
share of the results of operations in the joint
\u00a0
venture. The financial statements of the joint
\u00a0
venture are prepared for the same
reporting period as the Group. When necessary, adjustments are made
\u00a0
to bring the accounting policies in line with
\u00a0
those of the
Group.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Inventories
Inventories comprise of drilling equipment, spare parts
\u00a0
and consumables for own use and are valued
\u00a0
at the lower of cost and net
realizable value. Inventories that meet the definition of
\u00a0
PP&E are presented under the PP&E and are
\u00a0
depreciated as part of the
underlying capitalized asset using the UoP method.
Accounting policies
Trade debtors
Trade debtors are recognized at nominal value less any provisions
\u00a0
for expected credit losses (ECL). ECLs are based
\u00a0
on the
difference between the contractual cash flows due in accordance
\u00a0
with the contract and all the (discounted)
\u00a0
cash flows that are
expected to be received (i.e., cash shortfalls).
\u00a0
ECLs on trade receivables are measured by applying
\u00a0
either the general model or the
simplified model. A company must apply the simplified
\u00a0
model for trade receivables, which, when
\u00a0
invoiced, were without a significant
financing component. This applies to the Company\u2019s oil
\u00a0
and gas sales and hence the simplified model
\u00a0
is applied in respect of the
ELC assessment of the Kurdistan trade debtors (see below).
Overlift/underlift
An underlift arises when the sale is less
\u00a0
than the Group\u2019s share of the oil and gas production.
\u00a0
In general, the overlift/underlift
balances are valued at production cost including
\u00a0
depreciation (the sales method). For overlift, see Note
\u00a0
22.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Cash and cash equivalents
Cash and short-term deposits in the statements
\u00a0
of financial position comprise cash held in banks,
\u00a0
cash in hand and short-term
deposits with an original maturity of three months
\u00a0
or less and held to meet short term commitments.
\u00a0
Restricted cash is cash reserved
for a specific purpose and therefore not available
\u00a0
for immediate and general use by the Group.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Equity
Ordinary shares
Ordinary shares are classified as equity. Costs directly attributable to the issue
\u00a0
of ordinary shares are recognized as a reduction
\u00a0
of
equity.
Repurchase of share capital (treasury shares)
Repurchased shares are classified as treasury shares
\u00a0
and are presented as a deduction from total
\u00a0
equity. When treasury shares are
subsequently sold or reissued, the amount received
\u00a0
is recognized as an increase in equity and
\u00a0
the resulting surplus or deficit of the
transaction is transferred to/from retained earnings.
Dividend
A liability to pay a dividend is recognized when
\u00a0
the distribution is authorized by the shareholders
\u00a0
at the AGM or the Board of
Directors based on authorization by the AGM.
\u00a0
A corresponding amount is recognized directly in equity.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Interest-bearing liabilities
At initial recognition, the bonds are measured at
\u00a0
its fair value minus transaction costs that are directly
\u00a0
attributable to the issue of the
financial liability. Subsequently, bonds are measured at amortized cost.
Transaction costs directly attributable to the acquisition, issuance, or
\u00a0
restructuring of financial liabilities, are amortized over
\u00a0
the
expected life of the liability using the effective interest rate
\u00a0
method. Amortization is recognized in the income
\u00a0
statement, ensuring a
systematic and rational allocation of these costs over
\u00a0
the period during which the liability is outstanding.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Lease liabilities
The Group assesses at contract inception whether
\u00a0
a contract is, or contains, a lease. The Group
\u00a0
applies a single recognition and
measurement approach for all leases, except for
\u00a0
short-term leases (12 months or less) and leases
\u00a0
of low-value assets. Short term
leases and leases of low value assets have not
\u00a0
been reflected in the balance sheet but expensed
\u00a0
or capitalized as incurred,
depending on the activity in which the leased asset
\u00a0
is used.
Lease liabilities are measured at the present value
\u00a0
of lease payments to be made over the lease
\u00a0
term. In calculating the present
value of lease payments, the Group uses
\u00a0
the implicit interest rate and if not readily determinable,
\u00a0
its incremental borrowing rate at
the lease commencement date. Extension options
\u00a0
are included in the lease liability when, based
\u00a0
on the management\u2019s judgement, it
is reasonably certain that an extension will be exercised.
In the consolidated cash flow, lease payments related to lease liabilities recognized
\u00a0
in accordance with IFRS 16, are presented as
cash flow used in financing activities.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Provisions for asset retirement obligations (ARO)
Provisions for ARO are initially recognized at the
\u00a0
present value of the estimated future costs
\u00a0
determined in accordance with local
conditions and requirements. A corresponding asset of
\u00a0
an amount equivalent to the ARO provision
\u00a0
is also recognized initially and is
presented as part of the PP&E. The retirement
\u00a0
asset is subsequently depreciated as part of
\u00a0
the development and production asset it
relates to.
The ARO provisions and the discount rates are reviewed
\u00a0
at each balance sheet date. The discount rates
\u00a0
used in the calculation of
the present value of the ARO are pre-tax risk-free
\u00a0
rates with the addition of a credit margin. The
\u00a0
risk-free rate used has a maturity
date that is expected to coincide with the time
\u00a0
the removal will be affected and denominated
\u00a0
in the same currency as the expected
future expenditures. According to IFRIC 1
Changes in Existing Decommissioning, Restoration
\u00a0
and Similar Liabilities
, changes in the
measurement of the ARO resulting from a
\u00a0
change in the timing or amount of the outflow of
\u00a0
resources embodying economic benefits
required to settle the obligation, or a change
\u00a0
in the discount rate, are added to or deducted
\u00a0
from the cost of the related asset.
Changes in the estimated ARO provisions impact
\u00a0
the retirement asset in the period in which the
\u00a0
estimate is revised.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Estimation of the cost for
\u00a0
decommissioning
Estimation of the costs for decommissioning is complex
\u00a0
and requires judgement as these estimates
\u00a0
are based on currently
applicable laws, regulations and technology. Decommissioning activities will normally
\u00a0
take place in the distant future, and the
technology, regulatory requirements and related costs may change. The energy transition
\u00a0
may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated decommissioning provisions. Based
\u00a0
on various scenario analysis
performed by the Company, management does not expect any reasonable
\u00a0
change in the expected timeframe to have a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost estimates (i.e., cash flows) remain unchanged.
\u00a0
The estimates
cover expected removal concepts based on known technology
\u00a0
and, in the case of offshore decommissioning, estimated
\u00a0
costs of
maritime operations, hiring of heavy-lift barges and
\u00a0
drilling rigs. As a result, the initial recognition
\u00a0
of the liability and the capitalized
cost associated with decommissioning obligations,
\u00a0
and the subsequent adjustment of these balance
\u00a0
sheet items, involve the
application of significant judgement. Based on
\u00a0
the described uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
\u00a0
\n
\u00a0
\n
Provisions for other liabilities
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as a
\u00a0
result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
The provisions are reviewed at each balance
\u00a0
sheet date and adjusted to reflect the current best estimate.
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Overlift
An overlift arises when the Group sells more
\u00a0
than its share of the oil and gas production (the
\u00a0
sales method). For underlift, see Note
15.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Financial instruments
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Financial assets
The Group\u2019s financial assets include trade and other
\u00a0
receivables, tax receivables and cash and
\u00a0
cash equivalents.
\u00a0
Financial assets are initially recognized at fair
\u00a0
value. After initial recognition the measurement
\u00a0
and accounting treatment depend on
the type of instrument and classification: Financial
\u00a0
investments at amortized cost through profit and
\u00a0
loss, at fair value through profit
and loss (FVTPL),
\u00a0
and at fair value through other comprehensive
\u00a0
income (FVTOCI).
A financial asset is derecognized when the Group no
\u00a0
longer has the right to receive cash flows from
\u00a0
the asset, and risks and rewards
are of ownership are transferred through sale or
\u00a0
the contractual rights to the cash flows expire, are
\u00a0
redeemed or cancelled.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Financial liabilities
The Group\u2019s financial liabilities include trade and other payables
\u00a0
and loans.
\u00a0
Interest-bearing loans are after initial recognition
\u00a0
measured at amortized cost using the effective interest
\u00a0
rate method. Gains and
losses are recognized in profit or loss when
\u00a0
the liabilities are derecognized as well as
\u00a0
through the amortization process. Amortized
cost is calculated by taking into account any discount
\u00a0
or premium on acquisition and fees or costs
\u00a0
that are an integral part of the
effective interest rate. The amortization cost is included
\u00a0
as finance expense in the statements of comprehensive
\u00a0
income. This applies
mainly to bond loans, see Note 18.
\u00a0
A financial liability is derecognized when the obligation
\u00a0
under the liability is discharged, cancelled or expires.
\u00a0
When an existing
financial liability is replaced by another from the
\u00a0
same lender on substantially different terms, or the
\u00a0
terms of an existing liability are
substantially modified, such a modification is treated
\u00a0
as a derecognition of the original liability and
\u00a0
a recognition of a new liability. The
difference in the respective carrying amounts is recognized
\u00a0
in the statements of comprehensive income.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Commitments and contingencies
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as
\u00a0
a result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
\u00a0
Contingent liabilities are not recognized but are
\u00a0
disclosed unless the possibility of an outflow
\u00a0
of resources is remote.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Contingencies, provisions
\u00a0
and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or more uncertain future event
\u00a0
occurs or fails to occur. The
assessment of the existence and potential quantum of
\u00a0
contingencies inherently involves the exercise of
\u00a0
significant judgment and the
use of estimates regarding the outcome of future
\u00a0
events. Management uses its judgment to evaluate
\u00a0
certain provisions and legal
disputes in order to ensure the correct accounting
\u00a0
treatment.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Reserves and resources estimates
\u00a0
DNO\u2019s reserves and contingent resources are estimated
\u00a0
and classified by the Company in accordance
\u00a0
with the rules and guidelines
of the Society of Petroleum Engineers (SPE) and are
\u00a0
in conformity with requirements from the Oslo Stock
\u00a0
Exchange for the reporting
of reserves and resources. All estimates of reserves
\u00a0
and resources involve uncertainty.
Important factors that could cause actual results to
\u00a0
differ from the estimates include, but are not limited
\u00a0
to: technical, geological and
geotechnical conditions; economic and market conditions; oil
\u00a0
and gas prices; changes in government regulations;
\u00a0
political
developments; interest rates; and currency exchange
\u00a0
rates. Specific parameters of uncertainty related
\u00a0
to the field/reservoir include
but are not limited to: reservoir pressure and
\u00a0
porosity; recovery factors; water cut development;
\u00a0
production decline rates; gas/oil
ratios; and oil properties.
\u00a0
Changes in commodity prices and costs may impact economic
\u00a0
cut-off and remaining reserves, which may change the
\u00a0
timing of any
decommissioning activities. Future changes to estimated
\u00a0
reserves can also have a material effect on depreciation,
\u00a0
impairment of oil
and gas fields and operating results. The Group
\u00a0
may also not be able to commercially develop
\u00a0
its contingent resources that are used
in impairment assessments or acquisition accounting
\u00a0
where the fair value approach is applied.
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Significant events after the reporting date
Adjusting events are those providing evidence of
\u00a0
conditions existing at the end of the reporting
\u00a0
period, whereas non-adjusting events
are indicative of conditions arising after the reporting
\u00a0
period (the latter being disclosed where
\u00a0
material).
", "dimensions": { "concept": "ifrs-full:DisclosureOfMaterialAccountingPolicyInformationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_5": { "value": "international oil and gas exploration, development and production operations.", "dimensions": { "concept": "ifrs-full:DescriptionOfNatureOfEntitysOperationsAndPrincipalActivities", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_6": { "value": "DNO\u2019s activities are mainly undertaken in the Middle East, the North Sea and West Africa.", "dimensions": { "concept": "ifrs-full:PrincipalPlaceOfBusiness", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_7": { "value": "DNO ASA", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_8": { "value": "DNO ASA", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_9": { "value": "DNO ASA", "dimensions": { "concept": "ifrs-full:NameOfUltimateParentOfGroup", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_10": { "value": "public limited liability", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_11": { "value": "Norway", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_12": { "value": "Norway", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_13": { "value": "Dokkveien 1, 0250 Oslo, Norway", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_14": { "value": "
Statement of compliance
The consolidated financial statements of DNO ASA have
\u00a0
been
prepared in accordance with IFRS Accounting
\u00a0
Standards as
adopted by the EU and additional disclosure requirements
\u00a0
in the
Norwegian Accounting Act, effective as of 31 December 2024.
The consolidated financial statements were approved
\u00a0
by the
Board of Directors on 2 April 2025.
", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_15": { "value": "
Basis for preparation
The consolidated financial statements have been prepared
\u00a0
on a
historical cost basis.
As permitted by International Accounting
Standard (IAS) 1
Presentation of Financial Statements
\u00a0
and in
conformity with industry practice,
\u00a0
the expenses in the
consolidated statements of comprehensive income are presented
as a combination of nature and function as this gives
\u00a0
the most
relevant and reliable presentation for the Group.
Due to rounding, the figures in one or more rows
\u00a0
or columns
included in the financial statements
\u00a0
and notes may not add up to
the subtotals or totals of that row or column.
", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_16": { "value": "
Group accounting and consolidation principles
Basis for consolidation
The consolidated financial statements include the financial
statements of DNO ASA and its subsidiaries. The Company
currently holds a 100 percent interest in all
\u00a0
of its subsidiaries.
", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_17": { "value": "
Functional and presentational currency
The consolidated financial statements are presented
\u00a0
in USD,
\u00a0
which is also DNO ASA\u2019s functional currency and presentation
currency.
\u00a0
Statements of comprehensive income and statements of
\u00a0
cash
flows of subsidiaries and joint operations that have
\u00a0
a functional
currency different from the parent company are translated
\u00a0
into the
presentation currency at average exchange rates
\u00a0
each month.
Statements of financial position items are translated using
\u00a0
the
exchange rate at the reporting date, with the
\u00a0
translation
differences taken directly to other comprehensive income.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_18": { "value": "
Functional and presentational currency
The consolidated financial statements are presented
\u00a0
in USD,
\u00a0
which is also DNO ASA\u2019s functional currency and presentation
currency.
\u00a0
Statements of comprehensive income and statements of
\u00a0
cash
flows of subsidiaries and joint operations that have
\u00a0
a functional
currency different from the parent company are translated
\u00a0
into the
presentation currency at average exchange rates
\u00a0
each month.
Statements of financial position items are translated using
\u00a0
the
exchange rate at the reporting date, with the
\u00a0
translation
differences taken directly to other comprehensive income.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_19": { "value": "
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO
\u00a0
holds a long-term
interest which is jointly controlled by DNO and
\u00a0
one or more other
parties under a contractual arrangement in which
\u00a0
decisions about
the relevant activities require the unanimous
\u00a0
consent of the
parties sharing control. Such joint arrangements are classified
\u00a0
as
either joint operations or joint ventures.
\u00a0
Joint operations
DNO recognizes its investments in joint operations
\u00a0
by reporting its
share of related revenues, expenses, assets, liabilities
\u00a0
and cash
flows under the respective items in the Group's
\u00a0
financial
statements.
\u00a0
Joint ventures
The Group\u2019s investments in a joint venture are accounted
\u00a0
for
using the equity method in accordance with
IAS 28 Investments in
Associates and Joint Ventures
.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTransactionsWithNoncontrollingInterestsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_20": { "value": "
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO
\u00a0
holds a long-term
interest which is jointly controlled by DNO and
\u00a0
one or more other
parties under a contractual arrangement in which
\u00a0
decisions about
the relevant activities require the unanimous
\u00a0
consent of the
parties sharing control. Such joint arrangements are classified
\u00a0
as
either joint operations or joint ventures.
\u00a0
Joint operations
DNO recognizes its investments in joint operations
\u00a0
by reporting its
share of related revenues, expenses, assets, liabilities
\u00a0
and cash
flows under the respective items in the Group's
\u00a0
financial
statements.
\u00a0
Joint ventures
The Group\u2019s investments in a joint venture are accounted
\u00a0
for
using the equity method in accordance with
IAS 28 Investments in
Associates and Joint Ventures
.
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
Joint Venture
The Group\u2019s investments in a joint venture are accounted
\u00a0
for using the equity method. The income statement
\u00a0
reflects the Group\u2019s
share of the results of operations in the joint
\u00a0
venture. The financial statements of the joint
\u00a0
venture are prepared for the same
reporting period as the Group. When necessary, adjustments are made
\u00a0
to bring the accounting policies in line with
\u00a0
those of the
Group.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_21": { "value": "
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO
\u00a0
holds a long-term
interest which is jointly controlled by DNO and
\u00a0
one or more other
parties under a contractual arrangement in which
\u00a0
decisions about
the relevant activities require the unanimous
\u00a0
consent of the
parties sharing control. Such joint arrangements are classified
\u00a0
as
either joint operations or joint ventures.
\u00a0
Joint operations
DNO recognizes its investments in joint operations
\u00a0
by reporting its
share of related revenues, expenses, assets, liabilities
\u00a0
and cash
flows under the respective items in the Group's
\u00a0
financial
statements.
\u00a0
Joint ventures
The Group\u2019s investments in a joint venture are accounted
\u00a0
for
using the equity method in accordance with
IAS 28 Investments in
Associates and Joint Ventures
.
Note 13
Joint Venture
\u00a0
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Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
Joint Venture
The Group\u2019s investments in a joint venture are accounted
\u00a0
for using the equity method. The income statement
\u00a0
reflects the Group\u2019s
share of the results of operations in the joint
\u00a0
venture. The financial statements of the joint
\u00a0
venture are prepared for the same
reporting period as the Group. When necessary, adjustments are made
\u00a0
to bring the accounting policies in line with
\u00a0
those of the
Group.
\u00a0
DNO holds 100 percent of the shares in Mondoil
\u00a0
Enterprises LLC (Mondoil Enterprises) which has
\u00a0
a 33.33 percent indirect interest in
privately-held Foxtrot International whose principal assets
\u00a0
are operated stakes in offshore production of
\u00a0
gas and associated liquids in
C\u00f4te d'Ivoire. Foxtrot International holds a 27.27 percent
\u00a0
interest in and operatorship of Block CI-27
\u00a0
containing reserves of gas,
produced together with condensate and oil, from
\u00a0
four offshore fields tied back to two fixed platforms.
\u00a0
Foxtrot International's summarized statement of financial position
Year ended 31 December
USD million
2024
2023
Non-current assets
159.3
199.9
Current assets
50.1
64.3
Total assets
209.4
264.2
Non-current liabilities
67.6
68.8
Current liabilities
24.8
27.5
Total liabilities
92.5
96.3
Equity
116.9
167.9
Group's share of net assets (33.33 percent)
38.1
56.0
Goodwill
0.8
0.8
Fair value uplift on PP&E and ARO (net of related deferred tax)
10.0
11.1
Carrying amount Investment in Joint Venture
48.8
67.9
Foxtrot International's summarized statement of comprehensive income
1 January - 31 December
USD million
2024
2023
Revenues
75.7
79.4
Expenses
-35.6
-17.6
Depreciation
-33.7
-30.8
Other income/finance income
6.2
8.6
Tax income/expense
-
-
Net profit/loss
12.6
39.6
Group's share of net profit (33.33 percent)
4.2
13.2
Depletion of fair value uplift of PP&E and ARO (net of related deferred tax)
-0.9
-1.3
Share of profit/loss from Joint Venture
3.3
11.9
Movement in the carrying amount of Investment in Joint Venture
1 January - 31 December
USD million
2024
2023
Opening balance
67.9
76.1
Share of profit/loss from Joint Venture
3.3
11.9
Equity contribution into Joint Venture
9.4
6.9
Dividends from Joint Venture
-31.8
-27.1
Carrying amount Investment in Joint Venture
48.8
67.9
", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_22": { "value": "
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO
\u00a0
holds a long-term
interest which is jointly controlled by DNO and
\u00a0
one or more other
parties under a contractual arrangement in which
\u00a0
decisions about
the relevant activities require the unanimous
\u00a0
consent of the
parties sharing control. Such joint arrangements are classified
\u00a0
as
either joint operations or joint ventures.
\u00a0
Joint operations
DNO recognizes its investments in joint operations
\u00a0
by reporting its
share of related revenues, expenses, assets, liabilities
\u00a0
and cash
flows under the respective items in the Group's
\u00a0
financial
statements.
\u00a0
Joint ventures
The Group\u2019s investments in a joint venture are accounted
\u00a0
for
using the equity method in accordance with
IAS 28 Investments in
Associates and Joint Ventures
.
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
Joint Venture
The Group\u2019s investments in a joint venture are accounted
\u00a0
for using the equity method. The income statement
\u00a0
reflects the Group\u2019s
share of the results of operations in the joint
\u00a0
venture. The financial statements of the joint
\u00a0
venture are prepared for the same
reporting period as the Group. When necessary, adjustments are made
\u00a0
to bring the accounting policies in line with
\u00a0
those of the
Group.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociatesAndJointVenturesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_23": { "value": "
License acquisitions, farm-in/out and swaps
Individual assessment is made whether the acquisition
\u00a0
of an oil
and gas license should be treated as a business combination
\u00a0
or
as an asset purchase. Generally, purchase of a license in
development or production phase is regarded as
\u00a0
a business
combination, while purchase of a license in the exploration
\u00a0
phase
is regarded as an asset purchase.
A farm-in or farm-out of an oil and gas license
\u00a0
takes place when
the owner of a working interest (the farmor)
\u00a0
transfers all or a
portion of its working interest to another party
\u00a0
(the farmee) in
return for an agreed upon consideration and/or
\u00a0
action, such as
conducting subsurface studies, drilling wells or developing
\u00a0
the
asset. Any cash consideration received directly from
\u00a0
the farmee is
credited against costs previously capitalized in relation
\u00a0
to the
whole interest with any excess accounted for by
\u00a0
the farmor as a
gain on disposal.
\u00a0
In the development or production phase, a farm-in/farm-out
agreement will be treated as a transaction recorded
\u00a0
at fair value
as represented by the costs carried by the farmee.
\u00a0
Any gain or
loss arising from the farm-in/farm-out is recognized
\u00a0
in the
statements of comprehensive income.
\u00a0
License swaps are measured at the fair value of
\u00a0
the asset being
exchanged, unless the transaction lacks commercial substance,
or neither the fair value of the asset received, nor
\u00a0
divested, can
be reliably measured. In the exploration phase,
\u00a0
the Group
normally recognizes license swaps based on historical
\u00a0
cost basis.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_24": { "value": "
Changes in accounting policies
The accounting policies adopted are consistent with
\u00a0
those of the
previous financial year.
\u00a0
Other amendments and interpretations may apply
\u00a0
for the first time
in 2024 but are not considered to have any material
\u00a0
impact on the
Group\u2019s financial statements.
", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_25": { "value": "
Note 2
Segment information
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\n
Accounting policies
Segment information
DNO\u2019s operating segments correspond to its reportable
\u00a0
segments. The Company identifies and reports
\u00a0
its segments based on the
nature of the risk and return within its business
\u00a0
and by the geographical location of the Group\u2019s
\u00a0
assets and operations. The segment
information is provided to the senior management
\u00a0
and the Board of Directors who are considered
\u00a0
to collectively be the Chief
Operating Decision Maker and is used as the basis
\u00a0
for allocation of resources and decision
\u00a0
making.
The accounting policies of the reporting segments
\u00a0
equal those described in these consolidated
\u00a0
financial statements. Transfer pricing
between the segments and companies is set using
\u00a0
the arm\u2019s length principle in a manner similar to transactions
\u00a0
with third parties and
are eliminated at the consolidated level. Segment profit/loss
\u00a0
includes profit/loss from inter-segment sales.
\u00a0
The Company reports the following three operating
\u00a0
segments: Kurdistan, the North Sea (which includes
\u00a0
DNO\u2019s oil and gas activities in
Norway and the UK) and West Africa (which represents DNO\u2019s
\u00a0
equity accounted investment in C\u00f4te d'Ivoire,
\u00a0
see Note 13). Remaining
operating segments are included in the other category
\u00a0
based on a materiality assessment. The
\u00a0
country-by-country reporting for
companies in extractive industries in line with
\u00a0
the Norwegian Accounting Act can be found on
\u00a0
page 118 of this report.
USD million
Total
Un-
Full-Year ending
West
reporting
allocated/
Total
31 December 2024
Note
Kurdistan
North Sea
Africa
Other
segments
eliminated
Group
COMPREHENSIVE INCOME INFORMATION
Revenues
3
230.8
436.0
-
-
666.8
-
666.8
Inter-segment sales
-
-
-
-
-
-
-
Production costs
-83.0
-142.6
-
-
-225.6
0.7
-224.9
Movement in overlift/underlift
-
2.1
-
-
2.1
-
2.1
Depreciation, depletion and amortization
-116.7
-64.1
-
-
-180.8
-3.4
-184.1
Cost of goods sold
4
-199.7
-204.5
-
-
-404.2
-2.7
-406.9
Gross profit
31.1
231.5
-
-
262.6
-2.7
259.9
Share of profit/loss from Joint Venture
13
-
-
3.3
-
3.3
-
3.3
Other income
0.3
0.6
-
-
0.9
0.1
1.0
Administrative expenses
\u00a0
5
-0.5
-10.6
-
-1.5
-12.7
-10.8
-23.5
Other operating expenses
5
-1.7
-
-
-0.9
-2.5
-
-2.5
Impairment of oil and gas assets
11
-89.0
-57.0
-
-
-146.0
-
-146.0
Exploration expenses
6
-
-88.9
-
-
-88.9
-
-88.9
Net gain on disposal of licenses
20
-
3.0
-
-
3.0
-
3.0
Operating profit/loss
-59.8
78.4
3.3
-2.4
19.5
-13.4
6.1
Net financial income/expense
7
11.6
-10.3
1.5
1.2
4.0
-23.4
-19.4
Tax income/expense
8
-
-13.8
-
-
-13.8
-
-13.8
Net profit/loss
\u00a0
-48.2
54.3
4.8
-1.2
9.7
-36.8
-27.1
FINANCIAL POSITION INFORMATION
Non-current assets
663.1
902.5
48.8
-
1,614.5
12.1
1,626.6
Current assets
237.4
283.2
-
1.3
521.8
817.7
1,339.5
Total assets
900.5
1,185.7
48.8
1.3
2,136.3
829.8
2,966.1
Non-current liabilities
71.4
705.1
-
-
776.5
755.7
1,532.2
Current liabilities
142.3
177.4
-
8.1
327.8
26.1
353.9
Total liabilities
213.8
882.4
-
8.1
1,104.3
781.8
1,886.1
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\n
USD million
Total
Un-
Full-Year ending
West
reporting
allocated/
Total
31 December 2023
Note
Kurdistan
North Sea
Africa
Other
segments
eliminated
Group
COMPREHENSIVE INCOME INFORMATION
Revenues
3
253.2
414.4
-
-
667.5
-
667.5
Inter-segment sales
-
-
-
-
-
-
-
Production costs
-101.7
-122.1
-
-
-223.8
-0.3
-224.1
Movement in overlift/underlift
-
5.6
-
-
5.6
-
5.6
Depreciation, depletion and amortization
-97.0
-45.9
-
-
-143.0
-3.4
-146.4
Cost of goods sold
4
-198.7
-162.4
-
-
-361.1
-3.7
-364.8
Gross profit
54.5
252.0
-
-
306.4
-3.7
302.7
Share of profit/loss from Joint Venture
13
-
-
11.9
-
11.9
-
11.9
Other income
-
1.6
-
-
1.6
-
1.6
Administrative expenses
\u00a0
5
-0.3
-5.3
-
-2.2
-7.8
-15.4
-23.3
Other operating expenses
5
-1.8
-
-
-6.1
-7.9
-
-7.9
Impairment of oil and gas assets
11
-
-24.9
-
-
-24.9
-
-24.9
Exploration expenses
6
-
-47.7
-
-
-47.7
-
-47.7
Operating profit/loss
52.4
181.4
11.9
-8.3
237.4
-19.1
218.3
Net financial income/expense
7
-50.2
-6.7
0.8
0.5
-55.6
-11.4
-67.0
Tax income/expense
8
-
-132.7
-
-
-132.7
-
-132.7
Net profit/loss
\u00a0
2.2
42.1
12.7
-7.9
49.1
-30.5
18.6
FINANCIAL POSITION INFORMATION
Non-current assets
855.1
639.0
67.9
-
1,562.0
14.2
1,576.2
Current assets
219.2
334.4
-
3.3
556.9
505.2
1,062.1
Total assets
1,074.3
973.4
67.9
3.3
2,118.9
519.4
2,638.3
Non-current liabilities
69.8
508.3
-
-
578.1
410.3
988.4
Current liabilities
67.3
189.9
-
7.9
265.1
150.0
415.1
Total liabilities
137.0
698.2
-
7.9
843.2
560.3
1,403.5
", "dimensions": { "concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_26": { "value": "
\u00a0
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\n
\u00a0
\n
\u00a0
\n
Accounting policies
Segment information
DNO\u2019s operating segments correspond to its reportable
\u00a0
segments. The Company identifies and reports
\u00a0
its segments based on the
nature of the risk and return within its business
\u00a0
and by the geographical location of the Group\u2019s
\u00a0
assets and operations. The segment
information is provided to the senior management
\u00a0
and the Board of Directors who are considered
\u00a0
to collectively be the Chief
Operating Decision Maker and is used as the basis
\u00a0
for allocation of resources and decision
\u00a0
making.
The accounting policies of the reporting segments
\u00a0
equal those described in these consolidated
\u00a0
financial statements. Transfer pricing
between the segments and companies is set using
\u00a0
the arm\u2019s length principle in a manner similar to transactions
\u00a0
with third parties and
are eliminated at the consolidated level. Segment profit/loss
\u00a0
includes profit/loss from inter-segment sales.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSegmentReportingExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_27": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
Note 3
Revenues
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Revenues
Revenues presented in the consolidated statements
\u00a0
of comprehensive income consist of Revenue
\u00a0
from contracts with customers.
Revenue from contracts with customers is recognized
\u00a0
when the customer obtains control of the oil
\u00a0
and gas, which normally will be
when title passes at the point of delivery, based on the contractual terms of
\u00a0
the agreements.
In general, the revenues from the Group\u2019s production of oil
\u00a0
and gas are recognized on the basis of
\u00a0
volumes lifted and sold to
customers during the period (the sales method).
Tariff income from processing of oil and gas is related to the North Sea segment and is
\u00a0
recognized as earned.
Revenue recognition in Kurdistan
\u00a0
During 2024 and most of 2023, revenues in
\u00a0
Kurdistan were generated from local sales and recognized
\u00a0
on the basis of volumes lifted
and sold to customers during the period. Local deliveries
\u00a0
are prepaid by the buyers directly to DNO.
Export revenues in Kurdistan were in the first three
\u00a0
months of 2023 generated through the sale of oil
\u00a0
produced from the Tawke and
the Baeshiqa licenses which was exported by
\u00a0
the pipeline through T\u00fcrkiye. Title to the oil was considered
\u00a0
to have passed on delivery
of oil to the export pipeline at Fish Khabur
\u00a0
terminal. Revenues generated from export sales
\u00a0
were recognized on the basis of invoiced
oil sales following monthly deliveries to the KRG.
\u00a0
Based on business practice, the KRG was
\u00a0
responsible for exporting the oil
produced in Kurdistan and it is assessed that
\u00a0
DNO has a customer relationship with
\u00a0
the KRG. The price for export oil deliveries to
the KRG was based on Brent prices with
\u00a0
adjustments for oil quality and transportation
\u00a0
fees.
\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
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\n
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
\n
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
Entitlement risk associated with operating in Kurdistan
DNO has interests in two licenses in Kurdistan
\u00a0
through Production Sharing Contracts (PSCs) and
\u00a0
has based its entitlement
calculations on the terms of these PSCs.
\u00a0
The Company notes from public reports that on 15
\u00a0
February 2022, the Federal Supreme Court
\u00a0
of Iraq (FSCI) ruled on two matters,
one stemming back to 2012 and another related
\u00a0
matter dating back to 2019. Reportedly, the FSCI found amongst other
\u00a0
things that
the Kurdistan Oil and Gas Law No. 27/2007 (KOGL)
\u00a0
is unconstitutional, that the KRG is to hand over
\u00a0
all oil production from areas
located in the Kurdistan region of Iraq (KRI) to the
\u00a0
Federal Government of Iraq (FGI) and that
\u00a0
the FGI has the right to pursue
\u00a0
the
nullity of the oil contracts concluded by the KRG.
\u00a0
DNO was not a party to these proceedings.
\u00a0
Further, DNO learned via media reports
that on 4 July 2022, the Karkh commercial court
\u00a0
in Baghdad ruled that PSCs signed between
\u00a0
the KRG and four international oil
companies (including DNO) should be voided. Similar
\u00a0
cases were reported as regards four other international
\u00a0
oil companies over the
ensuing weeks. Media then reported that on 21
\u00a0
August 2022, the KRG filed third party objections
\u00a0
to the reported 2022 Baghdad court
rulings including those understood to concern DNO.
\u00a0
On 18 December 2024, it was reported
\u00a0
that the Karkh Court of Appeal ruled in
favor of inter alia the KRG, confirming that the
\u00a0
PSCs in question were valid. That ruling was
\u00a0
also reported appealed by the FGI,
however, on 22 January 2025, DNO learnt, again from media reports,
\u00a0
that the Court of Cassation dismissed the
\u00a0
FGI\u2019s appeal and
thus confirmed that the PSCs are valid. On 27 February 2025,
\u00a0
there were reports that the FGI had requested
\u00a0
a correction of the
rulings of the Court of Cassation. The Company
\u00a0
notes reports that this process does not allow
\u00a0
the FGI to introduce new evidence or
arguments; it merely seeks to correct perceived
\u00a0
errors in the Court of Cassation\u2019s ruling.
\u00a0
As far as the Company is aware, that
process is still pending. Throughout the period
\u00a0
when these cases were pending, the KRG
\u00a0
issued repeated assurances that the PSCs
remain valid and there were also several rulings
\u00a0
in Erbil courts affirming the validity of the PSCs. In
\u00a0
2014, the FGI initiated an
arbitration case against the Government of T\u00fcrkiye and
\u00a0
its state-owned pipeline operator BOTAS relating to the ITP. Following an
arbitration ruling which became publicly known on
\u00a0
or around 24 March 2023, and which
\u00a0
were in parts in favor of Iraq, the ITP was
closed on 25 March 2023. As of the reporting
\u00a0
date, the ITP remains closed, despite T\u00fcrkiye\u2019s announcement
\u00a0
in October 2023 that
the ITP is ready to resume operations. Timing of export
\u00a0
resumption is uncertain. Consequently, DNO initiated cost reduction
measures in Kurdistan and commenced local sales on
\u00a0
a cash and carry basis, where the oil
\u00a0
is transported by traders by road tanker
or pipelined to local refineries. The contractor
\u00a0
entities\u2019 entitlement is sold by DNO. Varying by contract, local selling prices were
\u00a0
in the
mid USD 30s per barrel during 2024, significantly
\u00a0
lower than the international prices previously
\u00a0
achieved through pipeline export.
However, all local deliveries are prepaid by the buyers directly to
\u00a0
DNO, eliminating counterparty credit risk.
\u00a0
The FGI\u2019s 2023-2025 Federal Iraqi Budget Law (Budget
\u00a0
Law) entered into force in June 2023. The details
\u00a0
of FGI-KRG budget
allocations, implementation of the Budget Law and
\u00a0
the monetary size of the budget transfers to the
\u00a0
KRG are not clear to DNO. DNO
notes however that on 2 February 2025, the
\u00a0
Iraqi Parliament approved amendments of the Budget
\u00a0
Law. There have been several
media reports that indicate that the Budget Law
\u00a0
amendment may enable restart of export of Kurdish
\u00a0
oil through the ITP. DNO and
other member companies of the Association of the
\u00a0
Petroleum Industry of Kurdistan (APIKUR ) have
\u00a0
repeatedly stated that they are
prepared to resume exports, contingent upon reaching
\u00a0
agreements that provide for payment surety for
\u00a0
past and future exports, direct
payment and preservation of the legal, commercial and
\u00a0
economic terms of their production sharing contracts (Conditions).
\u00a0
\u00a0
\n
\u00a0
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\n
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\n
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\n
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\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\u00a0
\n
\u00a0
\n
\u00a0
\n
It is unclear to the Company how implementation
\u00a0
of the amended Budget Law can facilitate satisfaction
\u00a0
of the Conditions. It is also
not clear how the KRG and the FGI will address
\u00a0
these matters beyond 2025. To date, DNO continues its operations in Kurdistan, and
developments are closely monitored.
\u00a0
Due to the disagreements between the FGI and
\u00a0
the KRG, economic conditions in Kurdistan and
\u00a0
limited oil export channels, DNO has
historically faced constraints in fully monetizing the oil
\u00a0
it produces in Kurdistan. There is no guarantee
\u00a0
that oil can be exported or sold
locally in sufficient quantities or at prices required to
\u00a0
sustain DNO\u2019s operations and investment plans or
\u00a0
that the Group will promptly
receive its full entitlement payments for any oil it delivers
\u00a0
for export if the ITP reopens. Export sales have
\u00a0
not always followed the
PSC terms. Furthermore, there has also previously
\u00a0
been uncertainty related to receipt of payments
\u00a0
for oil sold to the KRG but
notwithstanding sometimes lengthy delays, payments
\u00a0
have ultimately been received by DNO.
At yearend 2024, the Company was owed a total
\u00a0
of USD 298.1 million, excluding any interest,
\u00a0
by the KRG mainly related to export
oil sales to the KRG for the months October 2022
\u00a0
through March 2023. These receivables are past
\u00a0
due (see Note 15). The KRG has
repeatedly stated that it is and remains committed
\u00a0
to its PSCs. Timing of export resumption and payments for previous
\u00a0
oil sales by
the KRG is uncertain. The Company continues to engage
\u00a0
with the KRG regarding recovery of the
\u00a0
arrears and payment terms and
conditions for any future oil exports.
The Company\u2019s PSCs include rights for the host
\u00a0
government to audit the PSC accounts which
\u00a0
may impact the Company\u2019s recovery
of costs and financial results. During 2024 in
\u00a0
Kurdistan, such audits were carried out with respect
\u00a0
to the Baeshiqa 2018-2019
Accounts and the Tawke 2021 Accounts.
\u00a0
1 January - 31 December
\u00a0
Kurdistan
\u00a0
North Sea
Total
USD million
2024
2023
2024
2023
2024
2023
Sale of oil
230.8
253.2
265.2
253.0
496.0
506.2
Sale of gas
-
-
138.5
137.3
138.5
137.3
Sale of natural gas liquids (NGL)
-
-
26.9
21.6
26.9
21.6
Tariff income
-
-
5.4
2.4
5.4
2.4
Total revenues from contracts with customers
230.8
253.2
436.0
414.4
666.8
667.5
Sale of oil (bopd)
18,222
14,806
8,704
8,049
26,926
22,856
Sale of gas (boepd)
-
-
5,511
4,746
5,511
4,746
Sale of natural gas liquids (NGL) (boepd)
-
-
1,575
1,282
1,575
1,282
Total sales volume (boepd)
18,222
14,806
15,790
14,078
34,011
28,885
Prior to the ITP closure in March 2023, DNO generated
\u00a0
revenues in Kurdistan through the sale of oil
\u00a0
produced from the Tawke and the
Baeshiqa licenses which were exported by pipeline
\u00a0
through T\u00fcrkiye. Following closure of the ITP, the Company gradually resumed
operations at the Tawke license and has been selling oil to local trading companies
\u00a0
in Kurdistan since late Q2 2023.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_28": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
Note 3
Revenues
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Revenues
Revenues presented in the consolidated statements
\u00a0
of comprehensive income consist of Revenue
\u00a0
from contracts with customers.
Revenue from contracts with customers is recognized
\u00a0
when the customer obtains control of the oil
\u00a0
and gas, which normally will be
when title passes at the point of delivery, based on the contractual terms of
\u00a0
the agreements.
In general, the revenues from the Group\u2019s production of oil
\u00a0
and gas are recognized on the basis of
\u00a0
volumes lifted and sold to
customers during the period (the sales method).
Tariff income from processing of oil and gas is related to the North Sea segment and is
\u00a0
recognized as earned.
Revenue recognition in Kurdistan
\u00a0
During 2024 and most of 2023, revenues in
\u00a0
Kurdistan were generated from local sales and recognized
\u00a0
on the basis of volumes lifted
and sold to customers during the period. Local deliveries
\u00a0
are prepaid by the buyers directly to DNO.
Export revenues in Kurdistan were in the first three
\u00a0
months of 2023 generated through the sale of oil
\u00a0
produced from the Tawke and
the Baeshiqa licenses which was exported by
\u00a0
the pipeline through T\u00fcrkiye. Title to the oil was considered
\u00a0
to have passed on delivery
of oil to the export pipeline at Fish Khabur
\u00a0
terminal. Revenues generated from export sales
\u00a0
were recognized on the basis of invoiced
oil sales following monthly deliveries to the KRG.
\u00a0
Based on business practice, the KRG was
\u00a0
responsible for exporting the oil
produced in Kurdistan and it is assessed that
\u00a0
DNO has a customer relationship with
\u00a0
the KRG. The price for export oil deliveries to
the KRG was based on Brent prices with
\u00a0
adjustments for oil quality and transportation
\u00a0
fees.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Entitlement risk associated with operating in Kurdistan
DNO has interests in two licenses in Kurdistan
\u00a0
through Production Sharing Contracts (PSCs) and
\u00a0
has based its entitlement
calculations on the terms of these PSCs.
\u00a0
The Company notes from public reports that on 15
\u00a0
February 2022, the Federal Supreme Court
\u00a0
of Iraq (FSCI) ruled on two matters,
one stemming back to 2012 and another related
\u00a0
matter dating back to 2019. Reportedly, the FSCI found amongst other
\u00a0
things that
the Kurdistan Oil and Gas Law No. 27/2007 (KOGL)
\u00a0
is unconstitutional, that the KRG is to hand over
\u00a0
all oil production from areas
located in the Kurdistan region of Iraq (KRI) to the
\u00a0
Federal Government of Iraq (FGI) and that
\u00a0
the FGI has the right to pursue
\u00a0
the
nullity of the oil contracts concluded by the KRG.
\u00a0
DNO was not a party to these proceedings.
\u00a0
Further, DNO learned via media reports
that on 4 July 2022, the Karkh commercial court
\u00a0
in Baghdad ruled that PSCs signed between
\u00a0
the KRG and four international oil
companies (including DNO) should be voided. Similar
\u00a0
cases were reported as regards four other international
\u00a0
oil companies over the
ensuing weeks. Media then reported that on 21
\u00a0
August 2022, the KRG filed third party objections
\u00a0
to the reported 2022 Baghdad court
rulings including those understood to concern DNO.
\u00a0
On 18 December 2024, it was reported
\u00a0
that the Karkh Court of Appeal ruled in
favor of inter alia the KRG, confirming that the
\u00a0
PSCs in question were valid. That ruling was
\u00a0
also reported appealed by the FGI,
however, on 22 January 2025, DNO learnt, again from media reports,
\u00a0
that the Court of Cassation dismissed the
\u00a0
FGI\u2019s appeal and
thus confirmed that the PSCs are valid. On 27 February 2025,
\u00a0
there were reports that the FGI had requested
\u00a0
a correction of the
rulings of the Court of Cassation. The Company
\u00a0
notes reports that this process does not allow
\u00a0
the FGI to introduce new evidence or
arguments; it merely seeks to correct perceived
\u00a0
errors in the Court of Cassation\u2019s ruling.
\u00a0
As far as the Company is aware, that
process is still pending. Throughout the period
\u00a0
when these cases were pending, the KRG
\u00a0
issued repeated assurances that the PSCs
remain valid and there were also several rulings
\u00a0
in Erbil courts affirming the validity of the PSCs. In
\u00a0
2014, the FGI initiated an
arbitration case against the Government of T\u00fcrkiye and
\u00a0
its state-owned pipeline operator BOTAS relating to the ITP. Following an
arbitration ruling which became publicly known on
\u00a0
or around 24 March 2023, and which
\u00a0
were in parts in favor of Iraq, the ITP was
closed on 25 March 2023. As of the reporting
\u00a0
date, the ITP remains closed, despite T\u00fcrkiye\u2019s announcement
\u00a0
in October 2023 that
the ITP is ready to resume operations. Timing of export
\u00a0
resumption is uncertain. Consequently, DNO initiated cost reduction
measures in Kurdistan and commenced local sales on
\u00a0
a cash and carry basis, where the oil
\u00a0
is transported by traders by road tanker
or pipelined to local refineries. The contractor
\u00a0
entities\u2019 entitlement is sold by DNO. Varying by contract, local selling prices were
\u00a0
in the
mid USD 30s per barrel during 2024, significantly
\u00a0
lower than the international prices previously
\u00a0
achieved through pipeline export.
However, all local deliveries are prepaid by the buyers directly to
\u00a0
DNO, eliminating counterparty credit risk.
\u00a0
The FGI\u2019s 2023-2025 Federal Iraqi Budget Law (Budget
\u00a0
Law) entered into force in June 2023. The details
\u00a0
of FGI-KRG budget
allocations, implementation of the Budget Law and
\u00a0
the monetary size of the budget transfers to the
\u00a0
KRG are not clear to DNO. DNO
notes however that on 2 February 2025, the
\u00a0
Iraqi Parliament approved amendments of the Budget
\u00a0
Law. There have been several
media reports that indicate that the Budget Law
\u00a0
amendment may enable restart of export of Kurdish
\u00a0
oil through the ITP. DNO and
other member companies of the Association of the
\u00a0
Petroleum Industry of Kurdistan (APIKUR ) have
\u00a0
repeatedly stated that they are
prepared to resume exports, contingent upon reaching
\u00a0
agreements that provide for payment surety for
\u00a0
past and future exports, direct
payment and preservation of the legal, commercial and
\u00a0
economic terms of their production sharing contracts (Conditions).
\u00a0
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\u00a0
\n
It is unclear to the Company how implementation
\u00a0
of the amended Budget Law can facilitate satisfaction
\u00a0
of the Conditions. It is also
not clear how the KRG and the FGI will address
\u00a0
these matters beyond 2025. To date, DNO continues its operations in Kurdistan, and
developments are closely monitored.
\u00a0
Due to the disagreements between the FGI and
\u00a0
the KRG, economic conditions in Kurdistan and
\u00a0
limited oil export channels, DNO has
historically faced constraints in fully monetizing the oil
\u00a0
it produces in Kurdistan. There is no guarantee
\u00a0
that oil can be exported or sold
locally in sufficient quantities or at prices required to
\u00a0
sustain DNO\u2019s operations and investment plans or
\u00a0
that the Group will promptly
receive its full entitlement payments for any oil it delivers
\u00a0
for export if the ITP reopens. Export sales have
\u00a0
not always followed the
PSC terms. Furthermore, there has also previously
\u00a0
been uncertainty related to receipt of payments
\u00a0
for oil sold to the KRG but
notwithstanding sometimes lengthy delays, payments
\u00a0
have ultimately been received by DNO.
At yearend 2024, the Company was owed a total
\u00a0
of USD 298.1 million, excluding any interest,
\u00a0
by the KRG mainly related to export
oil sales to the KRG for the months October 2022
\u00a0
through March 2023. These receivables are past
\u00a0
due (see Note 15). The KRG has
repeatedly stated that it is and remains committed
\u00a0
to its PSCs. Timing of export resumption and payments for previous
\u00a0
oil sales by
the KRG is uncertain. The Company continues to engage
\u00a0
with the KRG regarding recovery of the
\u00a0
arrears and payment terms and
conditions for any future oil exports.
The Company\u2019s PSCs include rights for the host
\u00a0
government to audit the PSC accounts which
\u00a0
may impact the Company\u2019s recovery
of costs and financial results. During 2024 in
\u00a0
Kurdistan, such audits were carried out with respect
\u00a0
to the Baeshiqa 2018-2019
Accounts and the Tawke 2021 Accounts.
\u00a0
1 January - 31 December
\u00a0
Kurdistan
\u00a0
North Sea
Total
USD million
2024
2023
2024
2023
2024
2023
Sale of oil
230.8
253.2
265.2
253.0
496.0
506.2
Sale of gas
-
-
138.5
137.3
138.5
137.3
Sale of natural gas liquids (NGL)
-
-
26.9
21.6
26.9
21.6
Tariff income
-
-
5.4
2.4
5.4
2.4
Total revenues from contracts with customers
230.8
253.2
436.0
414.4
666.8
667.5
Sale of oil (bopd)
18,222
14,806
8,704
8,049
26,926
22,856
Sale of gas (boepd)
-
-
5,511
4,746
5,511
4,746
Sale of natural gas liquids (NGL) (boepd)
-
-
1,575
1,282
1,575
1,282
Total sales volume (boepd)
18,222
14,806
15,790
14,078
34,011
28,885
Prior to the ITP closure in March 2023, DNO generated
\u00a0
revenues in Kurdistan through the sale of oil
\u00a0
produced from the Tawke and the
Baeshiqa licenses which were exported by pipeline
\u00a0
through T\u00fcrkiye. Following closure of the ITP, the Company gradually resumed
operations at the Tawke license and has been selling oil to local trading companies
\u00a0
in Kurdistan since late Q2 2023.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_29": { "value": "
\u00a0
\n
\u00a0
\n
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\n
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\n
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\u00a0
\n
\u00a0
\n
\u00a0
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\n
\u00a0
\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Revenues
Revenues presented in the consolidated statements
\u00a0
of comprehensive income consist of Revenue
\u00a0
from contracts with customers.
Revenue from contracts with customers is recognized
\u00a0
when the customer obtains control of the oil
\u00a0
and gas, which normally will be
when title passes at the point of delivery, based on the contractual terms of
\u00a0
the agreements.
In general, the revenues from the Group\u2019s production of oil
\u00a0
and gas are recognized on the basis of
\u00a0
volumes lifted and sold to
customers during the period (the sales method).
Tariff income from processing of oil and gas is related to the North Sea segment and is
\u00a0
recognized as earned.
Revenue recognition in Kurdistan
\u00a0
During 2024 and most of 2023, revenues in
\u00a0
Kurdistan were generated from local sales and recognized
\u00a0
on the basis of volumes lifted
and sold to customers during the period. Local deliveries
\u00a0
are prepaid by the buyers directly to DNO.
Export revenues in Kurdistan were in the first three
\u00a0
months of 2023 generated through the sale of oil
\u00a0
produced from the Tawke and
the Baeshiqa licenses which was exported by
\u00a0
the pipeline through T\u00fcrkiye. Title to the oil was considered
\u00a0
to have passed on delivery
of oil to the export pipeline at Fish Khabur
\u00a0
terminal. Revenues generated from export sales
\u00a0
were recognized on the basis of invoiced
oil sales following monthly deliveries to the KRG.
\u00a0
Based on business practice, the KRG was
\u00a0
responsible for exporting the oil
produced in Kurdistan and it is assessed that
\u00a0
DNO has a customer relationship with
\u00a0
the KRG. The price for export oil deliveries to
the KRG was based on Brent prices with
\u00a0
adjustments for oil quality and transportation
\u00a0
fees.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_30": { "value": "
Note 4
Cost of goods sold
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Cost of goods sold
Lifting costs and Tariff and transportation expenses
Lifting costs consist of expenses related to the production
\u00a0
of oil and gas, including operation and maintenance
\u00a0
of installations, well
intervention activities and insurances. Tariff and transportation expenses consist of charges
\u00a0
incurred by the Group in the North Sea
for the use of infrastructure owned by other
\u00a0
companies. Lifting costs and Tariff and transportation expenses are recognized based on
the Group\u2019s paying interest in the oil and gas licenses.
\u00a0
Movement in overlift/underlift
A liability (overlift, see Note 22) arises when the
\u00a0
Group sells more than its share of the oil and
\u00a0
gas production. Similarly, an asset
(underlift, see Note 15) arises when the sale
\u00a0
is less than the Group\u2019s share of the oil and gas production.
\u00a0
In general, the
overlift/underlift balances are valued at production
\u00a0
cost including depreciation (the sales method). The
\u00a0
movements in overlift/underlift
are presented as an adjustment to Cost of
\u00a0
goods sold.
\u00a0
Depreciation, depletion and amortization
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the unit-of-production (UoP) method. See
\u00a0
Note 10 for more details.
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
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\u00a0
\n
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\n
\u00a0
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
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\n
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\n
\u00a0
\n
\u00a0
\n
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\n
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\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2024
2023
Lifting costs
-175.5
-191.7
Tariff and transportation expenses
-49.4
-32.4
Production costs based on produced volumes
-224.9
-224.1
Movement in overlift/underlift
2.1
5.6
Production costs based on sold volumes
-222.7
-218.4
Depreciation, depletion and amortization
-184.1
-146.4
Total cost of goods sold
-406.9
-364.8
", "dimensions": { "concept": "ifrs-full:DisclosureOfCostOfSalesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_31": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Cost of goods sold
Lifting costs and Tariff and transportation expenses
Lifting costs consist of expenses related to the production
\u00a0
of oil and gas, including operation and maintenance
\u00a0
of installations, well
intervention activities and insurances. Tariff and transportation expenses consist of charges
\u00a0
incurred by the Group in the North Sea
for the use of infrastructure owned by other
\u00a0
companies. Lifting costs and Tariff and transportation expenses are recognized based on
the Group\u2019s paying interest in the oil and gas licenses.
\u00a0
Movement in overlift/underlift
A liability (overlift, see Note 22) arises when the
\u00a0
Group sells more than its share of the oil and
\u00a0
gas production. Similarly, an asset
(underlift, see Note 15) arises when the sale
\u00a0
is less than the Group\u2019s share of the oil and gas production.
\u00a0
In general, the
overlift/underlift balances are valued at production
\u00a0
cost including depreciation (the sales method). The
\u00a0
movements in overlift/underlift
are presented as an adjustment to Cost of
\u00a0
goods sold.
\u00a0
Depreciation, depletion and amortization
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the unit-of-production (UoP) method. See
\u00a0
Note 10 for more details.
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Exploration expenses
The Group uses the successful efforts method to account for
\u00a0
its exploration and evaluation assets. All
\u00a0
exploration costs (including
purchase of seismic, geological and geophysical
\u00a0
costs and general and administrative costs),
\u00a0
except for acquisition costs of licenses
and drilling costs of exploration wells, are expensed
\u00a0
as incurred.
\u00a0
Acquisition costs of licenses and drilling costs
\u00a0
of exploration wells are temporarily capitalized
\u00a0
pending the determination of oil and
gas resources. These costs include directly attributable
\u00a0
employee remuneration, materials and fuel used,
\u00a0
rig costs and payments to
contractors. Continued capitalization of such costs is
\u00a0
assessed for impairment at each reporting
\u00a0
date. The main criterion is that there
must be plans for future activity in the license or
\u00a0
that a development decision is expected in
\u00a0
the near future. If reserves or resources
are not found, or if discoveries are assessed
\u00a0
not technically or commercially recoverable,
\u00a0
the costs of exploration wells and licenses
are expensed. Furthermore, 3D seismic cost over
\u00a0
a discovery area is capitalized when the
\u00a0
objective is to learn more about the
reservoir and to support the determination of new
\u00a0
well locations within the discovery area.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForExpensesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_32": { "value": "
Depreciation, depletion and amortization
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the unit-of-production (UoP) method. See
\u00a0
Note 10 for more details.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_33": { "value": "
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\n
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\n
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\n
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\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2024
2023
Lifting costs
-175.5
-191.7
Tariff and transportation expenses
-49.4
-32.4
Production costs based on produced volumes
-224.9
-224.1
Movement in overlift/underlift
2.1
5.6
Production costs based on sold volumes
-222.7
-218.4
Depreciation, depletion and amortization
-184.1
-146.4
Total cost of goods sold
-406.9
-364.8
", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_34": { "value": "
Note 5
Administrative/Other expenses
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Pensions and share-based payments
Pensions
The Group\u2019s pension obligations in Norway are limited
\u00a0
to certain defined contribution plans which are
\u00a0
paid to pension insurance
plans and charged to profit or loss in the period
\u00a0
in which they are incurred. Once the contributions
\u00a0
are paid there are no further
obligations.
Share-based payments
Cash-settled share-based payments are recognized in
\u00a0
the income statement as expenses during the
\u00a0
vesting period and as a liability.
The liability is measured at fair value and revaluated
\u00a0
using the Black & Scholes pricing model at each balance
\u00a0
sheet date and at the
date of settlement, with any change in the fair
\u00a0
value recognized in the income statement for
\u00a0
the period.
\u00a0
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\n
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\u00a0
\n
1 January - 31 December
USD million
2024
2023
Salaries, bonuses, etc.
-50.3
-53.1
Employer's payroll tax expenses
-6.8
-7.6
Pensions
-4.2
-4.6
Other personnel costs
-7.0
-4.3
General and administration expenses
-27.7
-27.8
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
72.5
74.1
Total administrative expenses
-23.5
-23.3
Other expenses
-2.5
-7.9
Total other operating expenses
-2.5
-7.9
Salaries and social expenses directly attributable
\u00a0
to license activities are reclassified to lifting costs and
\u00a0
exploration costs, or tangible
assets and capitalized exploration.
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.2 million expensed
\u00a0
in 2024 (USD 4.6 million in
2023). The Group\u2019s obligations are limited to the annual pension
\u00a0
contributions. DNO meets the Norwegian legal requirements
\u00a0
for
mandatory occupational pension
(\u201cobligatorisk tjenestepensjon\u201d).
At yearend 2024, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted
\u00a0
to USD 8.4 million (USD
5.0
million at yearend 2023). For more information
\u00a0
about remuneration to senior management, see Note
\u00a0
3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2024
2023
Outstanding as of 1 January
10,829,494
11,453,638
Granted during the year
3,553,754
4,288,935
Forfeited/reversed during the year
809,584
624,141
Settled during the year
576,473
4,288,938
Outstanding as of 31 December
12,997,191
10,829,494
Unrestricted as of 31 December
690,043
1,032,058
Weighted average remaining contractual life for the synthetic shares (years)
2.12
2.54
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.66
10.20
Settlement price for synthetic shares at the end of the year (NOK)
10.47
10.70
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\n
Remuneration to Board of Directors and senior
\u00a0
management
1 January - 31 December
USD million
2024
2023
Managing Director
Salary
-0.65
-0.58
Bonus
-0.12
-0.16
Pension
-0.02
-0.02
Other remuneration
-0.13
-0.41
Remuneration to Managing Director
-0.92
-1.17
Other senior management
Salary
-3.59
-1.69
Bonus
-0.47
-0.40
Pension
-0.17
-0.06
Other remuneration
-0.79
-0.78
Remuneration to other senior management
-5.02
-2.93
Total remuneration to senior management
-5.95
-4.09
Number of managers included
11
5
Total remuneration to Board of Directors
-1.59
-1.61
Total remuneration to Board of Directors and senior management
-7.54
-5.71
The list of leading personnel,
\u00a0
now referred to as senior management, has been
\u00a0
expanded compared to the previous year.
Shares and options held by Board of Directors
\u00a0
and senior management
Years ended 31 December
\u00a0
2024
\u00a0
\u00a0
2023
\u00a0
Directors and senior management
Shares
\u00a0
Options
\u00a0
Shares
\u00a0
Options
\u00a0
Bijan Mossavar-Rahmani, Executive Chairman*
125,683,241
-
125,683,241
-
Gunnar Hirsti, Deputy Chairman (Hirsti Invest AS)
350,000
-
350,000
-
Elin Karfjell, Director (Elika AS)
33,000
-
33,000
-
Anita Marie Hjerkinn Aarn\u00e6s, Director
-
-
-
-
Najmedin Meshkati, Director
-
-
-
-
Chris Spencer, Managing Director (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
75,000
-
50,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
Linn Hoel, Chief Commercial Officer
-
-
-
-
Erlend Wollan Einum, Chief Business Development Officer
-
-
-
-
Elisabeth Femsteinevik, General Manager North Sea
-
-
-
-
Tonje Pareli Gormley,
\u00a0
General Counsel - Middle East
\u00a0
-
-
-
-
Erling Moen Synnes, Chief Information Officer
-
-
-
-
Wieske Paulissen, Group Head of Exploration and Subsurface
-
-
-
-
Kjersti Kaurin, Corporate Counsel and Secretary
-
-
-
-
* Bijan Mossavar-Rahmani held interests in the Company through nominee accounts held by Goldman Sachs & Co. LLC, representing 12.89 percent of the
\u00a0
\u00a0
total number of outstanding Company shares at yearend 2024.
Senior management and the members of the Board of
\u00a0
Directors have been awarded synthetic shares
\u00a0
during the year as part of their
variable remuneration, see Note 3 in the parent company
\u00a0
accounts.
\u00a0
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\u00a0
\n
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2024
2023
Auditor fees
-0.65
-0.65
Other financial auditing
-0.03
-0.03
Tax advisory services
-0.08
-0.16
Other advisory services
-
-
Total auditor fees
-0.76
-0.84
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\n
\u00a0
\n
1 January - 31 December
USD million
2024
2023
Exploration expenses (G&G and field surveys)
-16.5
-15.0
Seismic costs
-16.5
-9.9
Exploration expenses capitalized in previous years carried to cost
-0.8
-
Exploration expenses capitalized during the year carried to cost
-36.8
-6.0
Other exploration expenses
-18.3
-16.8
Total exploration expenses
-88.9
-47.7
Exploration expenses in 2024 were related to exploration
\u00a0
activities in the North Sea, including expensing
\u00a0
of exploration wells (Falstaff
prospect in the Falstaff/Othello well and Angel and Hummer
\u00a0
wells). Exploration expenses in 2023 were
\u00a0
related to exploration activities in
the North Sea, including expensing of exploration
\u00a0
wells (Eggen and Litago wells).
", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesByNatureExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_35": { "value": "
Note 5
Administrative/Other expenses
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Pensions and share-based payments
Pensions
The Group\u2019s pension obligations in Norway are limited
\u00a0
to certain defined contribution plans which are
\u00a0
paid to pension insurance
plans and charged to profit or loss in the period
\u00a0
in which they are incurred. Once the contributions
\u00a0
are paid there are no further
obligations.
Share-based payments
Cash-settled share-based payments are recognized in
\u00a0
the income statement as expenses during the
\u00a0
vesting period and as a liability.
The liability is measured at fair value and revaluated
\u00a0
using the Black & Scholes pricing model at each balance
\u00a0
sheet date and at the
date of settlement, with any change in the fair
\u00a0
value recognized in the income statement for
\u00a0
the period.
\u00a0
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\n
1 January - 31 December
USD million
2024
2023
Salaries, bonuses, etc.
-50.3
-53.1
Employer's payroll tax expenses
-6.8
-7.6
Pensions
-4.2
-4.6
Other personnel costs
-7.0
-4.3
General and administration expenses
-27.7
-27.8
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
72.5
74.1
Total administrative expenses
-23.5
-23.3
Other expenses
-2.5
-7.9
Total other operating expenses
-2.5
-7.9
Salaries and social expenses directly attributable
\u00a0
to license activities are reclassified to lifting costs and
\u00a0
exploration costs, or tangible
assets and capitalized exploration.
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.2 million expensed
\u00a0
in 2024 (USD 4.6 million in
2023). The Group\u2019s obligations are limited to the annual pension
\u00a0
contributions. DNO meets the Norwegian legal requirements
\u00a0
for
mandatory occupational pension
(\u201cobligatorisk tjenestepensjon\u201d).
At yearend 2024, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted
\u00a0
to USD 8.4 million (USD
5.0
million at yearend 2023). For more information
\u00a0
about remuneration to senior management, see Note
\u00a0
3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2024
2023
Outstanding as of 1 January
10,829,494
11,453,638
Granted during the year
3,553,754
4,288,935
Forfeited/reversed during the year
809,584
624,141
Settled during the year
576,473
4,288,938
Outstanding as of 31 December
12,997,191
10,829,494
Unrestricted as of 31 December
690,043
1,032,058
Weighted average remaining contractual life for the synthetic shares (years)
2.12
2.54
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.66
10.20
Settlement price for synthetic shares at the end of the year (NOK)
10.47
10.70
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\u00a0
\n
Remuneration to Board of Directors and senior
\u00a0
management
1 January - 31 December
USD million
2024
2023
Managing Director
Salary
-0.65
-0.58
Bonus
-0.12
-0.16
Pension
-0.02
-0.02
Other remuneration
-0.13
-0.41
Remuneration to Managing Director
-0.92
-1.17
Other senior management
Salary
-3.59
-1.69
Bonus
-0.47
-0.40
Pension
-0.17
-0.06
Other remuneration
-0.79
-0.78
Remuneration to other senior management
-5.02
-2.93
Total remuneration to senior management
-5.95
-4.09
Number of managers included
11
5
Total remuneration to Board of Directors
-1.59
-1.61
Total remuneration to Board of Directors and senior management
-7.54
-5.71
The list of leading personnel,
\u00a0
now referred to as senior management, has been
\u00a0
expanded compared to the previous year.
Shares and options held by Board of Directors
\u00a0
and senior management
Years ended 31 December
\u00a0
2024
\u00a0
\u00a0
2023
\u00a0
Directors and senior management
Shares
\u00a0
Options
\u00a0
Shares
\u00a0
Options
\u00a0
Bijan Mossavar-Rahmani, Executive Chairman*
125,683,241
-
125,683,241
-
Gunnar Hirsti, Deputy Chairman (Hirsti Invest AS)
350,000
-
350,000
-
Elin Karfjell, Director (Elika AS)
33,000
-
33,000
-
Anita Marie Hjerkinn Aarn\u00e6s, Director
-
-
-
-
Najmedin Meshkati, Director
-
-
-
-
Chris Spencer, Managing Director (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
75,000
-
50,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
Linn Hoel, Chief Commercial Officer
-
-
-
-
Erlend Wollan Einum, Chief Business Development Officer
-
-
-
-
Elisabeth Femsteinevik, General Manager North Sea
-
-
-
-
Tonje Pareli Gormley,
\u00a0
General Counsel - Middle East
\u00a0
-
-
-
-
Erling Moen Synnes, Chief Information Officer
-
-
-
-
Wieske Paulissen, Group Head of Exploration and Subsurface
-
-
-
-
Kjersti Kaurin, Corporate Counsel and Secretary
-
-
-
-
* Bijan Mossavar-Rahmani held interests in the Company through nominee accounts held by Goldman Sachs & Co. LLC, representing 12.89 percent of the
\u00a0
\u00a0
total number of outstanding Company shares at yearend 2024.
Senior management and the members of the Board of
\u00a0
Directors have been awarded synthetic shares
\u00a0
during the year as part of their
variable remuneration, see Note 3 in the parent company
\u00a0
accounts.
\u00a0
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\n
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2024
2023
Auditor fees
-0.65
-0.65
Other financial auditing
-0.03
-0.03
Tax advisory services
-0.08
-0.16
Other advisory services
-
-
Total auditor fees
-0.76
-0.84
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\u00a0
\n
1 January - 31 December
USD million
2024
2023
Exploration expenses (G&G and field surveys)
-16.5
-15.0
Seismic costs
-16.5
-9.9
Exploration expenses capitalized in previous years carried to cost
-0.8
-
Exploration expenses capitalized during the year carried to cost
-36.8
-6.0
Other exploration expenses
-18.3
-16.8
Total exploration expenses
-88.9
-47.7
Exploration expenses in 2024 were related to exploration
\u00a0
activities in the North Sea, including expensing
\u00a0
of exploration wells (Falstaff
prospect in the Falstaff/Othello well and Angel and Hummer
\u00a0
wells). Exploration expenses in 2023 were
\u00a0
related to exploration activities in
the North Sea, including expensing of exploration
\u00a0
wells (Eggen and Litago wells).
", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_36": { "value": "
Note 5
Administrative/Other expenses
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
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\u00a0
\n
\u00a0
\n
Pensions and share-based payments
Pensions
The Group\u2019s pension obligations in Norway are limited
\u00a0
to certain defined contribution plans which are
\u00a0
paid to pension insurance
plans and charged to profit or loss in the period
\u00a0
in which they are incurred. Once the contributions
\u00a0
are paid there are no further
obligations.
Share-based payments
Cash-settled share-based payments are recognized in
\u00a0
the income statement as expenses during the
\u00a0
vesting period and as a liability.
The liability is measured at fair value and revaluated
\u00a0
using the Black & Scholes pricing model at each balance
\u00a0
sheet date and at the
date of settlement, with any change in the fair
\u00a0
value recognized in the income statement for
\u00a0
the period.
\u00a0
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1 January - 31 December
USD million
2024
2023
Salaries, bonuses, etc.
-50.3
-53.1
Employer's payroll tax expenses
-6.8
-7.6
Pensions
-4.2
-4.6
Other personnel costs
-7.0
-4.3
General and administration expenses
-27.7
-27.8
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
72.5
74.1
Total administrative expenses
-23.5
-23.3
Other expenses
-2.5
-7.9
Total other operating expenses
-2.5
-7.9
Salaries and social expenses directly attributable
\u00a0
to license activities are reclassified to lifting costs and
\u00a0
exploration costs, or tangible
assets and capitalized exploration.
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.2 million expensed
\u00a0
in 2024 (USD 4.6 million in
2023). The Group\u2019s obligations are limited to the annual pension
\u00a0
contributions. DNO meets the Norwegian legal requirements
\u00a0
for
mandatory occupational pension
(\u201cobligatorisk tjenestepensjon\u201d).
At yearend 2024, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted
\u00a0
to USD 8.4 million (USD
5.0
million at yearend 2023). For more information
\u00a0
about remuneration to senior management, see Note
\u00a0
3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2024
2023
Outstanding as of 1 January
10,829,494
11,453,638
Granted during the year
3,553,754
4,288,935
Forfeited/reversed during the year
809,584
624,141
Settled during the year
576,473
4,288,938
Outstanding as of 31 December
12,997,191
10,829,494
Unrestricted as of 31 December
690,043
1,032,058
Weighted average remaining contractual life for the synthetic shares (years)
2.12
2.54
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.66
10.20
Settlement price for synthetic shares at the end of the year (NOK)
10.47
10.70
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\u00a0
\n
Remuneration to Board of Directors and senior
\u00a0
management
1 January - 31 December
USD million
2024
2023
Managing Director
Salary
-0.65
-0.58
Bonus
-0.12
-0.16
Pension
-0.02
-0.02
Other remuneration
-0.13
-0.41
Remuneration to Managing Director
-0.92
-1.17
Other senior management
Salary
-3.59
-1.69
Bonus
-0.47
-0.40
Pension
-0.17
-0.06
Other remuneration
-0.79
-0.78
Remuneration to other senior management
-5.02
-2.93
Total remuneration to senior management
-5.95
-4.09
Number of managers included
11
5
Total remuneration to Board of Directors
-1.59
-1.61
Total remuneration to Board of Directors and senior management
-7.54
-5.71
The list of leading personnel,
\u00a0
now referred to as senior management, has been
\u00a0
expanded compared to the previous year.
Shares and options held by Board of Directors
\u00a0
and senior management
Years ended 31 December
\u00a0
2024
\u00a0
\u00a0
2023
\u00a0
Directors and senior management
Shares
\u00a0
Options
\u00a0
Shares
\u00a0
Options
\u00a0
Bijan Mossavar-Rahmani, Executive Chairman*
125,683,241
-
125,683,241
-
Gunnar Hirsti, Deputy Chairman (Hirsti Invest AS)
350,000
-
350,000
-
Elin Karfjell, Director (Elika AS)
33,000
-
33,000
-
Anita Marie Hjerkinn Aarn\u00e6s, Director
-
-
-
-
Najmedin Meshkati, Director
-
-
-
-
Chris Spencer, Managing Director (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
75,000
-
50,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
Linn Hoel, Chief Commercial Officer
-
-
-
-
Erlend Wollan Einum, Chief Business Development Officer
-
-
-
-
Elisabeth Femsteinevik, General Manager North Sea
-
-
-
-
Tonje Pareli Gormley,
\u00a0
General Counsel - Middle East
\u00a0
-
-
-
-
Erling Moen Synnes, Chief Information Officer
-
-
-
-
Wieske Paulissen, Group Head of Exploration and Subsurface
-
-
-
-
Kjersti Kaurin, Corporate Counsel and Secretary
-
-
-
-
* Bijan Mossavar-Rahmani held interests in the Company through nominee accounts held by Goldman Sachs & Co. LLC, representing 12.89 percent of the
\u00a0
\u00a0
total number of outstanding Company shares at yearend 2024.
Senior management and the members of the Board of
\u00a0
Directors have been awarded synthetic shares
\u00a0
during the year as part of their
variable remuneration, see Note 3 in the parent company
\u00a0
accounts.
\u00a0
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\n
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2024
2023
Auditor fees
-0.65
-0.65
Other financial auditing
-0.03
-0.03
Tax advisory services
-0.08
-0.16
Other advisory services
-
-
Total auditor fees
-0.76
-0.84
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_37": { "value": "
Note 5
Administrative/Other expenses
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\n
1 January - 31 December
USD million
2024
2023
Salaries, bonuses, etc.
-50.3
-53.1
Employer's payroll tax expenses
-6.8
-7.6
Pensions
-4.2
-4.6
Other personnel costs
-7.0
-4.3
General and administration expenses
-27.7
-27.8
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
72.5
74.1
Total administrative expenses
-23.5
-23.3
Other expenses
-2.5
-7.9
Total other operating expenses
-2.5
-7.9
Salaries and social expenses directly attributable
\u00a0
to license activities are reclassified to lifting costs and
\u00a0
exploration costs, or tangible
assets and capitalized exploration.
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.2 million expensed
\u00a0
in 2024 (USD 4.6 million in
2023). The Group\u2019s obligations are limited to the annual pension
\u00a0
contributions. DNO meets the Norwegian legal requirements
\u00a0
for
mandatory occupational pension
(\u201cobligatorisk tjenestepensjon\u201d).
At yearend 2024, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted
\u00a0
to USD 8.4 million (USD
5.0
million at yearend 2023). For more information
\u00a0
about remuneration to senior management, see Note
\u00a0
3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2024
2023
Outstanding as of 1 January
10,829,494
11,453,638
Granted during the year
3,553,754
4,288,935
Forfeited/reversed during the year
809,584
624,141
Settled during the year
576,473
4,288,938
Outstanding as of 31 December
12,997,191
10,829,494
Unrestricted as of 31 December
690,043
1,032,058
Weighted average remaining contractual life for the synthetic shares (years)
2.12
2.54
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.66
10.20
Settlement price for synthetic shares at the end of the year (NOK)
10.47
10.70
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\u00a0
\n
Remuneration to Board of Directors and senior
\u00a0
management
1 January - 31 December
USD million
2024
2023
Managing Director
Salary
-0.65
-0.58
Bonus
-0.12
-0.16
Pension
-0.02
-0.02
Other remuneration
-0.13
-0.41
Remuneration to Managing Director
-0.92
-1.17
Other senior management
Salary
-3.59
-1.69
Bonus
-0.47
-0.40
Pension
-0.17
-0.06
Other remuneration
-0.79
-0.78
Remuneration to other senior management
-5.02
-2.93
Total remuneration to senior management
-5.95
-4.09
Number of managers included
11
5
Total remuneration to Board of Directors
-1.59
-1.61
Total remuneration to Board of Directors and senior management
-7.54
-5.71
The list of leading personnel,
\u00a0
now referred to as senior management, has been
\u00a0
expanded compared to the previous year.
Shares and options held by Board of Directors
\u00a0
and senior management
Years ended 31 December
\u00a0
2024
\u00a0
\u00a0
2023
\u00a0
Directors and senior management
Shares
\u00a0
Options
\u00a0
Shares
\u00a0
Options
\u00a0
Bijan Mossavar-Rahmani, Executive Chairman*
125,683,241
-
125,683,241
-
Gunnar Hirsti, Deputy Chairman (Hirsti Invest AS)
350,000
-
350,000
-
Elin Karfjell, Director (Elika AS)
33,000
-
33,000
-
Anita Marie Hjerkinn Aarn\u00e6s, Director
-
-
-
-
Najmedin Meshkati, Director
-
-
-
-
Chris Spencer, Managing Director (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
75,000
-
50,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
Linn Hoel, Chief Commercial Officer
-
-
-
-
Erlend Wollan Einum, Chief Business Development Officer
-
-
-
-
Elisabeth Femsteinevik, General Manager North Sea
-
-
-
-
Tonje Pareli Gormley,
\u00a0
General Counsel - Middle East
\u00a0
-
-
-
-
Erling Moen Synnes, Chief Information Officer
-
-
-
-
Wieske Paulissen, Group Head of Exploration and Subsurface
-
-
-
-
Kjersti Kaurin, Corporate Counsel and Secretary
-
-
-
-
* Bijan Mossavar-Rahmani held interests in the Company through nominee accounts held by Goldman Sachs & Co. LLC, representing 12.89 percent of the
\u00a0
\u00a0
total number of outstanding Company shares at yearend 2024.
Senior management and the members of the Board of
\u00a0
Directors have been awarded synthetic shares
\u00a0
during the year as part of their
variable remuneration, see Note 3 in the parent company
\u00a0
accounts.
", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralAndAdministrativeExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_38": { "value": "
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Pensions and share-based payments
Pensions
The Group\u2019s pension obligations in Norway are limited
\u00a0
to certain defined contribution plans which are
\u00a0
paid to pension insurance
plans and charged to profit or loss in the period
\u00a0
in which they are incurred. Once the contributions
\u00a0
are paid there are no further
obligations.
Share-based payments
Cash-settled share-based payments are recognized in
\u00a0
the income statement as expenses during the
\u00a0
vesting period and as a liability.
The liability is measured at fair value and revaluated
\u00a0
using the Black & Scholes pricing model at each balance
\u00a0
sheet date and at the
date of settlement, with any change in the fair
\u00a0
value recognized in the income statement for
\u00a0
the period.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSharebasedPaymentTransactionsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_39": { "value": "
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Pensions and share-based payments
Pensions
The Group\u2019s pension obligations in Norway are limited
\u00a0
to certain defined contribution plans which are
\u00a0
paid to pension insurance
plans and charged to profit or loss in the period
\u00a0
in which they are incurred. Once the contributions
\u00a0
are paid there are no further
obligations.
Share-based payments
Cash-settled share-based payments are recognized in
\u00a0
the income statement as expenses during the
\u00a0
vesting period and as a liability.
The liability is measured at fair value and revaluated
\u00a0
using the Black & Scholes pricing model at each balance
\u00a0
sheet date and at the
date of settlement, with any change in the fair
\u00a0
value recognized in the income statement for
\u00a0
the period.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_40": { "value": "
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\n
1 January - 31 December
USD million
2024
2023
Salaries, bonuses, etc.
-50.3
-53.1
Employer's payroll tax expenses
-6.8
-7.6
Pensions
-4.2
-4.6
Other personnel costs
-7.0
-4.3
General and administration expenses
-27.7
-27.8
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
72.5
74.1
Total administrative expenses
-23.5
-23.3
Other expenses
-2.5
-7.9
Total other operating expenses
-2.5
-7.9
Salaries and social expenses directly attributable
\u00a0
to license activities are reclassified to lifting costs and
\u00a0
exploration costs, or tangible
assets and capitalized exploration.
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.2 million expensed
\u00a0
in 2024 (USD 4.6 million in
2023). The Group\u2019s obligations are limited to the annual pension
\u00a0
contributions. DNO meets the Norwegian legal requirements
\u00a0
for
mandatory occupational pension
(\u201cobligatorisk tjenestepensjon\u201d).
At yearend 2024, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted
\u00a0
to USD 8.4 million (USD
5.0
million at yearend 2023). For more information
\u00a0
about remuneration to senior management, see Note
\u00a0
3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2024
2023
Outstanding as of 1 January
10,829,494
11,453,638
Granted during the year
3,553,754
4,288,935
Forfeited/reversed during the year
809,584
624,141
Settled during the year
576,473
4,288,938
Outstanding as of 31 December
12,997,191
10,829,494
Unrestricted as of 31 December
690,043
1,032,058
Weighted average remaining contractual life for the synthetic shares (years)
2.12
2.54
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.66
10.20
Settlement price for synthetic shares at the end of the year (NOK)
10.47
10.70
\u00a0
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\n
Remuneration to Board of Directors and senior
\u00a0
management
1 January - 31 December
USD million
2024
2023
Managing Director
Salary
-0.65
-0.58
Bonus
-0.12
-0.16
Pension
-0.02
-0.02
Other remuneration
-0.13
-0.41
Remuneration to Managing Director
-0.92
-1.17
Other senior management
Salary
-3.59
-1.69
Bonus
-0.47
-0.40
Pension
-0.17
-0.06
Other remuneration
-0.79
-0.78
Remuneration to other senior management
-5.02
-2.93
Total remuneration to senior management
-5.95
-4.09
Number of managers included
11
5
Total remuneration to Board of Directors
-1.59
-1.61
Total remuneration to Board of Directors and senior management
-7.54
-5.71
The list of leading personnel,
\u00a0
now referred to as senior management, has been
\u00a0
expanded compared to the previous year.
Shares and options held by Board of Directors
\u00a0
and senior management
Years ended 31 December
\u00a0
2024
\u00a0
\u00a0
2023
\u00a0
Directors and senior management
Shares
\u00a0
Options
\u00a0
Shares
\u00a0
Options
\u00a0
Bijan Mossavar-Rahmani, Executive Chairman*
125,683,241
-
125,683,241
-
Gunnar Hirsti, Deputy Chairman (Hirsti Invest AS)
350,000
-
350,000
-
Elin Karfjell, Director (Elika AS)
33,000
-
33,000
-
Anita Marie Hjerkinn Aarn\u00e6s, Director
-
-
-
-
Najmedin Meshkati, Director
-
-
-
-
Chris Spencer, Managing Director (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
75,000
-
50,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
Linn Hoel, Chief Commercial Officer
-
-
-
-
Erlend Wollan Einum, Chief Business Development Officer
-
-
-
-
Elisabeth Femsteinevik, General Manager North Sea
-
-
-
-
Tonje Pareli Gormley,
\u00a0
General Counsel - Middle East
\u00a0
-
-
-
-
Erling Moen Synnes, Chief Information Officer
-
-
-
-
Wieske Paulissen, Group Head of Exploration and Subsurface
-
-
-
-
Kjersti Kaurin, Corporate Counsel and Secretary
-
-
-
-
* Bijan Mossavar-Rahmani held interests in the Company through nominee accounts held by Goldman Sachs & Co. LLC, representing 12.89 percent of the
\u00a0
\u00a0
total number of outstanding Company shares at yearend 2024.
Senior management and the members of the Board of
\u00a0
Directors have been awarded synthetic shares
\u00a0
during the year as part of their
variable remuneration, see Note 3 in the parent company
\u00a0
accounts.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutEmployeesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_41": { "value": "
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\n
1 January - 31 December
USD million
2024
2023
Salaries, bonuses, etc.
-50.3
-53.1
Employer's payroll tax expenses
-6.8
-7.6
Pensions
-4.2
-4.6
Other personnel costs
-7.0
-4.3
General and administration expenses
-27.7
-27.8
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
72.5
74.1
Total administrative expenses
-23.5
-23.3
Other expenses
-2.5
-7.9
Total other operating expenses
-2.5
-7.9
Salaries and social expenses directly attributable
\u00a0
to license activities are reclassified to lifting costs and
\u00a0
exploration costs, or tangible
assets and capitalized exploration.
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.2 million expensed
\u00a0
in 2024 (USD 4.6 million in
2023). The Group\u2019s obligations are limited to the annual pension
\u00a0
contributions. DNO meets the Norwegian legal requirements
\u00a0
for
mandatory occupational pension
(\u201cobligatorisk tjenestepensjon\u201d).
At yearend 2024, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted
\u00a0
to USD 8.4 million (USD
5.0
million at yearend 2023). For more information
\u00a0
about remuneration to senior management, see Note
\u00a0
3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2024
2023
Outstanding as of 1 January
10,829,494
11,453,638
Granted during the year
3,553,754
4,288,935
Forfeited/reversed during the year
809,584
624,141
Settled during the year
576,473
4,288,938
Outstanding as of 31 December
12,997,191
10,829,494
Unrestricted as of 31 December
690,043
1,032,058
Weighted average remaining contractual life for the synthetic shares (years)
2.12
2.54
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.66
10.20
Settlement price for synthetic shares at the end of the year (NOK)
10.47
10.70
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\n
\u00a0
\n
Remuneration to Board of Directors and senior
\u00a0
management
1 January - 31 December
USD million
2024
2023
Managing Director
Salary
-0.65
-0.58
Bonus
-0.12
-0.16
Pension
-0.02
-0.02
Other remuneration
-0.13
-0.41
Remuneration to Managing Director
-0.92
-1.17
Other senior management
Salary
-3.59
-1.69
Bonus
-0.47
-0.40
Pension
-0.17
-0.06
Other remuneration
-0.79
-0.78
Remuneration to other senior management
-5.02
-2.93
Total remuneration to senior management
-5.95
-4.09
Number of managers included
11
5
Total remuneration to Board of Directors
-1.59
-1.61
Total remuneration to Board of Directors and senior management
-7.54
-5.71
The list of leading personnel,
\u00a0
now referred to as senior management, has been
\u00a0
expanded compared to the previous year.
Shares and options held by Board of Directors
\u00a0
and senior management
Years ended 31 December
\u00a0
2024
\u00a0
\u00a0
2023
\u00a0
Directors and senior management
Shares
\u00a0
Options
\u00a0
Shares
\u00a0
Options
\u00a0
Bijan Mossavar-Rahmani, Executive Chairman*
125,683,241
-
125,683,241
-
Gunnar Hirsti, Deputy Chairman (Hirsti Invest AS)
350,000
-
350,000
-
Elin Karfjell, Director (Elika AS)
33,000
-
33,000
-
Anita Marie Hjerkinn Aarn\u00e6s, Director
-
-
-
-
Najmedin Meshkati, Director
-
-
-
-
Chris Spencer, Managing Director (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
75,000
-
50,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
Linn Hoel, Chief Commercial Officer
-
-
-
-
Erlend Wollan Einum, Chief Business Development Officer
-
-
-
-
Elisabeth Femsteinevik, General Manager North Sea
-
-
-
-
Tonje Pareli Gormley,
\u00a0
General Counsel - Middle East
\u00a0
-
-
-
-
Erling Moen Synnes, Chief Information Officer
-
-
-
-
Wieske Paulissen, Group Head of Exploration and Subsurface
-
-
-
-
Kjersti Kaurin, Corporate Counsel and Secretary
-
-
-
-
* Bijan Mossavar-Rahmani held interests in the Company through nominee accounts held by Goldman Sachs & Co. LLC, representing 12.89 percent of the
\u00a0
\u00a0
total number of outstanding Company shares at yearend 2024.
Senior management and the members of the Board of
\u00a0
Directors have been awarded synthetic shares
\u00a0
during the year as part of their
variable remuneration, see Note 3 in the parent company
\u00a0
accounts.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_42": { "value": "
\u00a0
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\n
\u00a0
\n
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2024
2023
Auditor fees
-0.65
-0.65
Other financial auditing
-0.03
-0.03
Tax advisory services
-0.08
-0.16
Other advisory services
-
-
Total auditor fees
-0.76
-0.84
", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_43": { "value": "
Note 6
Exploration expenses
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Exploration expenses
The Group uses the successful efforts method to account for
\u00a0
its exploration and evaluation assets. All
\u00a0
exploration costs (including
purchase of seismic, geological and geophysical
\u00a0
costs and general and administrative costs),
\u00a0
except for acquisition costs of licenses
and drilling costs of exploration wells, are expensed
\u00a0
as incurred.
\u00a0
Acquisition costs of licenses and drilling costs
\u00a0
of exploration wells are temporarily capitalized
\u00a0
pending the determination of oil and
gas resources. These costs include directly attributable
\u00a0
employee remuneration, materials and fuel used,
\u00a0
rig costs and payments to
contractors. Continued capitalization of such costs is
\u00a0
assessed for impairment at each reporting
\u00a0
date. The main criterion is that there
must be plans for future activity in the license or
\u00a0
that a development decision is expected in
\u00a0
the near future. If reserves or resources
are not found, or if discoveries are assessed
\u00a0
not technically or commercially recoverable,
\u00a0
the costs of exploration wells and licenses
are expensed. Furthermore, 3D seismic cost over
\u00a0
a discovery area is capitalized when the
\u00a0
objective is to learn more about the
reservoir and to support the determination of new
\u00a0
well locations within the discovery area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
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\n
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\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2024
2023
Exploration expenses (G&G and field surveys)
-16.5
-15.0
Seismic costs
-16.5
-9.9
Exploration expenses capitalized in previous years carried to cost
-0.8
-
Exploration expenses capitalized during the year carried to cost
-36.8
-6.0
Other exploration expenses
-18.3
-16.8
Total exploration expenses
-88.9
-47.7
Exploration expenses in 2024 were related to exploration
\u00a0
activities in the North Sea, including expensing
\u00a0
of exploration wells (Falstaff
prospect in the Falstaff/Othello well and Angel and Hummer
\u00a0
wells). Exploration expenses in 2023 were
\u00a0
related to exploration activities in
the North Sea, including expensing of exploration
\u00a0
wells (Eggen and Litago wells).
", "dimensions": { "concept": "ifrs-full:DisclosureOfResearchAndDevelopmentExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_44": { "value": "
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Exploration expenses
The Group uses the successful efforts method to account for
\u00a0
its exploration and evaluation assets. All
\u00a0
exploration costs (including
purchase of seismic, geological and geophysical
\u00a0
costs and general and administrative costs),
\u00a0
except for acquisition costs of licenses
and drilling costs of exploration wells, are expensed
\u00a0
as incurred.
\u00a0
Acquisition costs of licenses and drilling costs
\u00a0
of exploration wells are temporarily capitalized
\u00a0
pending the determination of oil and
gas resources. These costs include directly attributable
\u00a0
employee remuneration, materials and fuel used,
\u00a0
rig costs and payments to
contractors. Continued capitalization of such costs is
\u00a0
assessed for impairment at each reporting
\u00a0
date. The main criterion is that there
must be plans for future activity in the license or
\u00a0
that a development decision is expected in
\u00a0
the near future. If reserves or resources
are not found, or if discoveries are assessed
\u00a0
not technically or commercially recoverable,
\u00a0
the costs of exploration wells and licenses
are expensed. Furthermore, 3D seismic cost over
\u00a0
a discovery area is capitalized when the
\u00a0
objective is to learn more about the
reservoir and to support the determination of new
\u00a0
well locations within the discovery area.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForResearchAndDevelopmentExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_45": { "value": "
Note 7
Financial income and financial expenses
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Financial income and expenses
Accretion expenses from unwinding of the discount
\u00a0
related to the ARO provision and lease
\u00a0
liability are further detailed in Notes 19
and Note 20. Accounting effects from IFRS 9 (expected
\u00a0
credit loss model) assessment related to the
\u00a0
KRG arrears is further detailed
in Note 15.
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\u00a0
\n
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\n
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\n
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\n
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\n
\u00a0
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\n
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\n
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\u00a0
\n
\u00a0
\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2024
2023
Interest income
38.1
36.5
Currency exchange gains recognized in the income statement (net)
9.2
8.4
Other financial income
-
0.1
Financial income
47.3
45.0
Interest expenses
-54.3
-44.6
Capitalized interest
4.1
-
Time value effect trade debtors (Note 14)
11.6
-44.3
Amortization of borrowing issue costs
-3.8
-3.3
Accretion expense ARO (unwinding of discount rate, Note 20)
-20.4
-17.4
Currency exchange loss recognized in the income statement (net)
-0.0
-
Other financial expenses
-3.9
-2.3
Financial expenses
-66.7
-112.0
Net financial income/expenses
-19.4
-67.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_46": { "value": "
Note 7
Financial income and financial expenses
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Financial income and expenses
Accretion expenses from unwinding of the discount
\u00a0
related to the ARO provision and lease
\u00a0
liability are further detailed in Notes 19
and Note 20. Accounting effects from IFRS 9 (expected
\u00a0
credit loss model) assessment related to the
\u00a0
KRG arrears is further detailed
in Note 15.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2024
2023
Interest income
38.1
36.5
Currency exchange gains recognized in the income statement (net)
9.2
8.4
Other financial income
-
0.1
Financial income
47.3
45.0
Interest expenses
-54.3
-44.6
Capitalized interest
4.1
-
Time value effect trade debtors (Note 14)
11.6
-44.3
Amortization of borrowing issue costs
-3.8
-3.3
Accretion expense ARO (unwinding of discount rate, Note 20)
-20.4
-17.4
Currency exchange loss recognized in the income statement (net)
-0.0
-
Other financial expenses
-3.9
-2.3
Financial expenses
-66.7
-112.0
Net financial income/expenses
-19.4
-67.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_47": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Financial income and expenses
Accretion expenses from unwinding of the discount
\u00a0
related to the ARO provision and lease
\u00a0
liability are further detailed in Notes 19
and Note 20. Accounting effects from IFRS 9 (expected
\u00a0
credit loss model) assessment related to the
\u00a0
KRG arrears is further detailed
in Note 15.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinanceIncomeAndCostsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_48": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Financial income and expenses
Accretion expenses from unwinding of the discount
\u00a0
related to the ARO provision and lease
\u00a0
liability are further detailed in Notes 19
and Note 20. Accounting effects from IFRS 9 (expected
\u00a0
credit loss model) assessment related to the
\u00a0
KRG arrears is further detailed
in Note 15.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinanceCostsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_49": { "value": "
\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2024
2023
Interest income
38.1
36.5
Currency exchange gains recognized in the income statement (net)
9.2
8.4
Other financial income
-
0.1
Financial income
47.3
45.0
Interest expenses
-54.3
-44.6
Capitalized interest
4.1
-
Time value effect trade debtors (Note 14)
11.6
-44.3
Amortization of borrowing issue costs
-3.8
-3.3
Accretion expense ARO (unwinding of discount rate, Note 20)
-20.4
-17.4
Currency exchange loss recognized in the income statement (net)
-0.0
-
Other financial expenses
-3.9
-2.3
Financial expenses
-66.7
-112.0
Net financial income/expenses
-19.4
-67.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfEffectOfChangesInForeignExchangeRatesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_50": { "value": "
\u00a0
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\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
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\u00a0
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\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2024
2023
Interest income
38.1
36.5
Currency exchange gains recognized in the income statement (net)
9.2
8.4
Other financial income
-
0.1
Financial income
47.3
45.0
Interest expenses
-54.3
-44.6
Capitalized interest
4.1
-
Time value effect trade debtors (Note 14)
11.6
-44.3
Amortization of borrowing issue costs
-3.8
-3.3
Accretion expense ARO (unwinding of discount rate, Note 20)
-20.4
-17.4
Currency exchange loss recognized in the income statement (net)
-0.0
-
Other financial expenses
-3.9
-2.3
Financial expenses
-66.7
-112.0
Net financial income/expenses
-19.4
-67.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_51": { "value": "
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\u00a0
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\n
\u00a0
\n
\u00a0
\n
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\u00a0
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\n
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2024
2023
Interest income
38.1
36.5
Currency exchange gains recognized in the income statement (net)
9.2
8.4
Other financial income
-
0.1
Financial income
47.3
45.0
Interest expenses
-54.3
-44.6
Capitalized interest
4.1
-
Time value effect trade debtors (Note 14)
11.6
-44.3
Amortization of borrowing issue costs
-3.8
-3.3
Accretion expense ARO (unwinding of discount rate, Note 20)
-20.4
-17.4
Currency exchange loss recognized in the income statement (net)
-0.0
-
Other financial expenses
-3.9
-2.3
Financial expenses
-66.7
-112.0
Net financial income/expenses
-19.4
-67.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_52": { "value": "
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2024
2023
Interest income
38.1
36.5
Currency exchange gains recognized in the income statement (net)
9.2
8.4
Other financial income
-
0.1
Financial income
47.3
45.0
Interest expenses
-54.3
-44.6
Capitalized interest
4.1
-
Time value effect trade debtors (Note 14)
11.6
-44.3
Amortization of borrowing issue costs
-3.8
-3.3
Accretion expense ARO (unwinding of discount rate, Note 20)
-20.4
-17.4
Currency exchange loss recognized in the income statement (net)
-0.0
-
Other financial expenses
-3.9
-2.3
Financial expenses
-66.7
-112.0
Net financial income/expenses
-19.4
-67.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_53": { "value": "
Note 8
Income taxes
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Income taxes
Tax income/expense consists of taxes receivable/payable and changes in deferred taxes. Taxes receivable/payable are based on
the amount receivable from or payable to the tax
\u00a0
authorities. Deferred tax liability is calculated
\u00a0
on all taxable temporary differences
unless there is a recognition exception. A deferred
\u00a0
tax asset is recognized only to the extent
\u00a0
that it is probable that the future taxable
income will be available against which the asset
\u00a0
can be utilized. Unrecognized deferred tax assets
\u00a0
are reassessed at each reporting
date and are recognized to the extent that it has
\u00a0
become probable that future taxable profits will
\u00a0
allow the deferred tax asset to be
recovered. Deferred tax assets and deferred
\u00a0
tax liabilities are recognized at their nominal
\u00a0
value and classified as non-current
assets/liabilities in the statements of financial position.
\u00a0
Tax payable and deferred tax are recognized directly in the equity to the
extent that they relate to items charged directly to equity.
\u00a0
\u00a0
\n
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\u00a0
\n
\u00a0
\n
Estimation uncertainty: Notional corporate income tax/deferred
\u00a0
taxation in Kurdistan
DNO\u2019s PSCs in Kurdistan provide that the corporate income tax
\u00a0
to which the contractor is subject is deemed
\u00a0
to have been paid to the
government as part of the payment of profit
\u00a0
oil to the government or its representatives.
\u00a0
Current and deferred taxation arising from
such notional corporate income tax is not calculated
\u00a0
for Kurdistan, as there is uncertainty related to
\u00a0
the tax laws of the KRG and
there is currently no well-established tax regime
\u00a0
for international oil companies. As such, it has
\u00a0
not been possible to reliably measure
such notional corporate income taxes deemed to have
\u00a0
been paid on behalf of the Company\u2019s subsidiary, DNO Iraq AS. For
accounting purposes, if such notional income
\u00a0
tax is to be classified as income tax in accordance
\u00a0
with IAS 12
Income Taxes
, the
Group would present this as an income tax expense
\u00a0
with a corresponding increase in revenues.
\u00a0
Furthermore, it would be assessed
whether any deferred tax asset or liability is required
\u00a0
to be recognized equal to the difference between
\u00a0
book values and the tax
values of the qualifying assets and liabilities,
\u00a0
multiplied by the applicable tax rate.
\u00a0
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\n
Tax income/expense
1 January - 31 December
USD million
2024
2023
Changes in deferred taxes
-57.9
-125.8
Income taxes receivable/payable
44.1
-6.9
Total tax income/expense (-)
-13.8
-132.7
Income tax receivable/payable
Years ended 31 December
USD million
2024
2023
Tax receivables
27.5
-
Income taxes payable
-
-4.6
Net tax receivable/payable (-)
27.5
-4.6
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\n
The tax balances relate to the activity on the Norwegian
\u00a0
Continental Shelf (NCS) and the UK Continental
\u00a0
Shelf (UKCS).
During 2024, DNO paid net USD 0.8 million
\u00a0
in taxes in Norway related to taxable profits
\u00a0
in 2023.
Reconciliation of tax income/expense
1 January - 31 December
USD million
2024
2023
Profit/loss before income tax
-13.3
151.3
Expected income tax according to nominal tax rate in Norway, 22 percent
-66.0
8.0
Expected income tax according to nominal petroleum tax rate in Norway,
\u00a0
78 percent
3.6
-136.8
Expected income tax according to nominal tax outside Norway
13.1
0.0
Taxes paid in kind under PSCs
-0.4
-
Exploration tax refund NCS
9.1
-
Foreign exchange variations between functional and tax currency
-11.9
-6.8
Adjustment of previous years
-1.2
0.3
Adjustment of deferred tax assets not recognized
63.3
-1.1
Change in previous years
-0.1
-
Other items including other permanent differences
-25.0
3.7
Change in tax rate
1.7
-
Tax income/expense (-)
-13.8
-132.7
Effective income tax rate
-103.8%
-87.7%
Taxes charged to equity
-
-
Adjustment of deferred tax assets not recognized
\u00a0
mainly relates to initial recognition of tax losses
\u00a0
from the acquisition of Arran (USD
61.7 million). Other items above consist mainly of permanent
\u00a0
differences on impairments which are not tax deductible,
\u00a0
and permanent
differences on tax exempted profits/losses from upstream
\u00a0
activities outside of Norway carried out by
\u00a0
the Company\u2019s Norwegian
subsidiaries.
Tax effects on temporary differences
Years ended 31 December
USD million
2024
2023
Tangible assets
-399.2
-275.9
Intangible assets (including capitalized exploration expenses)
-166.8
-145.4
ARO provisions
298.2
238.0
Losses carried forward
214.8
174.4
Non-deductible interests carried forward
23.0
25.7
Other temporary differences
2.7
-0.6
Net deferred tax assets/liabilities
-27.3
16.2
Valuation allowance
-190.3
-208.6
Net deferred tax assets/liabilities (-)
-217.6
-192.4
Recognized deferred tax assets
39.6
-
Recognized deferred tax liabilities
-257.2
-192.4
A valuation allowance was recognized relating to
\u00a0
carried forward losses in Norway (ordinary
\u00a0
tax regime, USD 93.7 million) and the UK
(USD 96.6 million) due to the uncertainty regarding
\u00a0
future taxable profits.
Profits/losses by Norwegian companies from upstream
\u00a0
activities outside of Norway are not taxable/deductible
\u00a0
in Norway in accordance
with the General Tax Act, section 2-39. Under these rules, only certain financial income and expenses
\u00a0
are taxable in Norway.
There are no tax consequences attached to items recorded
\u00a0
in other comprehensive income.
The following nominal tax rates apply in the
\u00a0
jurisdictions where the subsidiaries of the Group
\u00a0
are taxable: Ordinary tax regime in Norway
(22 percent), the NCS (78 percent), ordinary
\u00a0
tax regime in the UK (25 percent), the UKCS
\u00a0
(40 percent) and UAE (9 percent).
Additionally, in the UK, Energy Profits Levy (EPL) applies which is a 38
\u00a0
percent temporary levy on oil and gas ringfenced
\u00a0
profits,
adjusted for decommissioning spend.
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\n
Reconciliation of change in deferred tax assets/liabilities
Years ended 31 December
USD million
2024
2023
Net deferred tax assets/liabilities at 1 January
-192.4
-62.4
Change in deferred taxes in the income statement
-57.9
-125.8
Deferred taxes related to business combinations and other transactions
9.9
1.3
Currency and other movements
22.8
-5.5
Net deferred tax assets/liabilities (-) at 31 December
-217.6
-192.4
Reconciliation of change in tax receivable/payable
Years ended 31 December
USD million
2024
2023
Net tax receivable/payable at 1 January
-4.6
-99.9
Tax receivable/payable related to transactions
\u00a0
posted directly to balance sheet
-12.2
0.1
Tax receivable/payable in the income statement
44.1
-6.9
Tax payment/refund
0.8
89.5
Currency and other movements
-0.6
12.6
Net tax receivable/payable (-) at 31 December
27.5
-4.6
Pillar Two
DNO is subject to OECD Pillar Two model rules, with Norway
\u00a0
and the UK having enacted legislation applicable
\u00a0
from 1 January 2024.
There is still some uncertainty regarding the detailed
\u00a0
application of these rules, but based on our
\u00a0
current assessment, we do not expect
any material impact on DNO\u2019s financial position or tax obligations.
", "dimensions": { "concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_54": { "value": "
Note 8
Income taxes
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Accounting policies
\u00a0
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\n
\u00a0
\n
Income taxes
Tax income/expense consists of taxes receivable/payable and changes in deferred taxes. Taxes receivable/payable are based on
the amount receivable from or payable to the tax
\u00a0
authorities. Deferred tax liability is calculated
\u00a0
on all taxable temporary differences
unless there is a recognition exception. A deferred
\u00a0
tax asset is recognized only to the extent
\u00a0
that it is probable that the future taxable
income will be available against which the asset
\u00a0
can be utilized. Unrecognized deferred tax assets
\u00a0
are reassessed at each reporting
date and are recognized to the extent that it has
\u00a0
become probable that future taxable profits will
\u00a0
allow the deferred tax asset to be
recovered. Deferred tax assets and deferred
\u00a0
tax liabilities are recognized at their nominal
\u00a0
value and classified as non-current
assets/liabilities in the statements of financial position.
\u00a0
Tax payable and deferred tax are recognized directly in the equity to the
extent that they relate to items charged directly to equity.
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\u00a0
\n
Estimation uncertainty: Notional corporate income tax/deferred
\u00a0
taxation in Kurdistan
DNO\u2019s PSCs in Kurdistan provide that the corporate income tax
\u00a0
to which the contractor is subject is deemed
\u00a0
to have been paid to the
government as part of the payment of profit
\u00a0
oil to the government or its representatives.
\u00a0
Current and deferred taxation arising from
such notional corporate income tax is not calculated
\u00a0
for Kurdistan, as there is uncertainty related to
\u00a0
the tax laws of the KRG and
there is currently no well-established tax regime
\u00a0
for international oil companies. As such, it has
\u00a0
not been possible to reliably measure
such notional corporate income taxes deemed to have
\u00a0
been paid on behalf of the Company\u2019s subsidiary, DNO Iraq AS. For
accounting purposes, if such notional income
\u00a0
tax is to be classified as income tax in accordance
\u00a0
with IAS 12
Income Taxes
, the
Group would present this as an income tax expense
\u00a0
with a corresponding increase in revenues.
\u00a0
Furthermore, it would be assessed
whether any deferred tax asset or liability is required
\u00a0
to be recognized equal to the difference between
\u00a0
book values and the tax
values of the qualifying assets and liabilities,
\u00a0
multiplied by the applicable tax rate.
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\n
Tax income/expense
1 January - 31 December
USD million
2024
2023
Changes in deferred taxes
-57.9
-125.8
Income taxes receivable/payable
44.1
-6.9
Total tax income/expense (-)
-13.8
-132.7
Income tax receivable/payable
Years ended 31 December
USD million
2024
2023
Tax receivables
27.5
-
Income taxes payable
-
-4.6
Net tax receivable/payable (-)
27.5
-4.6
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\n
The tax balances relate to the activity on the Norwegian
\u00a0
Continental Shelf (NCS) and the UK Continental
\u00a0
Shelf (UKCS).
During 2024, DNO paid net USD 0.8 million
\u00a0
in taxes in Norway related to taxable profits
\u00a0
in 2023.
Reconciliation of tax income/expense
1 January - 31 December
USD million
2024
2023
Profit/loss before income tax
-13.3
151.3
Expected income tax according to nominal tax rate in Norway, 22 percent
-66.0
8.0
Expected income tax according to nominal petroleum tax rate in Norway,
\u00a0
78 percent
3.6
-136.8
Expected income tax according to nominal tax outside Norway
13.1
0.0
Taxes paid in kind under PSCs
-0.4
-
Exploration tax refund NCS
9.1
-
Foreign exchange variations between functional and tax currency
-11.9
-6.8
Adjustment of previous years
-1.2
0.3
Adjustment of deferred tax assets not recognized
63.3
-1.1
Change in previous years
-0.1
-
Other items including other permanent differences
-25.0
3.7
Change in tax rate
1.7
-
Tax income/expense (-)
-13.8
-132.7
Effective income tax rate
-103.8%
-87.7%
Taxes charged to equity
-
-
Adjustment of deferred tax assets not recognized
\u00a0
mainly relates to initial recognition of tax losses
\u00a0
from the acquisition of Arran (USD
61.7 million). Other items above consist mainly of permanent
\u00a0
differences on impairments which are not tax deductible,
\u00a0
and permanent
differences on tax exempted profits/losses from upstream
\u00a0
activities outside of Norway carried out by
\u00a0
the Company\u2019s Norwegian
subsidiaries.
Tax effects on temporary differences
Years ended 31 December
USD million
2024
2023
Tangible assets
-399.2
-275.9
Intangible assets (including capitalized exploration expenses)
-166.8
-145.4
ARO provisions
298.2
238.0
Losses carried forward
214.8
174.4
Non-deductible interests carried forward
23.0
25.7
Other temporary differences
2.7
-0.6
Net deferred tax assets/liabilities
-27.3
16.2
Valuation allowance
-190.3
-208.6
Net deferred tax assets/liabilities (-)
-217.6
-192.4
Recognized deferred tax assets
39.6
-
Recognized deferred tax liabilities
-257.2
-192.4
A valuation allowance was recognized relating to
\u00a0
carried forward losses in Norway (ordinary
\u00a0
tax regime, USD 93.7 million) and the UK
(USD 96.6 million) due to the uncertainty regarding
\u00a0
future taxable profits.
Profits/losses by Norwegian companies from upstream
\u00a0
activities outside of Norway are not taxable/deductible
\u00a0
in Norway in accordance
with the General Tax Act, section 2-39. Under these rules, only certain financial income and expenses
\u00a0
are taxable in Norway.
There are no tax consequences attached to items recorded
\u00a0
in other comprehensive income.
The following nominal tax rates apply in the
\u00a0
jurisdictions where the subsidiaries of the Group
\u00a0
are taxable: Ordinary tax regime in Norway
(22 percent), the NCS (78 percent), ordinary
\u00a0
tax regime in the UK (25 percent), the UKCS
\u00a0
(40 percent) and UAE (9 percent).
Additionally, in the UK, Energy Profits Levy (EPL) applies which is a 38
\u00a0
percent temporary levy on oil and gas ringfenced
\u00a0
profits,
adjusted for decommissioning spend.
\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
Reconciliation of change in deferred tax assets/liabilities
Years ended 31 December
USD million
2024
2023
Net deferred tax assets/liabilities at 1 January
-192.4
-62.4
Change in deferred taxes in the income statement
-57.9
-125.8
Deferred taxes related to business combinations and other transactions
9.9
1.3
Currency and other movements
22.8
-5.5
Net deferred tax assets/liabilities (-) at 31 December
-217.6
-192.4
Reconciliation of change in tax receivable/payable
Years ended 31 December
USD million
2024
2023
Net tax receivable/payable at 1 January
-4.6
-99.9
Tax receivable/payable related to transactions
\u00a0
posted directly to balance sheet
-12.2
0.1
Tax receivable/payable in the income statement
44.1
-6.9
Tax payment/refund
0.8
89.5
Currency and other movements
-0.6
12.6
Net tax receivable/payable (-) at 31 December
27.5
-4.6
Pillar Two
DNO is subject to OECD Pillar Two model rules, with Norway
\u00a0
and the UK having enacted legislation applicable
\u00a0
from 1 January 2024.
There is still some uncertainty regarding the detailed
\u00a0
application of these rules, but based on our
\u00a0
current assessment, we do not expect
any material impact on DNO\u2019s financial position or tax obligations.
", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_55": { "value": "
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Income taxes
Tax income/expense consists of taxes receivable/payable and changes in deferred taxes. Taxes receivable/payable are based on
the amount receivable from or payable to the tax
\u00a0
authorities. Deferred tax liability is calculated
\u00a0
on all taxable temporary differences
unless there is a recognition exception. A deferred
\u00a0
tax asset is recognized only to the extent
\u00a0
that it is probable that the future taxable
income will be available against which the asset
\u00a0
can be utilized. Unrecognized deferred tax assets
\u00a0
are reassessed at each reporting
date and are recognized to the extent that it has
\u00a0
become probable that future taxable profits will
\u00a0
allow the deferred tax asset to be
recovered. Deferred tax assets and deferred
\u00a0
tax liabilities are recognized at their nominal
\u00a0
value and classified as non-current
assets/liabilities in the statements of financial position.
\u00a0
Tax payable and deferred tax are recognized directly in the equity to the
extent that they relate to items charged directly to equity.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Notional corporate income tax/deferred
\u00a0
taxation in Kurdistan
DNO\u2019s PSCs in Kurdistan provide that the corporate income tax
\u00a0
to which the contractor is subject is deemed
\u00a0
to have been paid to the
government as part of the payment of profit
\u00a0
oil to the government or its representatives.
\u00a0
Current and deferred taxation arising from
such notional corporate income tax is not calculated
\u00a0
for Kurdistan, as there is uncertainty related to
\u00a0
the tax laws of the KRG and
there is currently no well-established tax regime
\u00a0
for international oil companies. As such, it has
\u00a0
not been possible to reliably measure
such notional corporate income taxes deemed to have
\u00a0
been paid on behalf of the Company\u2019s subsidiary, DNO Iraq AS. For
accounting purposes, if such notional income
\u00a0
tax is to be classified as income tax in accordance
\u00a0
with IAS 12
Income Taxes
, the
Group would present this as an income tax expense
\u00a0
with a corresponding increase in revenues.
\u00a0
Furthermore, it would be assessed
whether any deferred tax asset or liability is required
\u00a0
to be recognized equal to the difference between
\u00a0
book values and the tax
values of the qualifying assets and liabilities,
\u00a0
multiplied by the applicable tax rate.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_56": { "value": "
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Income taxes
Tax income/expense consists of taxes receivable/payable and changes in deferred taxes. Taxes receivable/payable are based on
the amount receivable from or payable to the tax
\u00a0
authorities. Deferred tax liability is calculated
\u00a0
on all taxable temporary differences
unless there is a recognition exception. A deferred
\u00a0
tax asset is recognized only to the extent
\u00a0
that it is probable that the future taxable
income will be available against which the asset
\u00a0
can be utilized. Unrecognized deferred tax assets
\u00a0
are reassessed at each reporting
date and are recognized to the extent that it has
\u00a0
become probable that future taxable profits will
\u00a0
allow the deferred tax asset to be
recovered. Deferred tax assets and deferred
\u00a0
tax liabilities are recognized at their nominal
\u00a0
value and classified as non-current
assets/liabilities in the statements of financial position.
\u00a0
Tax payable and deferred tax are recognized directly in the equity to the
extent that they relate to items charged directly to equity.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Notional corporate income tax/deferred
\u00a0
taxation in Kurdistan
DNO\u2019s PSCs in Kurdistan provide that the corporate income tax
\u00a0
to which the contractor is subject is deemed
\u00a0
to have been paid to the
government as part of the payment of profit
\u00a0
oil to the government or its representatives.
\u00a0
Current and deferred taxation arising from
such notional corporate income tax is not calculated
\u00a0
for Kurdistan, as there is uncertainty related to
\u00a0
the tax laws of the KRG and
there is currently no well-established tax regime
\u00a0
for international oil companies. As such, it has
\u00a0
not been possible to reliably measure
such notional corporate income taxes deemed to have
\u00a0
been paid on behalf of the Company\u2019s subsidiary, DNO Iraq AS. For
accounting purposes, if such notional income
\u00a0
tax is to be classified as income tax in accordance
\u00a0
with IAS 12
Income Taxes
, the
Group would present this as an income tax expense
\u00a0
with a corresponding increase in revenues.
\u00a0
Furthermore, it would be assessed
whether any deferred tax asset or liability is required
\u00a0
to be recognized equal to the difference between
\u00a0
book values and the tax
values of the qualifying assets and liabilities,
\u00a0
multiplied by the applicable tax rate.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_57": { "value": "
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Tax income/expense
1 January - 31 December
USD million
2024
2023
Changes in deferred taxes
-57.9
-125.8
Income taxes receivable/payable
44.1
-6.9
Total tax income/expense (-)
-13.8
-132.7
Income tax receivable/payable
Years ended 31 December
USD million
2024
2023
Tax receivables
27.5
-
Income taxes payable
-
-4.6
Net tax receivable/payable (-)
27.5
-4.6
\u00a0
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\n
The tax balances relate to the activity on the Norwegian
\u00a0
Continental Shelf (NCS) and the UK Continental
\u00a0
Shelf (UKCS).
During 2024, DNO paid net USD 0.8 million
\u00a0
in taxes in Norway related to taxable profits
\u00a0
in 2023.
Reconciliation of tax income/expense
1 January - 31 December
USD million
2024
2023
Profit/loss before income tax
-13.3
151.3
Expected income tax according to nominal tax rate in Norway, 22 percent
-66.0
8.0
Expected income tax according to nominal petroleum tax rate in Norway,
\u00a0
78 percent
3.6
-136.8
Expected income tax according to nominal tax outside Norway
13.1
0.0
Taxes paid in kind under PSCs
-0.4
-
Exploration tax refund NCS
9.1
-
Foreign exchange variations between functional and tax currency
-11.9
-6.8
Adjustment of previous years
-1.2
0.3
Adjustment of deferred tax assets not recognized
63.3
-1.1
Change in previous years
-0.1
-
Other items including other permanent differences
-25.0
3.7
Change in tax rate
1.7
-
Tax income/expense (-)
-13.8
-132.7
Effective income tax rate
-103.8%
-87.7%
Taxes charged to equity
-
-
Adjustment of deferred tax assets not recognized
\u00a0
mainly relates to initial recognition of tax losses
\u00a0
from the acquisition of Arran (USD
61.7 million). Other items above consist mainly of permanent
\u00a0
differences on impairments which are not tax deductible,
\u00a0
and permanent
differences on tax exempted profits/losses from upstream
\u00a0
activities outside of Norway carried out by
\u00a0
the Company\u2019s Norwegian
subsidiaries.
Tax effects on temporary differences
Years ended 31 December
USD million
2024
2023
Tangible assets
-399.2
-275.9
Intangible assets (including capitalized exploration expenses)
-166.8
-145.4
ARO provisions
298.2
238.0
Losses carried forward
214.8
174.4
Non-deductible interests carried forward
23.0
25.7
Other temporary differences
2.7
-0.6
Net deferred tax assets/liabilities
-27.3
16.2
Valuation allowance
-190.3
-208.6
Net deferred tax assets/liabilities (-)
-217.6
-192.4
Recognized deferred tax assets
39.6
-
Recognized deferred tax liabilities
-257.2
-192.4
A valuation allowance was recognized relating to
\u00a0
carried forward losses in Norway (ordinary
\u00a0
tax regime, USD 93.7 million) and the UK
(USD 96.6 million) due to the uncertainty regarding
\u00a0
future taxable profits.
Profits/losses by Norwegian companies from upstream
\u00a0
activities outside of Norway are not taxable/deductible
\u00a0
in Norway in accordance
with the General Tax Act, section 2-39. Under these rules, only certain financial income and expenses
\u00a0
are taxable in Norway.
There are no tax consequences attached to items recorded
\u00a0
in other comprehensive income.
The following nominal tax rates apply in the
\u00a0
jurisdictions where the subsidiaries of the Group
\u00a0
are taxable: Ordinary tax regime in Norway
(22 percent), the NCS (78 percent), ordinary
\u00a0
tax regime in the UK (25 percent), the UKCS
\u00a0
(40 percent) and UAE (9 percent).
Additionally, in the UK, Energy Profits Levy (EPL) applies which is a 38
\u00a0
percent temporary levy on oil and gas ringfenced
\u00a0
profits,
adjusted for decommissioning spend.
\u00a0
\u00a0
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Reconciliation of change in deferred tax assets/liabilities
Years ended 31 December
USD million
2024
2023
Net deferred tax assets/liabilities at 1 January
-192.4
-62.4
Change in deferred taxes in the income statement
-57.9
-125.8
Deferred taxes related to business combinations and other transactions
9.9
1.3
Currency and other movements
22.8
-5.5
Net deferred tax assets/liabilities (-) at 31 December
-217.6
-192.4
Reconciliation of change in tax receivable/payable
Years ended 31 December
USD million
2024
2023
Net tax receivable/payable at 1 January
-4.6
-99.9
Tax receivable/payable related to transactions
\u00a0
posted directly to balance sheet
-12.2
0.1
Tax receivable/payable in the income statement
44.1
-6.9
Tax payment/refund
0.8
89.5
Currency and other movements
-0.6
12.6
Net tax receivable/payable (-) at 31 December
27.5
-4.6
Pillar Two
DNO is subject to OECD Pillar Two model rules, with Norway
\u00a0
and the UK having enacted legislation applicable
\u00a0
from 1 January 2024.
There is still some uncertainty regarding the detailed
\u00a0
application of these rules, but based on our
\u00a0
current assessment, we do not expect
any material impact on DNO\u2019s financial position or tax obligations.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTaxReceivablesAndPayablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_58": { "value": "
Note 9
Intangible assets
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Intangible assets
General
Intangible assets are stated at cost, less accumulated
\u00a0
amortization and accumulated impairment charges.
\u00a0
Intangible assets include
acquisition costs for oil and gas licenses, expenditures
\u00a0
on the exploration for oil and gas resources,
\u00a0
technical goodwill and other
intangible assets. Goodwill is not depreciated.
\u00a0
The useful lives of intangible assets are assessed
\u00a0
as either finite or infinite. Amortization of
\u00a0
intangible assets is based on the
expected useful economic life and assessed for
\u00a0
impairment whenever there is an indication that the intangible
\u00a0
asset might be
impaired. The impairment assessment of intangible assets
\u00a0
with infinite lives is undertaken annually or
\u00a0
more often if indicators exist.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Goodwill
The goodwill that is recognized by the Group is related
\u00a0
to technical goodwill and is recognized
\u00a0
due to the requirement to recognize
deferred tax for the difference between the assigned fair
\u00a0
values and the related tax base. Although not
\u00a0
an IFRS term, \u201ctechnical
goodwill\u201d is commonly used in the oil and gas
\u00a0
industry to describe a category of goodwill
\u00a0
arising as an offsetting amount to deferred
tax recognized in business combinations. There are
\u00a0
no specific IFRS guidelines about the allocation
\u00a0
of technical goodwill, and the
Group has therefore applied the general guidelines
\u00a0
for allocating goodwill. In general, technical goodwill
\u00a0
is allocated to a cash-
generating unit (CGU) or group of CGUs that give
\u00a0
rise to the technical goodwill, while any residual
\u00a0
goodwill may be allocated across
all CGUs based on facts and circumstances in
\u00a0
the business combination.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its exploration and evaluation assets. Acquisition
\u00a0
costs of licenses and
drilling costs of exploration wells are temporarily
\u00a0
capitalized pending the determination of oil and
\u00a0
gas resources. These costs include
directly attributable employee remuneration, materials
\u00a0
and fuel used, rig costs and payments to contractors.
\u00a0
Continued capitalization
of such costs is assessed for impairment at each
\u00a0
reporting date. The main criterion is that there
\u00a0
must be plans for future activity in
the license or that a development decision is expected
\u00a0
in the near future. If reserves or resources
\u00a0
are not found, or if discoveries are
assessed not technically or commercially recoverable,
\u00a0
the costs of exploration wells and licenses are
\u00a0
expensed. Furthermore, 3D
seismic costs over a discovery area is capitalized
\u00a0
when the objective is to learn more about
\u00a0
the reservoir and to support the
determination of new well locations within the discovery
\u00a0
area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment assessment of
\u00a0
capitalized exploration expenditures
\u00a0
The Group\u2019s accounting policy is to temporarily capitalize
\u00a0
drilling expenditures related to exploration wells,
\u00a0
pending an evaluation of
potential oil and gas discoveries. If resources are
\u00a0
not discovered, or if recovery of the resources
\u00a0
is not considered technically or
commercially viable, the costs of the exploration wells
\u00a0
are expensed in the income statement. Decisions
\u00a0
as to whether an exploration
well should remain capitalized or expensed during
\u00a0
the period may have a material effect on the financial
\u00a0
results for the period.
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\u00a0
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\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2024 - USD million
Goodwill
interest
assets
Other
\u00a0
assets
Total
As of 1 January 2024
Acquisition costs
397.5
97.8
443.2
15.8
556.9
954.4
Accumulated impairments
-354.3
-8.8
-262.1
-
-270.9
-625.2
Accumulated depreciation
-
-71.1
-
-12.8
-83.9
-83.9
Net book amount
43.2
18.0
181.1
3.0
202.1
245.2
Period ended 31 December 2024
Opening net book amount
43.2
18.0
181.1
3.0
202.1
245.2
Translation differences
-6.3
-0.1
-23.2
-0.4
-23.7
-30.0
Additions
-
-
87.9
-
87.9
87.9
Additions through business combinations
113.8
-
-
-
-
113.8
Transfers
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-
-35.9
-
-35.9
-35.9
Impairments
-47.7
-
-
-
-
-47.7
Depreciation
-
-1.1
-
-0.8
-1.9
-2.0
Closing net book amount
102.1
16.7
209.9
1.8
228.5
330.6
As of 31 December 2024
Acquisition costs
466.5
97.6
484.4
15.5
597.5
1,064.0
Accumulated impairments/exploration write-offs
-364.4
-8.7
-274.5
-
-283.1
-647.5
Accumulated depreciation
-
-72.2
-
-13.7
-85.9
-85.9
Net book amount
102.1
16.7
209.9
1.8
228.5
330.6
Depreciation method
UoP
Linear (3-7 years)
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\n
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2023 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2023
Acquisition costs
407.2
97.5
335.3
15.4
448.2
855.4
Accumulated impairments/exploration write-offs
-351.1
-8.8
-260.5
-
-269.3
-620.3
Accumulated depreciation
-
-70.1
-
-11.7
-81.8
-81.8
Net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Period ended 31 December 2023
Opening net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Translation differences
-1.9
0.3
1.4
-
1.7
-0.3
Additions
-
-
114.2
0.4
114.6
114.6
Transfers*
-
-
-3.3
-
-3.3
-3.3
Exploration cost previously capitalized carried to cost
-
-
-6.0
-6.0
-6.0
Impairments
-11.0
-
-
-
-
-11.0
Depreciation
-
-1.0
-
-1.2
-2.2
-2.2
Closing net book amount
43.2
17.9
181.1
3.0
202.1
245.3
As of 31 December 2023
Acquisition costs
397.5
97.8
443.2
15.8
556.8
954.3
Accumulated impairments/exploration write-offs
-354.3
-8.8
-262.1
-
-270.9
-625.2
Accumulated depreciation
-
-71.1
-
-12.8
-83.9
-83.9
Net book amount
43.2
18.0
181.1
3.0
202.1
245.3
Depreciation method
UoP
Linear (3-7 years)
* Transfers were related to reclassification of the book value of the Fenja license from
\u00a0
exploration phase (intangible assets) to development phase (tangible assets).
\u00a0
\n
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\n
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\n
Exploration and development costs
\u00a0
Capitalized exploration expenditures are classified as
\u00a0
intangible assets and reclassified to tangible
\u00a0
assets (i.e., PP&E) at the start of
the development. For accounting purposes, an oil
\u00a0
and gas field is considered to enter the development
\u00a0
phase when the technical
feasibility and commercial viability of extracting oil and
\u00a0
gas from the field are demonstrable. All
\u00a0
costs of developing commercial oil
and gas fields are capitalized, including indirect
\u00a0
costs. Capitalized development costs are classified
\u00a0
as tangible assets.
\u00a0
Acquired license rights are recognized as intangible
\u00a0
assets at the time of acquisition. Acquired
\u00a0
license rights related to fields in the
exploration phase remain as intangible assets when
\u00a0
the related fields enter the development or
\u00a0
production phase. Furthermore, 3D
seismic cost over a discovery area is capitalized
\u00a0
when the objective is to learn more about
\u00a0
the reservoir and to support the
determination of new well locations within the discovery
\u00a0
area.
", "dimensions": { "concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_59": { "value": "
Note 9
Intangible assets
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\n
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\n
\u00a0
\n
Accounting policies
\u00a0
\n
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\n
\u00a0
\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
Intangible assets
General
Intangible assets are stated at cost, less accumulated
\u00a0
amortization and accumulated impairment charges.
\u00a0
Intangible assets include
acquisition costs for oil and gas licenses, expenditures
\u00a0
on the exploration for oil and gas resources,
\u00a0
technical goodwill and other
intangible assets. Goodwill is not depreciated.
\u00a0
The useful lives of intangible assets are assessed
\u00a0
as either finite or infinite. Amortization of
\u00a0
intangible assets is based on the
expected useful economic life and assessed for
\u00a0
impairment whenever there is an indication that the intangible
\u00a0
asset might be
impaired. The impairment assessment of intangible assets
\u00a0
with infinite lives is undertaken annually or
\u00a0
more often if indicators exist.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Goodwill
The goodwill that is recognized by the Group is related
\u00a0
to technical goodwill and is recognized
\u00a0
due to the requirement to recognize
deferred tax for the difference between the assigned fair
\u00a0
values and the related tax base. Although not
\u00a0
an IFRS term, \u201ctechnical
goodwill\u201d is commonly used in the oil and gas
\u00a0
industry to describe a category of goodwill
\u00a0
arising as an offsetting amount to deferred
tax recognized in business combinations. There are
\u00a0
no specific IFRS guidelines about the allocation
\u00a0
of technical goodwill, and the
Group has therefore applied the general guidelines
\u00a0
for allocating goodwill. In general, technical goodwill
\u00a0
is allocated to a cash-
generating unit (CGU) or group of CGUs that give
\u00a0
rise to the technical goodwill, while any residual
\u00a0
goodwill may be allocated across
all CGUs based on facts and circumstances in
\u00a0
the business combination.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its exploration and evaluation assets. Acquisition
\u00a0
costs of licenses and
drilling costs of exploration wells are temporarily
\u00a0
capitalized pending the determination of oil and
\u00a0
gas resources. These costs include
directly attributable employee remuneration, materials
\u00a0
and fuel used, rig costs and payments to contractors.
\u00a0
Continued capitalization
of such costs is assessed for impairment at each
\u00a0
reporting date. The main criterion is that there
\u00a0
must be plans for future activity in
the license or that a development decision is expected
\u00a0
in the near future. If reserves or resources
\u00a0
are not found, or if discoveries are
assessed not technically or commercially recoverable,
\u00a0
the costs of exploration wells and licenses are
\u00a0
expensed. Furthermore, 3D
seismic costs over a discovery area is capitalized
\u00a0
when the objective is to learn more about
\u00a0
the reservoir and to support the
determination of new well locations within the discovery
\u00a0
area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment assessment of
\u00a0
capitalized exploration expenditures
\u00a0
The Group\u2019s accounting policy is to temporarily capitalize
\u00a0
drilling expenditures related to exploration wells,
\u00a0
pending an evaluation of
potential oil and gas discoveries. If resources are
\u00a0
not discovered, or if recovery of the resources
\u00a0
is not considered technically or
commercially viable, the costs of the exploration wells
\u00a0
are expensed in the income statement. Decisions
\u00a0
as to whether an exploration
well should remain capitalized or expensed during
\u00a0
the period may have a material effect on the financial
\u00a0
results for the period.
\u00a0
\n
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\n
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2024 - USD million
Goodwill
interest
assets
Other
\u00a0
assets
Total
As of 1 January 2024
Acquisition costs
397.5
97.8
443.2
15.8
556.9
954.4
Accumulated impairments
-354.3
-8.8
-262.1
-
-270.9
-625.2
Accumulated depreciation
-
-71.1
-
-12.8
-83.9
-83.9
Net book amount
43.2
18.0
181.1
3.0
202.1
245.2
Period ended 31 December 2024
Opening net book amount
43.2
18.0
181.1
3.0
202.1
245.2
Translation differences
-6.3
-0.1
-23.2
-0.4
-23.7
-30.0
Additions
-
-
87.9
-
87.9
87.9
Additions through business combinations
113.8
-
-
-
-
113.8
Transfers
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-
-35.9
-
-35.9
-35.9
Impairments
-47.7
-
-
-
-
-47.7
Depreciation
-
-1.1
-
-0.8
-1.9
-2.0
Closing net book amount
102.1
16.7
209.9
1.8
228.5
330.6
As of 31 December 2024
Acquisition costs
466.5
97.6
484.4
15.5
597.5
1,064.0
Accumulated impairments/exploration write-offs
-364.4
-8.7
-274.5
-
-283.1
-647.5
Accumulated depreciation
-
-72.2
-
-13.7
-85.9
-85.9
Net book amount
102.1
16.7
209.9
1.8
228.5
330.6
Depreciation method
UoP
Linear (3-7 years)
\u00a0
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\n
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2023 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2023
Acquisition costs
407.2
97.5
335.3
15.4
448.2
855.4
Accumulated impairments/exploration write-offs
-351.1
-8.8
-260.5
-
-269.3
-620.3
Accumulated depreciation
-
-70.1
-
-11.7
-81.8
-81.8
Net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Period ended 31 December 2023
Opening net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Translation differences
-1.9
0.3
1.4
-
1.7
-0.3
Additions
-
-
114.2
0.4
114.6
114.6
Transfers*
-
-
-3.3
-
-3.3
-3.3
Exploration cost previously capitalized carried to cost
-
-
-6.0
-6.0
-6.0
Impairments
-11.0
-
-
-
-
-11.0
Depreciation
-
-1.0
-
-1.2
-2.2
-2.2
Closing net book amount
43.2
17.9
181.1
3.0
202.1
245.3
As of 31 December 2023
Acquisition costs
397.5
97.8
443.2
15.8
556.8
954.3
Accumulated impairments/exploration write-offs
-354.3
-8.8
-262.1
-
-270.9
-625.2
Accumulated depreciation
-
-71.1
-
-12.8
-83.9
-83.9
Net book amount
43.2
18.0
181.1
3.0
202.1
245.3
Depreciation method
UoP
Linear (3-7 years)
* Transfers were related to reclassification of the book value of the Fenja license from
\u00a0
exploration phase (intangible assets) to development phase (tangible assets).
", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_60": { "value": "
Note 9
Intangible assets
\u00a0
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\n
\u00a0
\n
Accounting policies
\u00a0
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\n
Intangible assets
General
Intangible assets are stated at cost, less accumulated
\u00a0
amortization and accumulated impairment charges.
\u00a0
Intangible assets include
acquisition costs for oil and gas licenses, expenditures
\u00a0
on the exploration for oil and gas resources,
\u00a0
technical goodwill and other
intangible assets. Goodwill is not depreciated.
\u00a0
The useful lives of intangible assets are assessed
\u00a0
as either finite or infinite. Amortization of
\u00a0
intangible assets is based on the
expected useful economic life and assessed for
\u00a0
impairment whenever there is an indication that the intangible
\u00a0
asset might be
impaired. The impairment assessment of intangible assets
\u00a0
with infinite lives is undertaken annually or
\u00a0
more often if indicators exist.
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\n
Goodwill
The goodwill that is recognized by the Group is related
\u00a0
to technical goodwill and is recognized
\u00a0
due to the requirement to recognize
deferred tax for the difference between the assigned fair
\u00a0
values and the related tax base. Although not
\u00a0
an IFRS term, \u201ctechnical
goodwill\u201d is commonly used in the oil and gas
\u00a0
industry to describe a category of goodwill
\u00a0
arising as an offsetting amount to deferred
tax recognized in business combinations. There are
\u00a0
no specific IFRS guidelines about the allocation
\u00a0
of technical goodwill, and the
Group has therefore applied the general guidelines
\u00a0
for allocating goodwill. In general, technical goodwill
\u00a0
is allocated to a cash-
generating unit (CGU) or group of CGUs that give
\u00a0
rise to the technical goodwill, while any residual
\u00a0
goodwill may be allocated across
all CGUs based on facts and circumstances in
\u00a0
the business combination.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its exploration and evaluation assets. Acquisition
\u00a0
costs of licenses and
drilling costs of exploration wells are temporarily
\u00a0
capitalized pending the determination of oil and
\u00a0
gas resources. These costs include
directly attributable employee remuneration, materials
\u00a0
and fuel used, rig costs and payments to contractors.
\u00a0
Continued capitalization
of such costs is assessed for impairment at each
\u00a0
reporting date. The main criterion is that there
\u00a0
must be plans for future activity in
the license or that a development decision is expected
\u00a0
in the near future. If reserves or resources
\u00a0
are not found, or if discoveries are
assessed not technically or commercially recoverable,
\u00a0
the costs of exploration wells and licenses are
\u00a0
expensed. Furthermore, 3D
seismic costs over a discovery area is capitalized
\u00a0
when the objective is to learn more about
\u00a0
the reservoir and to support the
determination of new well locations within the discovery
\u00a0
area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment assessment of
\u00a0
capitalized exploration expenditures
\u00a0
The Group\u2019s accounting policy is to temporarily capitalize
\u00a0
drilling expenditures related to exploration wells,
\u00a0
pending an evaluation of
potential oil and gas discoveries. If resources are
\u00a0
not discovered, or if recovery of the resources
\u00a0
is not considered technically or
commercially viable, the costs of the exploration wells
\u00a0
are expensed in the income statement. Decisions
\u00a0
as to whether an exploration
well should remain capitalized or expensed during
\u00a0
the period may have a material effect on the financial
\u00a0
results for the period.
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2024 - USD million
Goodwill
interest
assets
Other
\u00a0
assets
Total
As of 1 January 2024
Acquisition costs
397.5
97.8
443.2
15.8
556.9
954.4
Accumulated impairments
-354.3
-8.8
-262.1
-
-270.9
-625.2
Accumulated depreciation
-
-71.1
-
-12.8
-83.9
-83.9
Net book amount
43.2
18.0
181.1
3.0
202.1
245.2
Period ended 31 December 2024
Opening net book amount
43.2
18.0
181.1
3.0
202.1
245.2
Translation differences
-6.3
-0.1
-23.2
-0.4
-23.7
-30.0
Additions
-
-
87.9
-
87.9
87.9
Additions through business combinations
113.8
-
-
-
-
113.8
Transfers
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-
-35.9
-
-35.9
-35.9
Impairments
-47.7
-
-
-
-
-47.7
Depreciation
-
-1.1
-
-0.8
-1.9
-2.0
Closing net book amount
102.1
16.7
209.9
1.8
228.5
330.6
As of 31 December 2024
Acquisition costs
466.5
97.6
484.4
15.5
597.5
1,064.0
Accumulated impairments/exploration write-offs
-364.4
-8.7
-274.5
-
-283.1
-647.5
Accumulated depreciation
-
-72.2
-
-13.7
-85.9
-85.9
Net book amount
102.1
16.7
209.9
1.8
228.5
330.6
Depreciation method
UoP
Linear (3-7 years)
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\n
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2023 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2023
Acquisition costs
407.2
97.5
335.3
15.4
448.2
855.4
Accumulated impairments/exploration write-offs
-351.1
-8.8
-260.5
-
-269.3
-620.3
Accumulated depreciation
-
-70.1
-
-11.7
-81.8
-81.8
Net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Period ended 31 December 2023
Opening net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Translation differences
-1.9
0.3
1.4
-
1.7
-0.3
Additions
-
-
114.2
0.4
114.6
114.6
Transfers*
-
-
-3.3
-
-3.3
-3.3
Exploration cost previously capitalized carried to cost
-
-
-6.0
-6.0
-6.0
Impairments
-11.0
-
-
-
-
-11.0
Depreciation
-
-1.0
-
-1.2
-2.2
-2.2
Closing net book amount
43.2
17.9
181.1
3.0
202.1
245.3
As of 31 December 2023
Acquisition costs
397.5
97.8
443.2
15.8
556.8
954.3
Accumulated impairments/exploration write-offs
-354.3
-8.8
-262.1
-
-270.9
-625.2
Accumulated depreciation
-
-71.1
-
-12.8
-83.9
-83.9
Net book amount
43.2
18.0
181.1
3.0
202.1
245.3
Depreciation method
UoP
Linear (3-7 years)
* Transfers were related to reclassification of the book value of the Fenja license from
\u00a0
exploration phase (intangible assets) to development phase (tangible assets).
", "dimensions": { "concept": "ifrs-full:DisclosureOfGoodwillExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_61": { "value": "
Note 9
Intangible assets
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
Intangible assets
General
Intangible assets are stated at cost, less accumulated
\u00a0
amortization and accumulated impairment charges.
\u00a0
Intangible assets include
acquisition costs for oil and gas licenses, expenditures
\u00a0
on the exploration for oil and gas resources,
\u00a0
technical goodwill and other
intangible assets. Goodwill is not depreciated.
\u00a0
The useful lives of intangible assets are assessed
\u00a0
as either finite or infinite. Amortization of
\u00a0
intangible assets is based on the
expected useful economic life and assessed for
\u00a0
impairment whenever there is an indication that the intangible
\u00a0
asset might be
impaired. The impairment assessment of intangible assets
\u00a0
with infinite lives is undertaken annually or
\u00a0
more often if indicators exist.
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Goodwill
The goodwill that is recognized by the Group is related
\u00a0
to technical goodwill and is recognized
\u00a0
due to the requirement to recognize
deferred tax for the difference between the assigned fair
\u00a0
values and the related tax base. Although not
\u00a0
an IFRS term, \u201ctechnical
goodwill\u201d is commonly used in the oil and gas
\u00a0
industry to describe a category of goodwill
\u00a0
arising as an offsetting amount to deferred
tax recognized in business combinations. There are
\u00a0
no specific IFRS guidelines about the allocation
\u00a0
of technical goodwill, and the
Group has therefore applied the general guidelines
\u00a0
for allocating goodwill. In general, technical goodwill
\u00a0
is allocated to a cash-
generating unit (CGU) or group of CGUs that give
\u00a0
rise to the technical goodwill, while any residual
\u00a0
goodwill may be allocated across
all CGUs based on facts and circumstances in
\u00a0
the business combination.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its exploration and evaluation assets. Acquisition
\u00a0
costs of licenses and
drilling costs of exploration wells are temporarily
\u00a0
capitalized pending the determination of oil and
\u00a0
gas resources. These costs include
directly attributable employee remuneration, materials
\u00a0
and fuel used, rig costs and payments to contractors.
\u00a0
Continued capitalization
of such costs is assessed for impairment at each
\u00a0
reporting date. The main criterion is that there
\u00a0
must be plans for future activity in
the license or that a development decision is expected
\u00a0
in the near future. If reserves or resources
\u00a0
are not found, or if discoveries are
assessed not technically or commercially recoverable,
\u00a0
the costs of exploration wells and licenses are
\u00a0
expensed. Furthermore, 3D
seismic costs over a discovery area is capitalized
\u00a0
when the objective is to learn more about
\u00a0
the reservoir and to support the
determination of new well locations within the discovery
\u00a0
area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment assessment of
\u00a0
capitalized exploration expenditures
\u00a0
The Group\u2019s accounting policy is to temporarily capitalize
\u00a0
drilling expenditures related to exploration wells,
\u00a0
pending an evaluation of
potential oil and gas discoveries. If resources are
\u00a0
not discovered, or if recovery of the resources
\u00a0
is not considered technically or
commercially viable, the costs of the exploration wells
\u00a0
are expensed in the income statement. Decisions
\u00a0
as to whether an exploration
well should remain capitalized or expensed during
\u00a0
the period may have a material effect on the financial
\u00a0
results for the period.
\u00a0
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\n
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2024 - USD million
Goodwill
interest
assets
Other
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assets
Total
As of 1 January 2024
Acquisition costs
397.5
97.8
443.2
15.8
556.9
954.4
Accumulated impairments
-354.3
-8.8
-262.1
-
-270.9
-625.2
Accumulated depreciation
-
-71.1
-
-12.8
-83.9
-83.9
Net book amount
43.2
18.0
181.1
3.0
202.1
245.2
Period ended 31 December 2024
Opening net book amount
43.2
18.0
181.1
3.0
202.1
245.2
Translation differences
-6.3
-0.1
-23.2
-0.4
-23.7
-30.0
Additions
-
-
87.9
-
87.9
87.9
Additions through business combinations
113.8
-
-
-
-
113.8
Transfers
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-
-35.9
-
-35.9
-35.9
Impairments
-47.7
-
-
-
-
-47.7
Depreciation
-
-1.1
-
-0.8
-1.9
-2.0
Closing net book amount
102.1
16.7
209.9
1.8
228.5
330.6
As of 31 December 2024
Acquisition costs
466.5
97.6
484.4
15.5
597.5
1,064.0
Accumulated impairments/exploration write-offs
-364.4
-8.7
-274.5
-
-283.1
-647.5
Accumulated depreciation
-
-72.2
-
-13.7
-85.9
-85.9
Net book amount
102.1
16.7
209.9
1.8
228.5
330.6
Depreciation method
UoP
Linear (3-7 years)
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2023 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2023
Acquisition costs
407.2
97.5
335.3
15.4
448.2
855.4
Accumulated impairments/exploration write-offs
-351.1
-8.8
-260.5
-
-269.3
-620.3
Accumulated depreciation
-
-70.1
-
-11.7
-81.8
-81.8
Net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Period ended 31 December 2023
Opening net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Translation differences
-1.9
0.3
1.4
-
1.7
-0.3
Additions
-
-
114.2
0.4
114.6
114.6
Transfers*
-
-
-3.3
-
-3.3
-3.3
Exploration cost previously capitalized carried to cost
-
-
-6.0
-6.0
-6.0
Impairments
-11.0
-
-
-
-
-11.0
Depreciation
-
-1.0
-
-1.2
-2.2
-2.2
Closing net book amount
43.2
17.9
181.1
3.0
202.1
245.3
As of 31 December 2023
Acquisition costs
397.5
97.8
443.2
15.8
556.8
954.3
Accumulated impairments/exploration write-offs
-354.3
-8.8
-262.1
-
-270.9
-625.2
Accumulated depreciation
-
-71.1
-
-12.8
-83.9
-83.9
Net book amount
43.2
18.0
181.1
3.0
202.1
245.3
Depreciation method
UoP
Linear (3-7 years)
* Transfers were related to reclassification of the book value of the Fenja license from
\u00a0
exploration phase (intangible assets) to development phase (tangible assets).
", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_62": { "value": "
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Intangible assets
General
Intangible assets are stated at cost, less accumulated
\u00a0
amortization and accumulated impairment charges.
\u00a0
Intangible assets include
acquisition costs for oil and gas licenses, expenditures
\u00a0
on the exploration for oil and gas resources,
\u00a0
technical goodwill and other
intangible assets. Goodwill is not depreciated.
\u00a0
The useful lives of intangible assets are assessed
\u00a0
as either finite or infinite. Amortization of
\u00a0
intangible assets is based on the
expected useful economic life and assessed for
\u00a0
impairment whenever there is an indication that the intangible
\u00a0
asset might be
impaired. The impairment assessment of intangible assets
\u00a0
with infinite lives is undertaken annually or
\u00a0
more often if indicators exist.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Goodwill
The goodwill that is recognized by the Group is related
\u00a0
to technical goodwill and is recognized
\u00a0
due to the requirement to recognize
deferred tax for the difference between the assigned fair
\u00a0
values and the related tax base. Although not
\u00a0
an IFRS term, \u201ctechnical
goodwill\u201d is commonly used in the oil and gas
\u00a0
industry to describe a category of goodwill
\u00a0
arising as an offsetting amount to deferred
tax recognized in business combinations. There are
\u00a0
no specific IFRS guidelines about the allocation
\u00a0
of technical goodwill, and the
Group has therefore applied the general guidelines
\u00a0
for allocating goodwill. In general, technical goodwill
\u00a0
is allocated to a cash-
generating unit (CGU) or group of CGUs that give
\u00a0
rise to the technical goodwill, while any residual
\u00a0
goodwill may be allocated across
all CGUs based on facts and circumstances in
\u00a0
the business combination.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its exploration and evaluation assets. Acquisition
\u00a0
costs of licenses and
drilling costs of exploration wells are temporarily
\u00a0
capitalized pending the determination of oil and
\u00a0
gas resources. These costs include
directly attributable employee remuneration, materials
\u00a0
and fuel used, rig costs and payments to contractors.
\u00a0
Continued capitalization
of such costs is assessed for impairment at each
\u00a0
reporting date. The main criterion is that there
\u00a0
must be plans for future activity in
the license or that a development decision is expected
\u00a0
in the near future. If reserves or resources
\u00a0
are not found, or if discoveries are
assessed not technically or commercially recoverable,
\u00a0
the costs of exploration wells and licenses are
\u00a0
expensed. Furthermore, 3D
seismic costs over a discovery area is capitalized
\u00a0
when the objective is to learn more about
\u00a0
the reservoir and to support the
determination of new well locations within the discovery
\u00a0
area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment assessment of
\u00a0
capitalized exploration expenditures
\u00a0
The Group\u2019s accounting policy is to temporarily capitalize
\u00a0
drilling expenditures related to exploration wells,
\u00a0
pending an evaluation of
potential oil and gas discoveries. If resources are
\u00a0
not discovered, or if recovery of the resources
\u00a0
is not considered technically or
commercially viable, the costs of the exploration wells
\u00a0
are expensed in the income statement. Decisions
\u00a0
as to whether an exploration
well should remain capitalized or expensed during
\u00a0
the period may have a material effect on the financial
\u00a0
results for the period.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_63": { "value": "
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Intangible assets
General
Intangible assets are stated at cost, less accumulated
\u00a0
amortization and accumulated impairment charges.
\u00a0
Intangible assets include
acquisition costs for oil and gas licenses, expenditures
\u00a0
on the exploration for oil and gas resources,
\u00a0
technical goodwill and other
intangible assets. Goodwill is not depreciated.
\u00a0
The useful lives of intangible assets are assessed
\u00a0
as either finite or infinite. Amortization of
\u00a0
intangible assets is based on the
expected useful economic life and assessed for
\u00a0
impairment whenever there is an indication that the intangible
\u00a0
asset might be
impaired. The impairment assessment of intangible assets
\u00a0
with infinite lives is undertaken annually or
\u00a0
more often if indicators exist.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Goodwill
The goodwill that is recognized by the Group is related
\u00a0
to technical goodwill and is recognized
\u00a0
due to the requirement to recognize
deferred tax for the difference between the assigned fair
\u00a0
values and the related tax base. Although not
\u00a0
an IFRS term, \u201ctechnical
goodwill\u201d is commonly used in the oil and gas
\u00a0
industry to describe a category of goodwill
\u00a0
arising as an offsetting amount to deferred
tax recognized in business combinations. There are
\u00a0
no specific IFRS guidelines about the allocation
\u00a0
of technical goodwill, and the
Group has therefore applied the general guidelines
\u00a0
for allocating goodwill. In general, technical goodwill
\u00a0
is allocated to a cash-
generating unit (CGU) or group of CGUs that give
\u00a0
rise to the technical goodwill, while any residual
\u00a0
goodwill may be allocated across
all CGUs based on facts and circumstances in
\u00a0
the business combination.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its exploration and evaluation assets. Acquisition
\u00a0
costs of licenses and
drilling costs of exploration wells are temporarily
\u00a0
capitalized pending the determination of oil and
\u00a0
gas resources. These costs include
directly attributable employee remuneration, materials
\u00a0
and fuel used, rig costs and payments to contractors.
\u00a0
Continued capitalization
of such costs is assessed for impairment at each
\u00a0
reporting date. The main criterion is that there
\u00a0
must be plans for future activity in
the license or that a development decision is expected
\u00a0
in the near future. If reserves or resources
\u00a0
are not found, or if discoveries are
assessed not technically or commercially recoverable,
\u00a0
the costs of exploration wells and licenses are
\u00a0
expensed. Furthermore, 3D
seismic costs over a discovery area is capitalized
\u00a0
when the objective is to learn more about
\u00a0
the reservoir and to support the
determination of new well locations within the discovery
\u00a0
area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment assessment of
\u00a0
capitalized exploration expenditures
\u00a0
The Group\u2019s accounting policy is to temporarily capitalize
\u00a0
drilling expenditures related to exploration wells,
\u00a0
pending an evaluation of
potential oil and gas discoveries. If resources are
\u00a0
not discovered, or if recovery of the resources
\u00a0
is not considered technically or
commercially viable, the costs of the exploration wells
\u00a0
are expensed in the income statement. Decisions
\u00a0
as to whether an exploration
well should remain capitalized or expensed during
\u00a0
the period may have a material effect on the financial
\u00a0
results for the period.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsOtherThanGoodwillExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_64": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Goodwill
The goodwill that is recognized by the Group is related
\u00a0
to technical goodwill and is recognized
\u00a0
due to the requirement to recognize
deferred tax for the difference between the assigned fair
\u00a0
values and the related tax base. Although not
\u00a0
an IFRS term, \u201ctechnical
goodwill\u201d is commonly used in the oil and gas
\u00a0
industry to describe a category of goodwill
\u00a0
arising as an offsetting amount to deferred
tax recognized in business combinations. There are
\u00a0
no specific IFRS guidelines about the allocation
\u00a0
of technical goodwill, and the
Group has therefore applied the general guidelines
\u00a0
for allocating goodwill. In general, technical goodwill
\u00a0
is allocated to a cash-
generating unit (CGU) or group of CGUs that give
\u00a0
rise to the technical goodwill, while any residual
\u00a0
goodwill may be allocated across
all CGUs based on facts and circumstances in
\u00a0
the business combination.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_65": { "value": "
Note 10
Property,
\u00a0
plant and equipment
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Property, plant and equipment (PP&E)
General
PP&E are recognized at historical cost and adjusted
\u00a0
for depreciation, depletion and amortization
\u00a0
(DD&A) and impairment charges.
\u00a0
Depreciation of PP&E other than oil and gas assets
\u00a0
are generally depreciated on a straight-line basis
\u00a0
over expected useful lives,
normally varying from three to seven years. Expected
\u00a0
useful lives are reviewed at each balance
\u00a0
sheet date and, where there are
changes in estimates, depreciation periods are changed
\u00a0
accordingly.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Exploration and development costs
\u00a0
Capitalized exploration expenditures are classified as
\u00a0
intangible assets and reclassified to tangible
\u00a0
assets (i.e., PP&E) at the start of
the development. For accounting purposes, an oil
\u00a0
and gas field is considered to enter the development
\u00a0
phase when the technical
feasibility and commercial viability of extracting oil and
\u00a0
gas from the field are demonstrable. All
\u00a0
costs of developing commercial oil
and gas fields are capitalized, including indirect
\u00a0
costs. Capitalized development costs are classified
\u00a0
as tangible assets.
\u00a0
Acquired license rights are recognized as intangible
\u00a0
assets at the time of acquisition. Acquired
\u00a0
license rights related to fields in the
exploration phase remain as intangible assets when
\u00a0
the related fields enter the development or
\u00a0
production phase. Furthermore, 3D
seismic cost over a discovery area is capitalized
\u00a0
when the objective is to learn more about
\u00a0
the reservoir and to support the
determination of new well locations within the discovery
\u00a0
area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Oil and gas assets in production
\u00a0
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the UoP method. The rate of depreciation
\u00a0
is equal to the ratio of oil
and gas production for the period over the estimated
\u00a0
remaining 2P reserves at the beginning of
\u00a0
the period. The future development
expenditures necessary to bring those reserves into
\u00a0
production are included in the basis for depreciation
\u00a0
and are estimated by the
management based on current period end un-escalated
\u00a0
price levels. The reserve basis used for depreciation
\u00a0
purposes is updated at
least once a year. Any changes in the reserves affecting UoP calculations
\u00a0
are reflected prospectively. Reserves and resources,
along with associated estimation uncertainty, are described in detail in Note
\u00a0
27.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Right-of-use (RoU) asset
s
\u00a0
The RoU assets in the balance sheet are mainly
\u00a0
related to office rent and are measured to cost, less
\u00a0
any accumulated depreciation
and impairment losses, and adjusted for any remeasurement
\u00a0
of lease liabilities. The RoU assets are depreciated
\u00a0
linearly over the
lifetime of the related lease contract. For measurement
\u00a0
of lease liabilities, see Note 19. In the
\u00a0
consolidated statements of
comprehensive income, operating lease costs, relating
\u00a0
to contracts that contain a lease, are replaced
\u00a0
by depreciation and interest
expense.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
\n
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\n
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\u00a0
\n
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\n
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\u00a0
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\u00a0
\n
PROPERTY, PLANT AND EQUIPMENT
Total
Development
Production
oil & gas
Other
RoU
2024 - USD million
assets
assets
assets
PP&E
assets
Total
As of 1 January 2024
Acquisition costs
286.7
3,304.6
3,591.3
14.9
45.1
3,651.3
Accumulated impairments
-137.5
-345.0
-482.6
-0.1
-
-482.7
Accumulated depreciation
-
-1,993.3
-1,993.3
-13.6
-28.5
-2,035.4
Net book amount
149.1
966.3
1,115.4
1.3
16.3
1,133.2
Period ended 31 December 2024
Opening net book amount
149.1
966.3
1,115.4
1.3
16.3
1,133.2
Translation differences
-19.7
-29.4
-49.2
-0.1
-0.3
-49.5
Additions*
113.9
111.0
224.9
1.2
0.3
226.4
Business combinations
28.4
84.1
112.5
-
-
112.5
Transfers**
-
-
-
-
-
-
Impairments (net)
-
-98.3
-98.3
-
-
-98.3
Depreciation
-
-179.5
-179.5
-0.7
-3.8
-184.1
Closing net book amount
271.6
823.3
1,094.9
1.6
12.7
1,109.4
As of 31 December 2024
Acquisition costs
399.2
3,344.2
3,743.4
15.1
32.0
3,790.6
Accumulated impairments
-127.6
-412.0
-539.5
-
-
-539.5
Accumulated depreciation
-
-2,109.0
-2,109.0
-13.5
-19.2
-2,141.7
Net book amount
271.7
823.3
1,094.9
1.6
12.8
1,109.4
Depreciation method
UoP
Linear (3-7 years)
\u00a0
* Includes changes in estimate of asset retirement, see Note 21.
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\n
PROPERTY, PLANT AND EQUIPMENT
Total
Development
Production
oil & gas
Other
RoU
2023 - USD million
assets
assets
assets
PP&E
assets
Total
As of 1 January 2023
Acquisition costs
358.3
3,072.1
3,430.5
14.3
34.2
3,479.0
Accumulated impairments
-140.6
-332.0
-472.6
-0.1
-
-472.7
Accumulated depreciation
-
-1,861.0
-1,861.0
-13.1
-23.3
-1,897.4
Net book amount
217.7
879.1
1,096.9
1.1
10.9
1,108.9
Period ended 31 December 2023
Opening net book amount
217.7
879.1
1,096.9
1.1
10.9
1,108.9
Translation differences
-4.4
-4.4
-8.9
-0.1
-1.1
-10.1
Additions*
53.9
123.7
177.6
0.7
10.7
189.1
Transfers**
-118.1
121.3
3.3
-
-
3.3
Disposal cost price
-
-
-
-
-
-
Disposal impairments/depreciations
-
-
-
-
-
-
Depreciation of RoU recognized against ARO
-
-
-
-
-
-
Impairments
-
-13.9
-13.9
-
-
-13.9
Depreciation
-
-139.6
-139.6
-0.6
-4.0
-144.1
Closing net book amount
149.1
966.3
1,115.4
1.2
16.6
1,133.2
As of 31 December 2023
Acquisition costs
286.7
3,304.6
3,591.3
14.9
45.1
3,651.2
Accumulated impairments
-137.5
-345.0
-482.6
-0.1
-
-482.7
Accumulated depreciation
-
-1993.3
-1993.3
-13.6
-28.5
-2,035.4
Net book amount
149.1
966.3
1,115.4
1.2
16.6
1,133.2
Depreciation method
UoP
Linear (3-7 years)
* Includes changes in estimate of asset retirement, see Note 21.
** Transfers were related to reclassification of the book value of Fenja license from development
\u00a0
phase to production phase.
Depreciation, depletion and amortization (DD&A) is charged to cost of goods sold in the statement of comprehensive
\u00a0
income.
", "dimensions": { "concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_66": { "value": "
\u00a0
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\n
\u00a0
\n
\u00a0
\n
Accounting policies
Property, plant and equipment (PP&E)
General
PP&E are recognized at historical cost and adjusted
\u00a0
for depreciation, depletion and amortization
\u00a0
(DD&A) and impairment charges.
\u00a0
Depreciation of PP&E other than oil and gas assets
\u00a0
are generally depreciated on a straight-line basis
\u00a0
over expected useful lives,
normally varying from three to seven years. Expected
\u00a0
useful lives are reviewed at each balance
\u00a0
sheet date and, where there are
changes in estimates, depreciation periods are changed
\u00a0
accordingly.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Exploration and development costs
\u00a0
Capitalized exploration expenditures are classified as
\u00a0
intangible assets and reclassified to tangible
\u00a0
assets (i.e., PP&E) at the start of
the development. For accounting purposes, an oil
\u00a0
and gas field is considered to enter the development
\u00a0
phase when the technical
feasibility and commercial viability of extracting oil and
\u00a0
gas from the field are demonstrable. All
\u00a0
costs of developing commercial oil
and gas fields are capitalized, including indirect
\u00a0
costs. Capitalized development costs are classified
\u00a0
as tangible assets.
\u00a0
Acquired license rights are recognized as intangible
\u00a0
assets at the time of acquisition. Acquired
\u00a0
license rights related to fields in the
exploration phase remain as intangible assets when
\u00a0
the related fields enter the development or
\u00a0
production phase. Furthermore, 3D
seismic cost over a discovery area is capitalized
\u00a0
when the objective is to learn more about
\u00a0
the reservoir and to support the
determination of new well locations within the discovery
\u00a0
area.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Oil and gas assets in production
\u00a0
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the UoP method. The rate of depreciation
\u00a0
is equal to the ratio of oil
and gas production for the period over the estimated
\u00a0
remaining 2P reserves at the beginning of
\u00a0
the period. The future development
expenditures necessary to bring those reserves into
\u00a0
production are included in the basis for depreciation
\u00a0
and are estimated by the
management based on current period end un-escalated
\u00a0
price levels. The reserve basis used for depreciation
\u00a0
purposes is updated at
least once a year. Any changes in the reserves affecting UoP calculations
\u00a0
are reflected prospectively. Reserves and resources,
along with associated estimation uncertainty, are described in detail in Note
\u00a0
27.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Right-of-use (RoU) asset
s
\u00a0
The RoU assets in the balance sheet are mainly
\u00a0
related to office rent and are measured to cost, less
\u00a0
any accumulated depreciation
and impairment losses, and adjusted for any remeasurement
\u00a0
of lease liabilities. The RoU assets are depreciated
\u00a0
linearly over the
lifetime of the related lease contract. For measurement
\u00a0
of lease liabilities, see Note 19. In the
\u00a0
consolidated statements of
comprehensive income, operating lease costs, relating
\u00a0
to contracts that contain a lease, are replaced
\u00a0
by depreciation and interest
expense.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_67": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Oil and gas assets in production
\u00a0
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the UoP method. The rate of depreciation
\u00a0
is equal to the ratio of oil
and gas production for the period over the estimated
\u00a0
remaining 2P reserves at the beginning of
\u00a0
the period. The future development
expenditures necessary to bring those reserves into
\u00a0
production are included in the basis for depreciation
\u00a0
and are estimated by the
management based on current period end un-escalated
\u00a0
price levels. The reserve basis used for depreciation
\u00a0
purposes is updated at
least once a year. Any changes in the reserves affecting UoP calculations
\u00a0
are reflected prospectively. Reserves and resources,
along with associated estimation uncertainty, are described in detail in Note
\u00a0
27.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForOilAndGasAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_68": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Right-of-use (RoU) asset
s
\u00a0
The RoU assets in the balance sheet are mainly
\u00a0
related to office rent and are measured to cost, less
\u00a0
any accumulated depreciation
and impairment losses, and adjusted for any remeasurement
\u00a0
of lease liabilities. The RoU assets are depreciated
\u00a0
linearly over the
lifetime of the related lease contract. For measurement
\u00a0
of lease liabilities, see Note 19. In the
\u00a0
consolidated statements of
comprehensive income, operating lease costs, relating
\u00a0
to contracts that contain a lease, are replaced
\u00a0
by depreciation and interest
expense.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Lease liabilities
The Group assesses at contract inception whether
\u00a0
a contract is, or contains, a lease. The Group
\u00a0
applies a single recognition and
measurement approach for all leases, except for
\u00a0
short-term leases (12 months or less) and leases
\u00a0
of low-value assets. Short term
leases and leases of low value assets have not
\u00a0
been reflected in the balance sheet but expensed
\u00a0
or capitalized as incurred,
depending on the activity in which the leased asset
\u00a0
is used.
Lease liabilities are measured at the present value
\u00a0
of lease payments to be made over the lease
\u00a0
term. In calculating the present
value of lease payments, the Group uses
\u00a0
the implicit interest rate and if not readily determinable,
\u00a0
its incremental borrowing rate at
the lease commencement date. Extension options
\u00a0
are included in the lease liability when, based
\u00a0
on the management\u2019s judgement, it
is reasonably certain that an extension will be exercised.
In the consolidated cash flow, lease payments related to lease liabilities recognized
\u00a0
in accordance with IFRS 16, are presented as
cash flow used in financing activities.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_69": { "value": "
Note 11
Impairments
\u00a0
\n
\u00a0
\n
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\n
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\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
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\n
\u00a0
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\n
\u00a0
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\u00a0
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\n
\u00a0
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\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Impairments
At the end of each reporting period, the Group
\u00a0
assesses whether there is any indication that an
\u00a0
asset may be impaired. If an
impairment indicator is concluded to exist, an impairment
\u00a0
test is performed.
\u00a0
Indications of impairment may include a decline
\u00a0
in the long-term oil and gas price (or short-term
\u00a0
oil and gas price for late-life oil and
gas fields), changes in future investments or significant
\u00a0
downward revision of reserve and resource
\u00a0
estimates. For the purposes of
impairment assessment, assets are grouped at the
\u00a0
lowest levels for which there are separable identifiable
\u00a0
cash inflows. For oil and
gas assets, a CGU may be individual oil and
\u00a0
gas fields, or a group of oil and gas fields
\u00a0
that are connected to the same
infrastructure/production facilities, or a license.
\u00a0
An impairment loss is recognized when the carrying
\u00a0
amount exceeds the recoverable amount of an
\u00a0
asset. The recoverable amount is
the higher of the asset\u2019s fair value less costs to sell
\u00a0
and its value in use. Fair value less costs
\u00a0
to sell determined through either the
discounted cash flow method (income approach) or
\u00a0
the market transactions method (market approach).
\u00a0
The value in use can only be
determined through the discounted cash flow method.
Technical goodwill
\u00a0
Technical goodwill is tested for impairment annually or more frequently when there are
\u00a0
impairment indicators. Those indicators may
be specific to an individual CGU or groups of
\u00a0
CGUs to which the technical goodwill is
\u00a0
related. Goodwill is not depreciated and hence,
impairment of technical goodwill is expected on
\u00a0
a recurring basis, unless there are positive
\u00a0
changes in underlying assumptions that
more than offset the production from the CGU (or
\u00a0
groups of CGUs).
\u00a0
When performing the impairment test for technical
\u00a0
goodwill, deferred tax recognized in relation to
\u00a0
the acquired assets in a business
combination reduces the net carrying value prior
\u00a0
to the impairment charges. After initial recognition,
\u00a0
depreciation of values calculated
in the purchase price allocations from business
\u00a0
combinations will result in decreased deferred tax
\u00a0
liability. When deferred tax from
the initial recognition decreases, more goodwill is exposed
\u00a0
for impairment.
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment/reversal of impairment
\u00a0
of oil and gas assets
The estimation of the recoverable amount for the
\u00a0
oil and gas assets includes assessments of
\u00a0
expected future cash flows and future
market conditions, including entitlement production,
\u00a0
future oil and gas prices, cost profiles, country
\u00a0
risk factors (i.e., discount rate)
and the date of expiration of the licenses.
\u00a0
The fair value of an asset or a liability is
\u00a0
measured using the assumptions that market participants
\u00a0
would use when pricing the asset
or liability, including assumptions about risk, assuming that market participants
\u00a0
act in their economic best interest. The Group
\u00a0
uses
valuation techniques that are appropriate in
\u00a0
the circumstances and for which sufficient data are available
\u00a0
to measure fair value. The
fair value of oil and gas assets is normally
\u00a0
based on discounted cash flow models (income
\u00a0
approach), where the determination of
different inputs in the model requires significant judgment
\u00a0
from management, as described in the section
\u00a0
above regarding
impairment.
Climate considerations in impairment assessments
Certain climate considerations are factored into
\u00a0
the Group\u2019s estimation of cash flows that are applied in
\u00a0
the calculation of recoverable
amount. This includes factoring in current legislation
\u00a0
(e.g., environmental taxes/fees) and estimation
\u00a0
of future levels of environmental
taxes/fees. For DNO\u2019s oil and gas assets on the NCS,
\u00a0
carbon pricing is in line with current legislation and
\u00a0
reflects the operators
forecasts for individual assets. As proposed in the Norwegian
\u00a0
Government\u2019s Climate Plan for 2021-2030, a steady increase
\u00a0
in the
total carbon price (quota plus CO2 tax) to
\u00a0
NOK 2,000 per tonnes (in 2020 real terms) is
\u00a0
expected by 2030. In Kurdistan, the KRG
introduced in 2021 a requirement for oil companies
\u00a0
to put plans in place to curb gas flaring
\u00a0
to reduce emissions. The Company has
run sensitivities for its Kurdistan oil assets with the
\u00a0
CO2 tax assumptions as described in the scenarios
\u00a0
described by the International
Energy Agency (IEA).
An energy transition is likely to impact future oil
\u00a0
and gas prices which in turn may affect
\u00a0
the recoverable amount of the oil and gas
assets. Indirectly, climate considerations are also assessed in the forecasting of
\u00a0
oil and gas prices where supply and demand
\u00a0
are
considered.
\u00a0
\u00a0
\n
\u00a0
\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Impairment testing
Impairment assessment of DNO\u2019s assets in Kurdistan is
\u00a0
based on the value in use approach. For oil
\u00a0
and gas assets and goodwill
recognized in relation to the acquisitions, the
\u00a0
impairment assessment is based on the fair
\u00a0
value approach (level 3 in fair value hierarchy,
IFRS 13). For both the value in use and fair value,
\u00a0
the impairment testing is performed based on
\u00a0
discounted cash flows. The expected
future cash flows are discounted to the net present
\u00a0
value by applying a discount rate after tax.
\u00a0
Cash flows are projected for the
estimated lifetime of the fields or license, which
\u00a0
may exceed periods longer than five years.
\u00a0
Below is an overview of the key assumptions
\u00a0
applied for impairment assessment purposes as of
\u00a0
31 December 2024.
\u00a0
Oil and gas prices
Forecasted oil and gas prices are based on
\u00a0
management\u2019s estimates and market data. The near-term price assumptions
\u00a0
are based on
forward curve pricing over the period for which there
\u00a0
is deemed to be a sufficient liquid market and observable
\u00a0
broker and analyst
consensus. The long-term price assumptions reflect
\u00a0
management\u2019s best estimate of the oil and gas
\u00a0
price development over the life of
the Group\u2019s oil and gas fields based on its view
\u00a0
of current market conditions and future developments.
\u00a0
Management\u2019s assessment also
includes comparison with long-term oil and gas price
\u00a0
assumptions communicated by peer companies
\u00a0
and other external forecasts. Oil
and gas price assumptions applied for impairment
\u00a0
testing are reviewed and, where necessary, adjusted on a periodic basis.
\u00a0
The nominal oil and gas price assumptions applied
\u00a0
for impairment assessments at yearend 2024 were
\u00a0
as follows (yearend 2023 in
brackets):
2025
2026
2027
2028
Brent (USD/bbl)
71.5 (84.0)
74.4 (75.5)
72.0 (73.6)
71.9 (71.8)
NBP (pence/therm)
110.7 (115.0)
87.6 (96.5)
85.6 (86.5)
80.9 (76.4)
For periods after year 2029, the long-term oil
\u00a0
and gas price assumptions applied were USD
\u00a0
65 per barrel and 69 pence sterling per
therm, respectively (in real terms, basis year 2024).
\u00a0
Oil and gas price differential
The estimated net oil and gas price is based
\u00a0
on the above nominal price assumptions adjusted
\u00a0
for price differentials due to quality and
transportation for each individual field.
\u00a0
Oil and gas reserves and resources
Future cash flows are calculated on the basis of expected
\u00a0
production profiles and estimated proven and
\u00a0
probable remaining reserves,
and additional risked contingent resources when the impairment
\u00a0
assessments are based on the fair value approach.
\u00a0
For more
information about reserves and resources estimate,
\u00a0
see Note 1 and Note 27.
Discount rate
The discount rate is derived from the Company\u2019s weighted
\u00a0
average cost of capital (WACC). Main elements of the WACC include:
\u2022
For the value in use calculations, the capital structure
\u00a0
considered in the WACC calculation is derived from DNO\u2019s debt
\u00a0
and equity to
enterprise value ratio at yearend. For the fair value
\u00a0
calculations, the capital structure considered in the
\u00a0
WACC calculation is derived
from the capital structures of an identified peer
\u00a0
group and market participants.
\u00a0
\u2022
The cost of equity is calculated on a country-by-country
\u00a0
basis using the Capital Asset Pricing Model
\u00a0
(CAPM) and adding a country risk
premium. The beta factor is based on publicly
\u00a0
available data about the Company\u2019s beta in the
\u00a0
value in use calculations, whereas the
beta factors used for the fair value calculations
\u00a0
are based on publicly available market data about
\u00a0
the identified peer group.
\u00a0
\u2022
For the value in use calculations, the cost of debt
\u00a0
is based on yield-to-maturity on the Company\u2019s outstanding
\u00a0
bond loans with an
upward adjustment to reflect a potential extension,
\u00a0
whereas for fair value calculations the cost of debt
\u00a0
is based on an identified peer
group\u2019s bond loan issues.
For the value in use calculations, the relevant post-tax
\u00a0
nominal discount rate at yearend 2024 was 13.3
\u00a0
percent (13.7 percent at
yearend 2023) for the Kurdistan assets. For the
\u00a0
fair value calculations, the relevant post-tax
\u00a0
nominal discount rates at yearend 2024
was 8.9 percent for the Norwegian North Sea
\u00a0
assets (9.8 percent at yearend 2023) and 8.6
\u00a0
percent for the UK North Sea assets (7.1
percent at yearend 2023).
Inflation and currency rates
The long-term inflation rate is assumed to be 2 percent
\u00a0
independent of the underlying country or currency
\u00a0
(unchanged from yearend
2023). DNO has applied the forward curve and
\u00a0
observable broker and analyst consensus as basis
\u00a0
for assessment of currency rates.
The USD/NOK applied for impairment testing at yearend
\u00a0
2024, was USD/NOK 11.0 for 2025, USD/NOK 10.5 for the years 2026-2027,
USD/NOK 10.0 for the years 2028-2029 and thereafter
\u00a0
kept constant at USD/NOK 10.0 from the year
\u00a0
2029
\u00a0
onwards.
\u00a0
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\n
Impairment charge and/or reversal
The following table shows the recoverable amounts
\u00a0
and net impairment charges or reversal for
\u00a0
the CGUs which were impaired in 2024
and 2023, and how it was recognized in
\u00a0
the income statement and the balance sheet.
Full-Year ended 31 December 2024
Income statement:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
\u00a0
-charge/
Tax
\u00a0
-charge/
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
\u00a0
-expense
(post-tax)
Goodwill
assets
equipment
\u00a0
-liability
effects
Baeshiqa, Kurdistan
82.0
-89.0
-
-89.0
-
-
-89.0
-
-
Arran, North Sea
20.1
-41.6
-
-41.6
-41.3
-
-
-
-0.3
Vilje, North Sea
5.3
-2.2
-
-2.2
-2.2
-
-
-
-0.0
Ula area, North Sea
-
-6.7
5.2
-1.5
-
-
-6.6
5.2
-0.0
Other CGUs, North Sea
-
-6.4
-
-6.4
-2.4
-
-2.6
-
-1.4
Total
-146.0
5.2
-140.8
-46.0
-
-98.2
5.2
-1.8
Full-Year ended 31 December 2023
Income statement:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
\u00a0
-charge/
Tax
\u00a0
-charge/
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
\u00a0
-expense
(post-tax)
Goodwill
assets
equipment
\u00a0
-liability
effects
Ula area, North Sea
-
-14.9
12.7
-2.2
-
-
-15.6
13.2
0.2
Vilje, North Sea
9.4
-10.9
-
-10.9
-11.3
-
-
-
0.4
Other CGUs, North Sea
-
1.0
-
1.0
-
-
1.1
-
-0.1
Total
-24.9
12.7
-12.1
-11.3
-
-14.5
13.2
0.5
During 2024, a total impairment charge of USD
\u00a0
146.0 million (USD 140.8 million post-tax) was
\u00a0
recognized, mainly driven by:
\u00a0
\u2022
The results of well testing programs (Baeshiqa CGU);
\u2022
Recognition of a deferred tax asset which triggered
\u00a0
a partial impairment of goodwill (Arran
\u00a0
CGU, see Note 12)
\u2022
Updated economic profiles (Vilje CGU); and
\u2022
Upward revision in the cost estimate for decommissioning
\u00a0
(Ula area CGU).
At yearend 2024, total book value of goodwill of USD
\u00a0
102.1 million is mainly related to technical
\u00a0
goodwill from the Norne area
acquisition (USD 54.5 million),
\u00a0
Arran acquisition (USD 20.2 million) and
\u00a0
Alve CGU (USD 26.2 million).
During 2023, a total impairment charge of USD
\u00a0
24.9 million (USD 12.1 million post-tax) was
\u00a0
recognized, mainly driven by:
\u00a0
\u2022
Downward revision of the oil price assumption
\u00a0
and reserves estimates, and updated cost
\u00a0
profiles (Vilje CGU); and
\u2022
Upward revision in the cost estimate for decommissioning
\u00a0
(Ula area CGU).
The Company performed testing of its Kurdistan
\u00a0
assets following the ITP closure in March 2023 (Note
\u00a0
3). The estimated recoverable
amounts were higher than the carrying amounts
\u00a0
and thus no impairment charges were recognized
\u00a0
at yearend 2023.
\u00a0
At yearend 2023, total book value of goodwill of USD
\u00a0
43.2 million was mainly related to technical
\u00a0
goodwill on Alve CGU (USD 29.2
million).
Sensitivities
The table below illustrates how the net profit/loss
\u00a0
in 2024 would have been affected by changes in the
\u00a0
various assumptions, holding the
remaining assumptions unchanged. The estimated recoverable
\u00a0
amounts related to the Tawke license in Kurdistan are substantially
higher than the carrying amounts and the same sensitivity
\u00a0
tests would not imply any impairment charges.
Change in reported net profit/loss (net)
Assumption (USD million)
Change
Increase in assumption:
Decrease in assumption:
Oil and gas price
\u00a0
+/- 15%
90.1
-94.6
Reserves (2P) and resources (2C)
\u00a0
+/- 5%
32.7
-31.7
Discount rate (WACC)
\u00a0
+/- 1%
-11.0
12.0
Currency rate (USD/NOK)
\u00a0
+/- 1.0 NOK
0.8
-0.9
Climate considerations in impairment assessment
To
assess the robustness of the Group\u2019s oil and gas
\u00a0
assets, the Company has run sensitivities with
\u00a0
the oil and gas price assumptions
described by three scenarios outlined by the IEA: the Net
\u00a0
Zero Emissions Scenario by 2050, the Announced
\u00a0
Pledges Scenario and the
Stated Policies Scenario. These scenarios are commonly applied
\u00a0
by peer companies and the Company believes
\u00a0
that these are useful
for investors and other stakeholders in assessing
\u00a0
portfolio resilience across companies in the industry. The oil and gas price
assumptions in the scenarios have been provided by
\u00a0
the IEA for the years 2030 and 2050 (in 2023
\u00a0
real terms), and for the sensitivity
calculation a linear development between average
\u00a0
actual 2024 and IEA 2030, as well as between
\u00a0
IEA 2030 and IEA 2050 have been
applied. The table below summarizes how the reported
\u00a0
net profit would be impacted by an increase
\u00a0
(+) or decrease (-) in impairment
charge using the oil and gas price assumptions in
\u00a0
the following scenarios:
Oil price USD/bbl (assumption)
Gas price USD/MMBTU (assumption)
Change in reported
IEA scenario (USD million)
2030
2050
2030
2050
net profit/loss (net):
Stated Policies
79.0
75.0
6.5
7.7
0.1
Announced Pledges
\u00a0
72.0
58.0
6.0
5.2
-3.7
Net Zero Emissions by 2050
42.0
25.0
4.4
4.0
-125.2
A significant reduction in the oil and gas price assumptions
\u00a0
could also affect the estimated economic cut-off of the projects.
\u00a0
These illustrative impairment sensitivities assume no changes
\u00a0
to assumptions other than oil and gas prices.
\u00a0
The illustrative sensitivities
on climate change are not considered to represent
\u00a0
a best estimate of an expected impairment
\u00a0
impact. Moreover, a significant and
prolonged reduction in oil and gas prices would
\u00a0
likely result in mitigating actions by DNO and
\u00a0
its license partners; for example it could
have an impact on drilling plans and production profiles
\u00a0
for new and existing assets. Quantifying such
\u00a0
impacts is considered
impracticable, as it requires detailed evaluations based
\u00a0
on hypothetical scenarios and not based on
\u00a0
existing business or development
plans.
License expiry and economic cut-off dates for development
\u00a0
and production assets
In Kurdistan, the Tawke license expires in 2026 but DNO has the right to one
\u00a0
automatic five-year extension (i.e., to 2031) and,
\u00a0
if
commercial production is still possible at the end
\u00a0
of this extended period, DNO is entitled to, upon
\u00a0
request to the KRG, a further five-
year extension (i.e., to 2036). Based on DNO\u2019s current
\u00a0
assessments, the production from Tawke license will be commercial for the
duration of its contractual term and through subsequent
\u00a0
extensions. On the Baeshiqa license, commerciality was
\u00a0
declared by the
contractor on 1 August 2021, terminating the exploration
\u00a0
period and moving into the PSC development
\u00a0
period, which has as a 20-year
duration. If commercial production is still possible at the end
\u00a0
of the 20-year period, DNO is entitled
\u00a0
to a five-year extension.
In the North Sea, the following relevant license expiry and
\u00a0
economic cut-off (in brackets) dates were applied in relation
\u00a0
to yearend 2024
impairment assessments; the Ula area CGU have license
\u00a0
expiry dates that ranges between 2029 and
\u00a0
2036 (economic cut-off assumed
to be at the end of 2028); the Norne area
\u00a0
CGU have license expiry dates that ranges between
\u00a0
2029 and 2036 (2032); the Brage area
CGU license expiry dates ranges between 2030
\u00a0
and 2031 (2031); the Trym license expires in 2027 (2027);
\u00a0
the Vilje license expires in
2032 (2032); the Fenja license expires in 2039
\u00a0
(2038); the Arran field expires in 2028 (2029);
\u00a0
and the Berling license expires 2043
(2036).
", "dimensions": { "concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_70": { "value": "
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Impairments
At the end of each reporting period, the Group
\u00a0
assesses whether there is any indication that an
\u00a0
asset may be impaired. If an
impairment indicator is concluded to exist, an impairment
\u00a0
test is performed.
\u00a0
Indications of impairment may include a decline
\u00a0
in the long-term oil and gas price (or short-term
\u00a0
oil and gas price for late-life oil and
gas fields), changes in future investments or significant
\u00a0
downward revision of reserve and resource
\u00a0
estimates. For the purposes of
impairment assessment, assets are grouped at the
\u00a0
lowest levels for which there are separable identifiable
\u00a0
cash inflows. For oil and
gas assets, a CGU may be individual oil and
\u00a0
gas fields, or a group of oil and gas fields
\u00a0
that are connected to the same
infrastructure/production facilities, or a license.
\u00a0
An impairment loss is recognized when the carrying
\u00a0
amount exceeds the recoverable amount of an
\u00a0
asset. The recoverable amount is
the higher of the asset\u2019s fair value less costs to sell
\u00a0
and its value in use. Fair value less costs
\u00a0
to sell determined through either the
discounted cash flow method (income approach) or
\u00a0
the market transactions method (market approach).
\u00a0
The value in use can only be
determined through the discounted cash flow method.
Technical goodwill
\u00a0
Technical goodwill is tested for impairment annually or more frequently when there are
\u00a0
impairment indicators. Those indicators may
be specific to an individual CGU or groups of
\u00a0
CGUs to which the technical goodwill is
\u00a0
related. Goodwill is not depreciated and hence,
impairment of technical goodwill is expected on
\u00a0
a recurring basis, unless there are positive
\u00a0
changes in underlying assumptions that
more than offset the production from the CGU (or
\u00a0
groups of CGUs).
\u00a0
When performing the impairment test for technical
\u00a0
goodwill, deferred tax recognized in relation to
\u00a0
the acquired assets in a business
combination reduces the net carrying value prior
\u00a0
to the impairment charges. After initial recognition,
\u00a0
depreciation of values calculated
in the purchase price allocations from business
\u00a0
combinations will result in decreased deferred tax
\u00a0
liability. When deferred tax from
the initial recognition decreases, more goodwill is exposed
\u00a0
for impairment.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment/reversal of impairment
\u00a0
of oil and gas assets
The estimation of the recoverable amount for the
\u00a0
oil and gas assets includes assessments of
\u00a0
expected future cash flows and future
market conditions, including entitlement production,
\u00a0
future oil and gas prices, cost profiles, country
\u00a0
risk factors (i.e., discount rate)
and the date of expiration of the licenses.
\u00a0
The fair value of an asset or a liability is
\u00a0
measured using the assumptions that market participants
\u00a0
would use when pricing the asset
or liability, including assumptions about risk, assuming that market participants
\u00a0
act in their economic best interest. The Group
\u00a0
uses
valuation techniques that are appropriate in
\u00a0
the circumstances and for which sufficient data are available
\u00a0
to measure fair value. The
fair value of oil and gas assets is normally
\u00a0
based on discounted cash flow models (income
\u00a0
approach), where the determination of
different inputs in the model requires significant judgment
\u00a0
from management, as described in the section
\u00a0
above regarding
impairment.
Climate considerations in impairment assessments
Certain climate considerations are factored into
\u00a0
the Group\u2019s estimation of cash flows that are applied in
\u00a0
the calculation of recoverable
amount. This includes factoring in current legislation
\u00a0
(e.g., environmental taxes/fees) and estimation
\u00a0
of future levels of environmental
taxes/fees. For DNO\u2019s oil and gas assets on the NCS,
\u00a0
carbon pricing is in line with current legislation and
\u00a0
reflects the operators
forecasts for individual assets. As proposed in the Norwegian
\u00a0
Government\u2019s Climate Plan for 2021-2030, a steady increase
\u00a0
in the
total carbon price (quota plus CO2 tax) to
\u00a0
NOK 2,000 per tonnes (in 2020 real terms) is
\u00a0
expected by 2030. In Kurdistan, the KRG
introduced in 2021 a requirement for oil companies
\u00a0
to put plans in place to curb gas flaring
\u00a0
to reduce emissions. The Company has
run sensitivities for its Kurdistan oil assets with the
\u00a0
CO2 tax assumptions as described in the scenarios
\u00a0
described by the International
Energy Agency (IEA).
An energy transition is likely to impact future oil
\u00a0
and gas prices which in turn may affect
\u00a0
the recoverable amount of the oil and gas
assets. Indirectly, climate considerations are also assessed in the forecasting of
\u00a0
oil and gas prices where supply and demand
\u00a0
are
considered.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_71": { "value": "
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Impairments
At the end of each reporting period, the Group
\u00a0
assesses whether there is any indication that an
\u00a0
asset may be impaired. If an
impairment indicator is concluded to exist, an impairment
\u00a0
test is performed.
\u00a0
Indications of impairment may include a decline
\u00a0
in the long-term oil and gas price (or short-term
\u00a0
oil and gas price for late-life oil and
gas fields), changes in future investments or significant
\u00a0
downward revision of reserve and resource
\u00a0
estimates. For the purposes of
impairment assessment, assets are grouped at the
\u00a0
lowest levels for which there are separable identifiable
\u00a0
cash inflows. For oil and
gas assets, a CGU may be individual oil and
\u00a0
gas fields, or a group of oil and gas fields
\u00a0
that are connected to the same
infrastructure/production facilities, or a license.
\u00a0
An impairment loss is recognized when the carrying
\u00a0
amount exceeds the recoverable amount of an
\u00a0
asset. The recoverable amount is
the higher of the asset\u2019s fair value less costs to sell
\u00a0
and its value in use. Fair value less costs
\u00a0
to sell determined through either the
discounted cash flow method (income approach) or
\u00a0
the market transactions method (market approach).
\u00a0
The value in use can only be
determined through the discounted cash flow method.
Technical goodwill
\u00a0
Technical goodwill is tested for impairment annually or more frequently when there are
\u00a0
impairment indicators. Those indicators may
be specific to an individual CGU or groups of
\u00a0
CGUs to which the technical goodwill is
\u00a0
related. Goodwill is not depreciated and hence,
impairment of technical goodwill is expected on
\u00a0
a recurring basis, unless there are positive
\u00a0
changes in underlying assumptions that
more than offset the production from the CGU (or
\u00a0
groups of CGUs).
\u00a0
When performing the impairment test for technical
\u00a0
goodwill, deferred tax recognized in relation to
\u00a0
the acquired assets in a business
combination reduces the net carrying value prior
\u00a0
to the impairment charges. After initial recognition,
\u00a0
depreciation of values calculated
in the purchase price allocations from business
\u00a0
combinations will result in decreased deferred tax
\u00a0
liability. When deferred tax from
the initial recognition decreases, more goodwill is exposed
\u00a0
for impairment.
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Impairment/reversal of impairment
\u00a0
of oil and gas assets
The estimation of the recoverable amount for the
\u00a0
oil and gas assets includes assessments of
\u00a0
expected future cash flows and future
market conditions, including entitlement production,
\u00a0
future oil and gas prices, cost profiles, country
\u00a0
risk factors (i.e., discount rate)
and the date of expiration of the licenses.
\u00a0
The fair value of an asset or a liability is
\u00a0
measured using the assumptions that market participants
\u00a0
would use when pricing the asset
or liability, including assumptions about risk, assuming that market participants
\u00a0
act in their economic best interest. The Group
\u00a0
uses
valuation techniques that are appropriate in
\u00a0
the circumstances and for which sufficient data are available
\u00a0
to measure fair value. The
fair value of oil and gas assets is normally
\u00a0
based on discounted cash flow models (income
\u00a0
approach), where the determination of
different inputs in the model requires significant judgment
\u00a0
from management, as described in the section
\u00a0
above regarding
impairment.
Climate considerations in impairment assessments
Certain climate considerations are factored into
\u00a0
the Group\u2019s estimation of cash flows that are applied in
\u00a0
the calculation of recoverable
amount. This includes factoring in current legislation
\u00a0
(e.g., environmental taxes/fees) and estimation
\u00a0
of future levels of environmental
taxes/fees. For DNO\u2019s oil and gas assets on the NCS,
\u00a0
carbon pricing is in line with current legislation and
\u00a0
reflects the operators
forecasts for individual assets. As proposed in the Norwegian
\u00a0
Government\u2019s Climate Plan for 2021-2030, a steady increase
\u00a0
in the
total carbon price (quota plus CO2 tax) to
\u00a0
NOK 2,000 per tonnes (in 2020 real terms) is
\u00a0
expected by 2030. In Kurdistan, the KRG
introduced in 2021 a requirement for oil companies
\u00a0
to put plans in place to curb gas flaring
\u00a0
to reduce emissions. The Company has
run sensitivities for its Kurdistan oil assets with the
\u00a0
CO2 tax assumptions as described in the scenarios
\u00a0
described by the International
Energy Agency (IEA).
An energy transition is likely to impact future oil
\u00a0
and gas prices which in turn may affect
\u00a0
the recoverable amount of the oil and gas
assets. Indirectly, climate considerations are also assessed in the forecasting of
\u00a0
oil and gas prices where supply and demand
\u00a0
are
considered.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfNonfinancialAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_72": { "value": "
Note 12
Business combinations
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\n
\u00a0
\n
Accounting policies
Business combinations
In accordance with IFRS 3 Business Combinations,
\u00a0
an acquisition is considered a business combination,
\u00a0
when the acquired asset or
groups of assets constitute a business (i.e., an integrated
\u00a0
set of operations and assets conducted and
\u00a0
managed for the purpose of
providing a return to the investors).
Acquired businesses are included in the financial statements
\u00a0
from the transaction date. The transaction date
\u00a0
is defined as the date
on which the Group achieves control over the
\u00a0
financial and operating assets. This date may
\u00a0
differ from the actual date on which the
assets are transferred.
For accounting purposes, the acquisition method is used
\u00a0
in connection with the purchase of businesses.
\u00a0
Acquisition cost equals the
fair value of the assets used as consideration, including
\u00a0
contingent consideration, equity instruments issued
\u00a0
and liabilities assumed
in connection with the transfer of control. Acquisition
\u00a0
cost is measured against the fair value of the acquired
\u00a0
assets and assumed
liabilities. Identifiable intangible assets are included
\u00a0
in connection with acquisitions if they can be
\u00a0
separated from other assets or
meet the legal contractual criteria. If the acquisition
\u00a0
cost at the time of the acquisition exceeds
\u00a0
the fair value of the acquired net
assets (when the acquiring entity achieves control
\u00a0
of the transferring entity), goodwill arises. If the
\u00a0
fair value of the acquired net
assets exceeds the acquisition cost on the acquisition
\u00a0
date, the excess amount is taken to profit
\u00a0
or loss immediately.
\u00a0
Goodwill is allocated to the CGUs or groups of
\u00a0
CGUs that are expected to benefit from
\u00a0
synergy effects of the acquisition. The
allocation of goodwill may vary depending on the
\u00a0
basis of its initial recognition.
The goodwill that is recognized by the Group is related
\u00a0
to technical goodwill and is recognized
\u00a0
due to the requirement to recognize
deferred tax for the difference between the assigned fair
\u00a0
values and the related tax base. The fair
\u00a0
values of the Group\u2019s licenses in
the North Sea are based on cash flows after tax. This
\u00a0
is because these licenses are sold only on
\u00a0
an after-tax basis. The purchaser is
therefore not entitled to a tax deduction for the
\u00a0
consideration paid above the seller\u2019s tax
\u00a0
values. In accordance with IAS 12, a
provision is made for deferred tax corresponding
\u00a0
to the tax rate multiplied by the difference between
\u00a0
the fair values of the acquired
assets and the transferred tax depreciation basis.
\u00a0
The offsetting entry to this deferred tax is goodwill. Hence,
\u00a0
goodwill arises as a
technical effect of deferred tax. Technical goodwill is tested for impairment separately for each CGU
\u00a0
which gives rise to the technical
goodwill. A CGU may be individual oil fields, or a
\u00a0
group of oil fields that are connected to
\u00a0
the same infrastructure/production facilities,
or a license.
The estimation of fair value may be adjusted up
\u00a0
to 12 months after the acquisition date if new
\u00a0
information emerges about facts and
circumstances that existed at the time of the
\u00a0
takeover and which, had they been known, would
\u00a0
have affected the calculation of the
amounts that were included from that date.
Acquisition-related costs, except costs to issue debt
\u00a0
or equity securities, are expensed as incurred.
\u00a0
Taxes payable and deferred
taxes are recognized directly in the equity to
\u00a0
the extent that they relate to items charged
\u00a0
directly to the equity.
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
\u00a0
\n
Estimation uncertainty
The Group applies the acquisition method for transactions
\u00a0
involving business combinations and applies the principles
\u00a0
of the
acquisition method when an interest or an additional
\u00a0
interest is acquired in a joint operation
\u00a0
which constitutes a business. Application
of the acquisition method may require significant judgement
\u00a0
in, among other matters, determining and
\u00a0
measuring the fair value of the
transaction consideration including contingent consideration
\u00a0
elements, identifying all assets acquired and
\u00a0
liabilities assumed,
establishing their fair values, determining deferred taxes,
\u00a0
and allocating the purchase price accordingly, including measurement
\u00a0
and
allocation of goodwill.
\u00a0
The assets acquired through business combinations are
\u00a0
recognized at fair values and, as such, are
\u00a0
sensitive to adverse changes in
a number of often volatile economic factors, including
\u00a0
future oil and gas prices and the underlying
\u00a0
performance of the assets.
The Company has completed two transactions during 2024
\u00a0
as described below. The transactions are regarded
\u00a0
as business
combinations and accounted for using the acquisition
\u00a0
method. Purchase price allocations (PPA) have been performed to allocate
\u00a0
the
consideration to fair value of assets acquired and
\u00a0
liabilities assumed. No material changes booked
\u00a0
during the measurement period.
\u00a0
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\n
Arran acquisition
On 6 February 2024, the Company announced that
\u00a0
its wholly owned subsidiary DNO Exploration UK
\u00a0
Limited had entered into an
agreement to acquire a 25 percent interest in the
\u00a0
Arran field on the UKCS from ONE-Dyas E&P Limited.
\u00a0
The transaction completed on
15 May 2024 which is also the acquisition date
\u00a0
for accounting purposes. The goodwill recognized relates
\u00a0
mainly to technical goodwill
and tax synergies. No contingent consideration is
\u00a0
to be paid. Transaction costs of USD 0.7 million were
\u00a0
incurred and expensed in the
profit/loss statement.
\u00a0
Since the acquisition, DNO has included in its
\u00a0
consolidated statement of comprehensive income a revenue
\u00a0
of USD 34.3 million and a
profit of USD 4.3 million. If the business combination
\u00a0
had occurred in the beginning of 2024, DNO
\u00a0
would have included in its
consolidated statement of comprehensive income a revenue
\u00a0
of USD 66.2 million and a profit of USD
\u00a0
9.2 million.
\u00a0
Fair value at
USD million
acquisition date
Deferred tax assets
8.4
Producing asset
37.5
Other current assets
0.3
Total assets
46.2
Deferred tax liabilities
20.3
Asset retirement obligation
21.1
Other current liabilities
6.4
Total liabilities
47.8
Total identifiable net assets at fair value
\u00a0
-1.6
Consideration (cash)
60.1
Goodwill
61.7
After the recognition of the PPA, a reassessment of the utilization of
\u00a0
tax losses in the acquiring entity was carried out,
\u00a0
which triggered
the recognition of a deferred tax asset and a
\u00a0
partial impairment of goodwill. The overall impact
\u00a0
on the Net profit/loss is positive but the
adjustments are reported through different lines in the accounts.
Impairment of goodwill
-41.3
Tax income due to recognition of deferred
\u00a0
tax asset
61.7
Impact on Net profit/loss
20.4
\u00a0
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\n
Norne Area acquisition
On 8 May 2024, the Company announced that its
\u00a0
wholly owned subsidiary DNO Norge AS had entered
\u00a0
into an agreement to acquire
stakes in five oil and gas fields, including an operatorship,
\u00a0
in the Norne area in the Norwegian Sea
\u00a0
from V\u00e5r Energi ASA. The
transaction included interests in four producing fields, Norne
\u00a0
(6.9 percent), Skuld (11.5 percent), Urd (11.5 percent) and Marulk (20
percent and operatorship) plus the ongoing Verdande development (10 percent).
\u00a0
The transaction completed on 30 August 2024
\u00a0
which is
also the acquisition date for accounting purposes.
\u00a0
The goodwill recognized relates mainly to technical
\u00a0
goodwill. No contingent
consideration is to be paid. Transaction costs of USD 0.2 million
\u00a0
were incurred and expensed in the profit/loss
\u00a0
statement.
\u00a0
Since the acquisition, DNO has included in its
\u00a0
consolidated statement of comprehensive income a revenue
\u00a0
of USD 12.7 million and a
profit of USD 1.9 million. If the business combination
\u00a0
had occurred in the beginning of 2024, DNO
\u00a0
would have included in its
consolidated statement of comprehensive income a revenue
\u00a0
of USD 71.7 million and a profit of USD
\u00a0
9.1 million.
\u00a0
Fair value at
USD million
acquisition date
Deferred tax assets
55.6
Producing asset
75.0
Other current assets
3.0
Total assets
133.6
Deferred tax liabilities
54.5
Asset retirement obligation
67.0
Other current liabilities
11.4
Tax payable
12.9
Total liabilities
145.8
Consideration (cash)
28.3
Ringhorne East transfer at fair value
\u00a0
11.6
Total consideration
39.9
Net assets excluding goodwill
-12.2
Consideration
\u00a0
39.9
Goodwill
52.1
The transfer of DNO\u2019s 22.6 percent interest in Ringhorne
\u00a0
East to V\u00e5r Energi ASA, the other element of the
\u00a0
swap, was also completed on
30 August 2024. The gain on the disposal is
\u00a0
the difference between the proceeds and the carrying
\u00a0
amount and has been recognized in
the profit/loss statement.
Net asset derecognized
12.3
Consideration received
15.3
Gain
3.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_73": { "value": "
Note 13
Joint Venture
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\n
Accounting policies
\u00a0
\n
\u00a0
\n
\u00a0
\n
Joint Venture
The Group\u2019s investments in a joint venture are accounted
\u00a0
for using the equity method. The income statement
\u00a0
reflects the Group\u2019s
share of the results of operations in the joint
\u00a0
venture. The financial statements of the joint
\u00a0
venture are prepared for the same
reporting period as the Group. When necessary, adjustments are made
\u00a0
to bring the accounting policies in line with
\u00a0
those of the
Group.
\u00a0
DNO holds 100 percent of the shares in Mondoil
\u00a0
Enterprises LLC (Mondoil Enterprises) which has
\u00a0
a 33.33 percent indirect interest in
privately-held Foxtrot International whose principal assets
\u00a0
are operated stakes in offshore production of
\u00a0
gas and associated liquids in
C\u00f4te d'Ivoire. Foxtrot International holds a 27.27 percent
\u00a0
interest in and operatorship of Block CI-27
\u00a0
containing reserves of gas,
produced together with condensate and oil, from
\u00a0
four offshore fields tied back to two fixed platforms.
\u00a0
Foxtrot International's summarized statement of financial position
Year ended 31 December
USD million
2024
2023
Non-current assets
159.3
199.9
Current assets
50.1
64.3
Total assets
209.4
264.2
Non-current liabilities
67.6
68.8
Current liabilities
24.8
27.5
Total liabilities
92.5
96.3
Equity
116.9
167.9
Group's share of net assets (33.33 percent)
38.1
56.0
Goodwill
0.8
0.8
Fair value uplift on PP&E and ARO (net of related deferred tax)
10.0
11.1
Carrying amount Investment in Joint Venture
48.8
67.9
Foxtrot International's summarized statement of comprehensive income
1 January - 31 December
USD million
2024
2023
Revenues
75.7
79.4
Expenses
-35.6
-17.6
Depreciation
-33.7
-30.8
Other income/finance income
6.2
8.6
Tax income/expense
-
-
Net profit/loss
12.6
39.6
Group's share of net profit (33.33 percent)
4.2
13.2
Depletion of fair value uplift of PP&E and ARO (net of related deferred tax)
-0.9
-1.3
Share of profit/loss from Joint Venture
3.3
11.9
Movement in the carrying amount of Investment in Joint Venture
1 January - 31 December
USD million
2024
2023
Opening balance
67.9
76.1
Share of profit/loss from Joint Venture
3.3
11.9
Equity contribution into Joint Venture
9.4
6.9
Dividends from Joint Venture
-31.8
-27.1
Carrying amount Investment in Joint Venture
48.8
67.9
", "dimensions": { "concept": "ifrs-full:DisclosureOfJointVenturesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_74": { "value": "
Note 13
Joint Venture
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Accounting policies
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\n
Joint Venture
The Group\u2019s investments in a joint venture are accounted
\u00a0
for using the equity method. The income statement
\u00a0
reflects the Group\u2019s
share of the results of operations in the joint
\u00a0
venture. The financial statements of the joint
\u00a0
venture are prepared for the same
reporting period as the Group. When necessary, adjustments are made
\u00a0
to bring the accounting policies in line with
\u00a0
those of the
Group.
\u00a0
DNO holds 100 percent of the shares in Mondoil
\u00a0
Enterprises LLC (Mondoil Enterprises) which has
\u00a0
a 33.33 percent indirect interest in
privately-held Foxtrot International whose principal assets
\u00a0
are operated stakes in offshore production of
\u00a0
gas and associated liquids in
C\u00f4te d'Ivoire. Foxtrot International holds a 27.27 percent
\u00a0
interest in and operatorship of Block CI-27
\u00a0
containing reserves of gas,
produced together with condensate and oil, from
\u00a0
four offshore fields tied back to two fixed platforms.
\u00a0
Foxtrot International's summarized statement of financial position
Year ended 31 December
USD million
2024
2023
Non-current assets
159.3
199.9
Current assets
50.1
64.3
Total assets
209.4
264.2
Non-current liabilities
67.6
68.8
Current liabilities
24.8
27.5
Total liabilities
92.5
96.3
Equity
116.9
167.9
Group's share of net assets (33.33 percent)
38.1
56.0
Goodwill
0.8
0.8
Fair value uplift on PP&E and ARO (net of related deferred tax)
10.0
11.1
Carrying amount Investment in Joint Venture
48.8
67.9
Foxtrot International's summarized statement of comprehensive income
1 January - 31 December
USD million
2024
2023
Revenues
75.7
79.4
Expenses
-35.6
-17.6
Depreciation
-33.7
-30.8
Other income/finance income
6.2
8.6
Tax income/expense
-
-
Net profit/loss
12.6
39.6
Group's share of net profit (33.33 percent)
4.2
13.2
Depletion of fair value uplift of PP&E and ARO (net of related deferred tax)
-0.9
-1.3
Share of profit/loss from Joint Venture
3.3
11.9
Movement in the carrying amount of Investment in Joint Venture
1 January - 31 December
USD million
2024
2023
Opening balance
67.9
76.1
Share of profit/loss from Joint Venture
3.3
11.9
Equity contribution into Joint Venture
9.4
6.9
Dividends from Joint Venture
-31.8
-27.1
Carrying amount Investment in Joint Venture
48.8
67.9
Note 26
Group companies and other companies
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\n
Ownership and voting
USD million
Office
interest (percent)
Shares in the Company's subsidiaries
DNO Iraq AS
Norway
100
DNO UK Limited
United Kingdom
100
DNO Mena AS
Norway
100
DNO Technical Services AS
Norway
100
DNO Yemen AS
Norway
100
DNO North Sea plc
United Kingdom
100
Mondoil Enterprises LLC
United States
100
Shares in subsidiaries owned through subsidiaries
DNO Mena AS
West Limited
Bermuda
100
DNO Tunisia Limited
Guernsey
100
RAK Petroleum Public Company Limited
United Arab Emirates
100
DNO North Sea plc
DNO Norge AS
Norway
100
DNO North Sea (U.K.) Limited
United Kingdom
100
DNO North Sea (ROGB) Limited
United Kingdom
100
DNO North Sea (Energy) Limited
United Kingdom
100
DNO Exploration UK Limited
United Kingdom
100
DNO North Sea SIP EBT Limited
United Kingdom
100
Shares in other entities, indirectly (equity accounted)
Mondoil C\u00f4te d\u2019Ivoire LLC
United States
50
Foxtrot International
Cayman Islands
33.33
The Group\u2019s operations in Kurdistan are carried out through
\u00a0
its subsidiary DNO Iraq AS, while activities on
\u00a0
the NCS are carried out
through DNO Norge AS. UKCS activities are carried
\u00a0
out through DNO North Sea (U.K.) Limited,
\u00a0
DNO North Sea (ROGB) Limited and
DNO Exploration UK Limited.
\u00a0
DNO Exploration UK Limited was disposed from
\u00a0
DNO ASA to DNO North Sea plc in 2024.
\u00a0
Activities in
C\u00f4te d'Ivoire are carried out by Foxtrot International,
\u00a0
in which the Company\u2019s indirect ownership of 33.33
\u00a0
percent is accounted for using
the equity method. DNO ASA, DNO Technical Services AS and DNO North Sea plc provide
\u00a0
technical support and services to the
various companies in the Group. The other subsidiaries
\u00a0
from the table above had minimal activity during
\u00a0
the year. In 2024 DNO Oman
Limited was renamed to West Limited and DNO Oman
\u00a0
Block 8 Limited was liquidated.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestsInOtherEntitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_75": { "value": "
Note 14
Inventory
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\n
Accounting policies
Inventories
Inventories comprise of drilling equipment, spare parts
\u00a0
and consumables for own use and are valued
\u00a0
at the lower of cost and net
realizable value. Inventories that meet the definition of
\u00a0
PP&E are presented under the PP&E and are
\u00a0
depreciated as part of the
underlying capitalized asset using the UoP method.
Years ended 31 December
\u00a0
Kurdistan
\u00a0
North Sea
\u00a0
Total
USD million
2024
2023
2024
2023
2024
2023
Drilling equipment, spare parts and consumables
70.9
80.4
23.4
14.8
94.3
95.2
Provision for obsolete inventory
-15.2
-15.0
-4.3
-2.3
-19.4
-17.4
Total inventories
55.7
65.3
19.1
12.5
74.8
77.8
", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_76": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Inventories
Inventories comprise of drilling equipment, spare parts
\u00a0
and consumables for own use and are valued
\u00a0
at the lower of cost and net
realizable value. Inventories that meet the definition of
\u00a0
PP&E are presented under the PP&E and are
\u00a0
depreciated as part of the
underlying capitalized asset using the UoP method.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForMeasuringInventories", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_77": { "value": "
Accounting policies
Trade debtors
Trade debtors are recognized at nominal value less any provisions
\u00a0
for expected credit losses (ECL). ECLs are based
\u00a0
on the
difference between the contractual cash flows due in accordance
\u00a0
with the contract and all the (discounted)
\u00a0
cash flows that are
expected to be received (i.e., cash shortfalls).
\u00a0
ECLs on trade receivables are measured by applying
\u00a0
either the general model or the
simplified model. A company must apply the simplified
\u00a0
model for trade receivables, which, when
\u00a0
invoiced, were without a significant
financing component. This applies to the Company\u2019s oil
\u00a0
and gas sales and hence the simplified model
\u00a0
is applied in respect of the
ELC assessment of the Kurdistan trade debtors (see below).
Overlift/underlift
An underlift arises when the sale is less
\u00a0
than the Group\u2019s share of the oil and gas production.
\u00a0
In general, the overlift/underlift
balances are valued at production cost including
\u00a0
depreciation (the sales method). For overlift, see Note
\u00a0
22.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_78": { "value": "
\u00a0
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Note 15
Other non-current receivables/Trade and other receivables
Years ended 31 December
USD million
2024
2023
Trade debtors (non-current portion)
98.2
129.8
Other long-term receivables
-
-
Total other non-current receivables
98.2
129.8
Trade debtors
185.0
149.5
Underlift
7.1
12.1
Other short-term receivables
146.1
103.8
Total trade and other receivables
338.1
265.4
At yearend 2024, the Company was owed over USD
\u00a0
298.1 million, excluding any interest, by the
\u00a0
KRG mainly related to sales of DNO\u2019s
entitlement shares of oil to the KRG for the months October
\u00a0
2022 through March 2023 plus part of
\u00a0
the amount invoiced for oil sold to the
KRG in September 2022. These receivables are
\u00a0
past due. Since 2017, DNO has consistently invoiced
\u00a0
the KRG for such oil sales based
on an agreed Brent-based pricing mechanism. For
\u00a0
September 2022, the KRG unilaterally decided to
\u00a0
pay based on a purported price
realized by the KRG during the delivery month. The
\u00a0
KRG proposed such change to the agreed pricing
\u00a0
mechanism in September 2022 to
which DNO has not agreed. DNO therefore
\u00a0
continues to request payment of the full invoiced
\u00a0
amount. During 2024, DNO recognized
that USD 16.9 million of these arrears had been
\u00a0
settled by way of offsetting against payables due
\u00a0
to the KRG.
The Company continues to engage with the KRG regarding
\u00a0
collection of the arrears and expects that it will recover
\u00a0
the full invoiced
amount (as has occurred in the past), but the
\u00a0
timing of recovery is uncertain. Nonetheless, due
\u00a0
to the IFRS 9 Financial Instruments
requirement to incorporate the time value of money, the Company reduced the book
\u00a0
value of the KRG arrears in 2023 by USD 44.6
million (presented under
Financial expenses
\u00a0
in the income statement) when comparing the book
\u00a0
value of these arrears with the present
value of the estimated future cash flows. As of 31 December
\u00a0
2024, the Company re-estimated the present
\u00a0
value with updated
assumptions, resulting in an accumulated increase
\u00a0
of USD 11.9 million to the book value of KRG arrears during 2024. The
\u00a0
calculation of
present value in accordance with IFRS 9, considers
\u00a0
a range of possible scenarios with assigned
\u00a0
weighting, involving estimation of the
timing of receipt of the arrears which will be
\u00a0
dependent upon uncertain future events, in
\u00a0
particular the assumed timing of the re-opening
of the ITP which has been shut-down since end
\u00a0
of March 2023. A discount rate of 12 percent
\u00a0
has been applied.
The underlift receivable of USD 7.1 million at yearend
\u00a0
2024 relates to North Sea. Other short-term
\u00a0
receivables mainly relate to working
capital items in licenses in Kurdistan and the North
\u00a0
Sea and accrual for earned income not invoiced
\u00a0
in the North Sea.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_79": { "value": "
Note 16
Cash and cash equivalents
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Cash and cash equivalents
Cash and short-term deposits in the statements
\u00a0
of financial position comprise cash held in banks,
\u00a0
cash in hand and short-term
deposits with an original maturity of three months
\u00a0
or less and held to meet short term commitments.
\u00a0
Restricted cash is cash reserved
for a specific purpose and therefore not available
\u00a0
for immediate and general use by the Group.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Years ended 31 December
USD million
2024
2023
Cash and cash equivalents, restricted
17.5
14.3
Cash and cash equivalents, non-restricted
881.5
704.5
Total cash and cash equivalents
899.0
718.8
Restricted cash consists of deposits on escrow account,
\u00a0
employees\u2019 tax withholdings and deposits for rent.
\u00a0
Non-restricted cash is
mainly related to bank deposits in USD, NOK, GBP
\u00a0
and EUR as of 31 December 2024.
Included in the non-restricted cash and cash equivalents
\u00a0
as of 31 December 2024 is USD 304 million
\u00a0
held on fixed interest time deposit
contracts with different duration and maturity dates up
\u00a0
to 14 February 2025.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_80": { "value": "
Note 16
Cash and cash equivalents
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Cash and cash equivalents
Cash and short-term deposits in the statements
\u00a0
of financial position comprise cash held in banks,
\u00a0
cash in hand and short-term
deposits with an original maturity of three months
\u00a0
or less and held to meet short term commitments.
\u00a0
Restricted cash is cash reserved
for a specific purpose and therefore not available
\u00a0
for immediate and general use by the Group.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Years ended 31 December
USD million
2024
2023
Cash and cash equivalents, restricted
17.5
14.3
Cash and cash equivalents, non-restricted
881.5
704.5
Total cash and cash equivalents
899.0
718.8
Restricted cash consists of deposits on escrow account,
\u00a0
employees\u2019 tax withholdings and deposits for rent.
\u00a0
Non-restricted cash is
mainly related to bank deposits in USD, NOK, GBP
\u00a0
and EUR as of 31 December 2024.
Included in the non-restricted cash and cash equivalents
\u00a0
as of 31 December 2024 is USD 304 million
\u00a0
held on fixed interest time deposit
contracts with different duration and maturity dates up
\u00a0
to 14 February 2025.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRestrictedCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_81": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Cash and cash equivalents
Cash and short-term deposits in the statements
\u00a0
of financial position comprise cash held in banks,
\u00a0
cash in hand and short-term
deposits with an original maturity of three months
\u00a0
or less and held to meet short term commitments.
\u00a0
Restricted cash is cash reserved
for a specific purpose and therefore not available
\u00a0
for immediate and general use by the Group.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_82": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Cash and cash equivalents
Cash and short-term deposits in the statements
\u00a0
of financial position comprise cash held in banks,
\u00a0
cash in hand and short-term
deposits with an original maturity of three months
\u00a0
or less and held to meet short term commitments.
\u00a0
Restricted cash is cash reserved
for a specific purpose and therefore not available
\u00a0
for immediate and general use by the Group.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRestrictedCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_83": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Years ended 31 December
USD million
2024
2023
Cash and cash equivalents, restricted
17.5
14.3
Cash and cash equivalents, non-restricted
881.5
704.5
Total cash and cash equivalents
899.0
718.8
Restricted cash consists of deposits on escrow account,
\u00a0
employees\u2019 tax withholdings and deposits for rent.
\u00a0
Non-restricted cash is
mainly related to bank deposits in USD, NOK, GBP
\u00a0
and EUR as of 31 December 2024.
Included in the non-restricted cash and cash equivalents
\u00a0
as of 31 December 2024 is USD 304 million
\u00a0
held on fixed interest time deposit
contracts with different duration and maturity dates up
\u00a0
to 14 February 2025.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndBankBalancesAtCentralBanksExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_84": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Note 17
Equity
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Equity
Ordinary shares
Ordinary shares are classified as equity. Costs directly attributable to the issue
\u00a0
of ordinary shares are recognized as a reduction
\u00a0
of
equity.
Repurchase of share capital (treasury shares)
Repurchased shares are classified as treasury shares
\u00a0
and are presented as a deduction from total
\u00a0
equity. When treasury shares are
subsequently sold or reissued, the amount received
\u00a0
is recognized as an increase in equity and
\u00a0
the resulting surplus or deficit of the
transaction is transferred to/from retained earnings.
Dividend
A liability to pay a dividend is recognized when
\u00a0
the distribution is authorized by the shareholders
\u00a0
at the AGM or the Board of
Directors based on authorization by the AGM.
\u00a0
A corresponding amount is recognized directly in equity.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2023
1,018,008
34.8
-0.9
33.9
Treasury shares purchased
-43,007
-
-1.0
-1.0
As of 31 December 2023
975,000
32.9
-
32.9
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2024
975,000
32.9
-
32.9
Treasury shares purchased
-
-
-
-
As of 31 December 2024
975,000
32.9
-
32.9
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\n
At the 2024 AGM, the Board of Directors was
\u00a0
given the authority to acquire treasury shares with
\u00a0
a total nominal value of up to NOK
24,375,000 which corresponds to 97,500,000 new shares.
\u00a0
The maximum amount to be paid per share
\u00a0
is NOK 100 and the minimum
amount is NOK 1. The authorization is time-limited until
\u00a0
the 2025 AGM, and not beyond 30 June 2025.
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital by
\u00a0
up to NOK 24,375.000 which
corresponds to 97,500,000 shares. The authorization is
\u00a0
time-limited until the 2025 AGM, and not beyond
\u00a0
30 June 2025.
\u00a0
In addition, the Board of Directors was given the authority
\u00a0
to raise convertible bonds with an aggregate
\u00a0
principal amount of up to USD
300,000,000. Upon conversion of bonds issued pursuant
\u00a0
to this authorization, the Company\u2019s share capital may be
\u00a0
increased by up to
NOK 24,375.000.
\u00a0
The authorization is valid until the 2025 AGM, but
\u00a0
not beyond 30 June 2025.
\u00a0
The Board of Directors was given the authority
\u00a0
to approve total dividend distributions from the date
\u00a0
of the 2024 AGM until the date of the
2025 AGM. Following this, the Board of Directors decided
\u00a0
to distribute quarterly dividends, NOK 0.25 per
\u00a0
share in February and May
and dividends of NOK 0.3125 per share in August and
\u00a0
November 2024.
Interest
The Company's shareholders as of 31 December 2024
Shares
(percent)
Goldman Sachs & Co. LLC
92,535,456
9.49
Folketrygdfondet
71,148,737
7.30
Clearstream Banking S.A.
63,878,853
6.55
BNP Paribas
42,956,895
4.41
RAK Gas LLC
34,311,403
3.52
Goldman Sachs & Co. LLC
33,147,785
3.40
Euroclear Bank S.A./N.V.
28,433,212
2.92
The Bank of New York Mellon
25,116,930
2.58
UBS Switzerland AG
19,583,592
2.01
JPMorgan Chase Bank, N.A., London
18,807,514
1.93
State Street Bank and Trust Comp
18,045,289
1.85
Nordnet Bank AB
12,321,500
1.26
State Street Bank and Trust Comp
10,890,560
1.12
Salt Value AS
10,660,968
1.09
Verdipapirfondet KLP Aksjenorge IN
10,035,479
1.03
Caceis Bank
8,696,391
0.89
Avanza Bank AB
7,887,883
0.81
Goldman Sachs & Co. LLC
7,678,701
0.79
Verdipapirfondet Storebrand Indeks
7,611,789
0.78
Verdipapirfondet DNB Norge Indeks
7,481,659
0.77
Other shareholders
443,769,404
45.51
Total number of shares excluding treasury shares
975,000,000
100.00
Treasury shares as of 31 December 2024 (DNO ASA)
0.00
0.00
Total number of outstanding shares
975,000,000
100.00
* At yearend 2024, DNO's Executive Chairman Bijan Mossavar
\u00a0
-Rahmani held interests in the Company through nominee
\u00a0
accounts at the
\u00a0
\u00a0
Goldman Sachs & Co. LLC, representing 12.89 percent
\u00a0
of the total number of outstanding shares.
Dividends of USD 101.9 million were paid in 2024
\u00a0
(USD 92.0 million in 2023). See Note 29
\u00a0
for dividend payment approved by the Board
after the reporting date. See Note 5 for shares held
\u00a0
by the Board of Directors and the senior management.
", "dimensions": { "concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_85": { "value": "
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\n
Accounting policies
Equity
Ordinary shares
Ordinary shares are classified as equity. Costs directly attributable to the issue
\u00a0
of ordinary shares are recognized as a reduction
\u00a0
of
equity.
Repurchase of share capital (treasury shares)
Repurchased shares are classified as treasury shares
\u00a0
and are presented as a deduction from total
\u00a0
equity. When treasury shares are
subsequently sold or reissued, the amount received
\u00a0
is recognized as an increase in equity and
\u00a0
the resulting surplus or deficit of the
transaction is transferred to/from retained earnings.
Dividend
A liability to pay a dividend is recognized when
\u00a0
the distribution is authorized by the shareholders
\u00a0
at the AGM or the Board of
Directors based on authorization by the AGM.
\u00a0
A corresponding amount is recognized directly in equity.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIssuedCapitalExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_86": { "value": "
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\n
Accounting policies
Equity
Ordinary shares
Ordinary shares are classified as equity. Costs directly attributable to the issue
\u00a0
of ordinary shares are recognized as a reduction
\u00a0
of
equity.
Repurchase of share capital (treasury shares)
Repurchased shares are classified as treasury shares
\u00a0
and are presented as a deduction from total
\u00a0
equity. When treasury shares are
subsequently sold or reissued, the amount received
\u00a0
is recognized as an increase in equity and
\u00a0
the resulting surplus or deficit of the
transaction is transferred to/from retained earnings.
Dividend
A liability to pay a dividend is recognized when
\u00a0
the distribution is authorized by the shareholders
\u00a0
at the AGM or the Board of
Directors based on authorization by the AGM.
\u00a0
A corresponding amount is recognized directly in equity.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTreasurySharesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_87": { "value": "
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\n
\u00a0
\n
Accounting policies
Equity
Ordinary shares
Ordinary shares are classified as equity. Costs directly attributable to the issue
\u00a0
of ordinary shares are recognized as a reduction
\u00a0
of
equity.
Repurchase of share capital (treasury shares)
Repurchased shares are classified as treasury shares
\u00a0
and are presented as a deduction from total
\u00a0
equity. When treasury shares are
subsequently sold or reissued, the amount received
\u00a0
is recognized as an increase in equity and
\u00a0
the resulting surplus or deficit of the
transaction is transferred to/from retained earnings.
Dividend
A liability to pay a dividend is recognized when
\u00a0
the distribution is authorized by the shareholders
\u00a0
at the AGM or the Board of
Directors based on authorization by the AGM.
\u00a0
A corresponding amount is recognized directly in equity.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDividendsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_88": { "value": "
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\n
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2023
1,018,008
34.8
-0.9
33.9
Treasury shares purchased
-43,007
-
-1.0
-1.0
As of 31 December 2023
975,000
32.9
-
32.9
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2024
975,000
32.9
-
32.9
Treasury shares purchased
-
-
-
-
As of 31 December 2024
975,000
32.9
-
32.9
\u00a0
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\u00a0
\n
At the 2024 AGM, the Board of Directors was
\u00a0
given the authority to acquire treasury shares with
\u00a0
a total nominal value of up to NOK
24,375,000 which corresponds to 97,500,000 new shares.
\u00a0
The maximum amount to be paid per share
\u00a0
is NOK 100 and the minimum
amount is NOK 1. The authorization is time-limited until
\u00a0
the 2025 AGM, and not beyond 30 June 2025.
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital by
\u00a0
up to NOK 24,375.000 which
corresponds to 97,500,000 shares. The authorization is
\u00a0
time-limited until the 2025 AGM, and not beyond
\u00a0
30 June 2025.
\u00a0
In addition, the Board of Directors was given the authority
\u00a0
to raise convertible bonds with an aggregate
\u00a0
principal amount of up to USD
300,000,000. Upon conversion of bonds issued pursuant
\u00a0
to this authorization, the Company\u2019s share capital may be
\u00a0
increased by up to
NOK 24,375.000.
\u00a0
The authorization is valid until the 2025 AGM, but
\u00a0
not beyond 30 June 2025.
\u00a0
The Board of Directors was given the authority
\u00a0
to approve total dividend distributions from the date
\u00a0
of the 2024 AGM until the date of the
2025 AGM. Following this, the Board of Directors decided
\u00a0
to distribute quarterly dividends, NOK 0.25 per
\u00a0
share in February and May
and dividends of NOK 0.3125 per share in August and
\u00a0
November 2024.
Interest
The Company's shareholders as of 31 December 2024
Shares
(percent)
Goldman Sachs & Co. LLC
92,535,456
9.49
Folketrygdfondet
71,148,737
7.30
Clearstream Banking S.A.
63,878,853
6.55
BNP Paribas
42,956,895
4.41
RAK Gas LLC
34,311,403
3.52
Goldman Sachs & Co. LLC
33,147,785
3.40
Euroclear Bank S.A./N.V.
28,433,212
2.92
The Bank of New York Mellon
25,116,930
2.58
UBS Switzerland AG
19,583,592
2.01
JPMorgan Chase Bank, N.A., London
18,807,514
1.93
State Street Bank and Trust Comp
18,045,289
1.85
Nordnet Bank AB
12,321,500
1.26
State Street Bank and Trust Comp
10,890,560
1.12
Salt Value AS
10,660,968
1.09
Verdipapirfondet KLP Aksjenorge IN
10,035,479
1.03
Caceis Bank
8,696,391
0.89
Avanza Bank AB
7,887,883
0.81
Goldman Sachs & Co. LLC
7,678,701
0.79
Verdipapirfondet Storebrand Indeks
7,611,789
0.78
Verdipapirfondet DNB Norge Indeks
7,481,659
0.77
Other shareholders
443,769,404
45.51
Total number of shares excluding treasury shares
975,000,000
100.00
Treasury shares as of 31 December 2024 (DNO ASA)
0.00
0.00
Total number of outstanding shares
975,000,000
100.00
* At yearend 2024, DNO's Executive Chairman Bijan Mossavar
\u00a0
-Rahmani held interests in the Company through nominee
\u00a0
accounts at the
\u00a0
\u00a0
Goldman Sachs & Co. LLC, representing 12.89 percent
\u00a0
of the total number of outstanding shares.
Dividends of USD 101.9 million were paid in 2024
\u00a0
(USD 92.0 million in 2023). See Note 29
\u00a0
for dividend payment approved by the Board
after the reporting date. See Note 5 for shares held
\u00a0
by the Board of Directors and the senior management.
", "dimensions": { "concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_89": { "value": "
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\n
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2023
1,018,008
34.8
-0.9
33.9
Treasury shares purchased
-43,007
-
-1.0
-1.0
As of 31 December 2023
975,000
32.9
-
32.9
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2024
975,000
32.9
-
32.9
Treasury shares purchased
-
-
-
-
As of 31 December 2024
975,000
32.9
-
32.9
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\n
\u00a0
\n
At the 2024 AGM, the Board of Directors was
\u00a0
given the authority to acquire treasury shares with
\u00a0
a total nominal value of up to NOK
24,375,000 which corresponds to 97,500,000 new shares.
\u00a0
The maximum amount to be paid per share
\u00a0
is NOK 100 and the minimum
amount is NOK 1. The authorization is time-limited until
\u00a0
the 2025 AGM, and not beyond 30 June 2025.
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital by
\u00a0
up to NOK 24,375.000 which
corresponds to 97,500,000 shares. The authorization is
\u00a0
time-limited until the 2025 AGM, and not beyond
\u00a0
30 June 2025.
\u00a0
In addition, the Board of Directors was given the authority
\u00a0
to raise convertible bonds with an aggregate
\u00a0
principal amount of up to USD
300,000,000. Upon conversion of bonds issued pursuant
\u00a0
to this authorization, the Company\u2019s share capital may be
\u00a0
increased by up to
NOK 24,375.000.
\u00a0
The authorization is valid until the 2025 AGM, but
\u00a0
not beyond 30 June 2025.
\u00a0
The Board of Directors was given the authority
\u00a0
to approve total dividend distributions from the date
\u00a0
of the 2024 AGM until the date of the
2025 AGM. Following this, the Board of Directors decided
\u00a0
to distribute quarterly dividends, NOK 0.25 per
\u00a0
share in February and May
and dividends of NOK 0.3125 per share in August and
\u00a0
November 2024.
Interest
The Company's shareholders as of 31 December 2024
Shares
(percent)
Goldman Sachs & Co. LLC
92,535,456
9.49
Folketrygdfondet
71,148,737
7.30
Clearstream Banking S.A.
63,878,853
6.55
BNP Paribas
42,956,895
4.41
RAK Gas LLC
34,311,403
3.52
Goldman Sachs & Co. LLC
33,147,785
3.40
Euroclear Bank S.A./N.V.
28,433,212
2.92
The Bank of New York Mellon
25,116,930
2.58
UBS Switzerland AG
19,583,592
2.01
JPMorgan Chase Bank, N.A., London
18,807,514
1.93
State Street Bank and Trust Comp
18,045,289
1.85
Nordnet Bank AB
12,321,500
1.26
State Street Bank and Trust Comp
10,890,560
1.12
Salt Value AS
10,660,968
1.09
Verdipapirfondet KLP Aksjenorge IN
10,035,479
1.03
Caceis Bank
8,696,391
0.89
Avanza Bank AB
7,887,883
0.81
Goldman Sachs & Co. LLC
7,678,701
0.79
Verdipapirfondet Storebrand Indeks
7,611,789
0.78
Verdipapirfondet DNB Norge Indeks
7,481,659
0.77
Other shareholders
443,769,404
45.51
Total number of shares excluding treasury shares
975,000,000
100.00
Treasury shares as of 31 December 2024 (DNO ASA)
0.00
0.00
Total number of outstanding shares
975,000,000
100.00
* At yearend 2024, DNO's Executive Chairman Bijan Mossavar
\u00a0
-Rahmani held interests in the Company through nominee
\u00a0
accounts at the
\u00a0
\u00a0
Goldman Sachs & Co. LLC, representing 12.89 percent
\u00a0
of the total number of outstanding shares.
Dividends of USD 101.9 million were paid in 2024
\u00a0
(USD 92.0 million in 2023). See Note 29
\u00a0
for dividend payment approved by the Board
after the reporting date. See Note 5 for shares held
\u00a0
by the Board of Directors and the senior management.
", "dimensions": { "concept": "ifrs-full:DisclosureOfDividendsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_90": { "value": "
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\n
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2023
1,018,008
34.8
-0.9
33.9
Treasury shares purchased
-43,007
-
-1.0
-1.0
As of 31 December 2023
975,000
32.9
-
32.9
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2024
975,000
32.9
-
32.9
Treasury shares purchased
-
-
-
-
As of 31 December 2024
975,000
32.9
-
32.9
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\n
At the 2024 AGM, the Board of Directors was
\u00a0
given the authority to acquire treasury shares with
\u00a0
a total nominal value of up to NOK
24,375,000 which corresponds to 97,500,000 new shares.
\u00a0
The maximum amount to be paid per share
\u00a0
is NOK 100 and the minimum
amount is NOK 1. The authorization is time-limited until
\u00a0
the 2025 AGM, and not beyond 30 June 2025.
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital by
\u00a0
up to NOK 24,375.000 which
corresponds to 97,500,000 shares. The authorization is
\u00a0
time-limited until the 2025 AGM, and not beyond
\u00a0
30 June 2025.
\u00a0
In addition, the Board of Directors was given the authority
\u00a0
to raise convertible bonds with an aggregate
\u00a0
principal amount of up to USD
300,000,000. Upon conversion of bonds issued pursuant
\u00a0
to this authorization, the Company\u2019s share capital may be
\u00a0
increased by up to
NOK 24,375.000.
\u00a0
The authorization is valid until the 2025 AGM, but
\u00a0
not beyond 30 June 2025.
\u00a0
The Board of Directors was given the authority
\u00a0
to approve total dividend distributions from the date
\u00a0
of the 2024 AGM until the date of the
2025 AGM. Following this, the Board of Directors decided
\u00a0
to distribute quarterly dividends, NOK 0.25 per
\u00a0
share in February and May
and dividends of NOK 0.3125 per share in August and
\u00a0
November 2024.
Interest
The Company's shareholders as of 31 December 2024
Shares
(percent)
Goldman Sachs & Co. LLC
92,535,456
9.49
Folketrygdfondet
71,148,737
7.30
Clearstream Banking S.A.
63,878,853
6.55
BNP Paribas
42,956,895
4.41
RAK Gas LLC
34,311,403
3.52
Goldman Sachs & Co. LLC
33,147,785
3.40
Euroclear Bank S.A./N.V.
28,433,212
2.92
The Bank of New York Mellon
25,116,930
2.58
UBS Switzerland AG
19,583,592
2.01
JPMorgan Chase Bank, N.A., London
18,807,514
1.93
State Street Bank and Trust Comp
18,045,289
1.85
Nordnet Bank AB
12,321,500
1.26
State Street Bank and Trust Comp
10,890,560
1.12
Salt Value AS
10,660,968
1.09
Verdipapirfondet KLP Aksjenorge IN
10,035,479
1.03
Caceis Bank
8,696,391
0.89
Avanza Bank AB
7,887,883
0.81
Goldman Sachs & Co. LLC
7,678,701
0.79
Verdipapirfondet Storebrand Indeks
7,611,789
0.78
Verdipapirfondet DNB Norge Indeks
7,481,659
0.77
Other shareholders
443,769,404
45.51
Total number of shares excluding treasury shares
975,000,000
100.00
Treasury shares as of 31 December 2024 (DNO ASA)
0.00
0.00
Total number of outstanding shares
975,000,000
100.00
* At yearend 2024, DNO's Executive Chairman Bijan Mossavar
\u00a0
-Rahmani held interests in the Company through nominee
\u00a0
accounts at the
\u00a0
\u00a0
Goldman Sachs & Co. LLC, representing 12.89 percent
\u00a0
of the total number of outstanding shares.
Dividends of USD 101.9 million were paid in 2024
\u00a0
(USD 92.0 million in 2023). See Note 29
\u00a0
for dividend payment approved by the Board
after the reporting date. See Note 5 for shares held
\u00a0
by the Board of Directors and the senior management.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_91": { "value": "
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\n
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2023
1,018,008
34.8
-0.9
33.9
Treasury shares purchased
-43,007
-
-1.0
-1.0
As of 31 December 2023
975,000
32.9
-
32.9
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2024
975,000
32.9
-
32.9
Treasury shares purchased
-
-
-
-
As of 31 December 2024
975,000
32.9
-
32.9
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\u00a0
\n
At the 2024 AGM, the Board of Directors was
\u00a0
given the authority to acquire treasury shares with
\u00a0
a total nominal value of up to NOK
24,375,000 which corresponds to 97,500,000 new shares.
\u00a0
The maximum amount to be paid per share
\u00a0
is NOK 100 and the minimum
amount is NOK 1. The authorization is time-limited until
\u00a0
the 2025 AGM, and not beyond 30 June 2025.
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital by
\u00a0
up to NOK 24,375.000 which
corresponds to 97,500,000 shares. The authorization is
\u00a0
time-limited until the 2025 AGM, and not beyond
\u00a0
30 June 2025.
\u00a0
In addition, the Board of Directors was given the authority
\u00a0
to raise convertible bonds with an aggregate
\u00a0
principal amount of up to USD
300,000,000. Upon conversion of bonds issued pursuant
\u00a0
to this authorization, the Company\u2019s share capital may be
\u00a0
increased by up to
NOK 24,375.000.
\u00a0
The authorization is valid until the 2025 AGM, but
\u00a0
not beyond 30 June 2025.
\u00a0
The Board of Directors was given the authority
\u00a0
to approve total dividend distributions from the date
\u00a0
of the 2024 AGM until the date of the
2025 AGM. Following this, the Board of Directors decided
\u00a0
to distribute quarterly dividends, NOK 0.25 per
\u00a0
share in February and May
and dividends of NOK 0.3125 per share in August and
\u00a0
November 2024.
Interest
The Company's shareholders as of 31 December 2024
Shares
(percent)
Goldman Sachs & Co. LLC
92,535,456
9.49
Folketrygdfondet
71,148,737
7.30
Clearstream Banking S.A.
63,878,853
6.55
BNP Paribas
42,956,895
4.41
RAK Gas LLC
34,311,403
3.52
Goldman Sachs & Co. LLC
33,147,785
3.40
Euroclear Bank S.A./N.V.
28,433,212
2.92
The Bank of New York Mellon
25,116,930
2.58
UBS Switzerland AG
19,583,592
2.01
JPMorgan Chase Bank, N.A., London
18,807,514
1.93
State Street Bank and Trust Comp
18,045,289
1.85
Nordnet Bank AB
12,321,500
1.26
State Street Bank and Trust Comp
10,890,560
1.12
Salt Value AS
10,660,968
1.09
Verdipapirfondet KLP Aksjenorge IN
10,035,479
1.03
Caceis Bank
8,696,391
0.89
Avanza Bank AB
7,887,883
0.81
Goldman Sachs & Co. LLC
7,678,701
0.79
Verdipapirfondet Storebrand Indeks
7,611,789
0.78
Verdipapirfondet DNB Norge Indeks
7,481,659
0.77
Other shareholders
443,769,404
45.51
Total number of shares excluding treasury shares
975,000,000
100.00
Treasury shares as of 31 December 2024 (DNO ASA)
0.00
0.00
Total number of outstanding shares
975,000,000
100.00
* At yearend 2024, DNO's Executive Chairman Bijan Mossavar
\u00a0
-Rahmani held interests in the Company through nominee
\u00a0
accounts at the
\u00a0
\u00a0
Goldman Sachs & Co. LLC, representing 12.89 percent
\u00a0
of the total number of outstanding shares.
Dividends of USD 101.9 million were paid in 2024
\u00a0
(USD 92.0 million in 2023). See Note 29
\u00a0
for dividend payment approved by the Board
after the reporting date. See Note 5 for shares held
\u00a0
by the Board of Directors and the senior management.
", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_92": { "value": "
Note 18
Interest-bearing liabilities
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\n
\u00a0
\n
Accounting policies
Interest-bearing liabilities
At initial recognition, the bonds are measured at
\u00a0
its fair value minus transaction costs that are directly
\u00a0
attributable to the issue of the
financial liability. Subsequently, bonds are measured at amortized cost.
Transaction costs directly attributable to the acquisition, issuance, or
\u00a0
restructuring of financial liabilities, are amortized over
\u00a0
the
expected life of the liability using the effective interest rate
\u00a0
method. Amortization is recognized in the income
\u00a0
statement, ensuring a
systematic and rational allocation of these costs over
\u00a0
the period during which the liability is outstanding.
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Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
rate
\u00a0
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2024
2023
2024
2023
Non-current
Bond loan (ISIN NO0011088593)
DNO04
USD
350.0
7.875
09.09.26
8.8
352.4
378.1
350.0
400.0
Bond loan (ISIN NO0013243766)
DNO05
USD
400.0
9.250
04.06.29
10.0
410.0
-
400.0
-
Capitalized borrowing issue costs
-9.5
-8.0
Reserve based lending facility
-
USD
230.0
see below
see below
-
50.0
-
50.0
-
Total non-current interest-bearing liabilities
812.4
378.1
790.5
392.0
Current
Bond loan (ISIN NO0010852643)
DNO03
USD
131.2
8.375
29.05.24
9.0
-
130.9
-
131.2
Reserve based lending facility (current)
-
USD
230.0
see below
see below
-
-
35.0
-
35.0
Total current interest-bearing liabilities
-
165.9
-
166.2
Total interest-bearing liabilities
812.4
544.0
790.5
558.2
Facility and carrying amount for the bonds is
\u00a0
presented net of bonds held by the Company.
\u00a0
On 22 January 2024, DNO ASA fully completed a
\u00a0
USD 131.2 million call option redemption of
\u00a0
the DNO03 bond at a price of 100 percent
plus accrued interest.
\u00a0
On 4 June 2024, DNO ASA completed the placement
\u00a0
of a new USD 400 million, five-year senior
\u00a0
unsecured bond issued at 100 percent
at par with a coupon rate of 9.25 percent.
\u00a0
In connection with the bond placement, the
\u00a0
Company agreed to buy back USD 50 million
\u00a0
in
nominal value of DNO04 at par plus accrued interest.
\u00a0
The financial covenants of the bonds issued by
\u00a0
DNO ASA require minimum USD
40 million of liquidity, and that the Group maintains either an equity
\u00a0
ratio of 30 percent or a total equity
\u00a0
of a minimum of USD 600 million.
There is also a restriction on declaring
\u00a0
or making any dividend payments if the liquidity
\u00a0
of the Company is less than USD 80 million
immediately following such distribution.
As of 31 December 2024, the Group has a
\u00a0
reserve-based lending (RBL) facility for its Norway
\u00a0
and UK production licenses with a total
facility limit of USD 230 million which is available
\u00a0
for both debt and issuance of letters of
\u00a0
credit. Interest charged on utilizations is based
on SOFR plus a margin, currently 3.50 percent. The
\u00a0
facility will amortize over the loan life with
\u00a0
a final maturity date of 7 November 2026.
The entities that participate in the facility are
\u00a0
required to submit quarterly a liquidity test
\u00a0
and maintain a consolidated net debt divided by
EBITDAX ratio of maximum 3.50. The security under
\u00a0
the RBL includes, without limitation, a pledge
\u00a0
over the shares in DNO North Sea
plc and its subsidiaries, assignment of claims under
\u00a0
shareholder loans, intra-group loans and insurances,
\u00a0
a pledge of certain bank
accounts and mortgages over the license interests.
\u00a0
There are also restrictions on loans and dividend
\u00a0
payments to DNO ASA. The
borrowing base amount of the facility from 1
\u00a0
January 2025 is USD 150 million. Amount utilized
\u00a0
as of the reporting date is disclosed in
the table above. In addition, USD 18.6 million is
\u00a0
utilized in respect of letters of credit.
\u00a0
There have been no breaches of the financial
\u00a0
covenants of any interest-bearing liability in the
\u00a0
current period.
\u00a0
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\u00a0
\n
Changes in liabilities arising from financing activities
\u00a0
split on cash and non-cash changes
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2024
flows
Amortization
Currency
Acquisition
Reclass
2024
Bond loans (non-current)
400.0
350.0
-
-
-
-
750.0
Bond loans (current)
131.2
-131.2
-
-
-
-
-
Borrowing issue costs
-8.0
-5.6
4.1
-
-
-
-9.5
Reserve based lending facility (non-current)
-
15.0
-
-
-
35.0
50.0
Reserve based lending facility (current)
35.0
-
-
-
-
-35.0
-
Total
558.2
228.2
4.1
-
-
-
790.5
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2023
flows
Amortization
Currency
Acquisition
Reclass
2023
Bond loans (non-current)
531.2
-
-
-
-
-131.2
400.0
Bond loans (current)
-
-
-
-
-
131.2
131.2
Borrowing issue costs
-11.3
-
3.3
-
-
-
-8.0
Reserve based lending facility (non-current)
26.6
-
-
-
-
-26.6
-
Reserve based lending facility (current)
8.4
-
-
-
-
26.6
35.0
Total
554.8
-
3.3
-
-
-
558.2
Note 20
Asset retirement obligations
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Provisions for asset retirement obligations (ARO)
Provisions for ARO are initially recognized at the
\u00a0
present value of the estimated future costs
\u00a0
determined in accordance with local
conditions and requirements. A corresponding asset of
\u00a0
an amount equivalent to the ARO provision
\u00a0
is also recognized initially and is
presented as part of the PP&E. The retirement
\u00a0
asset is subsequently depreciated as part of
\u00a0
the development and production asset it
relates to.
The ARO provisions and the discount rates are reviewed
\u00a0
at each balance sheet date. The discount rates
\u00a0
used in the calculation of
the present value of the ARO are pre-tax risk-free
\u00a0
rates with the addition of a credit margin. The
\u00a0
risk-free rate used has a maturity
date that is expected to coincide with the time
\u00a0
the removal will be affected and denominated
\u00a0
in the same currency as the expected
future expenditures. According to IFRIC 1
Changes in Existing Decommissioning, Restoration
\u00a0
and Similar Liabilities
, changes in the
measurement of the ARO resulting from a
\u00a0
change in the timing or amount of the outflow of
\u00a0
resources embodying economic benefits
required to settle the obligation, or a change
\u00a0
in the discount rate, are added to or deducted
\u00a0
from the cost of the related asset.
Changes in the estimated ARO provisions impact
\u00a0
the retirement asset in the period in which the
\u00a0
estimate is revised.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Estimation of the cost for
\u00a0
decommissioning
Estimation of the costs for decommissioning is complex
\u00a0
and requires judgement as these estimates
\u00a0
are based on currently
applicable laws, regulations and technology. Decommissioning activities will normally
\u00a0
take place in the distant future, and the
technology, regulatory requirements and related costs may change. The energy transition
\u00a0
may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated decommissioning provisions. Based
\u00a0
on various scenario analysis
performed by the Company, management does not expect any reasonable
\u00a0
change in the expected timeframe to have a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost estimates (i.e., cash flows) remain unchanged.
\u00a0
The estimates
cover expected removal concepts based on known technology
\u00a0
and, in the case of offshore decommissioning, estimated
\u00a0
costs of
maritime operations, hiring of heavy-lift barges and
\u00a0
drilling rigs. As a result, the initial recognition
\u00a0
of the liability and the capitalized
cost associated with decommissioning obligations,
\u00a0
and the subsequent adjustment of these balance
\u00a0
sheet items, involve the
application of significant judgement. Based on
\u00a0
the described uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Asset retirement obligations (ARO)
The provisions for ARO are based on the present
\u00a0
value of estimated future cost of decommissioning oil
\u00a0
and gas assets in Kurdistan and
the North Sea. The discount rates before tax applied
\u00a0
at yearend 2024 were between 5.1 percent
\u00a0
and 5.3 percent (yearend 2023:
between 4.9 percent and 5.0 percent). The credit
\u00a0
risk element included in the discount rates
\u00a0
at yearend 2024 was 0.8 percent (yearend
2023: 0.8 percent).
Credit risk discussion
The Company note that IASB in relation to its
\u00a0
project \u201cProvisions \u2013 Targeted Improvements\u201d, based on a staff paper recommendation,
have tentatively proposed to specify the use of
\u00a0
a discount rate reflecting the time value
\u00a0
of money, based on a risk-free rate without
adjustments for credit risk element (non-performance
\u00a0
risk). However, considering that no new requirements in the standard
\u00a0
have been
concluded, the Company deems it reasonable not
\u00a0
to change its method for determining the discount
\u00a0
rate. The Company has compared
its discount rate towards peers and noted that they
\u00a0
are within a range applied by other peer
\u00a0
companies.
\u00a0
Years ended 31 December
USD million
2024
2023
Non-current asset retirement obligations (ARO)
467.9
382.7
Current asset retirement obligations (ARO)
12.9
10.6
Total asset retirement obligations (ARO)
480.8
393.2
Years ended 31 December
USD million
2024
2023
Asset retirement obligation as of 1 January
393.2
388.6
ARO provisions from business combinations
83.0
-
ARO provisions divested assets
-2.9
-
Decommissioning spend
-4.9
-17.9
Increase/decrease in existing/new provisions
-1.6
10.5
Effects of change in the discount rate
-6.4
-5.4
Accretion expenses (unwinding of discount)
20.4
17.4
Asset retirement obligation as of 31 December
480.8
393.2
Note 21
Other liabilities
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
Provisions for other liabilities
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as a
\u00a0
result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
The provisions are reviewed at each balance
\u00a0
sheet date and adjusted to reflect the current best estimate.
\u00a0
\n
\u00a0
\n
Estimation uncertainty
The assessment of the existence and potential quantum
\u00a0
of contingencies inherently involves the exercise
\u00a0
of significant judgment and
the use of estimates regarding the outcome of
\u00a0
future events. Management uses its judgment, and
\u00a0
if necessary also external legal
experts to evaluate certain provisions and legal
\u00a0
disputes in order to ensure the correct accounting
\u00a0
treatment.
\u00a0
Years ended 31 December
USD million
2024
2023
Non-current
Other long-term obligations
6.9
7.3
Total non-current other liabilities
6.9
7.3
Current
Accrued interest expense
4.4
2.8
Other provisions and charges
9.8
6.4
Total current other liabilities
14.2
9.1
Total other liabilities
21.1
16.5
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_93": { "value": "
Note 18
Interest-bearing liabilities
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Interest-bearing liabilities
At initial recognition, the bonds are measured at
\u00a0
its fair value minus transaction costs that are directly
\u00a0
attributable to the issue of the
financial liability. Subsequently, bonds are measured at amortized cost.
Transaction costs directly attributable to the acquisition, issuance, or
\u00a0
restructuring of financial liabilities, are amortized over
\u00a0
the
expected life of the liability using the effective interest rate
\u00a0
method. Amortization is recognized in the income
\u00a0
statement, ensuring a
systematic and rational allocation of these costs over
\u00a0
the period during which the liability is outstanding.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
rate
\u00a0
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2024
2023
2024
2023
Non-current
Bond loan (ISIN NO0011088593)
DNO04
USD
350.0
7.875
09.09.26
8.8
352.4
378.1
350.0
400.0
Bond loan (ISIN NO0013243766)
DNO05
USD
400.0
9.250
04.06.29
10.0
410.0
-
400.0
-
Capitalized borrowing issue costs
-9.5
-8.0
Reserve based lending facility
-
USD
230.0
see below
see below
-
50.0
-
50.0
-
Total non-current interest-bearing liabilities
812.4
378.1
790.5
392.0
Current
Bond loan (ISIN NO0010852643)
DNO03
USD
131.2
8.375
29.05.24
9.0
-
130.9
-
131.2
Reserve based lending facility (current)
-
USD
230.0
see below
see below
-
-
35.0
-
35.0
Total current interest-bearing liabilities
-
165.9
-
166.2
Total interest-bearing liabilities
812.4
544.0
790.5
558.2
Facility and carrying amount for the bonds is
\u00a0
presented net of bonds held by the Company.
\u00a0
On 22 January 2024, DNO ASA fully completed a
\u00a0
USD 131.2 million call option redemption of
\u00a0
the DNO03 bond at a price of 100 percent
plus accrued interest.
\u00a0
On 4 June 2024, DNO ASA completed the placement
\u00a0
of a new USD 400 million, five-year senior
\u00a0
unsecured bond issued at 100 percent
at par with a coupon rate of 9.25 percent.
\u00a0
In connection with the bond placement, the
\u00a0
Company agreed to buy back USD 50 million
\u00a0
in
nominal value of DNO04 at par plus accrued interest.
\u00a0
The financial covenants of the bonds issued by
\u00a0
DNO ASA require minimum USD
40 million of liquidity, and that the Group maintains either an equity
\u00a0
ratio of 30 percent or a total equity
\u00a0
of a minimum of USD 600 million.
There is also a restriction on declaring
\u00a0
or making any dividend payments if the liquidity
\u00a0
of the Company is less than USD 80 million
immediately following such distribution.
As of 31 December 2024, the Group has a
\u00a0
reserve-based lending (RBL) facility for its Norway
\u00a0
and UK production licenses with a total
facility limit of USD 230 million which is available
\u00a0
for both debt and issuance of letters of
\u00a0
credit. Interest charged on utilizations is based
on SOFR plus a margin, currently 3.50 percent. The
\u00a0
facility will amortize over the loan life with
\u00a0
a final maturity date of 7 November 2026.
The entities that participate in the facility are
\u00a0
required to submit quarterly a liquidity test
\u00a0
and maintain a consolidated net debt divided by
EBITDAX ratio of maximum 3.50. The security under
\u00a0
the RBL includes, without limitation, a pledge
\u00a0
over the shares in DNO North Sea
plc and its subsidiaries, assignment of claims under
\u00a0
shareholder loans, intra-group loans and insurances,
\u00a0
a pledge of certain bank
accounts and mortgages over the license interests.
\u00a0
There are also restrictions on loans and dividend
\u00a0
payments to DNO ASA. The
borrowing base amount of the facility from 1
\u00a0
January 2025 is USD 150 million. Amount utilized
\u00a0
as of the reporting date is disclosed in
the table above. In addition, USD 18.6 million is
\u00a0
utilized in respect of letters of credit.
\u00a0
There have been no breaches of the financial
\u00a0
covenants of any interest-bearing liability in the
\u00a0
current period.
\u00a0
\n
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\n
\u00a0
\n
\u00a0
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\n
\u00a0
\n
Changes in liabilities arising from financing activities
\u00a0
split on cash and non-cash changes
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2024
flows
Amortization
Currency
Acquisition
Reclass
2024
Bond loans (non-current)
400.0
350.0
-
-
-
-
750.0
Bond loans (current)
131.2
-131.2
-
-
-
-
-
Borrowing issue costs
-8.0
-5.6
4.1
-
-
-
-9.5
Reserve based lending facility (non-current)
-
15.0
-
-
-
35.0
50.0
Reserve based lending facility (current)
35.0
-
-
-
-
-35.0
-
Total
558.2
228.2
4.1
-
-
-
790.5
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2023
flows
Amortization
Currency
Acquisition
Reclass
2023
Bond loans (non-current)
531.2
-
-
-
-
-131.2
400.0
Bond loans (current)
-
-
-
-
-
131.2
131.2
Borrowing issue costs
-11.3
-
3.3
-
-
-
-8.0
Reserve based lending facility (non-current)
26.6
-
-
-
-
-26.6
-
Reserve based lending facility (current)
8.4
-
-
-
-
26.6
35.0
Total
554.8
-
3.3
-
-
-
558.2
", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_94": { "value": "
Note 18
Interest-bearing liabilities
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\n
Accounting policies
Interest-bearing liabilities
At initial recognition, the bonds are measured at
\u00a0
its fair value minus transaction costs that are directly
\u00a0
attributable to the issue of the
financial liability. Subsequently, bonds are measured at amortized cost.
Transaction costs directly attributable to the acquisition, issuance, or
\u00a0
restructuring of financial liabilities, are amortized over
\u00a0
the
expected life of the liability using the effective interest rate
\u00a0
method. Amortization is recognized in the income
\u00a0
statement, ensuring a
systematic and rational allocation of these costs over
\u00a0
the period during which the liability is outstanding.
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\n
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
rate
\u00a0
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2024
2023
2024
2023
Non-current
Bond loan (ISIN NO0011088593)
DNO04
USD
350.0
7.875
09.09.26
8.8
352.4
378.1
350.0
400.0
Bond loan (ISIN NO0013243766)
DNO05
USD
400.0
9.250
04.06.29
10.0
410.0
-
400.0
-
Capitalized borrowing issue costs
-9.5
-8.0
Reserve based lending facility
-
USD
230.0
see below
see below
-
50.0
-
50.0
-
Total non-current interest-bearing liabilities
812.4
378.1
790.5
392.0
Current
Bond loan (ISIN NO0010852643)
DNO03
USD
131.2
8.375
29.05.24
9.0
-
130.9
-
131.2
Reserve based lending facility (current)
-
USD
230.0
see below
see below
-
-
35.0
-
35.0
Total current interest-bearing liabilities
-
165.9
-
166.2
Total interest-bearing liabilities
812.4
544.0
790.5
558.2
Facility and carrying amount for the bonds is
\u00a0
presented net of bonds held by the Company.
\u00a0
On 22 January 2024, DNO ASA fully completed a
\u00a0
USD 131.2 million call option redemption of
\u00a0
the DNO03 bond at a price of 100 percent
plus accrued interest.
\u00a0
On 4 June 2024, DNO ASA completed the placement
\u00a0
of a new USD 400 million, five-year senior
\u00a0
unsecured bond issued at 100 percent
at par with a coupon rate of 9.25 percent.
\u00a0
In connection with the bond placement, the
\u00a0
Company agreed to buy back USD 50 million
\u00a0
in
nominal value of DNO04 at par plus accrued interest.
\u00a0
The financial covenants of the bonds issued by
\u00a0
DNO ASA require minimum USD
40 million of liquidity, and that the Group maintains either an equity
\u00a0
ratio of 30 percent or a total equity
\u00a0
of a minimum of USD 600 million.
There is also a restriction on declaring
\u00a0
or making any dividend payments if the liquidity
\u00a0
of the Company is less than USD 80 million
immediately following such distribution.
As of 31 December 2024, the Group has a
\u00a0
reserve-based lending (RBL) facility for its Norway
\u00a0
and UK production licenses with a total
facility limit of USD 230 million which is available
\u00a0
for both debt and issuance of letters of
\u00a0
credit. Interest charged on utilizations is based
on SOFR plus a margin, currently 3.50 percent. The
\u00a0
facility will amortize over the loan life with
\u00a0
a final maturity date of 7 November 2026.
The entities that participate in the facility are
\u00a0
required to submit quarterly a liquidity test
\u00a0
and maintain a consolidated net debt divided by
EBITDAX ratio of maximum 3.50. The security under
\u00a0
the RBL includes, without limitation, a pledge
\u00a0
over the shares in DNO North Sea
plc and its subsidiaries, assignment of claims under
\u00a0
shareholder loans, intra-group loans and insurances,
\u00a0
a pledge of certain bank
accounts and mortgages over the license interests.
\u00a0
There are also restrictions on loans and dividend
\u00a0
payments to DNO ASA. The
borrowing base amount of the facility from 1
\u00a0
January 2025 is USD 150 million. Amount utilized
\u00a0
as of the reporting date is disclosed in
the table above. In addition, USD 18.6 million is
\u00a0
utilized in respect of letters of credit.
\u00a0
There have been no breaches of the financial
\u00a0
covenants of any interest-bearing liability in the
\u00a0
current period.
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\u00a0
\n
Changes in liabilities arising from financing activities
\u00a0
split on cash and non-cash changes
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2024
flows
Amortization
Currency
Acquisition
Reclass
2024
Bond loans (non-current)
400.0
350.0
-
-
-
-
750.0
Bond loans (current)
131.2
-131.2
-
-
-
-
-
Borrowing issue costs
-8.0
-5.6
4.1
-
-
-
-9.5
Reserve based lending facility (non-current)
-
15.0
-
-
-
35.0
50.0
Reserve based lending facility (current)
35.0
-
-
-
-
-35.0
-
Total
558.2
228.2
4.1
-
-
-
790.5
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2023
flows
Amortization
Currency
Acquisition
Reclass
2023
Bond loans (non-current)
531.2
-
-
-
-
-131.2
400.0
Bond loans (current)
-
-
-
-
-
131.2
131.2
Borrowing issue costs
-11.3
-
3.3
-
-
-
-8.0
Reserve based lending facility (non-current)
26.6
-
-
-
-
-26.6
-
Reserve based lending facility (current)
8.4
-
-
-
-
26.6
35.0
Total
554.8
-
3.3
-
-
-
558.2
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\n
Asset retirement obligations (ARO)
The provisions for ARO are based on the present
\u00a0
value of estimated future cost of decommissioning oil
\u00a0
and gas assets in Kurdistan and
the North Sea. The discount rates before tax applied
\u00a0
at yearend 2024 were between 5.1 percent
\u00a0
and 5.3 percent (yearend 2023:
between 4.9 percent and 5.0 percent). The credit
\u00a0
risk element included in the discount rates
\u00a0
at yearend 2024 was 0.8 percent (yearend
2023: 0.8 percent).
Credit risk discussion
The Company note that IASB in relation to its
\u00a0
project \u201cProvisions \u2013 Targeted Improvements\u201d, based on a staff paper recommendation,
have tentatively proposed to specify the use of
\u00a0
a discount rate reflecting the time value
\u00a0
of money, based on a risk-free rate without
adjustments for credit risk element (non-performance
\u00a0
risk). However, considering that no new requirements in the standard
\u00a0
have been
concluded, the Company deems it reasonable not
\u00a0
to change its method for determining the discount
\u00a0
rate. The Company has compared
its discount rate towards peers and noted that they
\u00a0
are within a range applied by other peer
\u00a0
companies.
\u00a0
Years ended 31 December
USD million
2024
2023
Non-current asset retirement obligations (ARO)
467.9
382.7
Current asset retirement obligations (ARO)
12.9
10.6
Total asset retirement obligations (ARO)
480.8
393.2
Years ended 31 December
USD million
2024
2023
Asset retirement obligation as of 1 January
393.2
388.6
ARO provisions from business combinations
83.0
-
ARO provisions divested assets
-2.9
-
Decommissioning spend
-4.9
-17.9
Increase/decrease in existing/new provisions
-1.6
10.5
Effects of change in the discount rate
-6.4
-5.4
Accretion expenses (unwinding of discount)
20.4
17.4
Asset retirement obligation as of 31 December
480.8
393.2
Note 21
Other liabilities
\u00a0
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\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
Provisions for other liabilities
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as a
\u00a0
result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
The provisions are reviewed at each balance
\u00a0
sheet date and adjusted to reflect the current best estimate.
\u00a0
\n
\u00a0
\n
Estimation uncertainty
The assessment of the existence and potential quantum
\u00a0
of contingencies inherently involves the exercise
\u00a0
of significant judgment and
the use of estimates regarding the outcome of
\u00a0
future events. Management uses its judgment, and
\u00a0
if necessary also external legal
experts to evaluate certain provisions and legal
\u00a0
disputes in order to ensure the correct accounting
\u00a0
treatment.
\u00a0
Years ended 31 December
USD million
2024
2023
Non-current
Other long-term obligations
6.9
7.3
Total non-current other liabilities
6.9
7.3
Current
Accrued interest expense
4.4
2.8
Other provisions and charges
9.8
6.4
Total current other liabilities
14.2
9.1
Total other liabilities
21.1
16.5
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_95": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Interest-bearing liabilities
At initial recognition, the bonds are measured at
\u00a0
its fair value minus transaction costs that are directly
\u00a0
attributable to the issue of the
financial liability. Subsequently, bonds are measured at amortized cost.
Transaction costs directly attributable to the acquisition, issuance, or
\u00a0
restructuring of financial liabilities, are amortized over
\u00a0
the
expected life of the liability using the effective interest rate
\u00a0
method. Amortization is recognized in the income
\u00a0
statement, ensuring a
systematic and rational allocation of these costs over
\u00a0
the period during which the liability is outstanding.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_96": { "value": "
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Interest-bearing liabilities
At initial recognition, the bonds are measured at
\u00a0
its fair value minus transaction costs that are directly
\u00a0
attributable to the issue of the
financial liability. Subsequently, bonds are measured at amortized cost.
Transaction costs directly attributable to the acquisition, issuance, or
\u00a0
restructuring of financial liabilities, are amortized over
\u00a0
the
expected life of the liability using the effective interest rate
\u00a0
method. Amortization is recognized in the income
\u00a0
statement, ensuring a
systematic and rational allocation of these costs over
\u00a0
the period during which the liability is outstanding.
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Financial liabilities
The Group\u2019s financial liabilities include trade and other payables
\u00a0
and loans.
\u00a0
Interest-bearing loans are after initial recognition
\u00a0
measured at amortized cost using the effective interest
\u00a0
rate method. Gains and
losses are recognized in profit or loss when
\u00a0
the liabilities are derecognized as well as
\u00a0
through the amortization process. Amortized
cost is calculated by taking into account any discount
\u00a0
or premium on acquisition and fees or costs
\u00a0
that are an integral part of the
effective interest rate. The amortization cost is included
\u00a0
as finance expense in the statements of comprehensive
\u00a0
income. This applies
mainly to bond loans, see Note 18.
\u00a0
A financial liability is derecognized when the obligation
\u00a0
under the liability is discharged, cancelled or expires.
\u00a0
When an existing
financial liability is replaced by another from the
\u00a0
same lender on substantially different terms, or the
\u00a0
terms of an existing liability are
substantially modified, such a modification is treated
\u00a0
as a derecognition of the original liability and
\u00a0
a recognition of a new liability. The
difference in the respective carrying amounts is recognized
\u00a0
in the statements of comprehensive income.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_97": { "value": "
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\n
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
rate
\u00a0
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2024
2023
2024
2023
Non-current
Bond loan (ISIN NO0011088593)
DNO04
USD
350.0
7.875
09.09.26
8.8
352.4
378.1
350.0
400.0
Bond loan (ISIN NO0013243766)
DNO05
USD
400.0
9.250
04.06.29
10.0
410.0
-
400.0
-
Capitalized borrowing issue costs
-9.5
-8.0
Reserve based lending facility
-
USD
230.0
see below
see below
-
50.0
-
50.0
-
Total non-current interest-bearing liabilities
812.4
378.1
790.5
392.0
Current
Bond loan (ISIN NO0010852643)
DNO03
USD
131.2
8.375
29.05.24
9.0
-
130.9
-
131.2
Reserve based lending facility (current)
-
USD
230.0
see below
see below
-
-
35.0
-
35.0
Total current interest-bearing liabilities
-
165.9
-
166.2
Total interest-bearing liabilities
812.4
544.0
790.5
558.2
Facility and carrying amount for the bonds is
\u00a0
presented net of bonds held by the Company.
\u00a0
On 22 January 2024, DNO ASA fully completed a
\u00a0
USD 131.2 million call option redemption of
\u00a0
the DNO03 bond at a price of 100 percent
plus accrued interest.
\u00a0
On 4 June 2024, DNO ASA completed the placement
\u00a0
of a new USD 400 million, five-year senior
\u00a0
unsecured bond issued at 100 percent
at par with a coupon rate of 9.25 percent.
\u00a0
In connection with the bond placement, the
\u00a0
Company agreed to buy back USD 50 million
\u00a0
in
nominal value of DNO04 at par plus accrued interest.
\u00a0
The financial covenants of the bonds issued by
\u00a0
DNO ASA require minimum USD
40 million of liquidity, and that the Group maintains either an equity
\u00a0
ratio of 30 percent or a total equity
\u00a0
of a minimum of USD 600 million.
There is also a restriction on declaring
\u00a0
or making any dividend payments if the liquidity
\u00a0
of the Company is less than USD 80 million
immediately following such distribution.
As of 31 December 2024, the Group has a
\u00a0
reserve-based lending (RBL) facility for its Norway
\u00a0
and UK production licenses with a total
facility limit of USD 230 million which is available
\u00a0
for both debt and issuance of letters of
\u00a0
credit. Interest charged on utilizations is based
on SOFR plus a margin, currently 3.50 percent. The
\u00a0
facility will amortize over the loan life with
\u00a0
a final maturity date of 7 November 2026.
The entities that participate in the facility are
\u00a0
required to submit quarterly a liquidity test
\u00a0
and maintain a consolidated net debt divided by
EBITDAX ratio of maximum 3.50. The security under
\u00a0
the RBL includes, without limitation, a pledge
\u00a0
over the shares in DNO North Sea
plc and its subsidiaries, assignment of claims under
\u00a0
shareholder loans, intra-group loans and insurances,
\u00a0
a pledge of certain bank
accounts and mortgages over the license interests.
\u00a0
There are also restrictions on loans and dividend
\u00a0
payments to DNO ASA. The
borrowing base amount of the facility from 1
\u00a0
January 2025 is USD 150 million. Amount utilized
\u00a0
as of the reporting date is disclosed in
the table above. In addition, USD 18.6 million is
\u00a0
utilized in respect of letters of credit.
\u00a0
There have been no breaches of the financial
\u00a0
covenants of any interest-bearing liability in the
\u00a0
current period.
\u00a0
\n
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\u00a0
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\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\n
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\u00a0
\n
\u00a0
\n
Changes in liabilities arising from financing activities
\u00a0
split on cash and non-cash changes
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2024
flows
Amortization
Currency
Acquisition
Reclass
2024
Bond loans (non-current)
400.0
350.0
-
-
-
-
750.0
Bond loans (current)
131.2
-131.2
-
-
-
-
-
Borrowing issue costs
-8.0
-5.6
4.1
-
-
-
-9.5
Reserve based lending facility (non-current)
-
15.0
-
-
-
35.0
50.0
Reserve based lending facility (current)
35.0
-
-
-
-
-35.0
-
Total
558.2
228.2
4.1
-
-
-
790.5
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2023
flows
Amortization
Currency
Acquisition
Reclass
2023
Bond loans (non-current)
531.2
-
-
-
-
-131.2
400.0
Bond loans (current)
-
-
-
-
-
131.2
131.2
Borrowing issue costs
-11.3
-
3.3
-
-
-
-8.0
Reserve based lending facility (non-current)
26.6
-
-
-
-
-26.6
-
Reserve based lending facility (current)
8.4
-
-
-
-
26.6
35.0
Total
554.8
-
3.3
-
-
-
558.2
", "dimensions": { "concept": "ifrs-full:DisclosureOfDebtSecuritiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_98": { "value": "
Note 19
Lease liabilities
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Lease liabilities
The Group assesses at contract inception whether
\u00a0
a contract is, or contains, a lease. The Group
\u00a0
applies a single recognition and
measurement approach for all leases, except for
\u00a0
short-term leases (12 months or less) and leases
\u00a0
of low-value assets. Short term
leases and leases of low value assets have not
\u00a0
been reflected in the balance sheet but expensed
\u00a0
or capitalized as incurred,
depending on the activity in which the leased asset
\u00a0
is used.
Lease liabilities are measured at the present value
\u00a0
of lease payments to be made over the lease
\u00a0
term. In calculating the present
value of lease payments, the Group uses
\u00a0
the implicit interest rate and if not readily determinable,
\u00a0
its incremental borrowing rate at
the lease commencement date. Extension options
\u00a0
are included in the lease liability when, based
\u00a0
on the management\u2019s judgement, it
is reasonably certain that an extension will be exercised.
In the consolidated cash flow, lease payments related to lease liabilities recognized
\u00a0
in accordance with IFRS 16, are presented as
cash flow used in financing activities.
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Years ended 31 December
USD million
2024
2023
Non-current lease liabilities
9.7
14.0
Current lease liabilities
3.1
3.6
Total lease liabilities
12.7
17.5
The recognized lease liabilities in the balance sheet
\u00a0
are mainly related to office rent.
The identified lease liabilities have no significant
\u00a0
impact on the Group\u2019s financing, loan covenants or dividend
\u00a0
policy. The Group does
not have any residual value guarantees. Lease payments
\u00a0
related to short-term leases and leases of
\u00a0
low-value assets are mainly
recognized under lifting costs and exploration costs, or
\u00a0
tangible assets and capitalized exploration. Total lease payments related to
short-term leases and low-value assets were USD
\u00a0
58.2 million as of yearend 2024 (2023: USD
\u00a0
49.1 million) with most of the lease
payments related to drilling rigs.
The following table summarizes the Group\u2019s maturity profile
\u00a0
of the lease liabilities based on contractual undiscounted
\u00a0
lease payments
and are related to office rent and equipment.
1 January - 31 December
USD million
2024
2023
Within one year
4.0
4.8
Two to five years
\u00a0
8.7
11.8
After five years
\u00a0
3.2
5.4
Total undiscounted lease liabilities end of the period
\u00a0
15.9
22.0
.
", "dimensions": { "concept": "ifrs-full:DisclosureOfLeasesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_99": { "value": "
\u00a0
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\n
\u00a0
\n
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\n
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\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Years ended 31 December
USD million
2024
2023
Non-current lease liabilities
9.7
14.0
Current lease liabilities
3.1
3.6
Total lease liabilities
12.7
17.5
The recognized lease liabilities in the balance sheet
\u00a0
are mainly related to office rent.
The identified lease liabilities have no significant
\u00a0
impact on the Group\u2019s financing, loan covenants or dividend
\u00a0
policy. The Group does
not have any residual value guarantees. Lease payments
\u00a0
related to short-term leases and leases of
\u00a0
low-value assets are mainly
recognized under lifting costs and exploration costs, or
\u00a0
tangible assets and capitalized exploration. Total lease payments related to
short-term leases and low-value assets were USD
\u00a0
58.2 million as of yearend 2024 (2023: USD
\u00a0
49.1 million) with most of the lease
payments related to drilling rigs.
The following table summarizes the Group\u2019s maturity profile
\u00a0
of the lease liabilities based on contractual undiscounted
\u00a0
lease payments
and are related to office rent and equipment.
1 January - 31 December
USD million
2024
2023
Within one year
4.0
4.8
Two to five years
\u00a0
8.7
11.8
After five years
\u00a0
3.2
5.4
Total undiscounted lease liabilities end of the period
\u00a0
15.9
22.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfLeasePrepaymentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_100": { "value": "
Note 20
Asset retirement obligations
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Provisions for asset retirement obligations (ARO)
Provisions for ARO are initially recognized at the
\u00a0
present value of the estimated future costs
\u00a0
determined in accordance with local
conditions and requirements. A corresponding asset of
\u00a0
an amount equivalent to the ARO provision
\u00a0
is also recognized initially and is
presented as part of the PP&E. The retirement
\u00a0
asset is subsequently depreciated as part of
\u00a0
the development and production asset it
relates to.
The ARO provisions and the discount rates are reviewed
\u00a0
at each balance sheet date. The discount rates
\u00a0
used in the calculation of
the present value of the ARO are pre-tax risk-free
\u00a0
rates with the addition of a credit margin. The
\u00a0
risk-free rate used has a maturity
date that is expected to coincide with the time
\u00a0
the removal will be affected and denominated
\u00a0
in the same currency as the expected
future expenditures. According to IFRIC 1
Changes in Existing Decommissioning, Restoration
\u00a0
and Similar Liabilities
, changes in the
measurement of the ARO resulting from a
\u00a0
change in the timing or amount of the outflow of
\u00a0
resources embodying economic benefits
required to settle the obligation, or a change
\u00a0
in the discount rate, are added to or deducted
\u00a0
from the cost of the related asset.
Changes in the estimated ARO provisions impact
\u00a0
the retirement asset in the period in which the
\u00a0
estimate is revised.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Estimation of the cost for
\u00a0
decommissioning
Estimation of the costs for decommissioning is complex
\u00a0
and requires judgement as these estimates
\u00a0
are based on currently
applicable laws, regulations and technology. Decommissioning activities will normally
\u00a0
take place in the distant future, and the
technology, regulatory requirements and related costs may change. The energy transition
\u00a0
may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated decommissioning provisions. Based
\u00a0
on various scenario analysis
performed by the Company, management does not expect any reasonable
\u00a0
change in the expected timeframe to have a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost estimates (i.e., cash flows) remain unchanged.
\u00a0
The estimates
cover expected removal concepts based on known technology
\u00a0
and, in the case of offshore decommissioning, estimated
\u00a0
costs of
maritime operations, hiring of heavy-lift barges and
\u00a0
drilling rigs. As a result, the initial recognition
\u00a0
of the liability and the capitalized
cost associated with decommissioning obligations,
\u00a0
and the subsequent adjustment of these balance
\u00a0
sheet items, involve the
application of significant judgement. Based on
\u00a0
the described uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Asset retirement obligations (ARO)
The provisions for ARO are based on the present
\u00a0
value of estimated future cost of decommissioning oil
\u00a0
and gas assets in Kurdistan and
the North Sea. The discount rates before tax applied
\u00a0
at yearend 2024 were between 5.1 percent
\u00a0
and 5.3 percent (yearend 2023:
between 4.9 percent and 5.0 percent). The credit
\u00a0
risk element included in the discount rates
\u00a0
at yearend 2024 was 0.8 percent (yearend
2023: 0.8 percent).
Credit risk discussion
The Company note that IASB in relation to its
\u00a0
project \u201cProvisions \u2013 Targeted Improvements\u201d, based on a staff paper recommendation,
have tentatively proposed to specify the use of
\u00a0
a discount rate reflecting the time value
\u00a0
of money, based on a risk-free rate without
adjustments for credit risk element (non-performance
\u00a0
risk). However, considering that no new requirements in the standard
\u00a0
have been
concluded, the Company deems it reasonable not
\u00a0
to change its method for determining the discount
\u00a0
rate. The Company has compared
its discount rate towards peers and noted that they
\u00a0
are within a range applied by other peer
\u00a0
companies.
\u00a0
Years ended 31 December
USD million
2024
2023
Non-current asset retirement obligations (ARO)
467.9
382.7
Current asset retirement obligations (ARO)
12.9
10.6
Total asset retirement obligations (ARO)
480.8
393.2
Years ended 31 December
USD million
2024
2023
Asset retirement obligation as of 1 January
393.2
388.6
ARO provisions from business combinations
83.0
-
ARO provisions divested assets
-2.9
-
Decommissioning spend
-4.9
-17.9
Increase/decrease in existing/new provisions
-1.6
10.5
Effects of change in the discount rate
-6.4
-5.4
Accretion expenses (unwinding of discount)
20.4
17.4
Asset retirement obligation as of 31 December
480.8
393.2
Note 21
Other liabilities
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
Provisions for other liabilities
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as a
\u00a0
result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
The provisions are reviewed at each balance
\u00a0
sheet date and adjusted to reflect the current best estimate.
\u00a0
\n
\u00a0
\n
Estimation uncertainty
The assessment of the existence and potential quantum
\u00a0
of contingencies inherently involves the exercise
\u00a0
of significant judgment and
the use of estimates regarding the outcome of
\u00a0
future events. Management uses its judgment, and
\u00a0
if necessary also external legal
experts to evaluate certain provisions and legal
\u00a0
disputes in order to ensure the correct accounting
\u00a0
treatment.
\u00a0
Years ended 31 December
USD million
2024
2023
Non-current
Other long-term obligations
6.9
7.3
Total non-current other liabilities
6.9
7.3
Current
Accrued interest expense
4.4
2.8
Other provisions and charges
9.8
6.4
Total current other liabilities
14.2
9.1
Total other liabilities
21.1
16.5
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Note 22
Trade and other payables
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Overlift
An overlift arises when the Group sells more
\u00a0
than its share of the oil and gas production (the
\u00a0
sales method). For underlift, see Note
15.
Years ended 31 December
USD million
2024
2023
Trade payables
84.5
70.5
Public duties payable
4.0
4.3
Prepayments from customers
4.7
21.2
Overlift and other adjustments
103.7
1.2
Other accrued expenses
126.8
123.9
Total trade and other payables
323.7
221.1
Trade payables and other accrued expenses include items of
\u00a0
working capital related to participation in licenses
\u00a0
in Kurdistan and the
North Sea, and prepayment from customers related
\u00a0
to oil sales in the North Sea. The overlift and other
\u00a0
adjustments relate to North Sea
overlifted volumes, valued at production cost including
\u00a0
depreciation, and other lifting related adjustments
\u00a0
in Kurdistan.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Commitments and contingencies
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as
\u00a0
a result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
\u00a0
Contingent liabilities are not recognized but are
\u00a0
disclosed unless the possibility of an outflow
\u00a0
of resources is remote.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Contingencies, provisions
\u00a0
and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or more uncertain future event
\u00a0
occurs or fails to occur. The
assessment of the existence and potential quantum of
\u00a0
contingencies inherently involves the exercise of
\u00a0
significant judgment and the
use of estimates regarding the outcome of future
\u00a0
events. Management uses its judgment to evaluate
\u00a0
certain provisions and legal
disputes in order to ensure the correct accounting
\u00a0
treatment.
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen \u2013 Block 53
The Ministry of Oil and Minerals (MOM or
\u00a0
Ministry) of Yemen filed an arbitration claim against operator Dove Energy Limited
\u00a0
and the
other partners (including DNO Yemen AS) for allegedly wrongful withdrawal from
\u00a0
Block 53. An arbitral award was rendered in
\u00a0
July 2019
partially in the Ministry\u2019s favor in the amount of USD
\u00a0
29 million (out of a USD 171 million
\u00a0
claim). The Contractor (including DNO Yemen
AS) filed for annulment proceedings in the Paris Court
\u00a0
d\u2019Appel which is still pending before
\u00a0
the French Supreme Court.
\u00a0
In 2023, a net amount of USD 29.2 million
\u00a0
was paid by DNO Yemen AS to MOM in connection with arbitral awards
\u00a0
resolving disputes
regarding
\u00a0
inter alia
\u00a0
Block 53. DNO has taken action against a former
\u00a0
license partner to the amount paid, in respect of
\u00a0
which that partner
is liable, and an award has been rendered
\u00a0
in DNO\u2019s favor.
Other claims
During the normal course of its business, the
\u00a0
Group may be involved in other legal proceedings
\u00a0
and unresolved claims. The Group has
made provisions in its consolidated financial statements
\u00a0
for probable liabilities related to litigation and
\u00a0
claims based on management's
best judgment and in line with IAS 37. Other than what
\u00a0
is set out above, DNO is not aware of
\u00a0
any governmental, legal or arbitral
proceedings (including any such proceedings which are
\u00a0
pending or threatened) initiated against DNO
\u00a0
and which may have significant
effects on DNO\u2019s results of operations, cash flows or financial
\u00a0
position.
Capital commitments and abandonment expenditures
Based on work plans as of yearend 2024 and
\u00a0
contingent on future market conditions including
\u00a0
development in the oil price, and
outcome of ongoing discussions related to recovery
\u00a0
of arrears for past oil deliveries to the KRG
\u00a0
and payment terms and conditions for
any future oil exports, the Group\u2019s projected operational spend
\u00a0
for 2025 comprising of capital and exploration expenditures,
abandonment expenditures and operational expenditures
\u00a0
amounts to USD 750 million. The projected
\u00a0
operational spend reflects the
Group\u2019s share of planned drilling and facility investments and
\u00a0
decommissioning plan in its licenses for 2025. These
\u00a0
work plans are
subject to revisions.
Guarantees at yearend
The Company has issued parent company guarantees
\u00a0
to authorities in Norway and the UK on behalf
\u00a0
of certain subsidiaries that
participate in licenses on the NCS and the UKCS.
\u00a0
The Company has furthermore issued parent
\u00a0
company guarantees in connection with
surety bonds and asset transactions.
Liability for damages/insurance
Installations and operations are covered by various insurance
\u00a0
policies.
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_101": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Provisions for asset retirement obligations (ARO)
Provisions for ARO are initially recognized at the
\u00a0
present value of the estimated future costs
\u00a0
determined in accordance with local
conditions and requirements. A corresponding asset of
\u00a0
an amount equivalent to the ARO provision
\u00a0
is also recognized initially and is
presented as part of the PP&E. The retirement
\u00a0
asset is subsequently depreciated as part of
\u00a0
the development and production asset it
relates to.
The ARO provisions and the discount rates are reviewed
\u00a0
at each balance sheet date. The discount rates
\u00a0
used in the calculation of
the present value of the ARO are pre-tax risk-free
\u00a0
rates with the addition of a credit margin. The
\u00a0
risk-free rate used has a maturity
date that is expected to coincide with the time
\u00a0
the removal will be affected and denominated
\u00a0
in the same currency as the expected
future expenditures. According to IFRIC 1
Changes in Existing Decommissioning, Restoration
\u00a0
and Similar Liabilities
, changes in the
measurement of the ARO resulting from a
\u00a0
change in the timing or amount of the outflow of
\u00a0
resources embodying economic benefits
required to settle the obligation, or a change
\u00a0
in the discount rate, are added to or deducted
\u00a0
from the cost of the related asset.
Changes in the estimated ARO provisions impact
\u00a0
the retirement asset in the period in which the
\u00a0
estimate is revised.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Estimation of the cost for
\u00a0
decommissioning
Estimation of the costs for decommissioning is complex
\u00a0
and requires judgement as these estimates
\u00a0
are based on currently
applicable laws, regulations and technology. Decommissioning activities will normally
\u00a0
take place in the distant future, and the
technology, regulatory requirements and related costs may change. The energy transition
\u00a0
may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated decommissioning provisions. Based
\u00a0
on various scenario analysis
performed by the Company, management does not expect any reasonable
\u00a0
change in the expected timeframe to have a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost estimates (i.e., cash flows) remain unchanged.
\u00a0
The estimates
cover expected removal concepts based on known technology
\u00a0
and, in the case of offshore decommissioning, estimated
\u00a0
costs of
maritime operations, hiring of heavy-lift barges and
\u00a0
drilling rigs. As a result, the initial recognition
\u00a0
of the liability and the capitalized
cost associated with decommissioning obligations,
\u00a0
and the subsequent adjustment of these balance
\u00a0
sheet items, involve the
application of significant judgement. Based on
\u00a0
the described uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_102": { "value": "
Note 21
Other liabilities
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
Provisions for other liabilities
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as a
\u00a0
result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
The provisions are reviewed at each balance
\u00a0
sheet date and adjusted to reflect the current best estimate.
\u00a0
\n
\u00a0
\n
Estimation uncertainty
The assessment of the existence and potential quantum
\u00a0
of contingencies inherently involves the exercise
\u00a0
of significant judgment and
the use of estimates regarding the outcome of
\u00a0
future events. Management uses its judgment, and
\u00a0
if necessary also external legal
experts to evaluate certain provisions and legal
\u00a0
disputes in order to ensure the correct accounting
\u00a0
treatment.
\u00a0
Years ended 31 December
USD million
2024
2023
Non-current
Other long-term obligations
6.9
7.3
Total non-current other liabilities
6.9
7.3
Current
Accrued interest expense
4.4
2.8
Other provisions and charges
9.8
6.4
Total current other liabilities
14.2
9.1
Total other liabilities
21.1
16.5
Note 24
Commitments and contingencies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Commitments and contingencies
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as
\u00a0
a result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
\u00a0
Contingent liabilities are not recognized but are
\u00a0
disclosed unless the possibility of an outflow
\u00a0
of resources is remote.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Contingencies, provisions
\u00a0
and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or more uncertain future event
\u00a0
occurs or fails to occur. The
assessment of the existence and potential quantum of
\u00a0
contingencies inherently involves the exercise of
\u00a0
significant judgment and the
use of estimates regarding the outcome of future
\u00a0
events. Management uses its judgment to evaluate
\u00a0
certain provisions and legal
disputes in order to ensure the correct accounting
\u00a0
treatment.
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen \u2013 Block 53
The Ministry of Oil and Minerals (MOM or
\u00a0
Ministry) of Yemen filed an arbitration claim against operator Dove Energy Limited
\u00a0
and the
other partners (including DNO Yemen AS) for allegedly wrongful withdrawal from
\u00a0
Block 53. An arbitral award was rendered in
\u00a0
July 2019
partially in the Ministry\u2019s favor in the amount of USD
\u00a0
29 million (out of a USD 171 million
\u00a0
claim). The Contractor (including DNO Yemen
AS) filed for annulment proceedings in the Paris Court
\u00a0
d\u2019Appel which is still pending before
\u00a0
the French Supreme Court.
\u00a0
In 2023, a net amount of USD 29.2 million
\u00a0
was paid by DNO Yemen AS to MOM in connection with arbitral awards
\u00a0
resolving disputes
regarding
\u00a0
inter alia
\u00a0
Block 53. DNO has taken action against a former
\u00a0
license partner to the amount paid, in respect of
\u00a0
which that partner
is liable, and an award has been rendered
\u00a0
in DNO\u2019s favor.
Other claims
During the normal course of its business, the
\u00a0
Group may be involved in other legal proceedings
\u00a0
and unresolved claims. The Group has
made provisions in its consolidated financial statements
\u00a0
for probable liabilities related to litigation and
\u00a0
claims based on management's
best judgment and in line with IAS 37. Other than what
\u00a0
is set out above, DNO is not aware of
\u00a0
any governmental, legal or arbitral
proceedings (including any such proceedings which are
\u00a0
pending or threatened) initiated against DNO
\u00a0
and which may have significant
effects on DNO\u2019s results of operations, cash flows or financial
\u00a0
position.
Capital commitments and abandonment expenditures
Based on work plans as of yearend 2024 and
\u00a0
contingent on future market conditions including
\u00a0
development in the oil price, and
outcome of ongoing discussions related to recovery
\u00a0
of arrears for past oil deliveries to the KRG
\u00a0
and payment terms and conditions for
any future oil exports, the Group\u2019s projected operational spend
\u00a0
for 2025 comprising of capital and exploration expenditures,
abandonment expenditures and operational expenditures
\u00a0
amounts to USD 750 million. The projected
\u00a0
operational spend reflects the
Group\u2019s share of planned drilling and facility investments and
\u00a0
decommissioning plan in its licenses for 2025. These
\u00a0
work plans are
subject to revisions.
Guarantees at yearend
The Company has issued parent company guarantees
\u00a0
to authorities in Norway and the UK on behalf
\u00a0
of certain subsidiaries that
participate in licenses on the NCS and the UKCS.
\u00a0
The Company has furthermore issued parent
\u00a0
company guarantees in connection with
surety bonds and asset transactions.
Liability for damages/insurance
Installations and operations are covered by various insurance
\u00a0
policies.
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherProvisionsContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_103": { "value": "
Note 21
Other liabilities
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
Provisions for other liabilities
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as a
\u00a0
result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
The provisions are reviewed at each balance
\u00a0
sheet date and adjusted to reflect the current best estimate.
\u00a0
\n
\u00a0
\n
Estimation uncertainty
The assessment of the existence and potential quantum
\u00a0
of contingencies inherently involves the exercise
\u00a0
of significant judgment and
the use of estimates regarding the outcome of
\u00a0
future events. Management uses its judgment, and
\u00a0
if necessary also external legal
experts to evaluate certain provisions and legal
\u00a0
disputes in order to ensure the correct accounting
\u00a0
treatment.
\u00a0
Years ended 31 December
USD million
2024
2023
Non-current
Other long-term obligations
6.9
7.3
Total non-current other liabilities
6.9
7.3
Current
Accrued interest expense
4.4
2.8
Other provisions and charges
9.8
6.4
Total current other liabilities
14.2
9.1
Total other liabilities
21.1
16.5
", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_104": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
\u00a0
\n
\u00a0
\n
Provisions for other liabilities
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as a
\u00a0
result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
The provisions are reviewed at each balance
\u00a0
sheet date and adjusted to reflect the current best estimate.
\u00a0
\n
\u00a0
\n
Estimation uncertainty
The assessment of the existence and potential quantum
\u00a0
of contingencies inherently involves the exercise
\u00a0
of significant judgment and
the use of estimates regarding the outcome of
\u00a0
future events. Management uses its judgment, and
\u00a0
if necessary also external legal
experts to evaluate certain provisions and legal
\u00a0
disputes in order to ensure the correct accounting
\u00a0
treatment.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_105": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Note 22
Trade and other payables
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Overlift
An overlift arises when the Group sells more
\u00a0
than its share of the oil and gas production (the
\u00a0
sales method). For underlift, see Note
15.
Years ended 31 December
USD million
2024
2023
Trade payables
84.5
70.5
Public duties payable
4.0
4.3
Prepayments from customers
4.7
21.2
Overlift and other adjustments
103.7
1.2
Other accrued expenses
126.8
123.9
Total trade and other payables
323.7
221.1
Trade payables and other accrued expenses include items of
\u00a0
working capital related to participation in licenses
\u00a0
in Kurdistan and the
North Sea, and prepayment from customers related
\u00a0
to oil sales in the North Sea. The overlift and other
\u00a0
adjustments relate to North Sea
overlifted volumes, valued at production cost including
\u00a0
depreciation, and other lifting related adjustments
\u00a0
in Kurdistan.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_106": { "value": "
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\n
Note 22
Trade and other payables
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Overlift
An overlift arises when the Group sells more
\u00a0
than its share of the oil and gas production (the
\u00a0
sales method). For underlift, see Note
15.
Years ended 31 December
USD million
2024
2023
Trade payables
84.5
70.5
Public duties payable
4.0
4.3
Prepayments from customers
4.7
21.2
Overlift and other adjustments
103.7
1.2
Other accrued expenses
126.8
123.9
Total trade and other payables
323.7
221.1
Trade payables and other accrued expenses include items of
\u00a0
working capital related to participation in licenses
\u00a0
in Kurdistan and the
North Sea, and prepayment from customers related
\u00a0
to oil sales in the North Sea. The overlift and other
\u00a0
adjustments relate to North Sea
overlifted volumes, valued at production cost including
\u00a0
depreciation, and other lifting related adjustments
\u00a0
in Kurdistan.
", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_107": { "value": "
\u00a0
\n
\u00a0
\n
Note 22
Trade and other payables
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Overlift
An overlift arises when the Group sells more
\u00a0
than its share of the oil and gas production (the
\u00a0
sales method). For underlift, see Note
15.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_108": { "value": "
Note 23
Financial instruments
\u00a0
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Financial instruments
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Financial assets
The Group\u2019s financial assets include trade and other
\u00a0
receivables, tax receivables and cash and
\u00a0
cash equivalents.
\u00a0
Financial assets are initially recognized at fair
\u00a0
value. After initial recognition the measurement
\u00a0
and accounting treatment depend on
the type of instrument and classification: Financial
\u00a0
investments at amortized cost through profit and
\u00a0
loss, at fair value through profit
and loss (FVTPL),
\u00a0
and at fair value through other comprehensive
\u00a0
income (FVTOCI).
A financial asset is derecognized when the Group no
\u00a0
longer has the right to receive cash flows from
\u00a0
the asset, and risks and rewards
are of ownership are transferred through sale or
\u00a0
the contractual rights to the cash flows expire, are
\u00a0
redeemed or cancelled.
\u00a0
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\u00a0
\n
Financial liabilities
The Group\u2019s financial liabilities include trade and other payables
\u00a0
and loans.
\u00a0
Interest-bearing loans are after initial recognition
\u00a0
measured at amortized cost using the effective interest
\u00a0
rate method. Gains and
losses are recognized in profit or loss when
\u00a0
the liabilities are derecognized as well as
\u00a0
through the amortization process. Amortized
cost is calculated by taking into account any discount
\u00a0
or premium on acquisition and fees or costs
\u00a0
that are an integral part of the
effective interest rate. The amortization cost is included
\u00a0
as finance expense in the statements of comprehensive
\u00a0
income. This applies
mainly to bond loans, see Note 18.
\u00a0
A financial liability is derecognized when the obligation
\u00a0
under the liability is discharged, cancelled or expires.
\u00a0
When an existing
financial liability is replaced by another from the
\u00a0
same lender on substantially different terms, or the
\u00a0
terms of an existing liability are
substantially modified, such a modification is treated
\u00a0
as a derecognition of the original liability and
\u00a0
a recognition of a new liability. The
difference in the respective carrying amounts is recognized
\u00a0
in the statements of comprehensive income.
Financial risk management, objectives and policies
Overview
DNO is exposed to a range of risks affecting its financial
\u00a0
performance including market risk, liquidity
\u00a0
risk and credit risk. The Group
seeks to minimize potential adverse effects of such risks
\u00a0
through sound business practices and risk management
\u00a0
programs. No hedge
accounting is applied.
\u00a0
\n
\u00a0
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\u00a0
\n
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Market risk
The Group is exposed to market risks driven by
\u00a0
fluctuations in oil and gas prices, foreign currency
\u00a0
exchange rates and interest rates.
\u00a0
Oil and gas price risk
DNO\u2019s revenues are generated from the sale of oil
\u00a0
and gas. The Group had no oil and gas
\u00a0
price hedging arrangements at yearend 2024
although it monitors its oil and gas price risk on
\u00a0
a continuous basis and evaluates hedging alternatives.
The following table illustrates the impact on reported 2023
\u00a0
and 2024 profit/loss before income tax from
\u00a0
oil and gas price fluctuations
deemed reasonable and possible, with all other
\u00a0
variables held constant. In addition to driving revenues,
\u00a0
price fluctuations or the
expectations of price fluctuations could impact DNO\u2019s capital
\u00a0
expenditure levels and impairment assessments.
\u00a0
See Note 10 for a
sensitivity analysis related to the impairment assessment
\u00a0
of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
\u00a0
USD (percent)
\u00a0
(USD mill)
2024
+/- 15.0
\u00a0
+/- 87.9
2023
+/- 15.0
\u00a0
+/- 77.9
Foreign currency exchange rate risk
Revenues from oil and gas production are primarily
\u00a0
in USD and EUR, while operating expenses,
\u00a0
capital and abandonment expenditures
are primarily denominated in USD, NOK and GBP. Dividend distributions from the Company are
\u00a0
in NOK. The Group had no currency
hedging instruments at yearend 2024 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP to USD exchange
\u00a0
rates, with all other variables
held constant. The other currencies (e.g., AED, IQD) are
\u00a0
not included as the exposure is deemed
\u00a0
immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2024
+ 10.0
4.4
2024
- 10.0
-4.4
2023
+ 10.0
6.0
2023
- 10.0
-6.0
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2024
+ 10.0
30.0
2024
- 10.0
-30.0
2023
+ 10.0
36.7
2023
- 10.0
-36.7
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2024
+ 10.0
10.8
2024
- 10.0
-10.8
2023
+ 10.0
0.3
2023
- 10.0
-0.3
Interest rate risk
As most of the Group\u2019s financing derives from bond loans
\u00a0
which are issued in USD and at fixed
\u00a0
interest rates, the Group does not
engage in interest rate hedging. Interest rate exposure
\u00a0
on the RBL is considered limited and no hedging
\u00a0
arrangement was in place
during 2024. The Group is exposed to interest rate
\u00a0
risk on its cash deposits held at floating interest
\u00a0
rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from a change in interest
rates on that portion of interest-bearing liabilities and
\u00a0
cash deposits deemed reasonable and possible,
\u00a0
with all other variables held
constant.
\u00a0
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2024
+/- 100
+/-7.5
2023
+/- 100
+/-7.6
Liquidity risk
Liquidity risk is the risk that suitable sources of
\u00a0
funding for the Group\u2019s business activities may not be
\u00a0
available. Prudent liquidity risk
management requires sufficient cash balances, credit facilities
\u00a0
and other financial resources to maintain
\u00a0
financial flexibility under
dynamic market conditions. The Group\u2019s principal sources of liquidity
\u00a0
are operating cash flows from its producing assets
\u00a0
in Kurdistan
and the North Sea. In addition to its operating
\u00a0
cash flows, the Group relies on the debt capital markets
\u00a0
for both short- and long-term
funding, see Note 18. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the senior management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 13) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27, which are made on a regular
\u00a0
basis pursuant to an approved budget and work program.
\u00a0
The cash distributions anticipated
to be received from Foxtrot International will be
\u00a0
sufficient to enable the Company to meet all of its
\u00a0
scheduled and anticipated obligations.
\u00a0
Excessive risk concentration
Concentrations arise when a number of counterparties
\u00a0
are engaged in similar business activities, or
\u00a0
activities in the same geographical
region, or have economic features that would
\u00a0
cause their ability to meet contractual obligations
\u00a0
to be similarly affected by changes in
economic, political or other conditions. DNO\u2019s revenues
\u00a0
in 2024 derived primarily from production in
\u00a0
the Tawke license in Kurdistan (see
also entitlement risk described in Note 3) and from
\u00a0
several licenses in the North Sea. The Group actively
\u00a0
seeks to reduce such risk
through organic growth and asset acquisitions aimed
\u00a0
at further diversifying its revenue sources.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2024
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
-
400.0
400.0
Other provisions and charges
-
-
13.4
0.8
-
Taxes payable
-
-
-
-
-
Trade and other payables
-
223.7
100.0
-
-
Total liabilities
-
223.7
113.4
400.8
400.0
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2023
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
131.2
435.0
-
Other provisions and charges
-
-
9.1
-
-
Taxes payable
-
-
4.6
-
-
Trade and other payables
-
218.0
2.0
-
-
Total liabilities
-
218.0
146.9
435.0
-
* Face value of the bonds was USD 750.0 million at yearend 2024 (USD 531.2 million at yearend 2023).
For changes in liabilities arising from financing activities,
\u00a0
see Note 18.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
Credit risk
Credit risk is the risk that a customer or counterparty
\u00a0
to a financial instrument will fail to perform or
\u00a0
fail to pay amounts due causing
financial loss to the Group. The Group\u2019s exposure
\u00a0
to credit risk is mainly related to its outstanding
\u00a0
trade debtors. Other counterparty
credit risk exposure to DNO is related to its
\u00a0
cash deposits with banks and financial institutions.
\u00a0
The table below provides an overview of
financial assets exposed to credit risk at yearend.
\u00a0
Years ended 31 December
USD million
2024
2023
Trade debtors (non-current portion) (Note 15)
98.2
129.8
Trade debtors (Note 15)
185.0
149.5
Other receivables (Note 15)
153.1
115.9
Tax receivables
\u00a0
27.5
-
Cash and cash equivalents
899.0
718.8
Total
\u00a0
1,362.9
1,114.1
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 15 regarding ELC assessment
\u00a0
of the Kurdistan receivables.
The table below shows the aging of trade debtors and
\u00a0
information about credit risk exposure using a
\u00a0
provision matrix.
\u00a0
Contract
Days past due (trade debtors)
USD million
assets
Current
< 30 days
30-60 days
61-90 days
> 90 days
Total
As of 31 December 2024
Trade debtors (nominal value) (Note 15)
-
17.7
\u00a0
-
\u00a0
\u00a0
-
\u00a0
\u00a0
-
\u00a0
298.1
315.9
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2023
Trade debtors (nominal value) (Note 15)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Cash deposits
Credit risk from balances with banks and financial institutions
\u00a0
is managed by the Group\u2019s treasury function. The Group
\u00a0
limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the total equity and equity ratio, which is
\u00a0
calculated as total equity divided by total assets.
The financial covenants of the bond loans require a
\u00a0
minimum of USD 40 million of liquidity and
\u00a0
that the Group maintain either an equity
ratio of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
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\n
\u00a0
\n
\u00a0
\n
There is also a restriction on declaring or
\u00a0
making any dividend payments if the liquidity
\u00a0
of the Company is less than USD 80 million
immediately after such distribution is made, see Note
\u00a0
18. The equity ratio has dropped primarily due
\u00a0
to the issue of DNO05 bond,
recognition of decommissioning liabilities in connection
\u00a0
with acquisitions and a net loss in 2024. The
\u00a0
table below shows the book equity
ratio at yearend.
\u00a0
No changes were made in the objectives, policies
\u00a0
or processes for managing capital during 2024
\u00a0
and 2023.
Years ended 31 December
USD million
2024
2023
Total equity
1,080.0
1,234.8
Total assets
2,966.1
2,638.3
Equity ratio
36.4%
46.8%
Fair value measurement
Assets and liabilities for which fair value is measured
\u00a0
or disclosed in the financial statements are
\u00a0
categorized within the fair value
hierarchy as described below.
Level 1: quoted prices (unadjusted) in active
\u00a0
markets for identical assets or liabilities.
Level 2: inputs other than quoted prices included within
\u00a0
Level 1 that are observable for the asset or liability, either directly
\u00a0
or indirectly.
Level 3: inputs for the asset or liability that are
\u00a0
not based on observable market data (unobservable
\u00a0
inputs).
\u00a0
The following table shows the carrying amounts
\u00a0
and fair values of financial liabilities, including
\u00a0
their levels in the fair value hierarchy. It
does not include the carrying amounts and fair
\u00a0
value information for financial assets and financial
\u00a0
liabilities not measured or disclosed at
fair value if the carrying amount is a reasonable approximation
\u00a0
of fair value.
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2024 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
18
790.5
790.5
31 December 2024
762.4
-
50.0
Interest-bearing liabilities (current)
18
-
-
-
-
-
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2023 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
18
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
18
166.2
166.2
130.9
-
35.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_109": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Financial instruments
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Financial assets
The Group\u2019s financial assets include trade and other
\u00a0
receivables, tax receivables and cash and
\u00a0
cash equivalents.
\u00a0
Financial assets are initially recognized at fair
\u00a0
value. After initial recognition the measurement
\u00a0
and accounting treatment depend on
the type of instrument and classification: Financial
\u00a0
investments at amortized cost through profit and
\u00a0
loss, at fair value through profit
and loss (FVTPL),
\u00a0
and at fair value through other comprehensive
\u00a0
income (FVTOCI).
A financial asset is derecognized when the Group no
\u00a0
longer has the right to receive cash flows from
\u00a0
the asset, and risks and rewards
are of ownership are transferred through sale or
\u00a0
the contractual rights to the cash flows expire, are
\u00a0
redeemed or cancelled.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Financial liabilities
The Group\u2019s financial liabilities include trade and other payables
\u00a0
and loans.
\u00a0
Interest-bearing loans are after initial recognition
\u00a0
measured at amortized cost using the effective interest
\u00a0
rate method. Gains and
losses are recognized in profit or loss when
\u00a0
the liabilities are derecognized as well as
\u00a0
through the amortization process. Amortized
cost is calculated by taking into account any discount
\u00a0
or premium on acquisition and fees or costs
\u00a0
that are an integral part of the
effective interest rate. The amortization cost is included
\u00a0
as finance expense in the statements of comprehensive
\u00a0
income. This applies
mainly to bond loans, see Note 18.
\u00a0
A financial liability is derecognized when the obligation
\u00a0
under the liability is discharged, cancelled or expires.
\u00a0
When an existing
financial liability is replaced by another from the
\u00a0
same lender on substantially different terms, or the
\u00a0
terms of an existing liability are
substantially modified, such a modification is treated
\u00a0
as a derecognition of the original liability and
\u00a0
a recognition of a new liability. The
difference in the respective carrying amounts is recognized
\u00a0
in the statements of comprehensive income.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_110": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Financial instruments
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Financial assets
The Group\u2019s financial assets include trade and other
\u00a0
receivables, tax receivables and cash and
\u00a0
cash equivalents.
\u00a0
Financial assets are initially recognized at fair
\u00a0
value. After initial recognition the measurement
\u00a0
and accounting treatment depend on
the type of instrument and classification: Financial
\u00a0
investments at amortized cost through profit and
\u00a0
loss, at fair value through profit
and loss (FVTPL),
\u00a0
and at fair value through other comprehensive
\u00a0
income (FVTOCI).
A financial asset is derecognized when the Group no
\u00a0
longer has the right to receive cash flows from
\u00a0
the asset, and risks and rewards
are of ownership are transferred through sale or
\u00a0
the contractual rights to the cash flows expire, are
\u00a0
redeemed or cancelled.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Financial liabilities
The Group\u2019s financial liabilities include trade and other payables
\u00a0
and loans.
\u00a0
Interest-bearing loans are after initial recognition
\u00a0
measured at amortized cost using the effective interest
\u00a0
rate method. Gains and
losses are recognized in profit or loss when
\u00a0
the liabilities are derecognized as well as
\u00a0
through the amortization process. Amortized
cost is calculated by taking into account any discount
\u00a0
or premium on acquisition and fees or costs
\u00a0
that are an integral part of the
effective interest rate. The amortization cost is included
\u00a0
as finance expense in the statements of comprehensive
\u00a0
income. This applies
mainly to bond loans, see Note 18.
\u00a0
A financial liability is derecognized when the obligation
\u00a0
under the liability is discharged, cancelled or expires.
\u00a0
When an existing
financial liability is replaced by another from the
\u00a0
same lender on substantially different terms, or the
\u00a0
terms of an existing liability are
substantially modified, such a modification is treated
\u00a0
as a derecognition of the original liability and
\u00a0
a recognition of a new liability. The
difference in the respective carrying amounts is recognized
\u00a0
in the statements of comprehensive income.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_111": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Financial assets
The Group\u2019s financial assets include trade and other
\u00a0
receivables, tax receivables and cash and
\u00a0
cash equivalents.
\u00a0
Financial assets are initially recognized at fair
\u00a0
value. After initial recognition the measurement
\u00a0
and accounting treatment depend on
the type of instrument and classification: Financial
\u00a0
investments at amortized cost through profit and
\u00a0
loss, at fair value through profit
and loss (FVTPL),
\u00a0
and at fair value through other comprehensive
\u00a0
income (FVTOCI).
A financial asset is derecognized when the Group no
\u00a0
longer has the right to receive cash flows from
\u00a0
the asset, and risks and rewards
are of ownership are transferred through sale or
\u00a0
the contractual rights to the cash flows expire, are
\u00a0
redeemed or cancelled.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_112": { "value": "
Financial risk management, objectives and policies
Overview
DNO is exposed to a range of risks affecting its financial
\u00a0
performance including market risk, liquidity
\u00a0
risk and credit risk. The Group
seeks to minimize potential adverse effects of such risks
\u00a0
through sound business practices and risk management
\u00a0
programs. No hedge
accounting is applied.
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Market risk
The Group is exposed to market risks driven by
\u00a0
fluctuations in oil and gas prices, foreign currency
\u00a0
exchange rates and interest rates.
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Oil and gas price risk
DNO\u2019s revenues are generated from the sale of oil
\u00a0
and gas. The Group had no oil and gas
\u00a0
price hedging arrangements at yearend 2024
although it monitors its oil and gas price risk on
\u00a0
a continuous basis and evaluates hedging alternatives.
The following table illustrates the impact on reported 2023
\u00a0
and 2024 profit/loss before income tax from
\u00a0
oil and gas price fluctuations
deemed reasonable and possible, with all other
\u00a0
variables held constant. In addition to driving revenues,
\u00a0
price fluctuations or the
expectations of price fluctuations could impact DNO\u2019s capital
\u00a0
expenditure levels and impairment assessments.
\u00a0
See Note 10 for a
sensitivity analysis related to the impairment assessment
\u00a0
of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
\u00a0
USD (percent)
\u00a0
(USD mill)
2024
+/- 15.0
\u00a0
+/- 87.9
2023
+/- 15.0
\u00a0
+/- 77.9
Foreign currency exchange rate risk
Revenues from oil and gas production are primarily
\u00a0
in USD and EUR, while operating expenses,
\u00a0
capital and abandonment expenditures
are primarily denominated in USD, NOK and GBP. Dividend distributions from the Company are
\u00a0
in NOK. The Group had no currency
hedging instruments at yearend 2024 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
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The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP to USD exchange
\u00a0
rates, with all other variables
held constant. The other currencies (e.g., AED, IQD) are
\u00a0
not included as the exposure is deemed
\u00a0
immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2024
+ 10.0
4.4
2024
- 10.0
-4.4
2023
+ 10.0
6.0
2023
- 10.0
-6.0
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2024
+ 10.0
30.0
2024
- 10.0
-30.0
2023
+ 10.0
36.7
2023
- 10.0
-36.7
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2024
+ 10.0
10.8
2024
- 10.0
-10.8
2023
+ 10.0
0.3
2023
- 10.0
-0.3
Interest rate risk
As most of the Group\u2019s financing derives from bond loans
\u00a0
which are issued in USD and at fixed
\u00a0
interest rates, the Group does not
engage in interest rate hedging. Interest rate exposure
\u00a0
on the RBL is considered limited and no hedging
\u00a0
arrangement was in place
during 2024. The Group is exposed to interest rate
\u00a0
risk on its cash deposits held at floating interest
\u00a0
rates.
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The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from a change in interest
rates on that portion of interest-bearing liabilities and
\u00a0
cash deposits deemed reasonable and possible,
\u00a0
with all other variables held
constant.
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Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2024
+/- 100
+/-7.5
2023
+/- 100
+/-7.6
Liquidity risk
Liquidity risk is the risk that suitable sources of
\u00a0
funding for the Group\u2019s business activities may not be
\u00a0
available. Prudent liquidity risk
management requires sufficient cash balances, credit facilities
\u00a0
and other financial resources to maintain
\u00a0
financial flexibility under
dynamic market conditions. The Group\u2019s principal sources of liquidity
\u00a0
are operating cash flows from its producing assets
\u00a0
in Kurdistan
and the North Sea. In addition to its operating
\u00a0
cash flows, the Group relies on the debt capital markets
\u00a0
for both short- and long-term
funding, see Note 18. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the senior management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 13) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27, which are made on a regular
\u00a0
basis pursuant to an approved budget and work program.
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The cash distributions anticipated
to be received from Foxtrot International will be
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sufficient to enable the Company to meet all of its
\u00a0
scheduled and anticipated obligations.
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Excessive risk concentration
Concentrations arise when a number of counterparties
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are engaged in similar business activities, or
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activities in the same geographical
region, or have economic features that would
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cause their ability to meet contractual obligations
\u00a0
to be similarly affected by changes in
economic, political or other conditions. DNO\u2019s revenues
\u00a0
in 2024 derived primarily from production in
\u00a0
the Tawke license in Kurdistan (see
also entitlement risk described in Note 3) and from
\u00a0
several licenses in the North Sea. The Group actively
\u00a0
seeks to reduce such risk
through organic growth and asset acquisitions aimed
\u00a0
at further diversifying its revenue sources.
The tables below summarize the maturity profile of
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the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
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USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2024
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
-
400.0
400.0
Other provisions and charges
-
-
13.4
0.8
-
Taxes payable
-
-
-
-
-
Trade and other payables
-
223.7
100.0
-
-
Total liabilities
-
223.7
113.4
400.8
400.0
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2023
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
131.2
435.0
-
Other provisions and charges
-
-
9.1
-
-
Taxes payable
-
-
4.6
-
-
Trade and other payables
-
218.0
2.0
-
-
Total liabilities
-
218.0
146.9
435.0
-
* Face value of the bonds was USD 750.0 million at yearend 2024 (USD 531.2 million at yearend 2023).
For changes in liabilities arising from financing activities,
\u00a0
see Note 18.
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Credit risk
Credit risk is the risk that a customer or counterparty
\u00a0
to a financial instrument will fail to perform or
\u00a0
fail to pay amounts due causing
financial loss to the Group. The Group\u2019s exposure
\u00a0
to credit risk is mainly related to its outstanding
\u00a0
trade debtors. Other counterparty
credit risk exposure to DNO is related to its
\u00a0
cash deposits with banks and financial institutions.
\u00a0
The table below provides an overview of
financial assets exposed to credit risk at yearend.
\u00a0
Years ended 31 December
USD million
2024
2023
Trade debtors (non-current portion) (Note 15)
98.2
129.8
Trade debtors (Note 15)
185.0
149.5
Other receivables (Note 15)
153.1
115.9
Tax receivables
\u00a0
27.5
-
Cash and cash equivalents
899.0
718.8
Total
\u00a0
1,362.9
1,114.1
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 15 regarding ELC assessment
\u00a0
of the Kurdistan receivables.
The table below shows the aging of trade debtors and
\u00a0
information about credit risk exposure using a
\u00a0
provision matrix.
\u00a0
Contract
Days past due (trade debtors)
USD million
assets
Current
< 30 days
30-60 days
61-90 days
> 90 days
Total
As of 31 December 2024
Trade debtors (nominal value) (Note 15)
-
17.7
\u00a0
-
\u00a0
\u00a0
-
\u00a0
\u00a0
-
\u00a0
298.1
315.9
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2023
Trade debtors (nominal value) (Note 15)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Cash deposits
Credit risk from balances with banks and financial institutions
\u00a0
is managed by the Group\u2019s treasury function. The Group
\u00a0
limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the total equity and equity ratio, which is
\u00a0
calculated as total equity divided by total assets.
The financial covenants of the bond loans require a
\u00a0
minimum of USD 40 million of liquidity and
\u00a0
that the Group maintain either an equity
ratio of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
\u00a0
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\u00a0
\n
There is also a restriction on declaring or
\u00a0
making any dividend payments if the liquidity
\u00a0
of the Company is less than USD 80 million
immediately after such distribution is made, see Note
\u00a0
18. The equity ratio has dropped primarily due
\u00a0
to the issue of DNO05 bond,
recognition of decommissioning liabilities in connection
\u00a0
with acquisitions and a net loss in 2024. The
\u00a0
table below shows the book equity
ratio at yearend.
\u00a0
No changes were made in the objectives, policies
\u00a0
or processes for managing capital during 2024
\u00a0
and 2023.
Years ended 31 December
USD million
2024
2023
Total equity
1,080.0
1,234.8
Total assets
2,966.1
2,638.3
Equity ratio
36.4%
46.8%
Fair value measurement
Assets and liabilities for which fair value is measured
\u00a0
or disclosed in the financial statements are
\u00a0
categorized within the fair value
hierarchy as described below.
Level 1: quoted prices (unadjusted) in active
\u00a0
markets for identical assets or liabilities.
Level 2: inputs other than quoted prices included within
\u00a0
Level 1 that are observable for the asset or liability, either directly
\u00a0
or indirectly.
Level 3: inputs for the asset or liability that are
\u00a0
not based on observable market data (unobservable
\u00a0
inputs).
\u00a0
The following table shows the carrying amounts
\u00a0
and fair values of financial liabilities, including
\u00a0
their levels in the fair value hierarchy. It
does not include the carrying amounts and fair
\u00a0
value information for financial assets and financial
\u00a0
liabilities not measured or disclosed at
fair value if the carrying amount is a reasonable approximation
\u00a0
of fair value.
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2024 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
18
790.5
790.5
31 December 2024
762.4
-
50.0
Interest-bearing liabilities (current)
18
-
-
-
-
-
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2023 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
18
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
18
166.2
166.2
130.9
-
35.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_113": { "value": "
Financial risk management, objectives and policies
Overview
DNO is exposed to a range of risks affecting its financial
\u00a0
performance including market risk, liquidity
\u00a0
risk and credit risk. The Group
seeks to minimize potential adverse effects of such risks
\u00a0
through sound business practices and risk management
\u00a0
programs. No hedge
accounting is applied.
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Market risk
The Group is exposed to market risks driven by
\u00a0
fluctuations in oil and gas prices, foreign currency
\u00a0
exchange rates and interest rates.
\u00a0
Oil and gas price risk
DNO\u2019s revenues are generated from the sale of oil
\u00a0
and gas. The Group had no oil and gas
\u00a0
price hedging arrangements at yearend 2024
although it monitors its oil and gas price risk on
\u00a0
a continuous basis and evaluates hedging alternatives.
The following table illustrates the impact on reported 2023
\u00a0
and 2024 profit/loss before income tax from
\u00a0
oil and gas price fluctuations
deemed reasonable and possible, with all other
\u00a0
variables held constant. In addition to driving revenues,
\u00a0
price fluctuations or the
expectations of price fluctuations could impact DNO\u2019s capital
\u00a0
expenditure levels and impairment assessments.
\u00a0
See Note 10 for a
sensitivity analysis related to the impairment assessment
\u00a0
of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
\u00a0
USD (percent)
\u00a0
(USD mill)
2024
+/- 15.0
\u00a0
+/- 87.9
2023
+/- 15.0
\u00a0
+/- 77.9
Foreign currency exchange rate risk
Revenues from oil and gas production are primarily
\u00a0
in USD and EUR, while operating expenses,
\u00a0
capital and abandonment expenditures
are primarily denominated in USD, NOK and GBP. Dividend distributions from the Company are
\u00a0
in NOK. The Group had no currency
hedging instruments at yearend 2024 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
\u00a0
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\u00a0
\n
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\n
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\n
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\n
\u00a0
\n
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\n
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\n
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\n
\u00a0
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
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\n
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\n
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\n
\u00a0
\n
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP to USD exchange
\u00a0
rates, with all other variables
held constant. The other currencies (e.g., AED, IQD) are
\u00a0
not included as the exposure is deemed
\u00a0
immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2024
+ 10.0
4.4
2024
- 10.0
-4.4
2023
+ 10.0
6.0
2023
- 10.0
-6.0
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2024
+ 10.0
30.0
2024
- 10.0
-30.0
2023
+ 10.0
36.7
2023
- 10.0
-36.7
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2024
+ 10.0
10.8
2024
- 10.0
-10.8
2023
+ 10.0
0.3
2023
- 10.0
-0.3
Interest rate risk
As most of the Group\u2019s financing derives from bond loans
\u00a0
which are issued in USD and at fixed
\u00a0
interest rates, the Group does not
engage in interest rate hedging. Interest rate exposure
\u00a0
on the RBL is considered limited and no hedging
\u00a0
arrangement was in place
during 2024. The Group is exposed to interest rate
\u00a0
risk on its cash deposits held at floating interest
\u00a0
rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from a change in interest
rates on that portion of interest-bearing liabilities and
\u00a0
cash deposits deemed reasonable and possible,
\u00a0
with all other variables held
constant.
\u00a0
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2024
+/- 100
+/-7.5
2023
+/- 100
+/-7.6
Liquidity risk
Liquidity risk is the risk that suitable sources of
\u00a0
funding for the Group\u2019s business activities may not be
\u00a0
available. Prudent liquidity risk
management requires sufficient cash balances, credit facilities
\u00a0
and other financial resources to maintain
\u00a0
financial flexibility under
dynamic market conditions. The Group\u2019s principal sources of liquidity
\u00a0
are operating cash flows from its producing assets
\u00a0
in Kurdistan
and the North Sea. In addition to its operating
\u00a0
cash flows, the Group relies on the debt capital markets
\u00a0
for both short- and long-term
funding, see Note 18. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the senior management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 13) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27, which are made on a regular
\u00a0
basis pursuant to an approved budget and work program.
\u00a0
The cash distributions anticipated
to be received from Foxtrot International will be
\u00a0
sufficient to enable the Company to meet all of its
\u00a0
scheduled and anticipated obligations.
\u00a0
Excessive risk concentration
Concentrations arise when a number of counterparties
\u00a0
are engaged in similar business activities, or
\u00a0
activities in the same geographical
region, or have economic features that would
\u00a0
cause their ability to meet contractual obligations
\u00a0
to be similarly affected by changes in
economic, political or other conditions. DNO\u2019s revenues
\u00a0
in 2024 derived primarily from production in
\u00a0
the Tawke license in Kurdistan (see
also entitlement risk described in Note 3) and from
\u00a0
several licenses in the North Sea. The Group actively
\u00a0
seeks to reduce such risk
through organic growth and asset acquisitions aimed
\u00a0
at further diversifying its revenue sources.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\u00a0
\n
\u00a0
\n
\u00a0
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
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\n
\u00a0
\n
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2024
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
-
400.0
400.0
Other provisions and charges
-
-
13.4
0.8
-
Taxes payable
-
-
-
-
-
Trade and other payables
-
223.7
100.0
-
-
Total liabilities
-
223.7
113.4
400.8
400.0
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2023
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
131.2
435.0
-
Other provisions and charges
-
-
9.1
-
-
Taxes payable
-
-
4.6
-
-
Trade and other payables
-
218.0
2.0
-
-
Total liabilities
-
218.0
146.9
435.0
-
* Face value of the bonds was USD 750.0 million at yearend 2024 (USD 531.2 million at yearend 2023).
For changes in liabilities arising from financing activities,
\u00a0
see Note 18.
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\n
Credit risk
Credit risk is the risk that a customer or counterparty
\u00a0
to a financial instrument will fail to perform or
\u00a0
fail to pay amounts due causing
financial loss to the Group. The Group\u2019s exposure
\u00a0
to credit risk is mainly related to its outstanding
\u00a0
trade debtors. Other counterparty
credit risk exposure to DNO is related to its
\u00a0
cash deposits with banks and financial institutions.
\u00a0
The table below provides an overview of
financial assets exposed to credit risk at yearend.
\u00a0
Years ended 31 December
USD million
2024
2023
Trade debtors (non-current portion) (Note 15)
98.2
129.8
Trade debtors (Note 15)
185.0
149.5
Other receivables (Note 15)
153.1
115.9
Tax receivables
\u00a0
27.5
-
Cash and cash equivalents
899.0
718.8
Total
\u00a0
1,362.9
1,114.1
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 15 regarding ELC assessment
\u00a0
of the Kurdistan receivables.
The table below shows the aging of trade debtors and
\u00a0
information about credit risk exposure using a
\u00a0
provision matrix.
\u00a0
Contract
Days past due (trade debtors)
USD million
assets
Current
< 30 days
30-60 days
61-90 days
> 90 days
Total
As of 31 December 2024
Trade debtors (nominal value) (Note 15)
-
17.7
\u00a0
-
\u00a0
\u00a0
-
\u00a0
\u00a0
-
\u00a0
298.1
315.9
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2023
Trade debtors (nominal value) (Note 15)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Cash deposits
Credit risk from balances with banks and financial institutions
\u00a0
is managed by the Group\u2019s treasury function. The Group
\u00a0
limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the total equity and equity ratio, which is
\u00a0
calculated as total equity divided by total assets.
The financial covenants of the bond loans require a
\u00a0
minimum of USD 40 million of liquidity and
\u00a0
that the Group maintain either an equity
ratio of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
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\n
There is also a restriction on declaring or
\u00a0
making any dividend payments if the liquidity
\u00a0
of the Company is less than USD 80 million
immediately after such distribution is made, see Note
\u00a0
18. The equity ratio has dropped primarily due
\u00a0
to the issue of DNO05 bond,
recognition of decommissioning liabilities in connection
\u00a0
with acquisitions and a net loss in 2024. The
\u00a0
table below shows the book equity
ratio at yearend.
\u00a0
No changes were made in the objectives, policies
\u00a0
or processes for managing capital during 2024
\u00a0
and 2023.
Years ended 31 December
USD million
2024
2023
Total equity
1,080.0
1,234.8
Total assets
2,966.1
2,638.3
Equity ratio
36.4%
46.8%
Fair value measurement
Assets and liabilities for which fair value is measured
\u00a0
or disclosed in the financial statements are
\u00a0
categorized within the fair value
hierarchy as described below.
Level 1: quoted prices (unadjusted) in active
\u00a0
markets for identical assets or liabilities.
Level 2: inputs other than quoted prices included within
\u00a0
Level 1 that are observable for the asset or liability, either directly
\u00a0
or indirectly.
Level 3: inputs for the asset or liability that are
\u00a0
not based on observable market data (unobservable
\u00a0
inputs).
\u00a0
The following table shows the carrying amounts
\u00a0
and fair values of financial liabilities, including
\u00a0
their levels in the fair value hierarchy. It
does not include the carrying amounts and fair
\u00a0
value information for financial assets and financial
\u00a0
liabilities not measured or disclosed at
fair value if the carrying amount is a reasonable approximation
\u00a0
of fair value.
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2024 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
18
790.5
790.5
31 December 2024
762.4
-
50.0
Interest-bearing liabilities (current)
18
-
-
-
-
-
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2023 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
18
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
18
166.2
166.2
130.9
-
35.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_114": { "value": "
Financial risk management, objectives and policies
Overview
DNO is exposed to a range of risks affecting its financial
\u00a0
performance including market risk, liquidity
\u00a0
risk and credit risk. The Group
seeks to minimize potential adverse effects of such risks
\u00a0
through sound business practices and risk management
\u00a0
programs. No hedge
accounting is applied.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Market risk
The Group is exposed to market risks driven by
\u00a0
fluctuations in oil and gas prices, foreign currency
\u00a0
exchange rates and interest rates.
\u00a0
Oil and gas price risk
DNO\u2019s revenues are generated from the sale of oil
\u00a0
and gas. The Group had no oil and gas
\u00a0
price hedging arrangements at yearend 2024
although it monitors its oil and gas price risk on
\u00a0
a continuous basis and evaluates hedging alternatives.
The following table illustrates the impact on reported 2023
\u00a0
and 2024 profit/loss before income tax from
\u00a0
oil and gas price fluctuations
deemed reasonable and possible, with all other
\u00a0
variables held constant. In addition to driving revenues,
\u00a0
price fluctuations or the
expectations of price fluctuations could impact DNO\u2019s capital
\u00a0
expenditure levels and impairment assessments.
\u00a0
See Note 10 for a
sensitivity analysis related to the impairment assessment
\u00a0
of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
\u00a0
USD (percent)
\u00a0
(USD mill)
2024
+/- 15.0
\u00a0
+/- 87.9
2023
+/- 15.0
\u00a0
+/- 77.9
Foreign currency exchange rate risk
Revenues from oil and gas production are primarily
\u00a0
in USD and EUR, while operating expenses,
\u00a0
capital and abandonment expenditures
are primarily denominated in USD, NOK and GBP. Dividend distributions from the Company are
\u00a0
in NOK. The Group had no currency
hedging instruments at yearend 2024 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
\u00a0
\n
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\n
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\u00a0
\n
\u00a0
\n
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP to USD exchange
\u00a0
rates, with all other variables
held constant. The other currencies (e.g., AED, IQD) are
\u00a0
not included as the exposure is deemed
\u00a0
immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2024
+ 10.0
4.4
2024
- 10.0
-4.4
2023
+ 10.0
6.0
2023
- 10.0
-6.0
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2024
+ 10.0
30.0
2024
- 10.0
-30.0
2023
+ 10.0
36.7
2023
- 10.0
-36.7
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2024
+ 10.0
10.8
2024
- 10.0
-10.8
2023
+ 10.0
0.3
2023
- 10.0
-0.3
Interest rate risk
As most of the Group\u2019s financing derives from bond loans
\u00a0
which are issued in USD and at fixed
\u00a0
interest rates, the Group does not
engage in interest rate hedging. Interest rate exposure
\u00a0
on the RBL is considered limited and no hedging
\u00a0
arrangement was in place
during 2024. The Group is exposed to interest rate
\u00a0
risk on its cash deposits held at floating interest
\u00a0
rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from a change in interest
rates on that portion of interest-bearing liabilities and
\u00a0
cash deposits deemed reasonable and possible,
\u00a0
with all other variables held
constant.
\u00a0
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2024
+/- 100
+/-7.5
2023
+/- 100
+/-7.6
Liquidity risk
Liquidity risk is the risk that suitable sources of
\u00a0
funding for the Group\u2019s business activities may not be
\u00a0
available. Prudent liquidity risk
management requires sufficient cash balances, credit facilities
\u00a0
and other financial resources to maintain
\u00a0
financial flexibility under
dynamic market conditions. The Group\u2019s principal sources of liquidity
\u00a0
are operating cash flows from its producing assets
\u00a0
in Kurdistan
and the North Sea. In addition to its operating
\u00a0
cash flows, the Group relies on the debt capital markets
\u00a0
for both short- and long-term
funding, see Note 18. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the senior management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 13) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27, which are made on a regular
\u00a0
basis pursuant to an approved budget and work program.
\u00a0
The cash distributions anticipated
to be received from Foxtrot International will be
\u00a0
sufficient to enable the Company to meet all of its
\u00a0
scheduled and anticipated obligations.
\u00a0
Excessive risk concentration
Concentrations arise when a number of counterparties
\u00a0
are engaged in similar business activities, or
\u00a0
activities in the same geographical
region, or have economic features that would
\u00a0
cause their ability to meet contractual obligations
\u00a0
to be similarly affected by changes in
economic, political or other conditions. DNO\u2019s revenues
\u00a0
in 2024 derived primarily from production in
\u00a0
the Tawke license in Kurdistan (see
also entitlement risk described in Note 3) and from
\u00a0
several licenses in the North Sea. The Group actively
\u00a0
seeks to reduce such risk
through organic growth and asset acquisitions aimed
\u00a0
at further diversifying its revenue sources.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2024
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
-
400.0
400.0
Other provisions and charges
-
-
13.4
0.8
-
Taxes payable
-
-
-
-
-
Trade and other payables
-
223.7
100.0
-
-
Total liabilities
-
223.7
113.4
400.8
400.0
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2023
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
131.2
435.0
-
Other provisions and charges
-
-
9.1
-
-
Taxes payable
-
-
4.6
-
-
Trade and other payables
-
218.0
2.0
-
-
Total liabilities
-
218.0
146.9
435.0
-
* Face value of the bonds was USD 750.0 million at yearend 2024 (USD 531.2 million at yearend 2023).
For changes in liabilities arising from financing activities,
\u00a0
see Note 18.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
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\u00a0
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\u00a0
\n
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\n
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\u00a0
\n
\u00a0
\n
Credit risk
Credit risk is the risk that a customer or counterparty
\u00a0
to a financial instrument will fail to perform or
\u00a0
fail to pay amounts due causing
financial loss to the Group. The Group\u2019s exposure
\u00a0
to credit risk is mainly related to its outstanding
\u00a0
trade debtors. Other counterparty
credit risk exposure to DNO is related to its
\u00a0
cash deposits with banks and financial institutions.
\u00a0
The table below provides an overview of
financial assets exposed to credit risk at yearend.
\u00a0
Years ended 31 December
USD million
2024
2023
Trade debtors (non-current portion) (Note 15)
98.2
129.8
Trade debtors (Note 15)
185.0
149.5
Other receivables (Note 15)
153.1
115.9
Tax receivables
\u00a0
27.5
-
Cash and cash equivalents
899.0
718.8
Total
\u00a0
1,362.9
1,114.1
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 15 regarding ELC assessment
\u00a0
of the Kurdistan receivables.
The table below shows the aging of trade debtors and
\u00a0
information about credit risk exposure using a
\u00a0
provision matrix.
\u00a0
Contract
Days past due (trade debtors)
USD million
assets
Current
< 30 days
30-60 days
61-90 days
> 90 days
Total
As of 31 December 2024
Trade debtors (nominal value) (Note 15)
-
17.7
\u00a0
-
\u00a0
\u00a0
-
\u00a0
\u00a0
-
\u00a0
298.1
315.9
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2023
Trade debtors (nominal value) (Note 15)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Cash deposits
Credit risk from balances with banks and financial institutions
\u00a0
is managed by the Group\u2019s treasury function. The Group
\u00a0
limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the total equity and equity ratio, which is
\u00a0
calculated as total equity divided by total assets.
The financial covenants of the bond loans require a
\u00a0
minimum of USD 40 million of liquidity and
\u00a0
that the Group maintain either an equity
ratio of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\u00a0
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\n
There is also a restriction on declaring or
\u00a0
making any dividend payments if the liquidity
\u00a0
of the Company is less than USD 80 million
immediately after such distribution is made, see Note
\u00a0
18. The equity ratio has dropped primarily due
\u00a0
to the issue of DNO05 bond,
recognition of decommissioning liabilities in connection
\u00a0
with acquisitions and a net loss in 2024. The
\u00a0
table below shows the book equity
ratio at yearend.
\u00a0
No changes were made in the objectives, policies
\u00a0
or processes for managing capital during 2024
\u00a0
and 2023.
Years ended 31 December
USD million
2024
2023
Total equity
1,080.0
1,234.8
Total assets
2,966.1
2,638.3
Equity ratio
36.4%
46.8%
Fair value measurement
Assets and liabilities for which fair value is measured
\u00a0
or disclosed in the financial statements are
\u00a0
categorized within the fair value
hierarchy as described below.
Level 1: quoted prices (unadjusted) in active
\u00a0
markets for identical assets or liabilities.
Level 2: inputs other than quoted prices included within
\u00a0
Level 1 that are observable for the asset or liability, either directly
\u00a0
or indirectly.
Level 3: inputs for the asset or liability that are
\u00a0
not based on observable market data (unobservable
\u00a0
inputs).
\u00a0
The following table shows the carrying amounts
\u00a0
and fair values of financial liabilities, including
\u00a0
their levels in the fair value hierarchy. It
does not include the carrying amounts and fair
\u00a0
value information for financial assets and financial
\u00a0
liabilities not measured or disclosed at
fair value if the carrying amount is a reasonable approximation
\u00a0
of fair value.
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2024 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
18
790.5
790.5
31 December 2024
762.4
-
50.0
Interest-bearing liabilities (current)
18
-
-
-
-
-
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2023 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
18
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
18
166.2
166.2
130.9
-
35.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_115": { "value": "
Financial risk management, objectives and policies
Overview
DNO is exposed to a range of risks affecting its financial
\u00a0
performance including market risk, liquidity
\u00a0
risk and credit risk. The Group
seeks to minimize potential adverse effects of such risks
\u00a0
through sound business practices and risk management
\u00a0
programs. No hedge
accounting is applied.
\u00a0
\n
\u00a0
\n
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Market risk
The Group is exposed to market risks driven by
\u00a0
fluctuations in oil and gas prices, foreign currency
\u00a0
exchange rates and interest rates.
\u00a0
Oil and gas price risk
DNO\u2019s revenues are generated from the sale of oil
\u00a0
and gas. The Group had no oil and gas
\u00a0
price hedging arrangements at yearend 2024
although it monitors its oil and gas price risk on
\u00a0
a continuous basis and evaluates hedging alternatives.
The following table illustrates the impact on reported 2023
\u00a0
and 2024 profit/loss before income tax from
\u00a0
oil and gas price fluctuations
deemed reasonable and possible, with all other
\u00a0
variables held constant. In addition to driving revenues,
\u00a0
price fluctuations or the
expectations of price fluctuations could impact DNO\u2019s capital
\u00a0
expenditure levels and impairment assessments.
\u00a0
See Note 10 for a
sensitivity analysis related to the impairment assessment
\u00a0
of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
\u00a0
USD (percent)
\u00a0
(USD mill)
2024
+/- 15.0
\u00a0
+/- 87.9
2023
+/- 15.0
\u00a0
+/- 77.9
Foreign currency exchange rate risk
Revenues from oil and gas production are primarily
\u00a0
in USD and EUR, while operating expenses,
\u00a0
capital and abandonment expenditures
are primarily denominated in USD, NOK and GBP. Dividend distributions from the Company are
\u00a0
in NOK. The Group had no currency
hedging instruments at yearend 2024 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP to USD exchange
\u00a0
rates, with all other variables
held constant. The other currencies (e.g., AED, IQD) are
\u00a0
not included as the exposure is deemed
\u00a0
immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2024
+ 10.0
4.4
2024
- 10.0
-4.4
2023
+ 10.0
6.0
2023
- 10.0
-6.0
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2024
+ 10.0
30.0
2024
- 10.0
-30.0
2023
+ 10.0
36.7
2023
- 10.0
-36.7
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2024
+ 10.0
10.8
2024
- 10.0
-10.8
2023
+ 10.0
0.3
2023
- 10.0
-0.3
Interest rate risk
As most of the Group\u2019s financing derives from bond loans
\u00a0
which are issued in USD and at fixed
\u00a0
interest rates, the Group does not
engage in interest rate hedging. Interest rate exposure
\u00a0
on the RBL is considered limited and no hedging
\u00a0
arrangement was in place
during 2024. The Group is exposed to interest rate
\u00a0
risk on its cash deposits held at floating interest
\u00a0
rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from a change in interest
rates on that portion of interest-bearing liabilities and
\u00a0
cash deposits deemed reasonable and possible,
\u00a0
with all other variables held
constant.
\u00a0
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2024
+/- 100
+/-7.5
2023
+/- 100
+/-7.6
Liquidity risk
Liquidity risk is the risk that suitable sources of
\u00a0
funding for the Group\u2019s business activities may not be
\u00a0
available. Prudent liquidity risk
management requires sufficient cash balances, credit facilities
\u00a0
and other financial resources to maintain
\u00a0
financial flexibility under
dynamic market conditions. The Group\u2019s principal sources of liquidity
\u00a0
are operating cash flows from its producing assets
\u00a0
in Kurdistan
and the North Sea. In addition to its operating
\u00a0
cash flows, the Group relies on the debt capital markets
\u00a0
for both short- and long-term
funding, see Note 18. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the senior management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 13) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27, which are made on a regular
\u00a0
basis pursuant to an approved budget and work program.
\u00a0
The cash distributions anticipated
to be received from Foxtrot International will be
\u00a0
sufficient to enable the Company to meet all of its
\u00a0
scheduled and anticipated obligations.
\u00a0
Excessive risk concentration
Concentrations arise when a number of counterparties
\u00a0
are engaged in similar business activities, or
\u00a0
activities in the same geographical
region, or have economic features that would
\u00a0
cause their ability to meet contractual obligations
\u00a0
to be similarly affected by changes in
economic, political or other conditions. DNO\u2019s revenues
\u00a0
in 2024 derived primarily from production in
\u00a0
the Tawke license in Kurdistan (see
also entitlement risk described in Note 3) and from
\u00a0
several licenses in the North Sea. The Group actively
\u00a0
seeks to reduce such risk
through organic growth and asset acquisitions aimed
\u00a0
at further diversifying its revenue sources.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
\u00a0
\n
\u00a0
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\n
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\n
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\n
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\n
\u00a0
\n
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2024
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
-
400.0
400.0
Other provisions and charges
-
-
13.4
0.8
-
Taxes payable
-
-
-
-
-
Trade and other payables
-
223.7
100.0
-
-
Total liabilities
-
223.7
113.4
400.8
400.0
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2023
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
131.2
435.0
-
Other provisions and charges
-
-
9.1
-
-
Taxes payable
-
-
4.6
-
-
Trade and other payables
-
218.0
2.0
-
-
Total liabilities
-
218.0
146.9
435.0
-
* Face value of the bonds was USD 750.0 million at yearend 2024 (USD 531.2 million at yearend 2023).
For changes in liabilities arising from financing activities,
\u00a0
see Note 18.
\u00a0
\n
\u00a0
\n
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\u00a0
\n
Credit risk
Credit risk is the risk that a customer or counterparty
\u00a0
to a financial instrument will fail to perform or
\u00a0
fail to pay amounts due causing
financial loss to the Group. The Group\u2019s exposure
\u00a0
to credit risk is mainly related to its outstanding
\u00a0
trade debtors. Other counterparty
credit risk exposure to DNO is related to its
\u00a0
cash deposits with banks and financial institutions.
\u00a0
The table below provides an overview of
financial assets exposed to credit risk at yearend.
\u00a0
Years ended 31 December
USD million
2024
2023
Trade debtors (non-current portion) (Note 15)
98.2
129.8
Trade debtors (Note 15)
185.0
149.5
Other receivables (Note 15)
153.1
115.9
Tax receivables
\u00a0
27.5
-
Cash and cash equivalents
899.0
718.8
Total
\u00a0
1,362.9
1,114.1
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 15 regarding ELC assessment
\u00a0
of the Kurdistan receivables.
The table below shows the aging of trade debtors and
\u00a0
information about credit risk exposure using a
\u00a0
provision matrix.
\u00a0
Contract
Days past due (trade debtors)
USD million
assets
Current
< 30 days
30-60 days
61-90 days
> 90 days
Total
As of 31 December 2024
Trade debtors (nominal value) (Note 15)
-
17.7
\u00a0
-
\u00a0
\u00a0
-
\u00a0
\u00a0
-
\u00a0
298.1
315.9
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2023
Trade debtors (nominal value) (Note 15)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Cash deposits
Credit risk from balances with banks and financial institutions
\u00a0
is managed by the Group\u2019s treasury function. The Group
\u00a0
limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the total equity and equity ratio, which is
\u00a0
calculated as total equity divided by total assets.
The financial covenants of the bond loans require a
\u00a0
minimum of USD 40 million of liquidity and
\u00a0
that the Group maintain either an equity
ratio of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
\u00a0
\n
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\u00a0
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\n
\u00a0
\n
\u00a0
\n
There is also a restriction on declaring or
\u00a0
making any dividend payments if the liquidity
\u00a0
of the Company is less than USD 80 million
immediately after such distribution is made, see Note
\u00a0
18. The equity ratio has dropped primarily due
\u00a0
to the issue of DNO05 bond,
recognition of decommissioning liabilities in connection
\u00a0
with acquisitions and a net loss in 2024. The
\u00a0
table below shows the book equity
ratio at yearend.
\u00a0
No changes were made in the objectives, policies
\u00a0
or processes for managing capital during 2024
\u00a0
and 2023.
Years ended 31 December
USD million
2024
2023
Total equity
1,080.0
1,234.8
Total assets
2,966.1
2,638.3
Equity ratio
36.4%
46.8%
Fair value measurement
Assets and liabilities for which fair value is measured
\u00a0
or disclosed in the financial statements are
\u00a0
categorized within the fair value
hierarchy as described below.
Level 1: quoted prices (unadjusted) in active
\u00a0
markets for identical assets or liabilities.
Level 2: inputs other than quoted prices included within
\u00a0
Level 1 that are observable for the asset or liability, either directly
\u00a0
or indirectly.
Level 3: inputs for the asset or liability that are
\u00a0
not based on observable market data (unobservable
\u00a0
inputs).
\u00a0
The following table shows the carrying amounts
\u00a0
and fair values of financial liabilities, including
\u00a0
their levels in the fair value hierarchy. It
does not include the carrying amounts and fair
\u00a0
value information for financial assets and financial
\u00a0
liabilities not measured or disclosed at
fair value if the carrying amount is a reasonable approximation
\u00a0
of fair value.
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2024 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
18
790.5
790.5
31 December 2024
762.4
-
50.0
Interest-bearing liabilities (current)
18
-
-
-
-
-
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2023 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
18
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
18
166.2
166.2
130.9
-
35.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_116": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Market risk
The Group is exposed to market risks driven by
\u00a0
fluctuations in oil and gas prices, foreign currency
\u00a0
exchange rates and interest rates.
\u00a0
Oil and gas price risk
DNO\u2019s revenues are generated from the sale of oil
\u00a0
and gas. The Group had no oil and gas
\u00a0
price hedging arrangements at yearend 2024
although it monitors its oil and gas price risk on
\u00a0
a continuous basis and evaluates hedging alternatives.
The following table illustrates the impact on reported 2023
\u00a0
and 2024 profit/loss before income tax from
\u00a0
oil and gas price fluctuations
deemed reasonable and possible, with all other
\u00a0
variables held constant. In addition to driving revenues,
\u00a0
price fluctuations or the
expectations of price fluctuations could impact DNO\u2019s capital
\u00a0
expenditure levels and impairment assessments.
\u00a0
See Note 10 for a
sensitivity analysis related to the impairment assessment
\u00a0
of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
\u00a0
USD (percent)
\u00a0
(USD mill)
2024
+/- 15.0
\u00a0
+/- 87.9
2023
+/- 15.0
\u00a0
+/- 77.9
Foreign currency exchange rate risk
Revenues from oil and gas production are primarily
\u00a0
in USD and EUR, while operating expenses,
\u00a0
capital and abandonment expenditures
are primarily denominated in USD, NOK and GBP. Dividend distributions from the Company are
\u00a0
in NOK. The Group had no currency
hedging instruments at yearend 2024 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
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\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
\n
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\n
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\n
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP to USD exchange
\u00a0
rates, with all other variables
held constant. The other currencies (e.g., AED, IQD) are
\u00a0
not included as the exposure is deemed
\u00a0
immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2024
+ 10.0
4.4
2024
- 10.0
-4.4
2023
+ 10.0
6.0
2023
- 10.0
-6.0
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2024
+ 10.0
30.0
2024
- 10.0
-30.0
2023
+ 10.0
36.7
2023
- 10.0
-36.7
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2024
+ 10.0
10.8
2024
- 10.0
-10.8
2023
+ 10.0
0.3
2023
- 10.0
-0.3
Interest rate risk
As most of the Group\u2019s financing derives from bond loans
\u00a0
which are issued in USD and at fixed
\u00a0
interest rates, the Group does not
engage in interest rate hedging. Interest rate exposure
\u00a0
on the RBL is considered limited and no hedging
\u00a0
arrangement was in place
during 2024. The Group is exposed to interest rate
\u00a0
risk on its cash deposits held at floating interest
\u00a0
rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/loss before income tax in 2023 and 2024
\u00a0
from a change in interest
rates on that portion of interest-bearing liabilities and
\u00a0
cash deposits deemed reasonable and possible,
\u00a0
with all other variables held
constant.
\u00a0
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2024
+/- 100
+/-7.5
2023
+/- 100
+/-7.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfMarketRiskExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_117": { "value": "
Liquidity risk
Liquidity risk is the risk that suitable sources of
\u00a0
funding for the Group\u2019s business activities may not be
\u00a0
available. Prudent liquidity risk
management requires sufficient cash balances, credit facilities
\u00a0
and other financial resources to maintain
\u00a0
financial flexibility under
dynamic market conditions. The Group\u2019s principal sources of liquidity
\u00a0
are operating cash flows from its producing assets
\u00a0
in Kurdistan
and the North Sea. In addition to its operating
\u00a0
cash flows, the Group relies on the debt capital markets
\u00a0
for both short- and long-term
funding, see Note 18. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the senior management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 13) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27, which are made on a regular
\u00a0
basis pursuant to an approved budget and work program.
\u00a0
The cash distributions anticipated
to be received from Foxtrot International will be
\u00a0
sufficient to enable the Company to meet all of its
\u00a0
scheduled and anticipated obligations.
\u00a0
Excessive risk concentration
Concentrations arise when a number of counterparties
\u00a0
are engaged in similar business activities, or
\u00a0
activities in the same geographical
region, or have economic features that would
\u00a0
cause their ability to meet contractual obligations
\u00a0
to be similarly affected by changes in
economic, political or other conditions. DNO\u2019s revenues
\u00a0
in 2024 derived primarily from production in
\u00a0
the Tawke license in Kurdistan (see
also entitlement risk described in Note 3) and from
\u00a0
several licenses in the North Sea. The Group actively
\u00a0
seeks to reduce such risk
through organic growth and asset acquisitions aimed
\u00a0
at further diversifying its revenue sources.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
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\n
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\n
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\n
\u00a0
\n
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\n
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\n
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\n
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
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\u00a0
\n
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2024
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
-
400.0
400.0
Other provisions and charges
-
-
13.4
0.8
-
Taxes payable
-
-
-
-
-
Trade and other payables
-
223.7
100.0
-
-
Total liabilities
-
223.7
113.4
400.8
400.0
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2023
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
-
131.2
435.0
-
Other provisions and charges
-
-
9.1
-
-
Taxes payable
-
-
4.6
-
-
Trade and other payables
-
218.0
2.0
-
-
Total liabilities
-
218.0
146.9
435.0
-
* Face value of the bonds was USD 750.0 million at yearend 2024 (USD 531.2 million at yearend 2023).
For changes in liabilities arising from financing activities,
\u00a0
see Note 18.
", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_118": { "value": "
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\n
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\n
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\u00a0
\n
\u00a0
\n
\u00a0
\n
Credit risk
Credit risk is the risk that a customer or counterparty
\u00a0
to a financial instrument will fail to perform or
\u00a0
fail to pay amounts due causing
financial loss to the Group. The Group\u2019s exposure
\u00a0
to credit risk is mainly related to its outstanding
\u00a0
trade debtors. Other counterparty
credit risk exposure to DNO is related to its
\u00a0
cash deposits with banks and financial institutions.
\u00a0
The table below provides an overview of
financial assets exposed to credit risk at yearend.
\u00a0
Years ended 31 December
USD million
2024
2023
Trade debtors (non-current portion) (Note 15)
98.2
129.8
Trade debtors (Note 15)
185.0
149.5
Other receivables (Note 15)
153.1
115.9
Tax receivables
\u00a0
27.5
-
Cash and cash equivalents
899.0
718.8
Total
\u00a0
1,362.9
1,114.1
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 15 regarding ELC assessment
\u00a0
of the Kurdistan receivables.
The table below shows the aging of trade debtors and
\u00a0
information about credit risk exposure using a
\u00a0
provision matrix.
\u00a0
Contract
Days past due (trade debtors)
USD million
assets
Current
< 30 days
30-60 days
61-90 days
> 90 days
Total
As of 31 December 2024
Trade debtors (nominal value) (Note 15)
-
17.7
\u00a0
-
\u00a0
\u00a0
-
\u00a0
\u00a0
-
\u00a0
298.1
315.9
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2023
Trade debtors (nominal value) (Note 15)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Cash deposits
Credit risk from balances with banks and financial institutions
\u00a0
is managed by the Group\u2019s treasury function. The Group
\u00a0
limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCreditRiskExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_119": { "value": "
Note 24
Commitments and contingencies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Commitments and contingencies
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as
\u00a0
a result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
\u00a0
Contingent liabilities are not recognized but are
\u00a0
disclosed unless the possibility of an outflow
\u00a0
of resources is remote.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Contingencies, provisions
\u00a0
and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or more uncertain future event
\u00a0
occurs or fails to occur. The
assessment of the existence and potential quantum of
\u00a0
contingencies inherently involves the exercise of
\u00a0
significant judgment and the
use of estimates regarding the outcome of future
\u00a0
events. Management uses its judgment to evaluate
\u00a0
certain provisions and legal
disputes in order to ensure the correct accounting
\u00a0
treatment.
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen \u2013 Block 53
The Ministry of Oil and Minerals (MOM or
\u00a0
Ministry) of Yemen filed an arbitration claim against operator Dove Energy Limited
\u00a0
and the
other partners (including DNO Yemen AS) for allegedly wrongful withdrawal from
\u00a0
Block 53. An arbitral award was rendered in
\u00a0
July 2019
partially in the Ministry\u2019s favor in the amount of USD
\u00a0
29 million (out of a USD 171 million
\u00a0
claim). The Contractor (including DNO Yemen
AS) filed for annulment proceedings in the Paris Court
\u00a0
d\u2019Appel which is still pending before
\u00a0
the French Supreme Court.
\u00a0
In 2023, a net amount of USD 29.2 million
\u00a0
was paid by DNO Yemen AS to MOM in connection with arbitral awards
\u00a0
resolving disputes
regarding
\u00a0
inter alia
\u00a0
Block 53. DNO has taken action against a former
\u00a0
license partner to the amount paid, in respect of
\u00a0
which that partner
is liable, and an award has been rendered
\u00a0
in DNO\u2019s favor.
Other claims
During the normal course of its business, the
\u00a0
Group may be involved in other legal proceedings
\u00a0
and unresolved claims. The Group has
made provisions in its consolidated financial statements
\u00a0
for probable liabilities related to litigation and
\u00a0
claims based on management's
best judgment and in line with IAS 37. Other than what
\u00a0
is set out above, DNO is not aware of
\u00a0
any governmental, legal or arbitral
proceedings (including any such proceedings which are
\u00a0
pending or threatened) initiated against DNO
\u00a0
and which may have significant
effects on DNO\u2019s results of operations, cash flows or financial
\u00a0
position.
Capital commitments and abandonment expenditures
Based on work plans as of yearend 2024 and
\u00a0
contingent on future market conditions including
\u00a0
development in the oil price, and
outcome of ongoing discussions related to recovery
\u00a0
of arrears for past oil deliveries to the KRG
\u00a0
and payment terms and conditions for
any future oil exports, the Group\u2019s projected operational spend
\u00a0
for 2025 comprising of capital and exploration expenditures,
abandonment expenditures and operational expenditures
\u00a0
amounts to USD 750 million. The projected
\u00a0
operational spend reflects the
Group\u2019s share of planned drilling and facility investments and
\u00a0
decommissioning plan in its licenses for 2025. These
\u00a0
work plans are
subject to revisions.
Guarantees at yearend
The Company has issued parent company guarantees
\u00a0
to authorities in Norway and the UK on behalf
\u00a0
of certain subsidiaries that
participate in licenses on the NCS and the UKCS.
\u00a0
The Company has furthermore issued parent
\u00a0
company guarantees in connection with
surety bonds and asset transactions.
Liability for damages/insurance
Installations and operations are covered by various insurance
\u00a0
policies.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_120": { "value": "
Note 24
Commitments and contingencies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Commitments and contingencies
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as
\u00a0
a result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
\u00a0
Contingent liabilities are not recognized but are
\u00a0
disclosed unless the possibility of an outflow
\u00a0
of resources is remote.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Contingencies, provisions
\u00a0
and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or more uncertain future event
\u00a0
occurs or fails to occur. The
assessment of the existence and potential quantum of
\u00a0
contingencies inherently involves the exercise of
\u00a0
significant judgment and the
use of estimates regarding the outcome of future
\u00a0
events. Management uses its judgment to evaluate
\u00a0
certain provisions and legal
disputes in order to ensure the correct accounting
\u00a0
treatment.
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen \u2013 Block 53
The Ministry of Oil and Minerals (MOM or
\u00a0
Ministry) of Yemen filed an arbitration claim against operator Dove Energy Limited
\u00a0
and the
other partners (including DNO Yemen AS) for allegedly wrongful withdrawal from
\u00a0
Block 53. An arbitral award was rendered in
\u00a0
July 2019
partially in the Ministry\u2019s favor in the amount of USD
\u00a0
29 million (out of a USD 171 million
\u00a0
claim). The Contractor (including DNO Yemen
AS) filed for annulment proceedings in the Paris Court
\u00a0
d\u2019Appel which is still pending before
\u00a0
the French Supreme Court.
\u00a0
In 2023, a net amount of USD 29.2 million
\u00a0
was paid by DNO Yemen AS to MOM in connection with arbitral awards
\u00a0
resolving disputes
regarding
\u00a0
inter alia
\u00a0
Block 53. DNO has taken action against a former
\u00a0
license partner to the amount paid, in respect of
\u00a0
which that partner
is liable, and an award has been rendered
\u00a0
in DNO\u2019s favor.
Other claims
During the normal course of its business, the
\u00a0
Group may be involved in other legal proceedings
\u00a0
and unresolved claims. The Group has
made provisions in its consolidated financial statements
\u00a0
for probable liabilities related to litigation and
\u00a0
claims based on management's
best judgment and in line with IAS 37. Other than what
\u00a0
is set out above, DNO is not aware of
\u00a0
any governmental, legal or arbitral
proceedings (including any such proceedings which are
\u00a0
pending or threatened) initiated against DNO
\u00a0
and which may have significant
effects on DNO\u2019s results of operations, cash flows or financial
\u00a0
position.
Capital commitments and abandonment expenditures
Based on work plans as of yearend 2024 and
\u00a0
contingent on future market conditions including
\u00a0
development in the oil price, and
outcome of ongoing discussions related to recovery
\u00a0
of arrears for past oil deliveries to the KRG
\u00a0
and payment terms and conditions for
any future oil exports, the Group\u2019s projected operational spend
\u00a0
for 2025 comprising of capital and exploration expenditures,
abandonment expenditures and operational expenditures
\u00a0
amounts to USD 750 million. The projected
\u00a0
operational spend reflects the
Group\u2019s share of planned drilling and facility investments and
\u00a0
decommissioning plan in its licenses for 2025. These
\u00a0
work plans are
subject to revisions.
Guarantees at yearend
The Company has issued parent company guarantees
\u00a0
to authorities in Norway and the UK on behalf
\u00a0
of certain subsidiaries that
participate in licenses on the NCS and the UKCS.
\u00a0
The Company has furthermore issued parent
\u00a0
company guarantees in connection with
surety bonds and asset transactions.
Liability for damages/insurance
Installations and operations are covered by various insurance
\u00a0
policies.
", "dimensions": { "concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_121": { "value": "
Note 24
Commitments and contingencies
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Commitments and contingencies
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as
\u00a0
a result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
\u00a0
Contingent liabilities are not recognized but are
\u00a0
disclosed unless the possibility of an outflow
\u00a0
of resources is remote.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Contingencies, provisions
\u00a0
and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or more uncertain future event
\u00a0
occurs or fails to occur. The
assessment of the existence and potential quantum of
\u00a0
contingencies inherently involves the exercise of
\u00a0
significant judgment and the
use of estimates regarding the outcome of future
\u00a0
events. Management uses its judgment to evaluate
\u00a0
certain provisions and legal
disputes in order to ensure the correct accounting
\u00a0
treatment.
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen \u2013 Block 53
The Ministry of Oil and Minerals (MOM or
\u00a0
Ministry) of Yemen filed an arbitration claim against operator Dove Energy Limited
\u00a0
and the
other partners (including DNO Yemen AS) for allegedly wrongful withdrawal from
\u00a0
Block 53. An arbitral award was rendered in
\u00a0
July 2019
partially in the Ministry\u2019s favor in the amount of USD
\u00a0
29 million (out of a USD 171 million
\u00a0
claim). The Contractor (including DNO Yemen
AS) filed for annulment proceedings in the Paris Court
\u00a0
d\u2019Appel which is still pending before
\u00a0
the French Supreme Court.
\u00a0
In 2023, a net amount of USD 29.2 million
\u00a0
was paid by DNO Yemen AS to MOM in connection with arbitral awards
\u00a0
resolving disputes
regarding
\u00a0
inter alia
\u00a0
Block 53. DNO has taken action against a former
\u00a0
license partner to the amount paid, in respect of
\u00a0
which that partner
is liable, and an award has been rendered
\u00a0
in DNO\u2019s favor.
Other claims
During the normal course of its business, the
\u00a0
Group may be involved in other legal proceedings
\u00a0
and unresolved claims. The Group has
made provisions in its consolidated financial statements
\u00a0
for probable liabilities related to litigation and
\u00a0
claims based on management's
best judgment and in line with IAS 37. Other than what
\u00a0
is set out above, DNO is not aware of
\u00a0
any governmental, legal or arbitral
proceedings (including any such proceedings which are
\u00a0
pending or threatened) initiated against DNO
\u00a0
and which may have significant
effects on DNO\u2019s results of operations, cash flows or financial
\u00a0
position.
Capital commitments and abandonment expenditures
Based on work plans as of yearend 2024 and
\u00a0
contingent on future market conditions including
\u00a0
development in the oil price, and
outcome of ongoing discussions related to recovery
\u00a0
of arrears for past oil deliveries to the KRG
\u00a0
and payment terms and conditions for
any future oil exports, the Group\u2019s projected operational spend
\u00a0
for 2025 comprising of capital and exploration expenditures,
abandonment expenditures and operational expenditures
\u00a0
amounts to USD 750 million. The projected
\u00a0
operational spend reflects the
Group\u2019s share of planned drilling and facility investments and
\u00a0
decommissioning plan in its licenses for 2025. These
\u00a0
work plans are
subject to revisions.
Guarantees at yearend
The Company has issued parent company guarantees
\u00a0
to authorities in Norway and the UK on behalf
\u00a0
of certain subsidiaries that
participate in licenses on the NCS and the UKCS.
\u00a0
The Company has furthermore issued parent
\u00a0
company guarantees in connection with
surety bonds and asset transactions.
Liability for damages/insurance
Installations and operations are covered by various insurance
\u00a0
policies.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_122": { "value": "
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\n
\u00a0
\n
Accounting policies
Commitments and contingencies
A provision is recognized when the Group has
\u00a0
a present obligation (legal or constructive) as
\u00a0
a result of a past event, there is likely
that an outflow of resources will be required
\u00a0
to settle the obligation and a reliable estimate
\u00a0
can be made of the obligation amount.
\u00a0
Contingent liabilities are not recognized but are
\u00a0
disclosed unless the possibility of an outflow
\u00a0
of resources is remote.
\u00a0
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Estimation uncertainty: Contingencies, provisions
\u00a0
and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or more uncertain future event
\u00a0
occurs or fails to occur. The
assessment of the existence and potential quantum of
\u00a0
contingencies inherently involves the exercise of
\u00a0
significant judgment and the
use of estimates regarding the outcome of future
\u00a0
events. Management uses its judgment to evaluate
\u00a0
certain provisions and legal
disputes in order to ensure the correct accounting
\u00a0
treatment.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_123": { "value": "
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Note 25
Earnings per share
1 January - 31 December
2024
2023
Net profit/loss attributable to ordinary equity holders of the parent (USD million)
-27.1
18.6
Weighted average number of ordinary shares excluding treasury shares (millions)
975.00
980.04
Earnings per share, basic (USD per share)
-0.03
0.02
Earnings per share, diluted (USD per share)
-0.03
0.02
Basic earnings per share are calculated by dividing
\u00a0
the net profit/loss attributable to equity holders
\u00a0
by the weighted average number of
outstanding ordinary shares during the period, excluding
\u00a0
ordinary shares purchased and held as treasury
\u00a0
shares.
The Company did not have any potential dilutive
\u00a0
shares at yearend 2024.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_124": { "value": "
Note 26
Group companies and other companies
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\n
Ownership and voting
USD million
Office
interest (percent)
Shares in the Company's subsidiaries
DNO Iraq AS
Norway
100
DNO UK Limited
United Kingdom
100
DNO Mena AS
Norway
100
DNO Technical Services AS
Norway
100
DNO Yemen AS
Norway
100
DNO North Sea plc
United Kingdom
100
Mondoil Enterprises LLC
United States
100
Shares in subsidiaries owned through subsidiaries
DNO Mena AS
West Limited
Bermuda
100
DNO Tunisia Limited
Guernsey
100
RAK Petroleum Public Company Limited
United Arab Emirates
100
DNO North Sea plc
DNO Norge AS
Norway
100
DNO North Sea (U.K.) Limited
United Kingdom
100
DNO North Sea (ROGB) Limited
United Kingdom
100
DNO North Sea (Energy) Limited
United Kingdom
100
DNO Exploration UK Limited
United Kingdom
100
DNO North Sea SIP EBT Limited
United Kingdom
100
Shares in other entities, indirectly (equity accounted)
Mondoil C\u00f4te d\u2019Ivoire LLC
United States
50
Foxtrot International
Cayman Islands
33.33
The Group\u2019s operations in Kurdistan are carried out through
\u00a0
its subsidiary DNO Iraq AS, while activities on
\u00a0
the NCS are carried out
through DNO Norge AS. UKCS activities are carried
\u00a0
out through DNO North Sea (U.K.) Limited,
\u00a0
DNO North Sea (ROGB) Limited and
DNO Exploration UK Limited.
\u00a0
DNO Exploration UK Limited was disposed from
\u00a0
DNO ASA to DNO North Sea plc in 2024.
\u00a0
Activities in
C\u00f4te d'Ivoire are carried out by Foxtrot International,
\u00a0
in which the Company\u2019s indirect ownership of 33.33
\u00a0
percent is accounted for using
the equity method. DNO ASA, DNO Technical Services AS and DNO North Sea plc provide
\u00a0
technical support and services to the
various companies in the Group. The other subsidiaries
\u00a0
from the table above had minimal activity during
\u00a0
the year. In 2024 DNO Oman
Limited was renamed to West Limited and DNO Oman
\u00a0
Block 8 Limited was liquidated.
", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_125": { "value": "
Note 27
Oil and gas reserves (unaudited)
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\n
Estimation uncertainty: Reserves and resources estimates
\u00a0
DNO\u2019s reserves and contingent resources are estimated
\u00a0
and classified by the Company in accordance
\u00a0
with the rules and guidelines
of the Society of Petroleum Engineers (SPE) and are
\u00a0
in conformity with requirements from the Oslo Stock
\u00a0
Exchange for the reporting
of reserves and resources. All estimates of reserves
\u00a0
and resources involve uncertainty.
Important factors that could cause actual results to
\u00a0
differ from the estimates include, but are not limited
\u00a0
to: technical, geological and
geotechnical conditions; economic and market conditions; oil
\u00a0
and gas prices; changes in government regulations;
\u00a0
political
developments; interest rates; and currency exchange
\u00a0
rates. Specific parameters of uncertainty related
\u00a0
to the field/reservoir include
but are not limited to: reservoir pressure and
\u00a0
porosity; recovery factors; water cut development;
\u00a0
production decline rates; gas/oil
ratios; and oil properties.
\u00a0
Changes in commodity prices and costs may impact economic
\u00a0
cut-off and remaining reserves, which may change the
\u00a0
timing of any
decommissioning activities. Future changes to estimated
\u00a0
reserves can also have a material effect on depreciation,
\u00a0
impairment of oil
and gas fields and operating results. The Group
\u00a0
may also not be able to commercially develop
\u00a0
its contingent resources that are used
in impairment assessments or acquisition accounting
\u00a0
where the fair value approach is applied.
Net reserves by region/field as of 31 December
\u00a0
2024
Proven (1P)
Proven and probable (2P)
Proven, probable and possible (3P)
MMboe
Oil
NGL
Gas
Total
Oil
NGL
Gas
Total
Oil
NGL
Gas
Total
Tawke
91.6
-
-
91.6
127.1
-
-
127.1
142.1
-
-
142.1
Peshkabir
51.2
-
-
51.2
97.8
-
-
97.8
115.8
-
-
115.8
Kurdistan
142.8
-
-
142.8
224.9
-
-
224.9
257.9
-
-
257.9
Arran
0.3
-
1.4
1.7
0.4
-
2.0
2.4
0.6
-
2.9
3.6
Blane
0.3
0.0
-
0.3
0.4
0.0
-
0.4
0.5
0.0
-
0.5
Enoch
0.0
-
-
0.0
0.0
-
-
0.0
0.0
-
-
0.0
UK
0.6
0.0
1.4
1.9
0.8
0.0
2.0
2.8
1.2
0.0
2.9
4.1
Alve
0.4
0.8
3.2
4.3
0.4
0.9
3.3
4.7
0.5
1.0
3.5
5.0
Andvare
0.1
0.5
2.5
3.1
0.2
0.8
3.5
4.5
0.3
1.2
4.9
6.4
Berling
1.5
1.1
4.8
7.3
2.2
1.6
6.8
10.6
3.1
2.2
8.8
14.2
Bestla
2.0
0.2
0.7
2.9
5.7
0.5
1.4
7.6
11.2
0.7
2.5
14.4
Brage
0.8
0.0
0.0
0.8
1.4
0.0
0.1
1.6
1.9
0.1
0.3
2.3
Fenja
0.4
0.1
0.7
1.1
0.8
0.1
0.9
1.8
1.3
0.1
1.3
2.7
Marulk
0.0
0.0
0.5
0.5
0.1
0.1
1.0
1.2
0.1
0.2
1.7
2.0
Norne
0.3
0.0
0.1
0.4
0.4
0.0
0.1
0.5
0.6
0.0
0.2
0.8
Oda
0.4
0.0
0.0
0.4
0.5
0.0
0.0
0.5
0.6
0.0
0.0
0.7
Skuld
0.3
0.0
0.2
0.5
0.4
0.0
0.2
0.6
0.6
0.0
0.2
0.7
Tambar
0.4
0.0
0.1
0.5
1.1
0.1
0.2
1.4
1.8
0.1
0.3
2.1
Tambar East
0.9
0.1
0.1
1.1
1.7
0.1
0.2
2.0
2.4
0.2
0.3
2.8
Trym
0.2
-
1.0
1.1
0.3
-
1.2
1.5
0.4
-
1.5
1.8
Ula
0.5
0.0
-
0.5
0.9
0.1
-
0.9
1.2
0.1
-
1.4
Urd
0.4
-
-
0.4
0.7
-
-
0.7
0.9
-
-
0.9
Verdande
1.8
0.0
0.3
2.1
3.0
0.1
0.5
3.6
4.2
0.1
0.8
5.1
Vilje
0.6
-
0.0
0.6
1.2
\u00a0
-
\u00a0
0.1
1.3
2.5
-
0.1
2.7
Norway
10.8
2.9
13.9
27.7
20.9
4.5
19.5
44.9
33.6
6.1
26.3
66.0
Subtotal Consolidated reserves
172.5
272.6
328.0
C\u00f4te d\u2019Ivoire CI-27
0.0
-
6.4
6.4
0.1
-
9.3
9.4
0.2
-
11.9
12.0
West Africa
0.0
-
6.4
6.4
0.1
-
9.3
9.4
0.2
-
11.9
12.0
Subtotal Equity accounted reserves
6.4
9.4
12.0
Total Group
178.9
281.9
340.1
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Reserves development by segment (net to DNO)
Kurdistan
North Sea
Subtotal
West Africa
Total Group
MMboe
1P
2P
3P
1P
2P
3P
1P
2P
3P
1P
2P
3P
1P
2P
3P
As of 1 January 2023
190.9
245.3
316.0
25.0
36.5
49.4
215.9
281.8
365.4
4.4
10.3
21.3
220.3
292.1
386.7
Production
-12.7
-12.7
-12.7
-5.2
-5.2
-5.2
-17.9
-17.9
-17.9
-1.3
-1.3
-1.3
-19.1
-19.1
-19.1
Acquisitions
-
-
-
-
-
-
-
-
-
4.5
1.5
-6.9
4.5
1.5
-6.9
Divestments
-
-
-
-
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
-
-
-
-
New developments
-
-
-
-
-
-
-
-
-
-
-
-
Revision of previous estimates
-3.2
11.9
-5.3
4.0
3.8
5.1
0.9
15.7
-0.2
0.9
15.7
-0.2
As of 31 December 2023
175.1
244.5
298.0
23.8
35.1
49.3
198.9
279.6
347.3
7.6
10.5
13.2
206.4
290.1
360.5
Production
-21.6
-21.6
-21.6
-5.6
-5.6
-5.6
-27.1
-27.1
-27.1
-1.1
-1.1
-1.1
-28.3
-28.3
-28.3
Acquisitions
-
-
-
5.9
9.0
12.8
5.9
9.0
12.8
5.9
9.0
12.8
Divestments
-
-
-
-1.0
-1.2
-1.4
-1.0
-1.2
-1.4
-1.0
-1.2
-1.4
Extensions and discoveries
-
-
-
-
-
-
-
-
-
-
-
-
New developments
-
-
-
2.9
7.6
14.4
2.9
7.6
14.4
2.9
7.6
14.4
Revision of previous estimates
-10.7
1.9
-18.5
3.6
2.8
0.5
-7.1
4.7
-18.0
-7.1
4.7
-18.0
As of 31 December 2024
142.8
224.9
257.9
29.6
47.7
70.2
172.5
272.6
328.0
6.4
9.4
12.0
178.9
281.9
340.1
Net Entitlement (NE) reserves by segment
Kurdistan
North Sea
Subtotal
West Africa
Total Group
MMboe
1P
2P
3P
1P
2P
3P
1P
2P
3P
1P
2P
3P
1P
2P
3P
As of 31 December 2023
60.9
74.0
82.7
23.8
35.1
49.3
84.7
109.1
132.0
4.9
6.8
8.3
89.6
115.9
140.3
As of 31 December 2024
50.3
69.4
75.0
29.6
47.7
70.2
80.0
117.1
145.1
4.2
6.3
7.8
84.2
123.4
152.9
The reserves and contingent resources are according
\u00a0
to the ASRR dated 2 April 2025. Reported reserves
\u00a0
fall within class 1-3 of the
NOD classification and 2C resources fall within
\u00a0
class 4-7.
\u00a0
The Company\u2019s ASRR has been prepared in accordance
\u00a0
with the Oslo Stock Exchange listing and
\u00a0
disclosure requirements Circular No.
1/2013. International petroleum consultants DeGolyer
\u00a0
and MacNaughton (D&M) carried out an independent
\u00a0
assessment of the Tawke
license (containing the Tawke and Peshkabir fields) and the Baeshiqa license (containing the
\u00a0
Baeshiqa and Zartik structures) in the
Kurdistan region of Iraq (Kurdistan). International
\u00a0
petroleum consultants RPS Energy Consultants
\u00a0
(RPS) carried out an independent
assessment of DNO reserves and resources in Norway
\u00a0
and the United Kingdom (UK). In Norway, contingent resources also
\u00a0
include
volumes that are classified as RC7F (production
\u00a0
not evaluated) as reported by the NOD. In 2023,
\u00a0
the international petroleum
consultants Beicip-Franlab carried out an independent
\u00a0
assessment of DNO's CI-27 license (held
\u00a0
through its indirect 33.33 percent
interest in the operating entity) in C\u00f4te d\u2019Ivoire.
\u00a0
For the P2543 license (Agar) in the UK and
\u00a0
Block 47 in Yemen, DNO\u2019s contingent
resources are internally assessed. The Dutch acreage
\u00a0
held by DNO does not hold any reserves
\u00a0
or resources.
At yearend 2024, DNO\u2019s net 1P reserves stood at 178.9
\u00a0
MMboe, compared to 206.4 MMboe at yearend
\u00a0
2023, after adjusting for
production during the year and changes due to acquisitions
\u00a0
and divestments, reclassifications and technical
\u00a0
revisions. On a 2P basis,
DNO\u2019s net reserves stood at 281.9 MMboe, compared to 290.1
\u00a0
MMboe at yearend 2023. On a 3P basis, DNO\u2019s net
\u00a0
reserves were
340.1 MMboe, compared to 360.5 MMboe at yearend
\u00a0
2023. DNO\u2019s net contingent (2C) resources were 213.4 MMboe,
\u00a0
up from 205.0
MMboe at yearend 2023 after adjusting for new discoveries,
\u00a0
volumes moved to reserves and technical revisions.
While net production of 28.3 MMboe during 2024
\u00a0
drew on DNO\u2019s reserves, the impact was partially offset
\u00a0
by acquisitions, volumes
moved up from contingent resources, as well as
\u00a0
technical revisions. Notably, DNO's 2024 acquisitions of a stake in the Arran field
offshore UK and Norne area assets in Norway added a
\u00a0
total of 4.9 MMboe in net 1P reserves, 7.8
\u00a0
MMboe in net 2P reserves and 11.4
MMboe in net 3P reserves (after allowing for divestment
\u00a0
of Ringhorne East, used as part of
\u00a0
the consideration for the Norne area
assets). Volumes moved from contingent resources to reserves all relate to
\u00a0
the 2024 sanctioning of the Bestla field development
\u00a0
in
Norway, which added 2.9 MMboe to 1P reserves, 7.6 MMboe to 2P reserves
\u00a0
and 14.4 MMboe to 3P reserves, all on
\u00a0
a net basis.
\u00a0
The Company\u2019s net yearend 2024 Reserve Life Index (R/P)
\u00a0
stood at 6.3 years on a 1P reserves basis,
\u00a0
10.0 years on a 2P reserves
basis and 12.0 years on a 3P reserves basis.
Net reserves in DNO\u2019s licenses governed by PSCs
\u00a0
(Kurdistan and C\u00f4te d\u2019Ivoire) are based on the
\u00a0
participation interest. Net Entitlement
(NE) reserves are net to DNO after royalty. Net reserves in these licenses reflect
\u00a0
DNO\u2019s share before government take while NE
reserves reflect DNO\u2019s share after government take. NE
\u00a0
reserves are based on economic evaluation of
\u00a0
the license agreements,
incorporating projections of future production, costs and
\u00a0
oil and gas prices. NE volumes may therefore
\u00a0
fluctuate over time, even if there
are no changes in the underlying gross and net
\u00a0
volumes.
Net and NE reserves in DNO\u2019s licenses not governed by
\u00a0
PSCs (Norway and the UK) are equivalent and
\u00a0
reflect gross reserves multiplied
by the Company\u2019s participating interest.
Note 28
Oil and gas license portfolio
\u00a0
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Kurdistan licenses
At yearend 2024, DNO held interests in two
\u00a0
licenses in Kurdistan. The Tawke license contains the producing Tawke and Peshkabir
fields. The Baeshiqa license contains two large structures
\u00a0
with multiple independent stacked target reservoirs,
\u00a0
including in the
Cretaceous, Jurassic and Triassic formations. The structures at Baeshiqa
\u00a0
and Zartik have the potential to be part of
\u00a0
a single
accumulation of hydrocarbons at one or more
\u00a0
of the geological formation intervals.
North Sea (Norway, the UK and other)
At yearend 2024, DNO held 85 offshore licenses in
\u00a0
Norway, seven offshore licenses in the UK and one offshore license in the
Netherlands.
West Africa (C\u00f4te d\u2019Ivoire)
Through a one-third stake in the operating company, Foxtrot International, DNO
\u00a0
holds a nine percent interest in C\u00f4te
\u00a0
d\u2019Ivoire\u2019s Block CI-
27. The block contains the Foxtrot gas field, the Mahi
\u00a0
gas field, the Marlin oil and gas field and
\u00a0
the Manta gas field. Formerly, Foxtrot
International also operated the CI-12 exploration
\u00a0
block, from which it withdrew in October 2024 after
\u00a0
having fulfilled the exploration
obligations pertaining to the license. In accordance
\u00a0
with IFRS, DNO\u2019s indirect interest in Foxtrot International
\u00a0
is accounted for using the
equity method (see Note 13).
Other
At yearend 2024, DNO held one onshore license
\u00a0
in Yemen.
As is customary in the oil and gas industry, most of the Group's assets are
\u00a0
held in partnership with other companies.
\u00a0
Below is an
overview of the Group's licenses, which are held
\u00a0
through several wholly-owned subsidiary companies.
\u00a0
As of 31 December 2024
Held through DNO as a subsidiary:
Participating
interest
\u00a0
Region/license
(percent)
Operator
Partner(s)
Kurdistan
Tawke PSC
75.0
DNO Iraq AS
Genel Energy International Limited
Baeshiqa PSC
64.0
DNO Iraq AS
Turkish Energy Company Limited, Kurdistan Regional Government
Norway
PL006 C (SE Tor)
65.0
DNO Norge AS
Aker BP ASA
PL018ES
45.0
DNO Norge AS
Sval Energi AS, A/S Norske shell
PL019 (Ula)
20.0
Aker BP ASA
DNO Norge AS
PL019 E (Ula)
20.0
Aker BP ASA
DNO Norge AS
PL019 F (Ula)
45.0
Aker BP ASA
DNO Norge AS
PL036 D (Vilje)
28.9
Aker BP ASA
DNO Norge AS, ORLEN Upstream Norway AS
PL048 D (Enoch)
9.3
Equinor Energy AS
DNO Norge AS, Petrolia NOCO AS, Aker BP ASA
PL053 B (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia Noco AS, M Vest Energy
\u00a0
AS
PL055 (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia Noco AS, M Vest Energy
\u00a0
AS
PL055 B (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia Noco AS, M Vest Energy
\u00a0
AS
PL055 D (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia Noco AS, M Vest Energy
\u00a0
AS
PL055 E (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia Noco AS, M Vest Energy
\u00a0
AS
PL055 FS (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia Noco AS, M Vest Energy
\u00a0
AS
PL065 (Tambar)
45.0
Aker BP ASA
DNO Norge AS
PL065 B (Tambar)
45.0
Aker BP ASA
DNO Norge AS
PL1049
40.0
DNO Norge AS
Concedo AS, Petoro AS
PL1084
40.0
Aker BP ASA
DNO Norge AS
PL1085
25.0
Aker BP ASA
DNO Norge AS, Petoro AS
PL1086
50.0
DNO Norge AS
Source Energy AS, Petoro AS, Aker BP ASA
PL1102
30.0
Aker BP ASA
DNO Norge AS, Equinor Energy AS
PL1102 B
30.0
Aker BP ASA
DNO Norge AS, Equinor Energy AS
PL1108
40.0
DNO Norge AS
Pandion Energy AS, OKEA ASA
PL1109*
20.0
OMV (Norge) AS
DNO Norge AS, Pandion Energy AS, Aker BP ASA
PL1119*
10.0
Equinor Energy AS
OKEA ASA, Pandion Energy AS, DNO Norge AS
PL1120
40.0
DNO Norge AS
Equinor Energy AS, V\u00e5r Energi AS, Harbour Energy Norge AS
PL1145
60.0
DNO Norge AS
AkerBP ASA
PL1147
20.0
Aker BP ASA
DNO Norge AS, Equinor Energy AS,
PL1148
30.0
Wellesley Petroleum AS
DNO Norge AS, AkerBP ASA, Equinor Energy AS
PL1148 B
30.0
Wellesley Petroleum AS
DNO Norge AS, AkerBP ASA, Equinor Energy AS
PL1148 CS
30.0
Wellesley Petroleum AS
DNO Norge AS, AkerBP ASA, Equinor Energy AS
PL1150 S
40.0
OKEA ASA
DNO Norge AS
PL1151
20.0
Harbour Energy Norge AS
DNO Norge AS, AkerBP ASA, Pandion Energy AS, Equinor Energy AS
PL1158
40.0
Aker BP ASA
DNO Norge AS, Sval Energi AS
PL1171
50.0
Aker BP ASA
DNO Norge AS
PL1172
30.0
Aker BP ASA
DNO Norge AS, ORLEN Upstream Norway AS
\u00a0
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PL1175
30.0
Aker BP ASA
DNO Norge AS, ORLEN Upstream Norway AS
PL1182 S
40.0
DNO Norge AS
AkerBP ASA, Japex Norge AS, Concedo AS
PL1186
20.0
Equinor Energy AS
DNO Norge AS, OKEA ASA, Harbour Energy Norge AS
PL1187
30.0
OKEA ASA
DNO Norge AS, M Vest Energy AS, Harbour Energy Norge AS
PL1198
20.0
Aker BP ASA
DNO Norge AS, Source Energy AS, Petoro AS
PL1203
20.0
V\u00e5r Energi ASA
DNO Norge AS, Equinor Energy AS, Petoro AS
PL1204
60.0
DNO Norge AS
Equinor Energy AS
PL1205
40.0
ConocoPhillips Skandinavia AS
DNO Norge AS
PL1209
40.0
DNO Norge AS
Equinor Energy AS, Concedo AS
PL1212 S
40.0
Equinor Energy AS
DNO Norge AS, Japex Norge AS
PL1213 S
30.0
V\u00e5r Energi ASA
DNO Norge AS, Harbour Energy Norge AS
PL1216
40.0
DNO Norge AS
Harbour Energy Norge AS, Source Energy AS
PL1226
40.0
Equinor Energy AS
DNO Norge AS
PL1228
30.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS
PL1229
30.0
Sval Energi AS
DNO Norge AS, Harbour Energy Norge AS, ORLEN Upstream Norway AS
PL122 (Marulk)
37.0
DNO Norge AS
Equinor Energy AS, ORLEN Upstream Norway AS
PL122 B (Marulk)
37.0
DNO Norge AS
Equinor Energy AS, ORLEN Upstream Norway AS
PL122 C (Marulk)
37.0
DNO Norge AS
Equinor Energy AS, ORLEN Upstream Norway AS
PL122 D (Marulk)
37.0
DNO Norge AS
Equinor Energy AS, ORLEN Upstream Norway AS
PL128 (Norne)
11.5
Equinor Energy AS
DNO Norge As, Petoro As
PL128 B (Norne)
11.5
Equinor Energy AS
DNO Norge As, Petoro As
PL128 D (Norne)
11.5
Equinor Energy AS
DNO Norge As, Petoro As
PL128 E (Norne)
11.5
Equinor Energy AS
DNO Norge As, Petoro As
PL147 (Trym)
50.0
DNO Norge AS
Sval Energi AS
PL159 B (Alve)
32.0
Equinor Energy AS
DNO Norge AS, ORLEN Upstream Norway AS
\u00a0
PL159 G (Alve)
32.0
Equinor Energy AS
DNO Norge AS, ORLEN Upstream Norway AS
\u00a0
PL185 (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia Noco AS, M Vest Energy
\u00a0
AS
PL248 F
20.0
Harbour Energy Norge AS
DNO Norge AS, Petoro AS
PL248 GS
20.0
Harbour Energy Norge AS
DNO Norge AS, Petoro AS
PL248 K
20.0
Harbour Energy Norge AS
DNO Norge AS, Petoro AS
PL293 B
29.0
Equinor Energy AS
DNO Norge AS, INPEX Idemitsu Petroleum Norge AS, Japex Norge AS
PL293 CS
29.0
Equinor Energy AS
DNO Norge AS, INPEX Idemitsu Petroleum Norge AS, Japex Norge AS
PL300 (Tambar \u00d8st)
45.0
Aker BP ASA
DNO Norge AS
PL405 (Oda)
15.0
Sval Energi AS
DNO Norge AS, Aker BP ASA
PL586 (Fenja)
7.5
V\u00e5r Energi ASA
DNO Norge AS, Sval Energi AS
PL586 B (Fenja)
7.5
V\u00e5r Energi ASA
DNO Norge AS, Sval Energi AS
PL644 (Berling)
30.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS
PL644 B (Berling)
30.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS
PL644 C (Berling)
30.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS
PL644 D (Berling)
30.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS
PL740 (Bestla)
39.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia Noco AS, M Vest Energy
\u00a0
AS
PL827 S
49.0
Equinor Energy AS
DNO Norge AS
PL827 SB
49.0
Equinor Energy AS
DNO Norge AS
PL836 S
30.0
Harbour Energy Norge AS
DNO Norge AS, Equinor Energy AS
PL836 SB
30.0
Harbour Energy Norge AS
DNO Norge AS, Equinor Energy AS
PL923
20.0
Equinor Energy AS
DNO Norge AS, Petoro AS
PL923 B
20.0
Equinor Energy AS
DNO Norge AS, Petoro AS
PL929
10.0
V\u00e5r Energi ASA
DNO Norge AS, Pandion Energy AS, Harbour Energy Norge AS, Aker BP ASA
PL984
30.0
DNO Norge AS
V\u00e5r Energi AS, Source Energy AS, Equinor Energy AS, Aker BP ASA
PL984 BS
30.0
DNO Norge AS
V\u00e5r Energi AS, Source Energy AS, Equinor Energy AS, Aker BP ASA
*DNO farmed into a 10 percent stake in the PL1119 license prior to the spud of the Mistral exploration well in late December 2024. In return, DNO gave up a 10 percent stake in the
PL1109 license containing the Horatio prospect, retaining 20 percent
UK
P111
54.3
Repsol Sinopec Resources UK Ltd
DNO North Sea (U.K.) Ltd, DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK)
Ltd.
P219
18.2
Repsol Sinopec North Sea Ltd
DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK) Ltd, Waldorf Production UK
Ltd
P255
45.0
Shell U.K. Ltd
DNO North Sea (U.K.) Ltd, Spirit Energy Resources Ltd
P1720 (Arran)
50.0
Rockrose UKCS4 Ltd
DNO North Sea (UK) Ltd
P2543
50.0
DNO North Sea (U.K.) Ltd
Aker BP UK Ltd
P359 Area A (Arran)
18.9
Shell U.K. Ltd
DNO North Sea (UK) Ltd, Rockrose UKCS4 Ltd
P359 Area B (Arran)
18.9
Shell U.K. Ltd
DNO North Sea (UK) Ltd, Rockrose UKCS4 Ltd
Netherlands
D18a
2.5
Neptune E&P UKCS Ltd
DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
Yemen
Block 47
64.0
DNO Yemen AS
The Yemen Company,
\u00a0
Geopetrol Hadramaut Incorporated
Held through equity-accounted investment Mondoil C\u00f4te d\u2019Ivoire/Foxtrot International as a joint venture (Note 13):
C\u00f4te d\u2019Ivoire
Block CI-27
27.3
Foxtrot International
SECI SA, Petroci
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As of 31 December 2023
Held through DNO as a subsidiary:
Participating
interest
Region/license
(percent)
Operator
Partner(s)
Kurdistan
Tawke PSC
75.0
DNO Iraq AS
Genel Energy International Limited
Baeshiqa PSC
64.0
DNO Iraq AS
Turkish Energy Company Limited, Kurdistan Regional Government
Norway
PL006 C (SE Tor)
65.0
DNO Norge AS
Aker BP ASA
PL018 ES
45.0
A/S Norske Shell
\u00a0
DNO Norge AS, Sval Energi AS
PL019 (Ula)
20.0
Aker BP ASA
DNO Norge AS
PL019 E (Ula)
20.0
Aker BP ASA
DNO Norge AS
PL019 F (Ula)
45.0
Aker BP ASA
DNO Norge AS
PL036 D (Vilje)
28.9
Aker BP ASA
DNO Norge AS, PGNiG Upstream Norway AS
PL048 D (Enoch)
9.3
Equinor Energy AS
DNO Norge AS, Petrolia NOCO AS, Aker BP ASA
PL053 B (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia NOCO AS, M Vest Energy
\u00a0
AS
PL055 (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia NOCO AS, M Vest Energy
\u00a0
AS
PL055 B (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia NOCO AS, M Vest Energy
\u00a0
AS
PL055 D (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia NOCO AS, M Vest Energy
\u00a0
AS
PL055 E (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia NOCO AS, M Vest Energy
\u00a0
AS
PL065 (Tambar)
45.0
Aker BP ASA
DNO Norge AS
PL065 B (Tambar)
45.0
Aker BP ASA
DNO Norge AS
PL1049
40.0
DNO Norge AS
Longboat Japex Norge AS, Petoro AS
PL1083
30.0
Aker BP ASA
DNO Norge AS, Petoro AS
PL1084
40.0
Aker BP ASA
DNO Norge AS
PL1085
25.0
Aker BP ASA
DNO Norge AS, Petoro AS
PL1086
50.0
DNO Norge AS
Source Energy AS, Petoro AS
PL1102
30.0
Aker BP ASA
DNO Norge AS, Equinor Energy AS
PL1106
40.0
DNO Norge AS
Petoro AS, Petrolia NOCO AS, Aker BP ASA
PL1108
40.0
DNO Norge AS
Pandion Energy AS, OKEA ASA
PL1109
30.0
OMV (Norge) AS
DNO Norge AS, Pandion Energy AS
\u00a0
PL1112
20.0
A/S Norske Shell
DNO Norge AS, Neptune Energy Norge AS, Sval Energi AS
PL1120
40.0
DNO Norge AS
Equinor Energy AS, V\u00e5r Energi ASA, Wintershall Dea Norge AS
PL1145
60.0
DNO Norge AS
Aker BP ASA
PL1146
25.0
ConocoPhillips Skandinavia AS
DNO Norge AS
PL1146B
25.0
ConocoPhillips Skandinavia AS
DNO Norge AS
PL1147
20.0
Sval Energi AS
DNO Norge AS, Equinor Energy AS, Aker BP ASA
PL1148
30.0
Wellesley Petroleum AS
DNO Norge AS, Aker BP ASA, Equinor Energy AS
PL1148B
30.0
Wellesley Petroleum AS
DNO Norge AS, Aker BP ASA, Equinor Energy AS
PL1151
20.0
Wintershall Dea Norge AS
DNO Norge AS, Aker BP ASA, Pandion Energy AS
PL1158
40.0
Aker BP ASA
DNO Norge AS, Sval Energi AS
PL1160
60.0
DNO Norge AS
Sval Energi AS
PL1171
50.0
Aker BP ASA
DNO Norge AS
PL1172
30.0
Aker BP ASA
DNO Norge AS, PGNiG Upstream Norway AS
PL1175
30.0
Aker BP ASA
DNO Norge AS, PGNiG Upstream Norway AS
PL1182S
40.0
DNO Norge AS
Aker BP ASA, Longboat Japex Norge AS
PL1186
20.0
Equinor Energy AS
DNO Norge AS, OKEA ASA, Wintershall DEA Norge AS
PL1187
30.0
OKEA ASA
DNO Norge AS, M Vest Energy AS, Wintershall DEA Norge AS
PL122 (Marulk)
17.0
V\u00e5r Energi ASA
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 B (Marulk)
17.0
V\u00e5r Energi ASA
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 C (Marulk)
17.0
V\u00e5r Energi ASA
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 D (Marulk)
17.0
V\u00e5r Energi ASA
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL147 (Trym)
50.0
DNO Norge AS
Sval Energi AS
PL159 B (Alve)
32.0
Equinor Energy AS
DNO Norge AS, PGNiG Upstream Norway AS
\u00a0
PL159 G (Alve)
32.0
Equinor Energy AS
DNO Norge AS, PGNiG Upstream Norway AS
\u00a0
PL169 E
\u00a0
(Ringhorne \u00d8st)
87.0
DNO Norge AS
V\u00e5r Energi ASA
PL185 (Brage)
14.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, Petrolia NOCO AS, M Vest Energy
\u00a0
AS
PL248 F
20.0
Wintershall Dea Norge AS
DNO Norge AS, Petoro AS
PL248 GS
20.0
Wintershall Dea Norge AS
DNO Norge AS, Petoro AS
PL248 K
20.0
Wintershall Dea Norge AS
DNO Norge AS, Petoro AS
PL293 B
29.0
Equinor Energy AS
DNO Norge AS, INPEX Idemitsu Norge AS, Longboat Japex Norge AS
PL293 CS
29.0
Equinor Energy AS
DNO Norge AS, INPEX Idemitsu Norge AS, Longboat Japex Norge AS
PL300 (Tambar \u00d8st)
45.0
Aker BP ASA
DNO Norge AS
PL405 (Oda)
15.0
Sval Energi AS
DNO Norge AS, Aker BP ASA
PL586 (Fenja)
7.5
Neptune Energy Norge AS
DNO Norge AS, V\u00e5r Energi ASA, Sval Energi AS
PL586 B (Fenja)
7.5
Neptune Energy Norge AS
DNO Norge AS, V\u00e5r Energi ASA, Sval Energi AS
PL644 (Berling)
30.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS
PL644 B (Berling)
30.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS
PL644 C (Berling)
30.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS
PL740 (Brasse)
39.3
OKEA ASA
DNO Norge AS, Lime Petroleum AS, M Vest Energy AS
PL827 S
49.0
Equinor Energy AS
DNO Norge AS
PL827 SB
49.0
Equinor Energy AS
DNO Norge AS
PL836 S
30.0
Wintershall Dea Norge AS
DNO Norge AS, Equinor Energy AS
PL836 SB
30.0
Wintershall Dea Norge AS
DNO Norge AS, Equinor Energy AS
PL923
20.0
Equinor Energy AS
DNO Norge AS, Petoro AS
\u00a0
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PL923 B
20.0
Equinor Energy AS
DNO Norge AS, Petoro AS
PL929
10.0
Neptune Energy Norge AS
DNO Norge AS, Pandion Energy AS, Wintershall Dea Norge AS, AkerBP ASA
PL969
45.0
A/S Norske Shell
DNO Norge AS, Sval Energi AS
PL969B
45.0
A/S Norske Shell
DNO Norge AS, Sval Energi AS
PL984
30.0
DNO Norge AS
V\u00e5r Energi ASA, Source Energy AS, Equinor Energy AS, AkerBP ASA
PL984 BS
30.0
DNO Norge AS
V\u00e5r Energi ASA, Source Energy AS, Equinor Energy AS, AkerBP ASA
UK
P111
54.3
BRITOIL LIMITED
DNO North Sea (U.K.) Ltd, DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK)
\u00a0
Ltd.
P219
18.2
Repsol Sinopec North Sea Ltd
DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK) Ltd, Waldorf Production UK
Ltd
P255
45.0
Shell U.K. Ltd
DNO North Sea (U.K.) Ltd, Spirit Energy Resources Ltd
P2543
50.0
DNO North Sea (U.K.) Ltd
Aker BP ASA
Netherlands
D18a
2.5
Neptune E&P UKCS Ltd
DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
Yemen
Block 47
64.0
DNO Yemen AS
The Yemen Company,
\u00a0
Geopetrol Hadramaut Incorporated
Held through equity-accounted investment Mondoil C\u00f4te d\u2019Ivoire/Foxtrot International as a joint venture (Note 13):
C\u00f4te d\u2019Ivoire
Block CI-27
27.3
Foxtrot International
SECI SA, Petroci
Block CI-12
24.0
Foxtrot International
SECI SA, Petroci
", "dimensions": { "concept": "ifrs-full:DisclosureOfAdditionalInformationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "ID_126": { "value": "
Note 29
Significant events after the reporting date
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Accounting policies
Significant events after the reporting date
Adjusting events are those providing evidence of
\u00a0
conditions existing at the end of the reporting
\u00a0
period, whereas non-adjusting events
are indicative of conditions arising after the reporting
\u00a0
period (the latter being disclosed where
\u00a0
material).
DNO receives 13 awards in Norway's APA licensing round
\u00a0
On 14 January 2025, the Company announced
\u00a0
that its wholly-owned subsidiary DNO Norge
\u00a0
AS had been awarded participation in 13
exploration licenses, of which three are operatorships,
\u00a0
under Norway's APA 2024 licensing round. Of the 13 new licenses,
\u00a0
10 are in the
North Sea and three in the Norwegian Sea.
The Company\u2019s Board of Directors approve dividend payment
\u00a0
On 6 February 2025, the Company announced
\u00a0
that pursuant to the authorization granted at
\u00a0
the 2024 AGM, the Board of Directors had
approved a dividend payment of NOK 0.3125 per
\u00a0
share. Payment of the dividend was made on
\u00a0
21 February 2025. This is considered a
non-adjusting event (see also parent company accounts).
Discovery in the Mistral prospect
On 5 March 2025, the Company announced a
\u00a0
gas/condensate discovery on the Mistral prospect
\u00a0
in the Norwegian Sea license PL1119
in which the Company\u2019s wholly-owned subsidiary
\u00a0
DNO Norge AS holds a 10 percent interest. Preliminary
\u00a0
estimates of gross
recoverable resources encountered are in the range
\u00a0
of 19-44 MMboe.
\u00a0
In addition to DNO. License partners include
\u00a0
Equinor Energy AS
(50 percent and operator), OKEA ASA and Pandion
\u00a0
Energy AS (20 percent each).
Acquisition of Sval Energi Group AS
On 7 March 2025, the Company announced
\u00a0
it had reached agreement to acquire 100 percent
\u00a0
of the shares of Sval Energi Group AS
from HitecVision for a cash consideration of USD 450
\u00a0
million based on an enterprise value of USD
\u00a0
1.6 billion. The transaction includes
non-operated interests in 16 producing fields offshore Norway, with the largest assets
\u00a0
being Nova, Martin Linge, Kvitebj\u00f8rn, Eldfisk,
Maria, Symra and Ekofisk. The effective date of the transaction
\u00a0
is 1 January 2025, with expected completion
\u00a0
mid-year 2025, subject to
customary regulatory approvals
\u00a0
from the Norwegian Ministry of Energy, the Norwegian Ministry of Finance
\u00a0
and competition authorities.
The acquisition will be financed with existing cash
\u00a0
and other debt financing facilities available
\u00a0
to DNO.
New bond placement and redemption of DNO04
On 14 March 2025, the Company announced
\u00a0
the completion of the placement of USD 600
\u00a0
million of new five-year senior unsecured
bonds with a coupon rate of 8.50 percent. The
\u00a0
proceeds will be used to fully redeem DNO04,
\u00a0
with the remainder to be used for general
corporate purposes.
Discovery in the Kj\u00f8ttkake prospect
On 26 March 2025, the Company announced a
\u00a0
discovery on the Kj\u00f8ttkake prospect in the Northern
\u00a0
North Sea license PL1182 S in
which the Company holds a 40 percent operated
\u00a0
interest.
\u00a0
Preliminary estimates of gross recoverable
\u00a0
resources encountered are in the
range of 39 to 75 MMboe. License partners include
\u00a0
Aker BP ASA (30 percent), Concedo AS and
\u00a0
Japex Norge AS (15 percent each).
\u00a0
Dry well in the Horatio prospect
On 26 March 2025, a dry well was announced on
\u00a0
the Horatio prospect in the Northern North
\u00a0
Sea license PL1109 in which the Company
holds a 20 percent operated interest. The majority
\u00a0
of the cost was incurred in 2025.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } } } }