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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 ASA consolidated
\u00a0
and
Company accounts are issued and taking into account
\u00a0
all
available information about the future covering at
\u00a0
least 12
months from the end of the reporting period. The
\u00a0
Board of
Directors\u2019 review included,
\u00a0
in particular,
\u00a0
assessment of the
Group\u2019s projected cash reserves and access to financing
arrangements,
\u00a0
considering debt maturities and its operational
outlook and work programs, while maintaining appropriate
headroom in respect of sound equity, liquidity and financial
covenant compliance throughout 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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\u00a0
\n
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\n
Oslo, 13 March 2024
Bijan Mossavar-Rahmani
Executive Chairman
Gunnar Hirsti
Deputy Chairman
Elin Karfjell
Director
Anita Marie Hjerkinn Aarn\u00e6s
Director
Najmedin Meshkati
Director
Christopher Spencer
Managing
\u00a0
Director
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"scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00", "ifrs-full:ComponentsOfEquityAxis": "ifrs-full:RetainedEarningsMember", "unit": "iso4217:USD" } }, "ID_155AA": { "value": "1234800000", "decimals": -5, "dimensions": { "concept": "ifrs-full:Equity", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "ID_3": { "value": "international oil and gas exploration, development and production operations.", "dimensions": { "concept": "ifrs-full:DescriptionOfNatureOfEntitysOperationsAndPrincipalActivities", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_4": { "value": "DNO ASA", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_5": { "value": "DNO ASA", "dimensions": { "concept": "ifrs-full:NameOfUltimateParentOfGroup", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_4A": { "value": "DNO ASA", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_4AA": { "value": "DNO ASA", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_6": { "value": "DNO ASA", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_7": { "value": "public limited liability", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_8": { "value": "Norway", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_9": { "value": "Norway", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_10": { "value": "Dokkveien 1, 0250 Oslo, Norway", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_11": { "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 2023.
The consolidated financial statements were approved
\u00a0
by the
Board of Directors on 13 March 2024.
Basis for preparation
The consolidated financial statements have been
\u00a0
prepared 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,
\u00a0
the figures in one or more rows 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_12": { "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 2023.
The consolidated financial statements were approved
\u00a0
by the
Board of Directors on 13 March 2024.
", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_13": { "value": "
Basis for preparation
The consolidated financial statements have been
\u00a0
prepared 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,
\u00a0
the figures in one or more rows 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_14": { "value": "
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,
\u00a0
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.
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 14);
\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 Estimation of the cost for decommissioning (Note
\u00a0
19);
\u2022 Contingencies, provisions and litigations (Note 23);
\u00a0
and
\u2022 Reserves and resources estimates (Note 26).
\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.
Functional and presentational currency
\u25a0
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 holds
\u00a0
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
\u00a0
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 2023 but are not considered to have any material
\u00a0
impact on the
Group\u2019s financial statements.
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 executive 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.
Accounting policies
Revenues
Revenues presented in the consolidated statements
\u00a0
of comprehensive income consist of
Revenue 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
Export revenues in Kurdistan are generated through
\u00a0
the sale of oil produced from the Tawke and the Baeshiqa licenses which is
exported by the pipeline through T\u00fcrkiye. Title to the oil is considered
\u00a0
to have passed on delivery of oil to the export
\u00a0
pipeline at Fish
Khabur terminal. Revenues generated from export
\u00a0
sales are recognized on the basis of invoiced
\u00a0
oil sales following monthly deliveries
to the KRG. Based on business practice, the
\u00a0
KRG is responsible for exporting the oil produced
\u00a0
in Kurdistan and it is assessed that
DNO has a customer relationship with the KRG. The
\u00a0
price for export oil deliveries to the KRG is based
\u00a0
on Brent prices with
adjustments for oil quality and transportation fees.
Revenues generated from local sales in Kurdistan
\u00a0
are recognized on the basis of volumes lifted
\u00a0
and sold to customers during the
period. Local deliveries are prepaid by the buyers
\u00a0
directly to DNO.
In addition, pursuant to a receivables settlement agreement
\u00a0
made with the KRG in August 2017, DNO
\u00a0
was entitled to three percent
of gross Tawke license revenues until 31 July 2022. Revenue was recognized based on
\u00a0
invoiced oil sales following monthly
deliveries to the KRG.
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 a matter
stemming back to 2012 along with 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 the legal proceedings.
\u00a0
DNO has learned via media reports
that on 4 July 2022, a commercial court in Baghdad
\u00a0
ruled that PSCs signed between the KRG and
\u00a0
four international oil companies
including DNO should be voided. Likewise, DNO notes
\u00a0
from media reports that on 21 August 2022,
\u00a0
the KRG filed third party
objections to the reported 4 July 2022 Baghdad court
\u00a0
rulings including those understood to concern
\u00a0
DNO. These cases, along with
other similar cases against international oil companies, are
\u00a0
reported to be still pending. Furthermore and
\u00a0
importantly, the KRG has
issued repeated reassurances that the PSCs remain
\u00a0
valid. There have been several rulings in Erbil
\u00a0
courts affirming the validity of the
PSCs. DNO notes from public reports that there is dialogue
\u00a0
between the KRG and the FGI on oil related
\u00a0
matters, including on
possible amendments of the new 2023-2025
\u00a0
Federal Iraqi Budget Law FGI\u2019s 2023 to 2025 Budget
\u00a0
Law (Budget Law). It is unclear
how and when the KRG and the FGI will permanently
\u00a0
address these matters. To date, DNO continues its operations in Kurdistan,
and developments are closely monitored.
\u00a0
Due to disagreements between the FGI and the
\u00a0
KRG, economic conditions in Kurdistan and limited
\u00a0
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 the oil it
\u00a0
delivers for export. Export sales have not always
\u00a0
followed the PSC terms and there
has been uncertainty related to receipt of payments
\u00a0
but notwithstanding sometimes lengthy delays, payments
\u00a0
have ultimately been
received by DNO.
In 2014, the FGI initiated an arbitration case
\u00a0
against the Government of T\u00fcrkiye and its state-owned
\u00a0
pipeline operator BOTAS
relating to the Iraq-T\u00fcrkiye Pipeline (ITP). Following an arbitration
\u00a0
ruling which became publicly known on
\u00a0
or around 24 March 2023,
and which were in parts in favor of Iraq,
\u00a0
the ITP was closed for export of Kurdish oil
\u00a0
on 25 March 2023. Consequently, DNO
announced an orderly shutdown of its production
\u00a0
in Kurdistan on 29 March 2023. As of the reporting
\u00a0
date, the ITP remains closed.
Despite T\u00fcrkiye\u2019s announcement in October 2023 that
\u00a0
the ITP is ready to resume operations. There
\u00a0
are media reports that indicate
that the ongoing discussions between the FGI and
\u00a0
the KRG about the Budget Law amendments can
\u00a0
be linked to the delay of the
restart of export of Kurdish oil through the
\u00a0
ITP.
\u00a0
At yearend 2023, the Company was owed a total
\u00a0
of USD 315 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
\u00a0
past due (see Note 14). 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. Consequently, DNO initiated cost reduction measures
\u00a0
in Kurdistan and commenced local sales on a
\u00a0
cash and
carry basis, where the oil is transported by traders
\u00a0
by road tanker or pipelined to local refineries.
\u00a0
The contractor entities\u2019 entitlement
is sold by DNO. Varying by contract, local selling prices were in the low-to-mid
\u00a0
USD 30s per barrel during 2023, significantly lower
than the international prices previously achieved
\u00a0
through pipeline export. However, all local deliveries are prepaid
\u00a0
by the buyers
directly to DNO, eliminating counterparty credit risk.
\u00a0
The Company continues to engage with the KRG
\u00a0
regarding recovery of the
arrears and payment terms and conditions for any
\u00a0
future oil exports.
The FGI\u2019s 2023 to 2025 Budget Law entered into
\u00a0
force in June 2023. Under the Budget Law, the KRG will be allocated
\u00a0
a share of the
federal budget plus compensation for oil production
\u00a0
and transportation costs which, according to the
\u00a0
Budget Law, shall be based on
an average cost of production of certain, undefined
\u00a0
Iraqi fields. The conditions for KRG receiving a
\u00a0
share of the FGI budget include a
requirement for the KRG to handover 400,000 bopd
\u00a0
of oil produced from fields in Kurdistan to
\u00a0
Iraq\u2019s State Oil Marketing Organization
(SOMO), for marketing and sale. The details of FGI-KRG
\u00a0
budget allocations, implementation of the Budget
\u00a0
Law and the monetary
size of the budget transfers to the KRG are not
\u00a0
clear to DNO and are reportedly still under negotiation
\u00a0
between the KRG and the
FGI.
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 21) arises when the
\u00a0
Group sells more than its share of the oil and
\u00a0
gas production. Similarly, an asset
(underlift, see Note 14) 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.
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
\u00a0
balance 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.
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.
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 18
and Note 19. Accounting effects from IFRS 9 (expected
\u00a0
credit loss model) assessment related to the
\u00a0
KRG arrears is further detailed
in Note 14.
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 authorities.
\u00a0
Deferred tax liability is calculated on all
\u00a0
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
Estimation uncertainty: Notional corporate income
\u00a0
tax/deferred 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.
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.
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 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.
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.
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
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.
Oil and gas assets in production
\u00a0
Capitalized costs for oil and gas assets are depreciated
\u00a0
using UoP method. The rate of depreciation
\u00a0
is equal to the ratio of oil and
gas production for the period over the estimated remaining
\u00a0
2P reserves at the beginning of the
\u00a0
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.
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 18. 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.
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. When deferred tax
\u00a0
from the initial recognition decreases,
more goodwill is exposed for impairment. After initial
\u00a0
recognition, depreciation of values calculated in the
\u00a0
purchase price allocations
from business combinations will result in decreased
\u00a0
deferred tax liability.
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 tonne (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 CO2
\u00a0
tax assumptions as described in the scenarios
\u00a0
described by the International
Energy Agency (IEA).
An energy transition is likely to impact the future oil
\u00a0
and gas prices which in turn may affect the recoverable
\u00a0
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.
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 venture
\u00a0
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.
Accounting policies
Inventories
Inventories comprise of drilling equipment, spare parts
\u00a0
and consumables and are valued at the lower
\u00a0
of cost and net realizable value.
Inventories that meet the definition of PP&E are
\u00a0
presented under the PP&E and are depreciated
\u00a0
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 and
\u00a0
gas sales and hence the simplified model is
\u00a0
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
21.
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 held to meet short term commitments. Restricted
\u00a0
cash is cash reserved for
a specific purpose and therefore not available
\u00a0
for immediate and general use by the Group.
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. A corresponding
amount is recognized directly in equity.
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.
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 of
\u00a0
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.
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 resources
\u00a0
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.
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 and regulations, and technology. Decommissioning activities will
\u00a0
normally 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.
Provisions for other liabilities
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.
The provisions are reviewed at each balance
\u00a0
sheet date and adjusted to reflect the current best estimate.
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.
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
14.
Accounting policies
Financial instruments
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
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 17.
\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.
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
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.
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
development; interest rates; and currency exchange rates.
\u00a0
Specific parameters of uncertainty related to the
\u00a0
field/reservoir include but
are not limited to: reservoir pressure and porosity;
\u00a0
recovery factors; water cut development; production
\u00a0
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
assumed decommissioning activities. Future changes to
\u00a0
estimated reserves can also have a material
\u00a0
effect on depreciation,
impairment of oil and gas fields and operating results.
\u00a0
The Group may also not be able to commercially
\u00a0
develop its contingent
resources that are used in impairment assessments
\u00a0
or acquisition accounting where the fair value
\u00a0
approach is applied.
", "dimensions": { "concept": "ifrs-full:DisclosureOfMaterialAccountingPolicyInformationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_15": { "value": "
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,
\u00a0
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.
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 14);
\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 Estimation of the cost for decommissioning (Note
\u00a0
19);
\u2022 Contingencies, provisions and litigations (Note 23);
\u00a0
and
\u2022 Reserves and resources estimates (Note 26).
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 a matter
stemming back to 2012 along with 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 the legal proceedings.
\u00a0
DNO has learned via media reports
that on 4 July 2022, a commercial court in Baghdad
\u00a0
ruled that PSCs signed between the KRG and
\u00a0
four international oil companies
including DNO should be voided. Likewise, DNO notes
\u00a0
from media reports that on 21 August 2022,
\u00a0
the KRG filed third party
objections to the reported 4 July 2022 Baghdad court
\u00a0
rulings including those understood to concern
\u00a0
DNO. These cases, along with
other similar cases against international oil companies, are
\u00a0
reported to be still pending. Furthermore and
\u00a0
importantly, the KRG has
issued repeated reassurances that the PSCs remain
\u00a0
valid. There have been several rulings in Erbil
\u00a0
courts affirming the validity of the
PSCs. DNO notes from public reports that there is dialogue
\u00a0
between the KRG and the FGI on oil related
\u00a0
matters, including on
possible amendments of the new 2023-2025
\u00a0
Federal Iraqi Budget Law FGI\u2019s 2023 to 2025 Budget
\u00a0
Law (Budget Law). It is unclear
how and when the KRG and the FGI will permanently
\u00a0
address these matters. To date, DNO continues its operations in Kurdistan,
and developments are closely monitored.
\u00a0
Due to disagreements between the FGI and the
\u00a0
KRG, economic conditions in Kurdistan and limited
\u00a0
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 the oil it
\u00a0
delivers for export. Export sales have not always
\u00a0
followed the PSC terms and there
has been uncertainty related to receipt of payments
\u00a0
but notwithstanding sometimes lengthy delays, payments
\u00a0
have ultimately been
received by DNO.
In 2014, the FGI initiated an arbitration case
\u00a0
against the Government of T\u00fcrkiye and its state-owned
\u00a0
pipeline operator BOTAS
relating to the Iraq-T\u00fcrkiye Pipeline (ITP). Following an arbitration
\u00a0
ruling which became publicly known on
\u00a0
or around 24 March 2023,
and which were in parts in favor of Iraq,
\u00a0
the ITP was closed for export of Kurdish oil
\u00a0
on 25 March 2023. Consequently, DNO
announced an orderly shutdown of its production
\u00a0
in Kurdistan on 29 March 2023. As of the reporting
\u00a0
date, the ITP remains closed.
Despite T\u00fcrkiye\u2019s announcement in October 2023 that
\u00a0
the ITP is ready to resume operations. There
\u00a0
are media reports that indicate
that the ongoing discussions between the FGI and
\u00a0
the KRG about the Budget Law amendments can
\u00a0
be linked to the delay of the
restart of export of Kurdish oil through the
\u00a0
ITP.
\u00a0
At yearend 2023, the Company was owed a total
\u00a0
of USD 315 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
\u00a0
past due (see Note 14). 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. Consequently, DNO initiated cost reduction measures
\u00a0
in Kurdistan and commenced local sales on a
\u00a0
cash and
carry basis, where the oil is transported by traders
\u00a0
by road tanker or pipelined to local refineries.
\u00a0
The contractor entities\u2019 entitlement
is sold by DNO. Varying by contract, local selling prices were in the low-to-mid
\u00a0
USD 30s per barrel during 2023, significantly lower
than the international prices previously achieved
\u00a0
through pipeline export. However, all local deliveries are prepaid
\u00a0
by the buyers
directly to DNO, eliminating counterparty credit risk.
\u00a0
The Company continues to engage with the KRG
\u00a0
regarding recovery of the
arrears and payment terms and conditions for any
\u00a0
future oil exports.
The FGI\u2019s 2023 to 2025 Budget Law entered into
\u00a0
force in June 2023. Under the Budget Law, the KRG will be allocated
\u00a0
a share of the
federal budget plus compensation for oil production
\u00a0
and transportation costs which, according to the
\u00a0
Budget Law, shall be based on
an average cost of production of certain, undefined
\u00a0
Iraqi fields. The conditions for KRG receiving a
\u00a0
share of the FGI budget include a
requirement for the KRG to handover 400,000 bopd
\u00a0
of oil produced from fields in Kurdistan to
\u00a0
Iraq\u2019s State Oil Marketing Organization
(SOMO), for marketing and sale. The details of FGI-KRG
\u00a0
budget allocations, implementation of the Budget
\u00a0
Law and the monetary
size of the budget transfers to the KRG are not
\u00a0
clear to DNO and are reportedly still under negotiation
\u00a0
between the KRG and the
FGI.
Estimation uncertainty: Notional corporate income
\u00a0
tax/deferred 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.
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.
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 tonne (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 CO2
\u00a0
tax assumptions as described in the scenarios
\u00a0
described by the International
Energy Agency (IEA).
An energy transition is likely to impact the future oil
\u00a0
and gas prices which in turn may affect the recoverable
\u00a0
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.
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 and regulations, and technology. Decommissioning activities will
\u00a0
normally 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.
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.
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.
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
development; interest rates; and currency exchange rates.
\u00a0
Specific parameters of uncertainty related to the
\u00a0
field/reservoir include but
are not limited to: reservoir pressure and porosity;
\u00a0
recovery factors; water cut development; production
\u00a0
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
assumed decommissioning activities. Future changes to
\u00a0
estimated reserves can also have a material
\u00a0
effect on depreciation,
impairment of oil and gas fields and operating results.
\u00a0
The Group may also not be able to commercially
\u00a0
develop its contingent
resources that are used in impairment assessments
\u00a0
or acquisition accounting where the fair value
\u00a0
approach is applied.
", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_16": { "value": "
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_17": { "value": "
Functional and presentational currency
\u25a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_18": { "value": "
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_19": { "value": "
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO holds
\u00a0
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
\u00a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_20": { "value": "
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO holds
\u00a0
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
\u00a0
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
.
Accounting policies
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 venture
\u00a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_21": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_22": { "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:DescriptionOfOtherAccountingPoliciesRelevantToUnderstandingOfFinancialStatements", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_23": { "value": "
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 2023 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_24": { "value": "
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 executive 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_25": { "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
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The Company reports the following three operating
\u00a0
segments: Kurdistan, the North Sea (which includes
\u00a0
the DNO\u2019s oil and gas activities
in Norway and the UK) and West Africa (which represents
\u00a0
the DNO\u2019s equity accounted investment in C\u00f4te d'Ivoire, see
\u00a0
Note 12).
Remaining operating segments are included in the other
\u00a0
category based on a materiality assessment.
\u00a0
The country-by-country reporting
for companies in extractive industries in line with
\u00a0
the Norwegian Accounting Act can be found in page
\u00a0
85 of this report.
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
12
-
-
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
Net gain on disposal of licenses
19
-
5.8
-
-
5.8
-
5.8
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
-7.8
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
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
Total
Un-
Full-Year ending
West
reporting
allocated/
Total
31 December 2022
Note
Kurdistan
North Sea
Africa
Other
segments
eliminated
Group
COMPREHENSIVE INCOME INFORMATION
Revenues
3
820.1
556.9
-
-
1,377.0
-
1,377.0
Inter-segment sales
-
-
-
-
-
-
-
Production costs
-124.7
-127.7
-
-
-252.4
0.1
-252.3
Movement in overlift/underlift
-
8.1
-
-
8.1
-
8.1
Depreciation, depletion and amortization
-126.8
-86.5
-
-
-213.3
-3.4
-216.7
Cost of goods sold
4
-251.5
-206.1
-
-
-457.6
-3.3
-460.9
Gross profit
568.5
350.8
-
-
919.4
-3.3
916.1
Share of profit/-loss from Joint Venture
12
-
-
6.0
-
6.0
-
6.0
Other income
-
2.8
-
-
2.8
-
2.8
Administrative expenses
\u00a0
5
-0.1
-6.0
-
-2.3
-8.4
-9.5
-17.9
Other operating expenses
5
-0.9
-
-
-6.8
-7.7
-
-7.7
Impairment of oil and gas assets
11
-
-371.3
-
-
-371.3
-
-371.3
Exploration expenses
6
-
-96.5
-
-
-96.5
-
-96.5
Operating profit/-loss
567.6
-120.3
6.0
-9.1
444.2
-12.8
431.4
Net financial income/-expense
7
10.4
-32.7
0.1
0.5
-21.6
-63.4
-85.0
Tax income/-expense
8
-
38.4
-
-
38.4
-
38.4
Net profit/-loss
\u00a0
578.0
-114.5
6.1
-8.6
461.1
-76.1
384.9
FINANCIAL POSITION INFORMATION
Non-current assets
750.2
503.5
76.1
-
1,329.8
8.3
1,338.1
Current assets
355.4
418.3
-
11.5
785.3
679.7
1,464.9
Total assets
1,105.5
921.8
76.1
11.5
2,115.0
687.9
2,803.0
Non-current liabilities
68.1
391.8
-
-
459.9
528.4
988.4
Current liabilities
97.5
284.4
-
41.6
423.4
21.9
445.3
Total liabilities
165.6
676.2
-
41.6
883.3
550.3
1,433.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_26": { "value": "
Accounting policies
Revenues
Revenues presented in the consolidated statements
\u00a0
of comprehensive income consist of
Revenue 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
Export revenues in Kurdistan are generated through
\u00a0
the sale of oil produced from the Tawke and the Baeshiqa licenses which is
exported by the pipeline through T\u00fcrkiye. Title to the oil is considered
\u00a0
to have passed on delivery of oil to the export
\u00a0
pipeline at Fish
Khabur terminal. Revenues generated from export
\u00a0
sales are recognized on the basis of invoiced
\u00a0
oil sales following monthly deliveries
to the KRG. Based on business practice, the
\u00a0
KRG is responsible for exporting the oil produced
\u00a0
in Kurdistan and it is assessed that
DNO has a customer relationship with the KRG. The
\u00a0
price for export oil deliveries to the KRG is based
\u00a0
on Brent prices with
adjustments for oil quality and transportation fees.
Revenues generated from local sales in Kurdistan
\u00a0
are recognized on the basis of volumes lifted
\u00a0
and sold to customers during the
period. Local deliveries are prepaid by the buyers
\u00a0
directly to DNO.
In addition, pursuant to a receivables settlement agreement
\u00a0
made with the KRG in August 2017, DNO
\u00a0
was entitled to three percent
of gross Tawke license revenues until 31 July 2022. Revenue was recognized based on
\u00a0
invoiced oil sales following monthly
deliveries to the KRG.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_27": { "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
1 January - 31 December
\u00a0
Kurdistan
\u00a0
North Sea
Total
USD million
2023
2022
2023
2022
2023
2022
Sale of oil
253.2
820.1
253.0
241.0
506.2
1,061.1
Sale of gas
-
-
137.3
281.1
137.3
281.1
Sale of natural gas liquids (NGL)
-
-
21.6
29.1
21.6
29.1
Tariff income
-
-
2.4
5.8
2.4
5.8
Total revenues from contracts with customers
253.2
820.1
414.4
556.9
667.5
1,377.0
Sale of oil (bopd)
14,806
25,933
8,049
6,341
22,856
32,273
Sale of gas (boepd)
-
-
4,746
4,800
4,746
4,800
Sale of natural gas liquids (NGL) (boepd)
-
-
1,282
1,370
1,282
1,370
Total sales volume (boepd)
14,806
25,933
14,078
12,511
28,885
38,444
Prior to the ITP closure in March last year, DNO generated revenues in
\u00a0
Kurdistan through the sale of oil produced
\u00a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_28": { "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
1 January - 31 December
\u00a0
Kurdistan
\u00a0
North Sea
Total
USD million
2023
2022
2023
2022
2023
2022
Sale of oil
253.2
820.1
253.0
241.0
506.2
1,061.1
Sale of gas
-
-
137.3
281.1
137.3
281.1
Sale of natural gas liquids (NGL)
-
-
21.6
29.1
21.6
29.1
Tariff income
-
-
2.4
5.8
2.4
5.8
Total revenues from contracts with customers
253.2
820.1
414.4
556.9
667.5
1,377.0
Sale of oil (bopd)
14,806
25,933
8,049
6,341
22,856
32,273
Sale of gas (boepd)
-
-
4,746
4,800
4,746
4,800
Sale of natural gas liquids (NGL) (boepd)
-
-
1,282
1,370
1,282
1,370
Total sales volume (boepd)
14,806
25,933
14,078
12,511
28,885
38,444
Prior to the ITP closure in March last year, DNO generated revenues in
\u00a0
Kurdistan through the sale of oil produced
\u00a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_29": { "value": "
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 21) arises when the
\u00a0
Group sells more than its share of the oil and
\u00a0
gas production. Similarly, an asset
(underlift, see Note 14) 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.
Accounting policies
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_30": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_31": { "value": "
\u00a0
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\n
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\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2023
2022
Lifting costs
-191.7
-222.1
Tariff and transportation expenses
-32.4
-30.2
Production costs based on produced volumes
-224.1
-252.3
Movement in overlift/underlift
5.6
8.1
Production costs based on sold volumes
-218.4
-244.2
Depreciation, depletion and amortization
-146.4
-216.7
Total cost of goods sold
-364.8
-460.9
", "dimensions": { "concept": "ifrs-full:DisclosureOfCostOfSalesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_32": { "value": "
\u00a0
\n
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\n
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\u00a0
\n
1 January - 31 December
USD million
2023
2022
Lifting costs
-191.7
-222.1
Tariff and transportation expenses
-32.4
-30.2
Production costs based on produced volumes
-224.1
-252.3
Movement in overlift/underlift
5.6
8.1
Production costs based on sold volumes
-218.4
-244.2
Depreciation, depletion and amortization
-146.4
-216.7
Total cost of goods sold
-364.8
-460.9
", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_33": { "value": "
Accounting policies
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
\u00a0
balance 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_34": { "value": "
Accounting policies
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
\u00a0
balance 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_35": { "value": "
\u00a0
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\u00a0
\n
1 January - 31 December
USD million
2023
2022
Salaries, bonuses, etc.
-53.1
-55.2
Employer's payroll tax expenses
-7.6
-5.1
Pensions
-4.6
-4.1
Other personnel costs
-4.3
-5.8
General and administration expenses
-27.8
-32.5
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
74.1
84.8
Total administrative expenses
-23.3
-17.9
Other expenses
-7.9
-7.7
Total other operating expenses
-7.9
-7.7
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. Other expenses
\u00a0
in 2023 were mainly related to provisions
\u00a0
for arbitral awards in Yemen,
\u00a0
(Note 23).
\u00a0
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.6 million expensed
\u00a0
in 2023 (USD 4.1 million in
2022). 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 2023, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted to USD
\u00a0
5 million (USD
5.4
million at yearend 2022). For more information
\u00a0
about remuneration to executive management,
\u00a0
see Note 3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2023
2022
Outstanding as of 1 January
11,453,638
3,178,536
Granted during the year
4,288,935
9,471,309
Forfeited/reversed during the year
624,141
37,099
Settled during the year
4,288,938
1,159,108
Outstanding as of 31 December
10,829,494
11,453,638
Unrestricted as of 31 December
1,032,058
834,872
Weighted average remaining contractual life for the synthetic shares (years)
2.54
2.43
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.20
12.56
Settlement price for synthetic shares at the end of the year (NOK)
10.70
11.81
\u00a0
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\n
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2023
2022
Managing Director
Salary
-0.58
-0.64
Bonus
-0.16
-0.26
Pension
-0.02
-0.02
Other remuneration
-0.41
-0.17
Remuneration to Managing Director
-1.17
-1.09
Other executive management
Salary
-1.69
-1.99
Bonus
-0.40
-0.15
Pension
-0.06
-0.08
Other remuneration
-0.78
-0.59
Remuneration to other executive management
-2.93
-2.81
Total remuneration to executive management
-4.09
-3.90
Number of managers included
5
6
Total remuneration to Board of Directors
-1.61
-1.17
Total remuneration to Board of Directors and executive management
-5.71
-5.07
On 7 September 2023, the Company announced
\u00a0
that Chris Spencer has been appointed Managing
\u00a0
Director of the Company as Bj\u00f8rn
Dale steps down as part of a planned management
\u00a0
transition initiated last year. Mr. Spencer has been DNO\u2019s Chief Operating Officer
(COO) since 2021. The Managing Director remuneration
\u00a0
presented above represents Mr. Spencer\u2019s remuneration both
\u00a0
in the role as the
COO and Managing Director in 2023. A remuneration
\u00a0
of USD 1.7 million (not included in the
\u00a0
above table) was in 2023 paid to Bj\u00f8rn
Dale (former Managing Director),
\u00a0
which included
\u00a0
severance pay portion.
\u00a0
For further details on remuneration to the
\u00a0
executive
management, see Note 3 in the parent company
\u00a0
accounts.
\u00a0
Shares and options held by Board of Directors and
\u00a0
executive management
Years ended 31 December
\u00a0
2023
\u00a0
\u00a0
2022
\u00a0
Directors and executive 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
50,750
-
35,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* 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 2023.
Executive management have been awarded synthetic
\u00a0
shares during the year as part of their
\u00a0
variable remuneration, see Note 3 in the
parent company accounts.
\u00a0
\n
\u00a0
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2023
2022
Auditor fees
-0.65
-0.71
Other financial auditing
-0.03
-0.04
Tax advisory services
-0.16
-0.08
Other advisory services
-
-
Total auditor fees
-0.84
-0.82
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_36": { "value": "
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\n
1 January - 31 December
USD million
2023
2022
Salaries, bonuses, etc.
-53.1
-55.2
Employer's payroll tax expenses
-7.6
-5.1
Pensions
-4.6
-4.1
Other personnel costs
-4.3
-5.8
General and administration expenses
-27.8
-32.5
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
74.1
84.8
Total administrative expenses
-23.3
-17.9
Other expenses
-7.9
-7.7
Total other operating expenses
-7.9
-7.7
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. Other expenses
\u00a0
in 2023 were mainly related to provisions
\u00a0
for arbitral awards in Yemen,
\u00a0
(Note 23).
\u00a0
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.6 million expensed
\u00a0
in 2023 (USD 4.1 million in
2022). 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 2023, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted to USD
\u00a0
5 million (USD
5.4
million at yearend 2022). For more information
\u00a0
about remuneration to executive management,
\u00a0
see Note 3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2023
2022
Outstanding as of 1 January
11,453,638
3,178,536
Granted during the year
4,288,935
9,471,309
Forfeited/reversed during the year
624,141
37,099
Settled during the year
4,288,938
1,159,108
Outstanding as of 31 December
10,829,494
11,453,638
Unrestricted as of 31 December
1,032,058
834,872
Weighted average remaining contractual life for the synthetic shares (years)
2.54
2.43
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.20
12.56
Settlement price for synthetic shares at the end of the year (NOK)
10.70
11.81
\u00a0
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\u00a0
\n
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2023
2022
Managing Director
Salary
-0.58
-0.64
Bonus
-0.16
-0.26
Pension
-0.02
-0.02
Other remuneration
-0.41
-0.17
Remuneration to Managing Director
-1.17
-1.09
Other executive management
Salary
-1.69
-1.99
Bonus
-0.40
-0.15
Pension
-0.06
-0.08
Other remuneration
-0.78
-0.59
Remuneration to other executive management
-2.93
-2.81
Total remuneration to executive management
-4.09
-3.90
Number of managers included
5
6
Total remuneration to Board of Directors
-1.61
-1.17
Total remuneration to Board of Directors and executive management
-5.71
-5.07
On 7 September 2023, the Company announced
\u00a0
that Chris Spencer has been appointed Managing
\u00a0
Director of the Company as Bj\u00f8rn
Dale steps down as part of a planned management
\u00a0
transition initiated last year. Mr. Spencer has been DNO\u2019s Chief Operating Officer
(COO) since 2021. The Managing Director remuneration
\u00a0
presented above represents Mr. Spencer\u2019s remuneration both
\u00a0
in the role as the
COO and Managing Director in 2023. A remuneration
\u00a0
of USD 1.7 million (not included in the
\u00a0
above table) was in 2023 paid to Bj\u00f8rn
Dale (former Managing Director),
\u00a0
which included
\u00a0
severance pay portion.
\u00a0
For further details on remuneration to the
\u00a0
executive
management, see Note 3 in the parent company
\u00a0
accounts.
\u00a0
Shares and options held by Board of Directors and
\u00a0
executive management
Years ended 31 December
\u00a0
2023
\u00a0
\u00a0
2022
\u00a0
Directors and executive 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
50,750
-
35,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* 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 2023.
Executive management have been awarded synthetic
\u00a0
shares during the year as part of their
\u00a0
variable remuneration, see Note 3 in the
parent company accounts.
\u00a0
\n
\u00a0
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2023
2022
Auditor fees
-0.65
-0.71
Other financial auditing
-0.03
-0.04
Tax advisory services
-0.16
-0.08
Other advisory services
-
-
Total auditor fees
-0.84
-0.82
\u00a0
\n
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\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2023
2022
Exploration expenses (G&G and field surveys)
-15.0
-10.2
Seismic costs
-9.9
-18.5
Exploration expenses capitalized in previous years carried to cost
-
-3.9
Exploration expenses capitalized during the year carried to cost
-6.0
-48.3
Other exploration expenses
-16.8
-15.6
Total exploration expenses
-47.7
-96.5
Exploration expenses in 2023 were related to exploration
\u00a0
activities in the North Sea, including expensing
\u00a0
of exploration wells (Eggen
and Litago wells).
\u00a0
Exploration expenses in 2022 were related to
\u00a0
exploration activities in the North Sea, including expensing
\u00a0
of
exploration wells (Edinburgh, Overly and Uer wells).
\u00a0
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\n
\u00a0
\n
1 January - 31 December
USD million
2023
2022
Interest income
36.5
12.9
Currency exchange gains recognized in the income statement (net)
8.4
-
Other financial income
0.1
1.0
Financial income
45.0
13.9
Interest expenses
-44.6
-57.5
Time value effect trade debtors (Note 14)
-44.3
-
Amortization of borrowing issue costs
-3.3
-5.2
Accretion expense ARO (unwinding of discount rate, Note 19)
-17.4
-15.5
Currency exchange loss recognized in the income statement (net)
-
-6.6
Other financial expenses
-2.3
-14.0
Financial expenses
-112.0
-98.9
Net financial income/-expenses
-67.0
-85.0
Other financial expenses in 2022 were higher than 2023
\u00a0
mainly due to bond premium expenses and incurred
\u00a0
put option premium.
", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_37": { "value": "
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\n
1 January - 31 December
USD million
2023
2022
Salaries, bonuses, etc.
-53.1
-55.2
Employer's payroll tax expenses
-7.6
-5.1
Pensions
-4.6
-4.1
Other personnel costs
-4.3
-5.8
General and administration expenses
-27.8
-32.5
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
74.1
84.8
Total administrative expenses
-23.3
-17.9
Other expenses
-7.9
-7.7
Total other operating expenses
-7.9
-7.7
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. Other expenses
\u00a0
in 2023 were mainly related to provisions
\u00a0
for arbitral awards in Yemen,
\u00a0
(Note 23).
\u00a0
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.6 million expensed
\u00a0
in 2023 (USD 4.1 million in
2022). 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 2023, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted to USD
\u00a0
5 million (USD
5.4
million at yearend 2022). For more information
\u00a0
about remuneration to executive management,
\u00a0
see Note 3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2023
2022
Outstanding as of 1 January
11,453,638
3,178,536
Granted during the year
4,288,935
9,471,309
Forfeited/reversed during the year
624,141
37,099
Settled during the year
4,288,938
1,159,108
Outstanding as of 31 December
10,829,494
11,453,638
Unrestricted as of 31 December
1,032,058
834,872
Weighted average remaining contractual life for the synthetic shares (years)
2.54
2.43
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.20
12.56
Settlement price for synthetic shares at the end of the year (NOK)
10.70
11.81
\u00a0
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\n
\u00a0
\n
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2023
2022
Managing Director
Salary
-0.58
-0.64
Bonus
-0.16
-0.26
Pension
-0.02
-0.02
Other remuneration
-0.41
-0.17
Remuneration to Managing Director
-1.17
-1.09
Other executive management
Salary
-1.69
-1.99
Bonus
-0.40
-0.15
Pension
-0.06
-0.08
Other remuneration
-0.78
-0.59
Remuneration to other executive management
-2.93
-2.81
Total remuneration to executive management
-4.09
-3.90
Number of managers included
5
6
Total remuneration to Board of Directors
-1.61
-1.17
Total remuneration to Board of Directors and executive management
-5.71
-5.07
On 7 September 2023, the Company announced
\u00a0
that Chris Spencer has been appointed Managing
\u00a0
Director of the Company as Bj\u00f8rn
Dale steps down as part of a planned management
\u00a0
transition initiated last year. Mr. Spencer has been DNO\u2019s Chief Operating Officer
(COO) since 2021. The Managing Director remuneration
\u00a0
presented above represents Mr. Spencer\u2019s remuneration both
\u00a0
in the role as the
COO and Managing Director in 2023. A remuneration
\u00a0
of USD 1.7 million (not included in the
\u00a0
above table) was in 2023 paid to Bj\u00f8rn
Dale (former Managing Director),
\u00a0
which included
\u00a0
severance pay portion.
\u00a0
For further details on remuneration to the
\u00a0
executive
management, see Note 3 in the parent company
\u00a0
accounts.
\u00a0
Shares and options held by Board of Directors and
\u00a0
executive management
Years ended 31 December
\u00a0
2023
\u00a0
\u00a0
2022
\u00a0
Directors and executive 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
50,750
-
35,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* 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 2023.
Executive management have been awarded synthetic
\u00a0
shares during the year as part of their
\u00a0
variable remuneration, see Note 3 in the
parent company accounts.
\u00a0
\n
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\u00a0
\n
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2023
2022
Auditor fees
-0.65
-0.71
Other financial auditing
-0.03
-0.04
Tax advisory services
-0.16
-0.08
Other advisory services
-
-
Total auditor fees
-0.84
-0.82
\u00a0
\n
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\u00a0
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\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2023
2022
Exploration expenses (G&G and field surveys)
-15.0
-10.2
Seismic costs
-9.9
-18.5
Exploration expenses capitalized in previous years carried to cost
-
-3.9
Exploration expenses capitalized during the year carried to cost
-6.0
-48.3
Other exploration expenses
-16.8
-15.6
Total exploration expenses
-47.7
-96.5
Exploration expenses in 2023 were related to exploration
\u00a0
activities in the North Sea, including expensing
\u00a0
of exploration wells (Eggen
and Litago wells).
\u00a0
Exploration expenses in 2022 were related to
\u00a0
exploration activities in the North Sea, including expensing
\u00a0
of
exploration wells (Edinburgh, Overly and Uer wells).
\u00a0
\n
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\u00a0
\n
1 January - 31 December
USD million
2023
2022
Interest income
36.5
12.9
Currency exchange gains recognized in the income statement (net)
8.4
-
Other financial income
0.1
1.0
Financial income
45.0
13.9
Interest expenses
-44.6
-57.5
Time value effect trade debtors (Note 14)
-44.3
-
Amortization of borrowing issue costs
-3.3
-5.2
Accretion expense ARO (unwinding of discount rate, Note 19)
-17.4
-15.5
Currency exchange loss recognized in the income statement (net)
-
-6.6
Other financial expenses
-2.3
-14.0
Financial expenses
-112.0
-98.9
Net financial income/-expenses
-67.0
-85.0
Other financial expenses in 2022 were higher than 2023
\u00a0
mainly due to bond premium expenses and incurred
\u00a0
put option premium.
", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesByNatureExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_38": { "value": "
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\u00a0
\n
1 January - 31 December
USD million
2023
2022
Salaries, bonuses, etc.
-53.1
-55.2
Employer's payroll tax expenses
-7.6
-5.1
Pensions
-4.6
-4.1
Other personnel costs
-4.3
-5.8
General and administration expenses
-27.8
-32.5
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
74.1
84.8
Total administrative expenses
-23.3
-17.9
Other expenses
-7.9
-7.7
Total other operating expenses
-7.9
-7.7
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. Other expenses
\u00a0
in 2023 were mainly related to provisions
\u00a0
for arbitral awards in Yemen,
\u00a0
(Note 23).
\u00a0
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.6 million expensed
\u00a0
in 2023 (USD 4.1 million in
2022). 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 2023, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted to USD
\u00a0
5 million (USD
5.4
million at yearend 2022). For more information
\u00a0
about remuneration to executive management,
\u00a0
see Note 3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2023
2022
Outstanding as of 1 January
11,453,638
3,178,536
Granted during the year
4,288,935
9,471,309
Forfeited/reversed during the year
624,141
37,099
Settled during the year
4,288,938
1,159,108
Outstanding as of 31 December
10,829,494
11,453,638
Unrestricted as of 31 December
1,032,058
834,872
Weighted average remaining contractual life for the synthetic shares (years)
2.54
2.43
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.20
12.56
Settlement price for synthetic shares at the end of the year (NOK)
10.70
11.81
\u00a0
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\n
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2023
2022
Managing Director
Salary
-0.58
-0.64
Bonus
-0.16
-0.26
Pension
-0.02
-0.02
Other remuneration
-0.41
-0.17
Remuneration to Managing Director
-1.17
-1.09
Other executive management
Salary
-1.69
-1.99
Bonus
-0.40
-0.15
Pension
-0.06
-0.08
Other remuneration
-0.78
-0.59
Remuneration to other executive management
-2.93
-2.81
Total remuneration to executive management
-4.09
-3.90
Number of managers included
5
6
Total remuneration to Board of Directors
-1.61
-1.17
Total remuneration to Board of Directors and executive management
-5.71
-5.07
On 7 September 2023, the Company announced
\u00a0
that Chris Spencer has been appointed Managing
\u00a0
Director of the Company as Bj\u00f8rn
Dale steps down as part of a planned management
\u00a0
transition initiated last year. Mr. Spencer has been DNO\u2019s Chief Operating Officer
(COO) since 2021. The Managing Director remuneration
\u00a0
presented above represents Mr. Spencer\u2019s remuneration both
\u00a0
in the role as the
COO and Managing Director in 2023. A remuneration
\u00a0
of USD 1.7 million (not included in the
\u00a0
above table) was in 2023 paid to Bj\u00f8rn
Dale (former Managing Director),
\u00a0
which included
\u00a0
severance pay portion.
\u00a0
For further details on remuneration to the
\u00a0
executive
management, see Note 3 in the parent company
\u00a0
accounts.
\u00a0
Shares and options held by Board of Directors and
\u00a0
executive management
Years ended 31 December
\u00a0
2023
\u00a0
\u00a0
2022
\u00a0
Directors and executive 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
50,750
-
35,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* 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 2023.
Executive management have been awarded synthetic
\u00a0
shares during the year as part of their
\u00a0
variable remuneration, see Note 3 in the
parent company accounts.
", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralAndAdministrativeExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_39": { "value": "
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\n
1 January - 31 December
USD million
2023
2022
Salaries, bonuses, etc.
-53.1
-55.2
Employer's payroll tax expenses
-7.6
-5.1
Pensions
-4.6
-4.1
Other personnel costs
-4.3
-5.8
General and administration expenses
-27.8
-32.5
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
74.1
84.8
Total administrative expenses
-23.3
-17.9
Other expenses
-7.9
-7.7
Total other operating expenses
-7.9
-7.7
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. Other expenses
\u00a0
in 2023 were mainly related to provisions
\u00a0
for arbitral awards in Yemen,
\u00a0
(Note 23).
\u00a0
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.6 million expensed
\u00a0
in 2023 (USD 4.1 million in
2022). 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 2023, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted to USD
\u00a0
5 million (USD
5.4
million at yearend 2022). For more information
\u00a0
about remuneration to executive management,
\u00a0
see Note 3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2023
2022
Outstanding as of 1 January
11,453,638
3,178,536
Granted during the year
4,288,935
9,471,309
Forfeited/reversed during the year
624,141
37,099
Settled during the year
4,288,938
1,159,108
Outstanding as of 31 December
10,829,494
11,453,638
Unrestricted as of 31 December
1,032,058
834,872
Weighted average remaining contractual life for the synthetic shares (years)
2.54
2.43
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.20
12.56
Settlement price for synthetic shares at the end of the year (NOK)
10.70
11.81
\u00a0
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\u00a0
\n
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2023
2022
Managing Director
Salary
-0.58
-0.64
Bonus
-0.16
-0.26
Pension
-0.02
-0.02
Other remuneration
-0.41
-0.17
Remuneration to Managing Director
-1.17
-1.09
Other executive management
Salary
-1.69
-1.99
Bonus
-0.40
-0.15
Pension
-0.06
-0.08
Other remuneration
-0.78
-0.59
Remuneration to other executive management
-2.93
-2.81
Total remuneration to executive management
-4.09
-3.90
Number of managers included
5
6
Total remuneration to Board of Directors
-1.61
-1.17
Total remuneration to Board of Directors and executive management
-5.71
-5.07
On 7 September 2023, the Company announced
\u00a0
that Chris Spencer has been appointed Managing
\u00a0
Director of the Company as Bj\u00f8rn
Dale steps down as part of a planned management
\u00a0
transition initiated last year. Mr. Spencer has been DNO\u2019s Chief Operating Officer
(COO) since 2021. The Managing Director remuneration
\u00a0
presented above represents Mr. Spencer\u2019s remuneration both
\u00a0
in the role as the
COO and Managing Director in 2023. A remuneration
\u00a0
of USD 1.7 million (not included in the
\u00a0
above table) was in 2023 paid to Bj\u00f8rn
Dale (former Managing Director),
\u00a0
which included
\u00a0
severance pay portion.
\u00a0
For further details on remuneration to the
\u00a0
executive
management, see Note 3 in the parent company
\u00a0
accounts.
\u00a0
Shares and options held by Board of Directors and
\u00a0
executive management
Years ended 31 December
\u00a0
2023
\u00a0
\u00a0
2022
\u00a0
Directors and executive 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
50,750
-
35,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* 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 2023.
Executive management have been awarded synthetic
\u00a0
shares during the year as part of their
\u00a0
variable remuneration, see Note 3 in the
parent company accounts.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutEmployeesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_40": { "value": "
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\n
1 January - 31 December
USD million
2023
2022
Salaries, bonuses, etc.
-53.1
-55.2
Employer's payroll tax expenses
-7.6
-5.1
Pensions
-4.6
-4.1
Other personnel costs
-4.3
-5.8
General and administration expenses
-27.8
-32.5
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
74.1
84.8
Total administrative expenses
-23.3
-17.9
Other expenses
-7.9
-7.7
Total other operating expenses
-7.9
-7.7
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. Other expenses
\u00a0
in 2023 were mainly related to provisions
\u00a0
for arbitral awards in Yemen,
\u00a0
(Note 23).
\u00a0
\u00a0
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.6 million expensed
\u00a0
in 2023 (USD 4.1 million in
2022). 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 2023, the Company\u2019s liability for synthetic shares as
\u00a0
part of other variable remuneration amounted to USD
\u00a0
5 million (USD
5.4
million at yearend 2022). For more information
\u00a0
about remuneration to executive management,
\u00a0
see Note 3 in the parent company
accounts.
Movement in synthetic Company shares during
\u00a0
the year
1 January - 31 December
Number of shares
2023
2022
Outstanding as of 1 January
11,453,638
3,178,536
Granted during the year
4,288,935
9,471,309
Forfeited/reversed during the year
624,141
37,099
Settled during the year
4,288,938
1,159,108
Outstanding as of 31 December
10,829,494
11,453,638
Unrestricted as of 31 December
1,032,058
834,872
Weighted average remaining contractual life for the synthetic shares (years)
2.54
2.43
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.20
12.56
Settlement price for synthetic shares at the end of the year (NOK)
10.70
11.81
\u00a0
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\u00a0
\n
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2023
2022
Managing Director
Salary
-0.58
-0.64
Bonus
-0.16
-0.26
Pension
-0.02
-0.02
Other remuneration
-0.41
-0.17
Remuneration to Managing Director
-1.17
-1.09
Other executive management
Salary
-1.69
-1.99
Bonus
-0.40
-0.15
Pension
-0.06
-0.08
Other remuneration
-0.78
-0.59
Remuneration to other executive management
-2.93
-2.81
Total remuneration to executive management
-4.09
-3.90
Number of managers included
5
6
Total remuneration to Board of Directors
-1.61
-1.17
Total remuneration to Board of Directors and executive management
-5.71
-5.07
On 7 September 2023, the Company announced
\u00a0
that Chris Spencer has been appointed Managing
\u00a0
Director of the Company as Bj\u00f8rn
Dale steps down as part of a planned management
\u00a0
transition initiated last year. Mr. Spencer has been DNO\u2019s Chief Operating Officer
(COO) since 2021. The Managing Director remuneration
\u00a0
presented above represents Mr. Spencer\u2019s remuneration both
\u00a0
in the role as the
COO and Managing Director in 2023. A remuneration
\u00a0
of USD 1.7 million (not included in the
\u00a0
above table) was in 2023 paid to Bj\u00f8rn
Dale (former Managing Director),
\u00a0
which included
\u00a0
severance pay portion.
\u00a0
For further details on remuneration to the
\u00a0
executive
management, see Note 3 in the parent company
\u00a0
accounts.
\u00a0
Shares and options held by Board of Directors and
\u00a0
executive management
Years ended 31 December
\u00a0
2023
\u00a0
\u00a0
2022
\u00a0
Directors and executive 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
50,750
-
35,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* 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 2023.
Executive management have been awarded synthetic
\u00a0
shares during the year as part of their
\u00a0
variable remuneration, see Note 3 in the
parent company accounts.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_41": { "value": "
\u00a0
\n
\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
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\n
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\n
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\n
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\n
\u00a0
\n
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2023
2022
Auditor fees
-0.65
-0.71
Other financial auditing
-0.03
-0.04
Tax advisory services
-0.16
-0.08
Other advisory services
-
-
Total auditor fees
-0.84
-0.82
", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_42": { "value": "
Accounting policies
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_43": { "value": "
\u00a0
\n
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\n
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\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2023
2022
Exploration expenses (G&G and field surveys)
-15.0
-10.2
Seismic costs
-9.9
-18.5
Exploration expenses capitalized in previous years carried to cost
-
-3.9
Exploration expenses capitalized during the year carried to cost
-6.0
-48.3
Other exploration expenses
-16.8
-15.6
Total exploration expenses
-47.7
-96.5
Exploration expenses in 2023 were related to exploration
\u00a0
activities in the North Sea, including expensing
\u00a0
of exploration wells (Eggen
and Litago wells).
\u00a0
Exploration expenses in 2022 were related to
\u00a0
exploration activities in the North Sea, including expensing
\u00a0
of
exploration wells (Edinburgh, Overly and Uer wells).
", "dimensions": { "concept": "dnoasa:DisclosureOfExplorationExpenses", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_44": { "value": "
\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
2023
2022
Exploration expenses (G&G and field surveys)
-15.0
-10.2
Seismic costs
-9.9
-18.5
Exploration expenses capitalized in previous years carried to cost
-
-3.9
Exploration expenses capitalized during the year carried to cost
-6.0
-48.3
Other exploration expenses
-16.8
-15.6
Total exploration expenses
-47.7
-96.5
Exploration expenses in 2023 were related to exploration
\u00a0
activities in the North Sea, including expensing
\u00a0
of exploration wells (Eggen
and Litago wells).
\u00a0
Exploration expenses in 2022 were related to
\u00a0
exploration activities in the North Sea, including expensing
\u00a0
of
exploration wells (Edinburgh, Overly and Uer wells).
", "dimensions": { "concept": "ifrs-full:DisclosureOfResearchAndDevelopmentExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_45": { "value": "
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 18
and Note 19. Accounting effects from IFRS 9 (expected
\u00a0
credit loss model) assessment related to the
\u00a0
KRG arrears is further detailed
in Note 14.
\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
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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
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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
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2023
2022
Interest income
36.5
12.9
Currency exchange gains recognized in the income statement (net)
8.4
-
Other financial income
0.1
1.0
Financial income
45.0
13.9
Interest expenses
-44.6
-57.5
Time value effect trade debtors (Note 14)
-44.3
-
Amortization of borrowing issue costs
-3.3
-5.2
Accretion expense ARO (unwinding of discount rate, Note 19)
-17.4
-15.5
Currency exchange loss recognized in the income statement (net)
-
-6.6
Other financial expenses
-2.3
-14.0
Financial expenses
-112.0
-98.9
Net financial income/-expenses
-67.0
-85.0
Other financial expenses in 2022 were higher than 2023
\u00a0
mainly due to bond premium expenses and incurred
\u00a0
put option premium.
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_46": { "value": "
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 18
and Note 19. Accounting effects from IFRS 9 (expected
\u00a0
credit loss model) assessment related to the
\u00a0
KRG arrears is further detailed
in Note 14.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinanceIncomeAndCostsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_47": { "value": "
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 18
and Note 19. Accounting effects from IFRS 9 (expected
\u00a0
credit loss model) assessment related to the
\u00a0
KRG arrears is further detailed
in Note 14.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInterestIncomeAndExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_48": { "value": "
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 18
and Note 19. Accounting effects from IFRS 9 (expected
\u00a0
credit loss model) assessment related to the
\u00a0
KRG arrears is further detailed
in Note 14.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinanceCostsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_49": { "value": "
\u00a0
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\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
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\n
\u00a0
\n
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\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
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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2023
2022
Interest income
36.5
12.9
Currency exchange gains recognized in the income statement (net)
8.4
-
Other financial income
0.1
1.0
Financial income
45.0
13.9
Interest expenses
-44.6
-57.5
Time value effect trade debtors (Note 14)
-44.3
-
Amortization of borrowing issue costs
-3.3
-5.2
Accretion expense ARO (unwinding of discount rate, Note 19)
-17.4
-15.5
Currency exchange loss recognized in the income statement (net)
-
-6.6
Other financial expenses
-2.3
-14.0
Financial expenses
-112.0
-98.9
Net financial income/-expenses
-67.0
-85.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfEffectOfChangesInForeignExchangeRatesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_50": { "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
\u00a0
\n
\u00a0
\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
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\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
1 January - 31 December
USD million
2023
2022
Interest income
36.5
12.9
Currency exchange gains recognized in the income statement (net)
8.4
-
Other financial income
0.1
1.0
Financial income
45.0
13.9
Interest expenses
-44.6
-57.5
Time value effect trade debtors (Note 14)
-44.3
-
Amortization of borrowing issue costs
-3.3
-5.2
Accretion expense ARO (unwinding of discount rate, Note 19)
-17.4
-15.5
Currency exchange loss recognized in the income statement (net)
-
-6.6
Other financial expenses
-2.3
-14.0
Financial expenses
-112.0
-98.9
Net financial income/-expenses
-67.0
-85.0
Other financial expenses in 2022 were higher than 2023
\u00a0
mainly due to bond premium expenses and incurred
\u00a0
put option premium.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_51": { "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
\u00a0
\n
\u00a0
\n
\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
1 January - 31 December
USD million
2023
2022
Interest income
36.5
12.9
Currency exchange gains recognized in the income statement (net)
8.4
-
Other financial income
0.1
1.0
Financial income
45.0
13.9
Interest expenses
-44.6
-57.5
Time value effect trade debtors (Note 14)
-44.3
-
Amortization of borrowing issue costs
-3.3
-5.2
Accretion expense ARO (unwinding of discount rate, Note 19)
-17.4
-15.5
Currency exchange loss recognized in the income statement (net)
-
-6.6
Other financial expenses
-2.3
-14.0
Financial expenses
-112.0
-98.9
Net financial income/-expenses
-67.0
-85.0
Other financial expenses in 2022 were higher than 2023
\u00a0
mainly due to bond premium expenses and incurred
\u00a0
put option premium.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_52": { "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
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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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\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2023
2022
Interest income
36.5
12.9
Currency exchange gains recognized in the income statement (net)
8.4
-
Other financial income
0.1
1.0
Financial income
45.0
13.9
Interest expenses
-44.6
-57.5
Time value effect trade debtors (Note 14)
-44.3
-
Amortization of borrowing issue costs
-3.3
-5.2
Accretion expense ARO (unwinding of discount rate, Note 19)
-17.4
-15.5
Currency exchange loss recognized in the income statement (net)
-
-6.6
Other financial expenses
-2.3
-14.0
Financial expenses
-112.0
-98.9
Net financial income/-expenses
-67.0
-85.0
Other financial expenses in 2022 were higher than 2023
\u00a0
mainly due to bond premium expenses and incurred
\u00a0
put option premium.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_53": { "value": "
\u00a0
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2023
2022
Interest income
36.5
12.9
Currency exchange gains recognized in the income statement (net)
8.4
-
Other financial income
0.1
1.0
Financial income
45.0
13.9
Interest expenses
-44.6
-57.5
Time value effect trade debtors (Note 14)
-44.3
-
Amortization of borrowing issue costs
-3.3
-5.2
Accretion expense ARO (unwinding of discount rate, Note 19)
-17.4
-15.5
Currency exchange loss recognized in the income statement (net)
-
-6.6
Other financial expenses
-2.3
-14.0
Financial expenses
-112.0
-98.9
Net financial income/-expenses
-67.0
-85.0
Other financial expenses in 2022 were higher than 2023
\u00a0
mainly due to bond premium expenses and incurred
\u00a0
put option premium.
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_54": { "value": "
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
1 January - 31 December
USD million
2023
2022
Interest income
36.5
12.9
Currency exchange gains recognized in the income statement (net)
8.4
-
Other financial income
0.1
1.0
Financial income
45.0
13.9
Interest expenses
-44.6
-57.5
Time value effect trade debtors (Note 14)
-44.3
-
Amortization of borrowing issue costs
-3.3
-5.2
Accretion expense ARO (unwinding of discount rate, Note 19)
-17.4
-15.5
Currency exchange loss recognized in the income statement (net)
-
-6.6
Other financial expenses
-2.3
-14.0
Financial expenses
-112.0
-98.9
Net financial income/-expenses
-67.0
-85.0
Other financial expenses in 2022 were higher than 2023
\u00a0
mainly due to bond premium expenses and incurred
\u00a0
put option premium.
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_55": { "value": "
Accounting policies
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 authorities.
\u00a0
Deferred tax liability is calculated on all
\u00a0
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
Estimation uncertainty: Notional corporate income
\u00a0
tax/deferred 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_56": { "value": "
Accounting policies
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 authorities.
\u00a0
Deferred tax liability is calculated on all
\u00a0
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
Estimation uncertainty: Notional corporate income
\u00a0
tax/deferred 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_57": { "value": "
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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
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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
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\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
Tax income/-expense
1 January - 31 December
USD million
2023
2022
Changes in deferred taxes
-125.8
162.9
Income taxes receivable/-payable
-6.9
-124.5
Total tax income/-expense
-132.7
38.4
Income tax receivable/-payable
Years ended 31 December
USD million
2023
2022
Tax receivables
-
25.8
Income taxes payable
-4.6
-125.7
Net tax receivable/-payable
-4.6
-99.9
The tax balances relate to the activity on the Norwegian
\u00a0
Continental Shelf (NCS).
During 2023, DNO received tax refunds of USD 27.2
\u00a0
million in the UK in relation to decommissioning
\u00a0
spend for 2022. In Norway, DNO
paid net USD 116.7 million in taxes related to taxable profits in 2022.
Reconciliation of tax income/-expense
1 January - 31 December
USD million
2023
2022
Profit/-loss before income tax
151.3
346.5
Expected income tax according to nominal tax rate in Norway, 22 percent
8.0
-108.1
Expected income tax according to nominal petroleum tax rate in Norway,
\u00a0
78 percent
-136.8
43.3
Expected income tax according to nominal tax outside Norway
0.0
33.5
Foreign exchange variations between functional and tax currency
-6.8
2.5
Adjustment of previous years
0.3
0.7
Adjustment of deferred tax assets not recognized
-1.1
-62.3
Other items including other permanent differences
3.7
116.2
Change in tax rate
-
12.4
Tax income/-expense
-132.7
38.4
Effective income tax rate
87.7%
11.1%
Taxes charged to equity
-
-
\u00a0
\n
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\n
\u00a0
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\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
\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
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 activities
\u00a0
outside of Norway carried out by the Company\u2019s
\u00a0
Norwegian subsidiaries.
Tax effects on temporary differences
Years ended 31 December
USD million
2023
2022
Tangible assets
-275.9
-195.8
Intangible assets (including capitalized exploration expenses)
-145.4
-76.9
ARO provisions
238.0
226.2
Losses carried forward
174.4
167.6
Non-deductible interests carried forward
25.7
26.5
Other temporary differences
-0.6
-0.9
Net deferred tax assets/-liabilities
16.2
146.8
Valuation allowance
-208.6
-209.1
Net deferred tax assets/-liabilities
-192.4
-62.4
Recognized deferred tax assets
-
-
Recognized deferred tax liabilities
-192.4
-62.4
A valuation allowance was recognized relating to
\u00a0
carried forward losses in Norway (ordinary
\u00a0
tax regime) and the UK due to the
uncertainty regarding 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) and the UKCS
\u00a0
(40 percent). Additionally, in the UK,
Energy Profits Levy (EPL) applies which is a 35 percent
\u00a0
temporary levy on oil and gas ringfenced
\u00a0
profits, adjusted for decommissioning
spend.
\u00a0
Reconciliation of change in deferred tax assets/-liabilities
Years ended 31 December
USD million
2023
2022
Net deferred tax assets/-liabilities at 1 January
-62.4
-238.0
Change in deferred taxes in the income statement
-125.8
162.9
Deferred taxes related to business combinations and other transactions
1.3
-
Prior period adjustment
-
-
Reclassification from/-to tax receivable
-
-15.3
Currency and other movements
-5.5
28.0
Net deferred tax assets/-liabilities at 31 December
-192.4
-62.4
Reconciliation of change in tax receivable/-payable
Years ended 31 December
USD million
2023
2022
Net tax receivable/-payable at 1 January
-99.9
-11.9
Tax receivable/-payable related to transactions
\u00a0
posted directly to balance sheet
0.1
0.9
Tax receivable/-payable in the income statement
-6.9
-124.5
Tax payment/-refund
89.5
21.2
Prior period adjustment
-
-0.5
Reclassification to/-from deferred tax asset
-
15.3
Currency and other movements
12.6
-0.4
Net tax receivable/-payable at 31 December
-4.6
-99.9
Pillar Two
DNO is subject to OECD Pillar Two model rules, with Norway and
\u00a0
the UK having enacted legislation applicable from 1
\u00a0
January 2024.
Since the Pillar Two legislation was not effective at the reporting date, DNO
\u00a0
has no related current tax exposure and applies
\u00a0
the
exception to recognizing and disclosing information
\u00a0
about any deferred tax assets and liabilities related
\u00a0
to this, as provided in the
amendments to IAS 12 issued in May 2023. DNO
\u00a0
is in the process of assessing its exposure to
\u00a0
the legislation and the expectation is
that DNO should not be impacted as all its subsidiaries
\u00a0
are already subject to high tax rates, exceeding
\u00a0
15 percent. However, due to
the impact of specific adjustments envisaged in
\u00a0
the Pillar Two legislation,
\u00a0
there might still be potential implications for
\u00a0
DNO. The
quantitative impact is not yet reasonably estimable
\u00a0
due to the complexities in applying the legislation.
", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_58": { "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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\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
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Tax income/-expense
1 January - 31 December
USD million
2023
2022
Changes in deferred taxes
-125.8
162.9
Income taxes receivable/-payable
-6.9
-124.5
Total tax income/-expense
-132.7
38.4
Income tax receivable/-payable
Years ended 31 December
USD million
2023
2022
Tax receivables
-
25.8
Income taxes payable
-4.6
-125.7
Net tax receivable/-payable
-4.6
-99.9
The tax balances relate to the activity on the Norwegian
\u00a0
Continental Shelf (NCS).
During 2023, DNO received tax refunds of USD 27.2
\u00a0
million in the UK in relation to decommissioning
\u00a0
spend for 2022. In Norway, DNO
paid net USD 116.7 million in taxes related to taxable profits in 2022.
Reconciliation of tax income/-expense
1 January - 31 December
USD million
2023
2022
Profit/-loss before income tax
151.3
346.5
Expected income tax according to nominal tax rate in Norway, 22 percent
8.0
-108.1
Expected income tax according to nominal petroleum tax rate in Norway,
\u00a0
78 percent
-136.8
43.3
Expected income tax according to nominal tax outside Norway
0.0
33.5
Foreign exchange variations between functional and tax currency
-6.8
2.5
Adjustment of previous years
0.3
0.7
Adjustment of deferred tax assets not recognized
-1.1
-62.3
Other items including other permanent differences
3.7
116.2
Change in tax rate
-
12.4
Tax income/-expense
-132.7
38.4
Effective income tax rate
87.7%
11.1%
Taxes charged to 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
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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
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\n
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\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
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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 activities
\u00a0
outside of Norway carried out by the Company\u2019s
\u00a0
Norwegian subsidiaries.
Tax effects on temporary differences
Years ended 31 December
USD million
2023
2022
Tangible assets
-275.9
-195.8
Intangible assets (including capitalized exploration expenses)
-145.4
-76.9
ARO provisions
238.0
226.2
Losses carried forward
174.4
167.6
Non-deductible interests carried forward
25.7
26.5
Other temporary differences
-0.6
-0.9
Net deferred tax assets/-liabilities
16.2
146.8
Valuation allowance
-208.6
-209.1
Net deferred tax assets/-liabilities
-192.4
-62.4
Recognized deferred tax assets
-
-
Recognized deferred tax liabilities
-192.4
-62.4
A valuation allowance was recognized relating to
\u00a0
carried forward losses in Norway (ordinary
\u00a0
tax regime) and the UK due to the
uncertainty regarding 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) and the UKCS
\u00a0
(40 percent). Additionally, in the UK,
Energy Profits Levy (EPL) applies which is a 35 percent
\u00a0
temporary levy on oil and gas ringfenced
\u00a0
profits, adjusted for decommissioning
spend.
\u00a0
Reconciliation of change in deferred tax assets/-liabilities
Years ended 31 December
USD million
2023
2022
Net deferred tax assets/-liabilities at 1 January
-62.4
-238.0
Change in deferred taxes in the income statement
-125.8
162.9
Deferred taxes related to business combinations and other transactions
1.3
-
Prior period adjustment
-
-
Reclassification from/-to tax receivable
-
-15.3
Currency and other movements
-5.5
28.0
Net deferred tax assets/-liabilities at 31 December
-192.4
-62.4
Reconciliation of change in tax receivable/-payable
Years ended 31 December
USD million
2023
2022
Net tax receivable/-payable at 1 January
-99.9
-11.9
Tax receivable/-payable related to transactions
\u00a0
posted directly to balance sheet
0.1
0.9
Tax receivable/-payable in the income statement
-6.9
-124.5
Tax payment/-refund
89.5
21.2
Prior period adjustment
-
-0.5
Reclassification to/-from deferred tax asset
-
15.3
Currency and other movements
12.6
-0.4
Net tax receivable/-payable at 31 December
-4.6
-99.9
Pillar Two
DNO is subject to OECD Pillar Two model rules, with Norway and
\u00a0
the UK having enacted legislation applicable from 1
\u00a0
January 2024.
Since the Pillar Two legislation was not effective at the reporting date, DNO
\u00a0
has no related current tax exposure and applies
\u00a0
the
exception to recognizing and disclosing information
\u00a0
about any deferred tax assets and liabilities related
\u00a0
to this, as provided in the
amendments to IAS 12 issued in May 2023. DNO
\u00a0
is in the process of assessing its exposure to
\u00a0
the legislation and the expectation is
that DNO should not be impacted as all its subsidiaries
\u00a0
are already subject to high tax rates, exceeding
\u00a0
15 percent. However, due to
the impact of specific adjustments envisaged in
\u00a0
the Pillar Two legislation,
\u00a0
there might still be potential implications for
\u00a0
DNO. The
quantitative impact is not yet reasonably estimable
\u00a0
due to the complexities in applying the legislation.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTaxReceivablesAndPayablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_59": { "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
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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
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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
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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
\u00a0
\n
\u00a0
\n
\u00a0
\n
Tax income/-expense
1 January - 31 December
USD million
2023
2022
Changes in deferred taxes
-125.8
162.9
Income taxes receivable/-payable
-6.9
-124.5
Total tax income/-expense
-132.7
38.4
Income tax receivable/-payable
Years ended 31 December
USD million
2023
2022
Tax receivables
-
25.8
Income taxes payable
-4.6
-125.7
Net tax receivable/-payable
-4.6
-99.9
The tax balances relate to the activity on the Norwegian
\u00a0
Continental Shelf (NCS).
During 2023, DNO received tax refunds of USD 27.2
\u00a0
million in the UK in relation to decommissioning
\u00a0
spend for 2022. In Norway, DNO
paid net USD 116.7 million in taxes related to taxable profits in 2022.
Reconciliation of tax income/-expense
1 January - 31 December
USD million
2023
2022
Profit/-loss before income tax
151.3
346.5
Expected income tax according to nominal tax rate in Norway, 22 percent
8.0
-108.1
Expected income tax according to nominal petroleum tax rate in Norway,
\u00a0
78 percent
-136.8
43.3
Expected income tax according to nominal tax outside Norway
0.0
33.5
Foreign exchange variations between functional and tax currency
-6.8
2.5
Adjustment of previous years
0.3
0.7
Adjustment of deferred tax assets not recognized
-1.1
-62.3
Other items including other permanent differences
3.7
116.2
Change in tax rate
-
12.4
Tax income/-expense
-132.7
38.4
Effective income tax rate
87.7%
11.1%
Taxes charged to equity
-
-
\u00a0
\n
\u00a0
\n
\u00a0
\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
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 activities
\u00a0
outside of Norway carried out by the Company\u2019s
\u00a0
Norwegian subsidiaries.
Tax effects on temporary differences
Years ended 31 December
USD million
2023
2022
Tangible assets
-275.9
-195.8
Intangible assets (including capitalized exploration expenses)
-145.4
-76.9
ARO provisions
238.0
226.2
Losses carried forward
174.4
167.6
Non-deductible interests carried forward
25.7
26.5
Other temporary differences
-0.6
-0.9
Net deferred tax assets/-liabilities
16.2
146.8
Valuation allowance
-208.6
-209.1
Net deferred tax assets/-liabilities
-192.4
-62.4
Recognized deferred tax assets
-
-
Recognized deferred tax liabilities
-192.4
-62.4
A valuation allowance was recognized relating to
\u00a0
carried forward losses in Norway (ordinary
\u00a0
tax regime) and the UK due to the
uncertainty regarding 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) and the UKCS
\u00a0
(40 percent). Additionally, in the UK,
Energy Profits Levy (EPL) applies which is a 35 percent
\u00a0
temporary levy on oil and gas ringfenced
\u00a0
profits, adjusted for decommissioning
spend.
\u00a0
Reconciliation of change in deferred tax assets/-liabilities
Years ended 31 December
USD million
2023
2022
Net deferred tax assets/-liabilities at 1 January
-62.4
-238.0
Change in deferred taxes in the income statement
-125.8
162.9
Deferred taxes related to business combinations and other transactions
1.3
-
Prior period adjustment
-
-
Reclassification from/-to tax receivable
-
-15.3
Currency and other movements
-5.5
28.0
Net deferred tax assets/-liabilities at 31 December
-192.4
-62.4
Reconciliation of change in tax receivable/-payable
Years ended 31 December
USD million
2023
2022
Net tax receivable/-payable at 1 January
-99.9
-11.9
Tax receivable/-payable related to transactions
\u00a0
posted directly to balance sheet
0.1
0.9
Tax receivable/-payable in the income statement
-6.9
-124.5
Tax payment/-refund
89.5
21.2
Prior period adjustment
-
-0.5
Reclassification to/-from deferred tax asset
-
15.3
Currency and other movements
12.6
-0.4
Net tax receivable/-payable at 31 December
-4.6
-99.9
Pillar Two
DNO is subject to OECD Pillar Two model rules, with Norway and
\u00a0
the UK having enacted legislation applicable from 1
\u00a0
January 2024.
Since the Pillar Two legislation was not effective at the reporting date, DNO
\u00a0
has no related current tax exposure and applies
\u00a0
the
exception to recognizing and disclosing information
\u00a0
about any deferred tax assets and liabilities related
\u00a0
to this, as provided in the
amendments to IAS 12 issued in May 2023. DNO
\u00a0
is in the process of assessing its exposure to
\u00a0
the legislation and the expectation is
that DNO should not be impacted as all its subsidiaries
\u00a0
are already subject to high tax rates, exceeding
\u00a0
15 percent. However, due to
the impact of specific adjustments envisaged in
\u00a0
the Pillar Two legislation,
\u00a0
there might still be potential implications for
\u00a0
DNO. The
quantitative impact is not yet reasonably estimable
\u00a0
due to the complexities in applying the legislation.
", "dimensions": { "concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_60": { "value": "
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.
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 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.
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_61": { "value": "
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.
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 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.
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_62": { "value": "
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_63": { "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
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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
\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
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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
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\n
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\n
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\n
\u00a0
\n
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2023 - USD million
Goodwill
interest
assets
Other
\u00a0
assets
Total
As of 1 January 2023
Acquisition costs
407.2
97.5
335.3
15.4
448.2
855.4
Accumulated impairments
-351.1
-8.8
-260.5
-
-269.3
-620.3
Accumulated depreciation
-
-70.1
-
-11.6
-81.8
-81.6
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
18.0
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)
\u00a0
* Transfers was related to reclassification of the book value of Fenja license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2022 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2022
Acquisition costs
456.8
98.1
368.4
14.6
481.1
938.0
Accumulated impairments/exploration write-offs
-368.6
-8.7
-161.3
-
-170.0
-538.6
Accumulated depreciation
-
-68.2
-
-10.5
-78.7
-78.7
Net book amount
88.2
21.2
207.1
4.1
232.4
320.6
Period ended 31 December 2022
Opening net book amount
88.2
21.2
207.1
4.1
232.4
320.6
Translation differences
-10.4
-1.0
-21.0
-
-22.0
-32.4
Additions
-
0.4
73.5
0.7
74.6
74.6
Transfers*
-
-
-132.6
-
-132.6
-132.6
Exploration cost previously capitalized carried to cost
-
-
-52.2
-52.2
-52.2
Impairments
-21.5
-
-
-
-
-21.5
Depreciation
-
-1.9
-
-1.1
-3.0
-3.0
Closing net book amount
56.1
18.7
74.8
3.8
97.2
153.3
As of 31 December 2022
Acquisition costs
407.2
97.5
335.2
15.4
448.1
855.3
Accumulated impairments/exploration write-offs
-351.1
-8.8
-260.5
-
-269.1
-620.3
Accumulated depreciation
-
-70.1
-
-11.6
-81.6
-81.6
Net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Depreciation method
UoP
Linear (3-7 years)
* Transfers was related to reclassification of the book value of Brasse license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
", "dimensions": { "concept": "ifrs-full:DisclosureOfGoodwillExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_64": { "value": "
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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
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
Total Other
License
Exploration
intangible
2023 - USD million
Goodwill
interest
assets
Other
\u00a0
assets
Total
As of 1 January 2023
Acquisition costs
407.2
97.5
335.3
15.4
448.2
855.4
Accumulated impairments
-351.1
-8.8
-260.5
-
-269.3
-620.3
Accumulated depreciation
-
-70.1
-
-11.6
-81.8
-81.6
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
18.0
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)
\u00a0
* Transfers was related to reclassification of the book value of Fenja license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2022 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2022
Acquisition costs
456.8
98.1
368.4
14.6
481.1
938.0
Accumulated impairments/exploration write-offs
-368.6
-8.7
-161.3
-
-170.0
-538.6
Accumulated depreciation
-
-68.2
-
-10.5
-78.7
-78.7
Net book amount
88.2
21.2
207.1
4.1
232.4
320.6
Period ended 31 December 2022
Opening net book amount
88.2
21.2
207.1
4.1
232.4
320.6
Translation differences
-10.4
-1.0
-21.0
-
-22.0
-32.4
Additions
-
0.4
73.5
0.7
74.6
74.6
Transfers*
-
-
-132.6
-
-132.6
-132.6
Exploration cost previously capitalized carried to cost
-
-
-52.2
-52.2
-52.2
Impairments
-21.5
-
-
-
-
-21.5
Depreciation
-
-1.9
-
-1.1
-3.0
-3.0
Closing net book amount
56.1
18.7
74.8
3.8
97.2
153.3
As of 31 December 2022
Acquisition costs
407.2
97.5
335.2
15.4
448.1
855.3
Accumulated impairments/exploration write-offs
-351.1
-8.8
-260.5
-
-269.1
-620.3
Accumulated depreciation
-
-70.1
-
-11.6
-81.6
-81.6
Net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Depreciation method
UoP
Linear (3-7 years)
* Transfers was related to reclassification of the book value of Brasse license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
", "dimensions": { "concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_65": { "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
\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
\u00a0
\n
\u00a0
\n
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2023 - USD million
Goodwill
interest
assets
Other
\u00a0
assets
Total
As of 1 January 2023
Acquisition costs
407.2
97.5
335.3
15.4
448.2
855.4
Accumulated impairments
-351.1
-8.8
-260.5
-
-269.3
-620.3
Accumulated depreciation
-
-70.1
-
-11.6
-81.8
-81.6
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
18.0
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)
\u00a0
* Transfers was related to reclassification of the book value of Fenja license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2022 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2022
Acquisition costs
456.8
98.1
368.4
14.6
481.1
938.0
Accumulated impairments/exploration write-offs
-368.6
-8.7
-161.3
-
-170.0
-538.6
Accumulated depreciation
-
-68.2
-
-10.5
-78.7
-78.7
Net book amount
88.2
21.2
207.1
4.1
232.4
320.6
Period ended 31 December 2022
Opening net book amount
88.2
21.2
207.1
4.1
232.4
320.6
Translation differences
-10.4
-1.0
-21.0
-
-22.0
-32.4
Additions
-
0.4
73.5
0.7
74.6
74.6
Transfers*
-
-
-132.6
-
-132.6
-132.6
Exploration cost previously capitalized carried to cost
-
-
-52.2
-52.2
-52.2
Impairments
-21.5
-
-
-
-
-21.5
Depreciation
-
-1.9
-
-1.1
-3.0
-3.0
Closing net book amount
56.1
18.7
74.8
3.8
97.2
153.3
As of 31 December 2022
Acquisition costs
407.2
97.5
335.2
15.4
448.1
855.3
Accumulated impairments/exploration write-offs
-351.1
-8.8
-260.5
-
-269.1
-620.3
Accumulated depreciation
-
-70.1
-
-11.6
-81.6
-81.6
Net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Depreciation method
UoP
Linear (3-7 years)
* Transfers was related to reclassification of the book value of Brasse license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_66": { "value": "
\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
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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
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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
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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
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\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
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
Total Other
License
Exploration
intangible
2023 - USD million
Goodwill
interest
assets
Other
\u00a0
assets
Total
As of 1 January 2023
Acquisition costs
407.2
97.5
335.3
15.4
448.2
855.4
Accumulated impairments
-351.1
-8.8
-260.5
-
-269.3
-620.3
Accumulated depreciation
-
-70.1
-
-11.6
-81.8
-81.6
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
18.0
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)
\u00a0
* Transfers was related to reclassification of the book value of Fenja license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2022 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2022
Acquisition costs
456.8
98.1
368.4
14.6
481.1
938.0
Accumulated impairments/exploration write-offs
-368.6
-8.7
-161.3
-
-170.0
-538.6
Accumulated depreciation
-
-68.2
-
-10.5
-78.7
-78.7
Net book amount
88.2
21.2
207.1
4.1
232.4
320.6
Period ended 31 December 2022
Opening net book amount
88.2
21.2
207.1
4.1
232.4
320.6
Translation differences
-10.4
-1.0
-21.0
-
-22.0
-32.4
Additions
-
0.4
73.5
0.7
74.6
74.6
Transfers*
-
-
-132.6
-
-132.6
-132.6
Exploration cost previously capitalized carried to cost
-
-
-52.2
-52.2
-52.2
Impairments
-21.5
-
-
-
-
-21.5
Depreciation
-
-1.9
-
-1.1
-3.0
-3.0
Closing net book amount
56.1
18.7
74.8
3.8
97.2
153.3
As of 31 December 2022
Acquisition costs
407.2
97.5
335.2
15.4
448.1
855.3
Accumulated impairments/exploration write-offs
-351.1
-8.8
-260.5
-
-269.1
-620.3
Accumulated depreciation
-
-70.1
-
-11.6
-81.6
-81.6
Net book amount
56.1
18.7
74.8
3.8
97.2
153.3
Depreciation method
UoP
Linear (3-7 years)
* Transfers was related to reclassification of the book value of Brasse license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_67": { "value": "
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
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.
Oil and gas assets in production
\u00a0
Capitalized costs for oil and gas assets are depreciated
\u00a0
using UoP method. The rate of depreciation
\u00a0
is equal to the ratio of oil and
gas production for the period over the estimated remaining
\u00a0
2P reserves at the beginning of the
\u00a0
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.
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 18. 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
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\n
Kurdistan licenses
At yearend 2023, DNO held interests in two licenses
\u00a0
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,
\u00a0
the UK and other)
At yearend 2023, DNO held 73 offshore licenses in
\u00a0
Norway, four offshore licenses in the UK and one offshore license in Netherlands.
West Africa (C\u00f4te d\u2019Ivoire)
At yearend 2023, DNO held two licenses in C\u00f4te
\u00a0
d\u2019Ivoire through its indirect 33.33 percent in
\u00a0
Foxtrot International, both of which are
PSCs. Foxtrot International holds a 27.27 percent interest
\u00a0
in and operatorship of the producing Block
\u00a0
CI-27, which contains the Foxtrot
gas field, the Mahi gas field, the Marlin oil and gas
\u00a0
field and the Manta gas field. Foxtrot International
\u00a0
also operates the exploration
Block CI-12, in which it holds a 24 percent interest.
\u00a0
In accordance with IFRS, DNO\u2019s indirect interest
\u00a0
in Foxtrot Mondoil C\u00f4te
d\u2019Ivoire/Foxtrot International is accounted for using
\u00a0
the equity method (see Note 12).
Other
At yearend 2023, 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 2023
Held through DNO as a subsidiary:
Participating
Region/license
interest
(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
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\n
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 (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
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)
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 12):
C\u00f4te d\u2019Ivoire
Block CI-27
27.3
Foxtrot International LDC
SECI SA, Petroci*
Block CI-12
24.0
Foxtrot International LDC
SECI SA, Petroci
\u00a0
\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
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
As of 31 December 2022
Held through DNO as a subsidiary:
Participating
Region/license
interest
(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, Spirit Energy Norway 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
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi ASA, Neptune Energy Norway
AS
\u00a0
PL055 (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi ASA, Neptune Energy Norway
AS
\u00a0
PL055 B (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi ASA, Neptune Energy Norway
AS
\u00a0
PL055 D (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi ASA, Neptune Energy Norway
AS
\u00a0
PL055 E (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi ASA, Neptune Energy Norway
AS
\u00a0
PL065 (Tambar)
45.0
Aker BP ASA
DNO Norge AS
PL065 B (Tambar)
45.0
Aker BP ASA
DNO Norge AS
PL1048
50.0
Lundin Energy Norway AS
DNO Norge AS
PL1076
50.0
Equinor Energy AS
DNO Norge AS
PL1083
30.0
Lundin Energy Norway AS
DNO Norge AS, Petoro AS
PL1084
40.0
Lundin Energy Norway AS
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
Lundin Norway AS
DNO Norge AS
PL1106
40.0
DNO Norge AS
Petoro AS, Petrolia NOCO AS, Lundin Energy Norway AS
PL1108
40.0
DNO Norge AS
Pandion Energy AS, OKEA ASA
PL1109
30.0
OMV (Norge) AS
DNO Norge AS, ONE-Dyas Norge AS
PL1112
20.0
A/S Norske Shell
DNO Norge AS, Neptune Energy Norge AS, Spirit Energy Norway AS
PL1120
40.0
DNO Norge AS
Equinor Energy AS, V\u00e5r Energi ASA, Wintershall Dea Norge AS
PL1145
60.0
DNO Norge AS
DNO Norge AS, Aker BP ASA
\u00a0
PL1146
25.0
ConocoPhilips Skandinavia AS
ConocoPhilips Skandinavia AS; DNO Norge AS
PL1147
20.0
Lundin Norway AS
Spirit Energy Norway AS; Lundin Energy Norway AS; DNO Norge AS; Equinor
Energy AS
PL1148
30.0
Wellesley Petroleum AS
Wellesley Petroleum AS; DNO Norge AS; Aker BP ASA; Equinor Energy AS
PL1151
20.0
Wintershall Dea Norge AS
Wintershall Dea Norge AS; DNO Norge AS; Aker BP ASA; ONE-Dyas Norge AS
PL1158
40.0
Lundin Norway AS
Aker BP ASA; DNO Norge AS; Spirit Energy Norway AS
PL1160
60.0
DNO Norge AS
DNO Norge AS; Spirit Energy Norway 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
Spirit Energy Norway 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 (Ringhorne
\u00d8st)
87.0
DNO Norge AS
V\u00e5r Energi ASA
PL185 (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi ASA, Neptune Energy Norge 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
PL274 (Oselvar)
55.0
DNO Norge AS
CapeOmega AS
PL293 B
29.0
Equinor Energy AS
DNO Norge AS, Idemitsu Petroleum Norge AS, Longboat Energy Norway AS
PL300 (Tambar \u00d8st)
45.0
Aker BP ASA
DNO Norge AS
PL405 (Oda)
15.0
Spirit Energy Norway AS
DNO Norge AS, Aker BP ASA, Suncor Energy Norge AS
PL586 (Fenja)
7.5
Neptune Energy Norge AS
DNO Norge AS, V\u00e5r Energi ASA, Suncor Energy Norge AS
PL586B (Fenja)
7.5
Neptune Energy Norge AS
DNO Norge AS, V\u00e5r Energi ASA, Suncor Energy Norge AS
PL644 (Berling)
20.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 B (Berling)
20.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 C (Berling)
20.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL740 (Brasse)
50.0
DNO Norge AS
V\u00e5r Energi ASA
PL827 S
49.0
Equinor Energy AS
DNO Norge AS
PL836 S
30.0
Wintershall Dea Norge AS
DNO Norge AS, Spirit Energy Norway AS
PL836 SB
30.0
Wintershall Dea Norge AS
DNO Norge AS, Spirit Energy Norway AS
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
PL906
30.0
Aker BP ASA
DNO Norge AS, Longboat Energy Norge AS
PL923
20.0
Equinor Energy AS
DNO Norge AS, Wellesley Petroleum AS, Petoro AS
PL923B
20.0
Equinor Energy AS
DNO Norge AS, Wellesley Petroleum AS, Petoro AS
PL929
10.0
Neptune Energy Norge AS
DNO Norge AS, Pandion Energy AS, Wintershall Dea Norge AS, Lundin Norway
AS
PL943
30.0
Equinor Energy AS
DNO Norge AS, Sval Energi AS
PL968
50.0
DNO Norge AS
Petoro AS, MOL Norge AS, Aker BP ASA
PL969
45.0
A/S Norske Shell
DNO Norge AS, Spirit Energy Norway AS
PL969B
45.0
A/S Norske Shell
DNO Norge AS, Spirit Energy Norway AS
PL984
30.0
DNO Norge AS
V\u00e5r Energi ASA, Source Energy AS
PL984 BS
30.0
DNO Norge AS
V\u00e5r Energi ASA, Source Energy AS
PL994
30.0
Neptune Energy Norge AS
DNO Norge AS, Petrolia NOCO AS
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
P2401
45.0
Shell U.K. Ltd
DNO North Sea (U.K), Spirit Energy Resources Ltd
P255
45.0
Shell U.K. Ltd
DNO North Sea (U.K.) Ltd, Spirit Energy Resources Ltd
P558
10.0
Britoil Ltd
DNO North Sea (U.K.) Ltd, Rockrose Energy
P803
10.0
BP Exploration Operating Company
Ltd
DNO North Sea (U.K.) Ltd, Rockrose UKCS 10 Ltd
P2537
30.0
Chrysaor Production (U.K.) Limited
DNO North Sea (U.K.) Ltd, Neo Energy (ZEX) Limited
Netherlands
D15
5.0
Neptune E&P UKCS Ltd
DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
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 12):
C\u00f4te d\u2019Ivoire
Block CI-27
27.3
Foxtrot International LDC
SECI SA, Petroci*
Block CI-12
24.0
Foxtrot International LDC
SECI SA, Petroci
*Soci
e\u0301
t
e\u0301
\u00a0
Nationale d\u2019Op
e\u0301
rations P
e\u0301
troli
e\u0300
res de la C
o\u0302
te d\u2019Ivoire
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForOilAndGasAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_68": { "value": "
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
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.
Oil and gas assets in production
\u00a0
Capitalized costs for oil and gas assets are depreciated
\u00a0
using UoP method. The rate of depreciation
\u00a0
is equal to the ratio of oil and
gas production for the period over the estimated remaining
\u00a0
2P reserves at the beginning of the
\u00a0
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.
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 18. 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_69": { "value": "
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 18. 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.
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 of
\u00a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_70": { "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
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\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
1,096.8
1.1
10.6
1,108.6
Period ended 31 December 2023
Opening net book amount
217.7
879.1
1,096.8
1.1
10.6
1,108.6
Translation differences
-4.4
-4.4
-8.8
0.1
-1.1
-9.8
Additions*
53.9
123.7
177.6
0.7
10.7
189.0
Transfers**
-118.1
121.3
3.3
-
-
3.3
Impairments (net)
-
-13.9
-13.9
-
-
-13.9
Depreciation
-
-139.6
-139.6
-0.6
-4.0
-144.2
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
3,651.3
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
1.2
16.6
1,133.2
Depreciation method
UoP
Linear (3-7 years)
\u00a0
* Includes changes in estimate of asset retirement, see Note 20.
** Transfer was related to reclassification of the book value of the Fenja license from
\u00a0
development phase to production phase.
PROPERTY, PLANT AND EQUIPMENT
Total
Development
Production
oil & gas
Other
RoU
2022 - USD million
assets
assets
assets
PP&E
assets
Total
As of 1 January 2022
Acquisition costs
290.3
2,785.1
3,075.4
13.9
34.6
3,123.9
Accumulated impairments
-42.1
-89.6
-131.7
-0.1
-
-131.8
Accumulated depreciation
-
-1,680.4
-1,680.4
-12.8
-14.1
-1,707.2
Net book amount
248.2
1,015.1
1,263.3
1.0
20.5
1,284.9
Period ended 31 December 2022
Opening net book amount
248.2
1,015.1
1,263.3
1.0
20.5
1,284.9
Translation differences
-19.0
-47.0
-66.0
-0.1
-1.2
-67.2
Additions*
49.4
275.8
325.2
0.9
1.8
327.9
Transfers**
38.1
94.5
132.6
-
-
132.6
Disposal cost price
-
4.6
4.6
-
0.4
5.0
Disposal impairments/depreciations
-
-4.6
-4.6
-
-0.2
-4.8
Depreciation of RoU recognized against ARO
-
-
-
-
-6.7
-6.7
Impairments
-99.0
-250.1
-349.1
-
-
-349.1
Depreciation
-
-209.3
-209.3
-0.7
-3.7
-213.8
Closing net book amount
217.7
879.1
1,096.8
1.1
10.6
1,108.6
As of 31 December 2022
Acquisition costs
358.3
3,072.1
3,430.5
14.4
34.2
3,479.0
Accumulated impairments
-140.6
-332.0
-472.7
-0.1
-
-472.7
Accumulated depreciation
-
-1861.0
-1861.0
-13.1
-23.3
-1,897.4
Net book amount
217.7
879.1
1,096.8
1.2
10.6
1,108.6
Depreciation method
UoP
Linear (3-7 years)
* Includes changes in estimate of asset retirement, see Note 20.
** Transfers were related to reclassification of the book value of Brasse license from
\u00a0
exploration phase (intangible assets) to development phase
\u00a0
(tangible assets) and reclassification of the book value of Baeshiqa license from development phase to production
\u00a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_71": { "value": "
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. When deferred tax
\u00a0
from the initial recognition decreases,
more goodwill is exposed for impairment. After initial
\u00a0
recognition, depreciation of values calculated in the
\u00a0
purchase price allocations
from business combinations will result in decreased
\u00a0
deferred tax liability.
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 tonne (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 CO2
\u00a0
tax assumptions as described in the scenarios
\u00a0
described by the International
Energy Agency (IEA).
An energy transition is likely to impact the future oil
\u00a0
and gas prices which in turn may affect the recoverable
\u00a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_72": { "value": "
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. When deferred tax
\u00a0
from the initial recognition decreases,
more goodwill is exposed for impairment. After initial
\u00a0
recognition, depreciation of values calculated in the
\u00a0
purchase price allocations
from business combinations will result in decreased
\u00a0
deferred tax liability.
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 tonne (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 CO2
\u00a0
tax assumptions as described in the scenarios
\u00a0
described by the International
Energy Agency (IEA).
An energy transition is likely to impact the future oil
\u00a0
and gas prices which in turn may affect the recoverable
\u00a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_73": { "value": "
\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 acquisition (e.g., Faroe
\u00a0
Petroleum Plc transaction and swap agreement with
\u00a0
Equinor ASA, both
transactions completed in 2019),
\u00a0
the impairment assessment is based on the
\u00a0
fair value approach (level 3 in fair value hierarchy, IFRS
13). For both the value in use and fair value, the
\u00a0
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. Cash
\u00a0
flows are projected for the estimated
lifetime of the fields or license, which may exceed
\u00a0
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 2023.
\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 2023 were
\u00a0
as follows (yearend 2022 in
brackets):
2024
2025
2026
2027
Brent (USD/bbl)
77.7 (88.5)
84.0 (85.0)
75.5 (78.4)
73.6 (70.4)
NBP (pence/therm)
104.3 (179.4)
115.0 (126.4)
96.5 (102.9)
86.5 (77.9)
For periods after year 2028, the long-term oil
\u00a0
and gas price assumptions applied were USD
\u00a0
65 per barrel and 72 pence sterling per
therm, respectively (in real terms, basis year 2023).
\u00a0
Oil and gas price differential
The estimated net oil and gas price is based on
\u00a0
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 26.
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 and
\u00a0
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 2023 was 13.7
\u00a0
percent (16.1 percent at
yearend 2022) for the Kurdistan assets. For the
\u00a0
fair value calculations, the relevant post-tax
\u00a0
nominal discount rates at yearend 2023
was 9.8 percent for the North Sea assets (8.4 percent
\u00a0
at yearend 2022).
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
2022). 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
2023, was USD/NOK 10.5 for 2024, USD/NOK 10
\u00a0
for the years 2025-2026,
USD/NOK 9.5 for the years 2027-2028 and thereafter
\u00a0
kept constant at USD/NOK 9.0 from the year 2029
\u00a0
onwards.
\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
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\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 2023
and 2022, and how it was recognized in
\u00a0
the income statement and the balance sheet.
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
Full-Year ended 31 December 2022
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
Brasse, North Sea
-
-147.0
108.1
-38.9
-8.5
-
-138.5
108.1
-
Berling, North Sea
28.0
39.4
-30.7
8.7
-
-
39.4
-30.7
-
Ula area, North Sea
-
-252.5
182.1
-70.4
-13.0
-
-238.8
180.6
-0.7
Schooner and Ketch, North Sea
-
-13.5
-
-13.5
-
-
-13.4
-
-0.1
Other CGUs, North Sea
-
2.2
-1.4
0.8
-
-
2.2
-1.4
-
Total
-371.3
258.2
-113.1
-21.5
-
-349.1
256.6
-0.8
During 2023, a total impairment charge of USD 24.9
\u00a0
million (USD 12.1 million post-tax) was recognized,
\u00a0
mainly driven by:
\u00a0
\u2022
Downward revision of the oil price assumption and
\u00a0
reserves estimates, and updated cost profiles (Vilje
\u00a0
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 is mainly related to technical goodwill
\u00a0
on Alve CGU (USD 29.2
million).
During 2022, a total impairment charge of USD
\u00a0
371.3 million (USD 113.1 million post-tax) was recognized, mainly driven by:
\u00a0
\u2022
Decision not to submit a PDO by yearend
\u00a0
2022 (Brasse pre-development asset);
\u2022
Downward revision of reserves and resource estimates,
\u00a0
and updated cost profiles (Ula area CGU);
\u2022
Upward revision in the cost estimate for decommissioning
\u00a0
(Schooner and Ketch fields and other CGUs);
\u00a0
and
\u2022
Partially offset by a reversal of previously recognized
\u00a0
impairments following decision to submit a PDO
\u00a0
and revised long-term gas price
assumption (Berling development asset).
At yearend 2022, total book value of goodwill of USD
\u00a0
56.1 million was mainly related to technical
\u00a0
goodwill on Alve CGU (USD 30.2
million) and Vilje CGU (USD 16.1 million).
Sensitivities
The table below illustrates how the net profit/-loss
\u00a0
in 2023 would have been affected by changes in
\u00a0
the various assumptions, holding the
remaining assumptions unchanged. The estimated recoverable
\u00a0
amounts related to the Tawke license in Kurdistan is 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%
-
-9
Reserves (2P) and resources (2C)
\u00a0
+/- 5%
-
-1
Discount rate (WACC)
\u00a0
+/- 1%
-
-
Currency rate (USD/NOK)
\u00a0
+/- 1.0 NOK
-
-2
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 2022
\u00a0
real terms), and for the sensitivity
calculation a linear development between average
\u00a0
actual 2023 and IEA 2030, as well as between
\u00a0
IEA 2030 and IEA 2050 have been
\u00a0
\n
\u00a0
\n
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\u00a0
\n
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
85
83
6.9
\u00a0
7.1
\u00a0
-
Announced Pledges
\u00a0
74
60
6.5
\u00a0
5.4
\u00a0
-
Net Zero Emissions by 2050
42
25
4.3
\u00a0
4.1
\u00a0
-127
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 a best
\u00a0
estimate of an expected impairment impact.
\u00a0
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
\u00a0
was 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
\u00a0
end 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
\u00a0
in relation to yearend 2023
impairment assessments; the Ula area CGU have
\u00a0
license expiry dates that ranges between 2029
\u00a0
and 2036 (economic cut-off assumed
to be at the end of 2028); the Ringhorne
\u00a0
East license expires in 2030 (2035); the Brage license
\u00a0
expires in 2030 (2030; the Trym license
expires in 2027 (2026); the Alve license expires
\u00a0
in 2029 (2029); the Marulk license expires
\u00a0
in 2030 (2030);
\u00a0
the Vilje license expires in
2032 (2030); the Fenja license expires in 2039
\u00a0
(2039); and the Berling license, where, following
\u00a0
the PDO approval in June 2023, the
partnership expects a 20-year extension to 2043
\u00a0
to be granted in due course (economic cut-off date
\u00a0
2033).
", "dimensions": { "concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_74": { "value": "
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 venture
\u00a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_75": { "value": "
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\n
\u00a0
\n
In October 2022, DNO acquired Mondoil Enterprises
\u00a0
LLC (Mondoil Enterprises) and its 33.33 percent
\u00a0
indirect interest in privately-held
Foxtrot International LDC (Foxtrot International) whose principal
\u00a0
assets are operated stakes in offshore production
\u00a0
of gas and
associated liquids in C\u00f4te d'Ivoire. Foxtrot International
\u00a0
holds a 27.27 percent interest in and operatorship
\u00a0
of Block CI-27 containing
reserves of gas, produced together with condensate
\u00a0
and oil, from four offshore fields tied back to two
\u00a0
fixed platforms. Foxtrot
International also operates an exploration license
\u00a0
offshore C\u00f4te d\u2019Ivoire, Block CI-12 in which it holds
\u00a0
a 24 percent interest.
Foxtrot International's summarized statement of financial position
Year ended 31 December
USD million
2023
2022
Non-current assets
199.9
216.5
Current assets
64.3
67.3
Total assets
264.2
283.7
Non-current liabilities
68.8
67.1
Current liabilities
27.5
30.0
Total liabilities
96.3
97.2
Equity
167.9
186.6
Group's share of net assets (33.33 percent)
56.0
62.2
Goodwill
0.8
0.8
Fair value uplift on PP&E and ARO (net of related deferred tax)
11.1
13.0
Carrying amount Investment in Joint Venture
67.9
76.1
Foxtrot International's summarized statement of comprehensive income
1 January -
\u00a0
31 December
USD million
2023
2022
Revenues
79.4
28.8
Expenses
-17.6
-4.2
Depreciation
-30.8
-8.0
Other income/finance income
8.6
3.5
Tax income/-expense
-
-
Net profit/-loss
39.6
20.1
Group's share of net profit (33.33 percent)
13.2
6.7
Depletion of fair value uplift of PP&E and ARO (net of related deferred tax)
-1.3
-0.7
Share of profit/-loss from Joint Venture
11.9
6.0
Movement in the carrying amount of Investment in Joint Venture
1 January -
\u00a0
31 December
USD million
2023
2022
Opening balance
76.1
77.5
Share of profit/-loss from Joint Venture
11.9
6.0
Equity contribution into Joint Venture
6.9
4.2
Dividends from Joint Venture
-27.1
-11.5
Carrying amount Investment in Joint Venture
67.9
76.1
", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_76": { "value": "
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\n
In October 2022, DNO acquired Mondoil Enterprises
\u00a0
LLC (Mondoil Enterprises) and its 33.33 percent
\u00a0
indirect interest in privately-held
Foxtrot International LDC (Foxtrot International) whose principal
\u00a0
assets are operated stakes in offshore production
\u00a0
of gas and
associated liquids in C\u00f4te d'Ivoire. Foxtrot International
\u00a0
holds a 27.27 percent interest in and operatorship
\u00a0
of Block CI-27 containing
reserves of gas, produced together with condensate
\u00a0
and oil, from four offshore fields tied back to two
\u00a0
fixed platforms. Foxtrot
International also operates an exploration license
\u00a0
offshore C\u00f4te d\u2019Ivoire, Block CI-12 in which it holds
\u00a0
a 24 percent interest.
Foxtrot International's summarized statement of financial position
Year ended 31 December
USD million
2023
2022
Non-current assets
199.9
216.5
Current assets
64.3
67.3
Total assets
264.2
283.7
Non-current liabilities
68.8
67.1
Current liabilities
27.5
30.0
Total liabilities
96.3
97.2
Equity
167.9
186.6
Group's share of net assets (33.33 percent)
56.0
62.2
Goodwill
0.8
0.8
Fair value uplift on PP&E and ARO (net of related deferred tax)
11.1
13.0
Carrying amount Investment in Joint Venture
67.9
76.1
Foxtrot International's summarized statement of comprehensive income
1 January -
\u00a0
31 December
USD million
2023
2022
Revenues
79.4
28.8
Expenses
-17.6
-4.2
Depreciation
-30.8
-8.0
Other income/finance income
8.6
3.5
Tax income/-expense
-
-
Net profit/-loss
39.6
20.1
Group's share of net profit (33.33 percent)
13.2
6.7
Depletion of fair value uplift of PP&E and ARO (net of related deferred tax)
-1.3
-0.7
Share of profit/-loss from Joint Venture
11.9
6.0
Movement in the carrying amount of Investment in Joint Venture
1 January -
\u00a0
31 December
USD million
2023
2022
Opening balance
76.1
77.5
Share of profit/-loss from Joint Venture
11.9
6.0
Equity contribution into Joint Venture
6.9
4.2
Dividends from Joint Venture
-27.1
-11.5
Carrying amount Investment in Joint Venture
67.9
76.1
", "dimensions": { "concept": "ifrs-full:DisclosureOfJointVenturesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_77": { "value": "
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In October 2022, DNO acquired Mondoil Enterprises
\u00a0
LLC (Mondoil Enterprises) and its 33.33 percent
\u00a0
indirect interest in privately-held
Foxtrot International LDC (Foxtrot International) whose principal
\u00a0
assets are operated stakes in offshore production
\u00a0
of gas and
associated liquids in C\u00f4te d'Ivoire. Foxtrot International
\u00a0
holds a 27.27 percent interest in and operatorship
\u00a0
of Block CI-27 containing
reserves of gas, produced together with condensate
\u00a0
and oil, from four offshore fields tied back to two
\u00a0
fixed platforms. Foxtrot
International also operates an exploration license
\u00a0
offshore C\u00f4te d\u2019Ivoire, Block CI-12 in which it holds
\u00a0
a 24 percent interest.
Foxtrot International's summarized statement of financial position
Year ended 31 December
USD million
2023
2022
Non-current assets
199.9
216.5
Current assets
64.3
67.3
Total assets
264.2
283.7
Non-current liabilities
68.8
67.1
Current liabilities
27.5
30.0
Total liabilities
96.3
97.2
Equity
167.9
186.6
Group's share of net assets (33.33 percent)
56.0
62.2
Goodwill
0.8
0.8
Fair value uplift on PP&E and ARO (net of related deferred tax)
11.1
13.0
Carrying amount Investment in Joint Venture
67.9
76.1
Foxtrot International's summarized statement of comprehensive income
1 January -
\u00a0
31 December
USD million
2023
2022
Revenues
79.4
28.8
Expenses
-17.6
-4.2
Depreciation
-30.8
-8.0
Other income/finance income
8.6
3.5
Tax income/-expense
-
-
Net profit/-loss
39.6
20.1
Group's share of net profit (33.33 percent)
13.2
6.7
Depletion of fair value uplift of PP&E and ARO (net of related deferred tax)
-1.3
-0.7
Share of profit/-loss from Joint Venture
11.9
6.0
Movement in the carrying amount of Investment in Joint Venture
1 January -
\u00a0
31 December
USD million
2023
2022
Opening balance
76.1
77.5
Share of profit/-loss from Joint Venture
11.9
6.0
Equity contribution into Joint Venture
6.9
4.2
Dividends from Joint Venture
-27.1
-11.5
Carrying amount Investment in Joint Venture
67.9
76.1
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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 Exploration UK Limited
United Kingdom
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
DNO Oman Limited
Bermuda
100
DNO Oman Block 8 Limited
Guernsey
100
South Limited
\u00a0
Guernsey
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 (UK) Limited
United Kingdom
100
DNO North Sea (ROGB) Limited
United Kingdom
100
DNO North Sea (Energy) 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 LDC
Cayman Islands
33.33
The Group\u2019s operations in Kurdistan are carried out through
\u00a0
its subsidiary DNO Iraq AS, while activities on the NCS
\u00a0
are carried out
through DNO Norge AS and UKCS activities
\u00a0
are carried out through DNO North Sea (UK) Limited
\u00a0
and DNO North Sea (ROGB) Limited.
Activities in C\u00f4te d'Ivoire are carried out by Foxtrot
\u00a0
International LDC, in which the Company\u2019s indirect ownership
\u00a0
of 33.33 percent is
accounted for using the equity method. DNO
\u00a0
ASA, DNO Technical Services AS and DNO North Sea plc provide technical support and
services to the various companies in the Group. The
\u00a0
other subsidiaries from the table above had minimal
\u00a0
activity during the year. In
2023 DNO Oman Block 30 Limited was renamed
\u00a0
to South Limited and North Limited was liquidated.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestsInOtherEntitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_78": { "value": "
Accounting policies
Inventories
Inventories comprise of drilling equipment, spare parts
\u00a0
and consumables and are valued at the lower
\u00a0
of cost and net realizable value.
Inventories that meet the definition of PP&E are
\u00a0
presented under the PP&E and are depreciated
\u00a0
as part of the underlying capitalized
asset using the UoP method.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForMeasuringInventories", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_79": { "value": "
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\u00a0
\n
Years ended 31 December
\u00a0
Kuristan
\u00a0
North Sea
\u00a0
Total
USD million
2023
2022
2023
2022
2023
2022
Drilling equipment, spare parts and consumables
80.4
48.8
14.8
15.3
95.2
64.0
Provision for obsolete inventory
-15.0
-15.0
-2.3
-2.0
-17.4
-17.0
Total inventories
65.3
33.7
12.5
13.3
77.8
47.0
", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_80": { "value": "
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 and
\u00a0
gas sales and hence the simplified model is
\u00a0
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
21.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_81": { "value": "
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\n
Years ended 31 December
USD million
2023
2022
Trade debtors (non-current portion)
129.8
-
Other long-term receivables
-
-
Total other non-current receivables
129.8
-
Trade debtors
149.5
311.8
Underlift
12.1
14.0
Other short-term receivables
103.8
111.9
Total trade and other receivables
265.4
437.8
At yearend 2023, the Company was owed a total
\u00a0
of USD 315 million, excluding any interest, by
\u00a0
the KRG mainly related to sales of
DNO\u2019s entitlement shares of oil to the KRG for the months
\u00a0
October 2022 through March 2023 plus part
\u00a0
of the amount invoiced for oil
sold to the KRG in September 2022. These receivables
\u00a0
are past due. Since 2017, DNO has consistently
\u00a0
invoiced the KRG for such oil
sales based on an agreed Brent pricing mechanism.
\u00a0
For September 2022, the KRG unilaterally decided
\u00a0
to pay based on a purported
price realized by the KRG during the delivery
\u00a0
month. The KRG proposed such change to the agreed
\u00a0
pricing mechanism in September
2022 to which DNO has not agreed. DNO
\u00a0
therefore continues to request payment of the full
\u00a0
invoiced amount.
\u00a0
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 has reduced
\u00a0
the book value of the KRG arrears by USD 44.3
\u00a0
million
(presented under
Financial expenses
\u00a0
in the income statement) when comparing
\u00a0
the book value of these arrears with the present
\u00a0
value
of the estimated future cash flows. The calculation
\u00a0
of present value in accordance with IFRS 9,
\u00a0
considers a range of possible scenarios
with assigned weighting, involving estimation of the
\u00a0
timing of receipt of the arrears which will be
\u00a0
dependent upon uncertain future
events, in particular the assumed timing of the re-opening
\u00a0
of the ITP which has been shut-in since end
\u00a0
of March 2023. A discount rate of
12 percent has been applied for discounting of
\u00a0
the estimated future cash flows. In addition, USD
\u00a0
129.8 million was reclassified from
short-term to non-current arrears considering the assumed
\u00a0
timing of the recovery of the arrears.
The underlift receivable of USD 12.1 million at
\u00a0
yearend 2023 relates to North Sea underlifted
\u00a0
volumes. Other short-term receivables
mainly relate to items of working capital in licenses
\u00a0
in Kurdistan and the North Sea and accrual
\u00a0
for earned income not invoiced in the
North Sea.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_82": { "value": "
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 held to meet short term commitments. Restricted
\u00a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_83": { "value": "
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 held to meet short term commitments. Restricted
\u00a0
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_84": { "value": "
\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
2023
2022
Cash and cash equivalents, restricted
14.3
22.5
Cash and cash equivalents, non-restricted
704.5
931.8
Total cash and cash equivalents
718.8
954.3
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 2023.
Included in the non-restricted cash and cash equivalents
\u00a0
as of 31 December 2023 is USD 41.2 million
\u00a0
held on fixed interest time deposit
contracts with different duration and maturity dates up
\u00a0
to 26 January 2024.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRestrictedCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_85": { "value": "
\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
2023
2022
Cash and cash equivalents, restricted
14.3
22.5
Cash and cash equivalents, non-restricted
704.5
931.8
Total cash and cash equivalents
718.8
954.3
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 2023.
Included in the non-restricted cash and cash equivalents
\u00a0
as of 31 December 2023 is USD 41.2 million
\u00a0
held on fixed interest time deposit
contracts with different duration and maturity dates up
\u00a0
to 26 January 2024.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_86": { "value": "
\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
2023
2022
Cash and cash equivalents, restricted
14.3
22.5
Cash and cash equivalents, non-restricted
704.5
931.8
Total cash and cash equivalents
718.8
954.3
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 2023.
Included in the non-restricted cash and cash equivalents
\u00a0
as of 31 December 2023 is USD 41.2 million
\u00a0
held on fixed interest time deposit
contracts with different duration and maturity dates up
\u00a0
to 26 January 2024.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndBankBalancesAtCentralBanksExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_87": { "value": "
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. A corresponding
amount is recognized directly in equity.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIssuedCapitalExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_88": { "value": "
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. A corresponding
amount is recognized directly in equity.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTreasurySharesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_89": { "value": "
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. A corresponding
amount is recognized directly in equity.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDividendsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_90": { "value": "
\u00a0
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Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2022
975,433
32.9
-
32.9
Treasury shares sold/-purchased
-36,369
-
-0.9
-0.9
Share issues
78,944
1.8
-
1.8
As of 31 December 2022
1,018,008
34.8
-0.9
33.9
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 sold/-purchased
-43,007
-
-1.0
-1.0
Cancellation of treasury shares
-
-1.9
1.9
-
As of 31 December 2023
975,000
32.9
-
32.9
\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
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
At the 2023 Annual General Meeting (AGM), the
\u00a0
Board of Directors was given the authority
\u00a0
to acquire treasury shares with a total
nominal value of up to NOK 24,375,000 which corresponds
\u00a0
to 97,500,000 new shares. The maximum amount
\u00a0
to be paid per share is
NOK 100 and the minimum amount is NOK 1.
\u00a0
Purchases of treasury shares are made on the
\u00a0
Oslo Stock Exchange. The authorization
was time-limited until the 2024 AGM, and not beyond
\u00a0
30 June 2024.
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital
\u00a0
by up to NOK 24,375.000 which
corresponds to 97,500,000 new shares. The authorization
\u00a0
was time-limited until the 2024 AGM, and not
\u00a0
beyond 30 June 2024.
\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 2024 AGM, but
\u00a0
not beyond 30 June 2024.
\u00a0
The Board of Directors was given the authority
\u00a0
to approve total dividend distributions of up
\u00a0
to NOK 1 per share from the date of the 2023
AGM until the date of the 2024 AGM. Following
\u00a0
this, the Board of Directors decided to distribute
\u00a0
quarterly dividends of NOK 0.25 in
February, May, August, and November 2023.
The Board of Directors was also given the authority
\u00a0
to reduce share capital by NOK 19,844,127.25
\u00a0
through the cancellation of
79,376,509 treasury shares, each with a nominal value
\u00a0
of NOK 0.25. On 17 August 2023 the
\u00a0
cancellation of all 79,376,509 treasury
shares held by the Company was completed.
Interest
The Company's shareholders as of 31 December 2023
Shares
(percent)
Goldman Sachs & Co. LLC*
92,535,456
9.49
Euroclear Bank S.A./N.V.
90,576,149
9.29
Folketrygdfondet
69,504,098
7.13
RAK Gas LLC
34,311,403
3.52
Goldman Sachs & Co. LLC*
33,147,785
3.40
BNP Paribas
30,908,678
3.17
State Street Bank and Trust Comp
24,816,914
2.55
The Bank of New York Mellon
18,136,059
1.86
JPMorgan Chase Bank
16,814,249
1.72
HSBC Bank Plc
13,888,921
1.42
Clearstream Banking S.A.
13,813,018
1.42
CACEIS Bank
12,803,672
1.31
Saxo Bank A/S
9,620,072
0.99
Salt Value AS
9,382,143
0.96
State Street Bank and Trust Comp
9,123,969
0.94
Verdipapirfondet KLP Aksjenorge IN
8,919,483
0.91
State Street Bank and Trust Comp
7,615,795
0.78
Nordnet Bank AB
7,533,472
0.77
UBS Switzerland AG
6,479,383
0.66
Nordnet Livsforsikring AS
5,876,299
0.60
Other shareholders
459,192,982
47.10
Total number of shares excluding treasury shares
975,000,000
100.00
Treasury shares as of 31 December 2023 (DNO ASA)
0.00
0.00
Total number of outstanding shares
975,000,000
100.00
* At yearend 2023, 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 92 million were paid in 2023
\u00a0
(USD 72.8 million in 2022). See Note 28
\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 executive management.
", "dimensions": { "concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_91": { "value": "
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Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2022
975,433
32.9
-
32.9
Treasury shares sold/-purchased
-36,369
-
-0.9
-0.9
Share issues
78,944
1.8
-
1.8
As of 31 December 2022
1,018,008
34.8
-0.9
33.9
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 sold/-purchased
-43,007
-
-1.0
-1.0
Cancellation of treasury shares
-
-1.9
1.9
-
As of 31 December 2023
975,000
32.9
-
32.9
\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
At the 2023 Annual General Meeting (AGM), the
\u00a0
Board of Directors was given the authority
\u00a0
to acquire treasury shares with a total
nominal value of up to NOK 24,375,000 which corresponds
\u00a0
to 97,500,000 new shares. The maximum amount
\u00a0
to be paid per share is
NOK 100 and the minimum amount is NOK 1.
\u00a0
Purchases of treasury shares are made on the
\u00a0
Oslo Stock Exchange. The authorization
was time-limited until the 2024 AGM, and not beyond
\u00a0
30 June 2024.
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital
\u00a0
by up to NOK 24,375.000 which
corresponds to 97,500,000 new shares. The authorization
\u00a0
was time-limited until the 2024 AGM, and not
\u00a0
beyond 30 June 2024.
\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 2024 AGM, but
\u00a0
not beyond 30 June 2024.
\u00a0
The Board of Directors was given the authority
\u00a0
to approve total dividend distributions of up
\u00a0
to NOK 1 per share from the date of the 2023
AGM until the date of the 2024 AGM. Following
\u00a0
this, the Board of Directors decided to distribute
\u00a0
quarterly dividends of NOK 0.25 in
February, May, August, and November 2023.
The Board of Directors was also given the authority
\u00a0
to reduce share capital by NOK 19,844,127.25
\u00a0
through the cancellation of
79,376,509 treasury shares, each with a nominal value
\u00a0
of NOK 0.25. On 17 August 2023 the
\u00a0
cancellation of all 79,376,509 treasury
shares held by the Company was completed.
Interest
The Company's shareholders as of 31 December 2023
Shares
(percent)
Goldman Sachs & Co. LLC*
92,535,456
9.49
Euroclear Bank S.A./N.V.
90,576,149
9.29
Folketrygdfondet
69,504,098
7.13
RAK Gas LLC
34,311,403
3.52
Goldman Sachs & Co. LLC*
33,147,785
3.40
BNP Paribas
30,908,678
3.17
State Street Bank and Trust Comp
24,816,914
2.55
The Bank of New York Mellon
18,136,059
1.86
JPMorgan Chase Bank
16,814,249
1.72
HSBC Bank Plc
13,888,921
1.42
Clearstream Banking S.A.
13,813,018
1.42
CACEIS Bank
12,803,672
1.31
Saxo Bank A/S
9,620,072
0.99
Salt Value AS
9,382,143
0.96
State Street Bank and Trust Comp
9,123,969
0.94
Verdipapirfondet KLP Aksjenorge IN
8,919,483
0.91
State Street Bank and Trust Comp
7,615,795
0.78
Nordnet Bank AB
7,533,472
0.77
UBS Switzerland AG
6,479,383
0.66
Nordnet Livsforsikring AS
5,876,299
0.60
Other shareholders
459,192,982
47.10
Total number of shares excluding treasury shares
975,000,000
100.00
Treasury shares as of 31 December 2023 (DNO ASA)
0.00
0.00
Total number of outstanding shares
975,000,000
100.00
* At yearend 2023, 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 92 million were paid in 2023
\u00a0
(USD 72.8 million in 2022). See Note 28
\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 executive management.
", "dimensions": { "concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_92": { "value": "
\u00a0
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\u00a0
\n
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2022
975,433
32.9
-
32.9
Treasury shares sold/-purchased
-36,369
-
-0.9
-0.9
Share issues
78,944
1.8
-
1.8
As of 31 December 2022
1,018,008
34.8
-0.9
33.9
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 sold/-purchased
-43,007
-
-1.0
-1.0
Cancellation of treasury shares
-
-1.9
1.9
-
As of 31 December 2023
975,000
32.9
-
32.9
\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
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
At the 2023 Annual General Meeting (AGM), the
\u00a0
Board of Directors was given the authority
\u00a0
to acquire treasury shares with a total
nominal value of up to NOK 24,375,000 which corresponds
\u00a0
to 97,500,000 new shares. The maximum amount
\u00a0
to be paid per share is
NOK 100 and the minimum amount is NOK 1.
\u00a0
Purchases of treasury shares are made on the
\u00a0
Oslo Stock Exchange. The authorization
was time-limited until the 2024 AGM, and not beyond
\u00a0
30 June 2024.
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital
\u00a0
by up to NOK 24,375.000 which
corresponds to 97,500,000 new shares. The authorization
\u00a0
was time-limited until the 2024 AGM, and not
\u00a0
beyond 30 June 2024.
\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 2024 AGM, but
\u00a0
not beyond 30 June 2024.
\u00a0
The Board of Directors was given the authority
\u00a0
to approve total dividend distributions of up
\u00a0
to NOK 1 per share from the date of the 2023
AGM until the date of the 2024 AGM. Following
\u00a0
this, the Board of Directors decided to distribute
\u00a0
quarterly dividends of NOK 0.25 in
February, May, August, and November 2023.
The Board of Directors was also given the authority
\u00a0
to reduce share capital by NOK 19,844,127.25
\u00a0
through the cancellation of
79,376,509 treasury shares, each with a nominal value
\u00a0
of NOK 0.25. On 17 August 2023 the
\u00a0
cancellation of all 79,376,509 treasury
shares held by the Company was completed.
Interest
The Company's shareholders as of 31 December 2023
Shares
(percent)
Goldman Sachs & Co. LLC*
92,535,456
9.49
Euroclear Bank S.A./N.V.
90,576,149
9.29
Folketrygdfondet
69,504,098
7.13
RAK Gas LLC
34,311,403
3.52
Goldman Sachs & Co. LLC*
33,147,785
3.40
BNP Paribas
30,908,678
3.17
State Street Bank and Trust Comp
24,816,914
2.55
The Bank of New York Mellon
18,136,059
1.86
JPMorgan Chase Bank
16,814,249
1.72
HSBC Bank Plc
13,888,921
1.42
Clearstream Banking S.A.
13,813,018
1.42
CACEIS Bank
12,803,672
1.31
Saxo Bank A/S
9,620,072
0.99
Salt Value AS
9,382,143
0.96
State Street Bank and Trust Comp
9,123,969
0.94
Verdipapirfondet KLP Aksjenorge IN
8,919,483
0.91
State Street Bank and Trust Comp
7,615,795
0.78
Nordnet Bank AB
7,533,472
0.77
UBS Switzerland AG
6,479,383
0.66
Nordnet Livsforsikring AS
5,876,299
0.60
Other shareholders
459,192,982
47.10
Total number of shares excluding treasury shares
975,000,000
100.00
Treasury shares as of 31 December 2023 (DNO ASA)
0.00
0.00
Total number of outstanding shares
975,000,000
100.00
* At yearend 2023, 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 92 million were paid in 2023
\u00a0
(USD 72.8 million in 2022). See Note 28
\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 executive management.
", "dimensions": { "concept": "ifrs-full:DisclosureOfDividendsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_93": { "value": "
\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
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2022
975,433
32.9
-
32.9
Treasury shares sold/-purchased
-36,369
-
-0.9
-0.9
Share issues
78,944
1.8
-
1.8
As of 31 December 2022
1,018,008
34.8
-0.9
33.9
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 sold/-purchased
-43,007
-
-1.0
-1.0
Cancellation of treasury shares
-
-1.9
1.9
-
As of 31 December 2023
975,000
32.9
-
32.9
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
At the 2023 Annual General Meeting (AGM), the
\u00a0
Board of Directors was given the authority
\u00a0
to acquire treasury shares with a total
nominal value of up to NOK 24,375,000 which corresponds
\u00a0
to 97,500,000 new shares. The maximum amount
\u00a0
to be paid per share is
NOK 100 and the minimum amount is NOK 1.
\u00a0
Purchases of treasury shares are made on the
\u00a0
Oslo Stock Exchange. The authorization
was time-limited until the 2024 AGM, and not beyond
\u00a0
30 June 2024.
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital
\u00a0
by up to NOK 24,375.000 which
corresponds to 97,500,000 new shares. The authorization
\u00a0
was time-limited until the 2024 AGM, and not
\u00a0
beyond 30 June 2024.
\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 2024 AGM, but
\u00a0
not beyond 30 June 2024.
\u00a0
The Board of Directors was given the authority
\u00a0
to approve total dividend distributions of up
\u00a0
to NOK 1 per share from the date of the 2023
AGM until the date of the 2024 AGM. Following
\u00a0
this, the Board of Directors decided to distribute
\u00a0
quarterly dividends of NOK 0.25 in
February, May, August, and November 2023.
The Board of Directors was also given the authority
\u00a0
to reduce share capital by NOK 19,844,127.25
\u00a0
through the cancellation of
79,376,509 treasury shares, each with a nominal value
\u00a0
of NOK 0.25. On 17 August 2023 the
\u00a0
cancellation of all 79,376,509 treasury
shares held by the Company was completed.
Interest
The Company's shareholders as of 31 December 2023
Shares
(percent)
Goldman Sachs & Co. LLC*
92,535,456
9.49
Euroclear Bank S.A./N.V.
90,576,149
9.29
Folketrygdfondet
69,504,098
7.13
RAK Gas LLC
34,311,403
3.52
Goldman Sachs & Co. LLC*
33,147,785
3.40
BNP Paribas
30,908,678
3.17
State Street Bank and Trust Comp
24,816,914
2.55
The Bank of New York Mellon
18,136,059
1.86
JPMorgan Chase Bank
16,814,249
1.72
HSBC Bank Plc
13,888,921
1.42
Clearstream Banking S.A.
13,813,018
1.42
CACEIS Bank
12,803,672
1.31
Saxo Bank A/S
9,620,072
0.99
Salt Value AS
9,382,143
0.96
State Street Bank and Trust Comp
9,123,969
0.94
Verdipapirfondet KLP Aksjenorge IN
8,919,483
0.91
State Street Bank and Trust Comp
7,615,795
0.78
Nordnet Bank AB
7,533,472
0.77
UBS Switzerland AG
6,479,383
0.66
Nordnet Livsforsikring AS
5,876,299
0.60
Other shareholders
459,192,982
47.10
Total number of shares excluding treasury shares
975,000,000
100.00
Treasury shares as of 31 December 2023 (DNO ASA)
0.00
0.00
Total number of outstanding shares
975,000,000
100.00
* At yearend 2023, 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 92 million were paid in 2023
\u00a0
(USD 72.8 million in 2022). See Note 28
\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 executive management.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_94": { "value": "
\u00a0
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\u00a0
\n
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2022
975,433
32.9
-
32.9
Treasury shares sold/-purchased
-36,369
-
-0.9
-0.9
Share issues
78,944
1.8
-
1.8
As of 31 December 2022
1,018,008
34.8
-0.9
33.9
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 sold/-purchased
-43,007
-
-1.0
-1.0
Cancellation of treasury shares
-
-1.9
1.9
-
As of 31 December 2023
975,000
32.9
-
32.9
\u00a0
\n
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\u00a0
\n
At the 2023 Annual General Meeting (AGM), the
\u00a0
Board of Directors was given the authority
\u00a0
to acquire treasury shares with a total
nominal value of up to NOK 24,375,000 which corresponds
\u00a0
to 97,500,000 new shares. The maximum amount
\u00a0
to be paid per share is
NOK 100 and the minimum amount is NOK 1.
\u00a0
Purchases of treasury shares are made on the
\u00a0
Oslo Stock Exchange. The authorization
was time-limited until the 2024 AGM, and not beyond
\u00a0
30 June 2024.
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital
\u00a0
by up to NOK 24,375.000 which
corresponds to 97,500,000 new shares. The authorization
\u00a0
was time-limited until the 2024 AGM, and not
\u00a0
beyond 30 June 2024.
\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 2024 AGM, but
\u00a0
not beyond 30 June 2024.
\u00a0
The Board of Directors was given the authority
\u00a0
to approve total dividend distributions of up
\u00a0
to NOK 1 per share from the date of the 2023
AGM until the date of the 2024 AGM. Following
\u00a0
this, the Board of Directors decided to distribute
\u00a0
quarterly dividends of NOK 0.25 in
February, May, August, and November 2023.
The Board of Directors was also given the authority
\u00a0
to reduce share capital by NOK 19,844,127.25
\u00a0
through the cancellation of
79,376,509 treasury shares, each with a nominal value
\u00a0
of NOK 0.25. On 17 August 2023 the
\u00a0
cancellation of all 79,376,509 treasury
shares held by the Company was completed.
Interest
The Company's shareholders as of 31 December 2023
Shares
(percent)
Goldman Sachs & Co. LLC*
92,535,456
9.49
Euroclear Bank S.A./N.V.
90,576,149
9.29
Folketrygdfondet
69,504,098
7.13
RAK Gas LLC
34,311,403
3.52
Goldman Sachs & Co. LLC*
33,147,785
3.40
BNP Paribas
30,908,678
3.17
State Street Bank and Trust Comp
24,816,914
2.55
The Bank of New York Mellon
18,136,059
1.86
JPMorgan Chase Bank
16,814,249
1.72
HSBC Bank Plc
13,888,921
1.42
Clearstream Banking S.A.
13,813,018
1.42
CACEIS Bank
12,803,672
1.31
Saxo Bank A/S
9,620,072
0.99
Salt Value AS
9,382,143
0.96
State Street Bank and Trust Comp
9,123,969
0.94
Verdipapirfondet KLP Aksjenorge IN
8,919,483
0.91
State Street Bank and Trust Comp
7,615,795
0.78
Nordnet Bank AB
7,533,472
0.77
UBS Switzerland AG
6,479,383
0.66
Nordnet Livsforsikring AS
5,876,299
0.60
Other shareholders
459,192,982
47.10
Total number of shares excluding treasury shares
975,000,000
100.00
Treasury shares as of 31 December 2023 (DNO ASA)
0.00
0.00
Total number of outstanding shares
975,000,000
100.00
* At yearend 2023, 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 92 million were paid in 2023
\u00a0
(USD 72.8 million in 2022). See Note 28
\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 executive management.
", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_95": { "value": "
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_96": { "value": "
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.
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 17.
\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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "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)
2023
2022
2023
2022
Non-current
Bond loan (ISIN NO0010852643)
DNO03
USD
131.2
8.375
29.05.24
9.0
-
131.5
-
131.2
Bond loan (ISIN NO0011088593)
DNO04
USD
400.0
7.875
09.09.26
8.8
378.1
375.8
400.0
400.0
Capitalized borrowing issue costs
-8.0
-11.3
Reserve based lending facility
-
USD
310.0
see below
see below
-
-
26.6
-
26.6
Total non-current interest-bearing liabilities
378.1
533.9
392.0
546.4
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
310.0
see below
see below
-
35.0
8.4
35.0
8.4
Total current interest-bearing liabilities
165.9
8.4
166.2
8.4
Total interest-bearing liabilities
544.0
542.3
558.2
554.8
Facility and carrying amount for the bonds is
\u00a0
shown net of bonds held by the Company. On 22 January 2024,
\u00a0
DNO ASA fully completed
a USD 131.2 million call option redemption of
\u00a0
the DNO03 bond (at a price of 100 percent plus
\u00a0
accrued interest).
\u00a0
The financial covenants of the bonds issued by DNO
\u00a0
ASA require a minimum USD 40 million of
\u00a0
liquidity and the maintenance by the
Group of either an equity ratio of 30 percent or
\u00a0
a total equity of a minimum of USD 600
\u00a0
million. There is also a restriction on declaring or
making any dividend payments if the liquidity of
\u00a0
the Company is less than USD 80 million immediately
\u00a0
following such distribution.
As of 31 December 2023, 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 310 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 3.00 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 and
\u00a0
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 2024 is USD 100 million. Amount utilized
\u00a0
as of the reporting date is disclosed in
the table above. In addition, USD 17.9 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
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\n
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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
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
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2022
flows
Amortization
Currency
Acquisition
Reclass
2022
Bond loans (non-current)
794.9
-263.7
-
-
-
-
531.2
Bond loans (current)
-
-
-
-
-
-
-
Borrowing issue costs
-16.5
-
5.2
-
-
-
-11.3
Reserve based lending facility (non-current)
95.0
-60.0
-
-
-
-8.4
26.6
Reserve based lending facility (current)
-
-
-
-
-
8.4
8.4
Total
873.4
-323.7
5.2
-
-
-
554.8
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 2023 were between 4.9 percent
\u00a0
and 5.0 percent (yearend 2022:
between 4.5 percent and 4.8 percent). The credit
\u00a0
risk element included in the discount rates
\u00a0
at yearend 2023 was 0.8 percent (yearend
2022: 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 deem it reasonable not
\u00a0
to change its method for determining the discount
\u00a0
rate. The Company have compared
its discount rate towards peers and noted that they
\u00a0
are within a range applied by other peer
\u00a0
companies.
\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
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Years ended 31 December
USD million
2023
2022
Non-current asset retirement obligations (ARO)
382.7
368.2
Current asset retirement obligations (ARO)
10.6
20.5
Total asset retirement obligations (ARO)
393.2
388.6
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
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\n
\u00a0
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\n
\u00a0
\n
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\n
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\u00a0
\n
\u00a0
\n
Years ended 31 December
USD million
2023
2022
Asset retirement obligation as of 1 January
388.6
456.0
Decommissioning spend
-17.9
-70.5
Increase/-decrease in existing provisions
10.5
25.0
Amounts charged against provisions
-
-
Effects of change in the discount rate
-5.4
-37.0
Accretion expenses (unwinding of discount)
17.4
15.2
Reclassification and transfer
-
-
Asset retirement obligation as of 31 December
393.2
388.6
Net gain on disposal of licenses of USD 5.5 million
\u00a0
in the third quarter, was mainly related to DNO's sale of the 10 percent
\u00a0
working
interest in the East Foinaven license on the UKCS. The
\u00a0
transaction was completed on 14 July 2023 and
\u00a0
involved a net negative
consideration of USD 5.4 million from DNO and in return,
\u00a0
the buyer took over the ARO obligation. Consequently, as part of
\u00a0
the gain/loss
calculation, the related book value of the ARO provision
\u00a0
(USD 10.4 million) was derecognized from the
\u00a0
balance sheet.
.
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_98": { "value": "
\u00a0
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\u00a0
\n
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
rate
\u00a0
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2023
2022
2023
2022
Non-current
Bond loan (ISIN NO0010852643)
DNO03
USD
131.2
8.375
29.05.24
9.0
-
131.5
-
131.2
Bond loan (ISIN NO0011088593)
DNO04
USD
400.0
7.875
09.09.26
8.8
378.1
375.8
400.0
400.0
Capitalized borrowing issue costs
-8.0
-11.3
Reserve based lending facility
-
USD
310.0
see below
see below
-
-
26.6
-
26.6
Total non-current interest-bearing liabilities
378.1
533.9
392.0
546.4
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
310.0
see below
see below
-
35.0
8.4
35.0
8.4
Total current interest-bearing liabilities
165.9
8.4
166.2
8.4
Total interest-bearing liabilities
544.0
542.3
558.2
554.8
Facility and carrying amount for the bonds is
\u00a0
shown net of bonds held by the Company. On 22 January 2024,
\u00a0
DNO ASA fully completed
a USD 131.2 million call option redemption of
\u00a0
the DNO03 bond (at a price of 100 percent plus
\u00a0
accrued interest).
\u00a0
The financial covenants of the bonds issued by DNO
\u00a0
ASA require a minimum USD 40 million of
\u00a0
liquidity and the maintenance by the
Group of either an equity ratio of 30 percent or
\u00a0
a total equity of a minimum of USD 600
\u00a0
million. There is also a restriction on declaring or
making any dividend payments if the liquidity of
\u00a0
the Company is less than USD 80 million immediately
\u00a0
following such distribution.
As of 31 December 2023, 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 310 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 3.00 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 and
\u00a0
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 2024 is USD 100 million. Amount utilized
\u00a0
as of the reporting date is disclosed in
the table above. In addition, USD 17.9 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
\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
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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
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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
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
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
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2022
flows
Amortization
Currency
Acquisition
Reclass
2022
Bond loans (non-current)
794.9
-263.7
-
-
-
-
531.2
Bond loans (current)
-
-
-
-
-
-
-
Borrowing issue costs
-16.5
-
5.2
-
-
-
-11.3
Reserve based lending facility (non-current)
95.0
-60.0
-
-
-
-8.4
26.6
Reserve based lending facility (current)
-
-
-
-
-
8.4
8.4
Total
873.4
-323.7
5.2
-
-
-
554.8
", "dimensions": { "concept": "ifrs-full:DisclosureOfDebtSecuritiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_99": { "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
\u00a0
\n
\u00a0
\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
\u00a0
\n
\u00a0
\n
\u00a0
\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
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
rate
\u00a0
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2023
2022
2023
2022
Non-current
Bond loan (ISIN NO0010852643)
DNO03
USD
131.2
8.375
29.05.24
9.0
-
131.5
-
131.2
Bond loan (ISIN NO0011088593)
DNO04
USD
400.0
7.875
09.09.26
8.8
378.1
375.8
400.0
400.0
Capitalized borrowing issue costs
-8.0
-11.3
Reserve based lending facility
-
USD
310.0
see below
see below
-
-
26.6
-
26.6
Total non-current interest-bearing liabilities
378.1
533.9
392.0
546.4
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
310.0
see below
see below
-
35.0
8.4
35.0
8.4
Total current interest-bearing liabilities
165.9
8.4
166.2
8.4
Total interest-bearing liabilities
544.0
542.3
558.2
554.8
Facility and carrying amount for the bonds is
\u00a0
shown net of bonds held by the Company. On 22 January 2024,
\u00a0
DNO ASA fully completed
a USD 131.2 million call option redemption of
\u00a0
the DNO03 bond (at a price of 100 percent plus
\u00a0
accrued interest).
\u00a0
The financial covenants of the bonds issued by DNO
\u00a0
ASA require a minimum USD 40 million of
\u00a0
liquidity and the maintenance by the
Group of either an equity ratio of 30 percent or
\u00a0
a total equity of a minimum of USD 600
\u00a0
million. There is also a restriction on declaring or
making any dividend payments if the liquidity of
\u00a0
the Company is less than USD 80 million immediately
\u00a0
following such distribution.
As of 31 December 2023, 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 310 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 3.00 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 and
\u00a0
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 2024 is USD 100 million. Amount utilized
\u00a0
as of the reporting date is disclosed in
the table above. In addition, USD 17.9 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
\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
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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
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
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
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2022
flows
Amortization
Currency
Acquisition
Reclass
2022
Bond loans (non-current)
794.9
-263.7
-
-
-
-
531.2
Bond loans (current)
-
-
-
-
-
-
-
Borrowing issue costs
-16.5
-
5.2
-
-
-
-11.3
Reserve based lending facility (non-current)
95.0
-60.0
-
-
-
-8.4
26.6
Reserve based lending facility (current)
-
-
-
-
-
8.4
8.4
Total
873.4
-323.7
5.2
-
-
-
554.8
", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_100": { "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
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Years ended 31 December
USD million
2023
2022
Non-current lease liabilities
14.0
6.5
Current lease liabilities
3.6
6.8
Total lease liabilities
17.5
13.3
The recognized lease liabilities in the balance sheet
\u00a0
are mainly related to office rent.
The identified lease liabilities have no significant impact
\u00a0
on the Group\u2019s financing, loan covenants or dividend 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
49.1 million as of yearend 2023 (2022: USD
\u00a0
56 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
2023
2022
Within one year
4.8
7.0
Two to five years
\u00a0
11.8
6.5
After five years
\u00a0
5.4
-
Total undiscounted lease liabilities end of the period
\u00a0
22.0
13.5
", "dimensions": { "concept": "ifrs-full:DisclosureOfLeasePrepaymentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_101": { "value": "
\u00a0
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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
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\n
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\n
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\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
Years ended 31 December
USD million
2023
2022
Non-current lease liabilities
14.0
6.5
Current lease liabilities
3.6
6.8
Total lease liabilities
17.5
13.3
The recognized lease liabilities in the balance sheet
\u00a0
are mainly related to office rent.
The identified lease liabilities have no significant impact
\u00a0
on the Group\u2019s financing, loan covenants or dividend 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
49.1 million as of yearend 2023 (2022: USD
\u00a0
56 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
2023
2022
Within one year
4.8
7.0
Two to five years
\u00a0
11.8
6.5
After five years
\u00a0
5.4
-
Total undiscounted lease liabilities end of the period
\u00a0
22.0
13.5
", "dimensions": { "concept": "ifrs-full:DisclosureOfLeasesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_102": { "value": "
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 resources
\u00a0
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.
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 and regulations, and technology. Decommissioning activities will
\u00a0
normally 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_103": { "value": "
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 2023 were between 4.9 percent
\u00a0
and 5.0 percent (yearend 2022:
between 4.5 percent and 4.8 percent). The credit
\u00a0
risk element included in the discount rates
\u00a0
at yearend 2023 was 0.8 percent (yearend
2022: 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 deem it reasonable not
\u00a0
to change its method for determining the discount
\u00a0
rate. The Company have compared
its discount rate towards peers and noted that they
\u00a0
are within a range applied by other peer
\u00a0
companies.
\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
Years ended 31 December
USD million
2023
2022
Non-current asset retirement obligations (ARO)
382.7
368.2
Current asset retirement obligations (ARO)
10.6
20.5
Total asset retirement obligations (ARO)
393.2
388.6
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
2023
2022
Asset retirement obligation as of 1 January
388.6
456.0
Decommissioning spend
-17.9
-70.5
Increase/-decrease in existing provisions
10.5
25.0
Amounts charged against provisions
-
-
Effects of change in the discount rate
-5.4
-37.0
Accretion expenses (unwinding of discount)
17.4
15.2
Reclassification and transfer
-
-
Asset retirement obligation as of 31 December
393.2
388.6
Net gain on disposal of licenses of USD 5.5 million
\u00a0
in the third quarter, was mainly related to DNO's sale of the 10 percent
\u00a0
working
interest in the East Foinaven license on the UKCS. The
\u00a0
transaction was completed on 14 July 2023 and
\u00a0
involved a net negative
consideration of USD 5.4 million from DNO and in return,
\u00a0
the buyer took over the ARO obligation. Consequently, as part of
\u00a0
the gain/loss
calculation, the related book value of the ARO provision
\u00a0
(USD 10.4 million) was derecognized from the
\u00a0
balance sheet.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
2023
2022
Non-current
Other long-term obligations
7.3
4.9
Total non-current other liabilities
7.3
4.9
Current
Accrued interest expense
2.8
2.8
Other provisions and charges
6.4
36.9
Total current other liabilities
9.1
39.8
Total other liabilities
16.5
44.7
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 payable
\u00a0
relates to North Sea overlifted
volumes, valued at production cost including depreciation.
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_104": { "value": "
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 2023 were between 4.9 percent
\u00a0
and 5.0 percent (yearend 2022:
between 4.5 percent and 4.8 percent). The credit
\u00a0
risk element included in the discount rates
\u00a0
at yearend 2023 was 0.8 percent (yearend
2022: 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 deem it reasonable not
\u00a0
to change its method for determining the discount
\u00a0
rate. The Company have compared
its discount rate towards peers and noted that they
\u00a0
are within a range applied by other peer
\u00a0
companies.
\u00a0
\n
\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
2023
2022
Non-current asset retirement obligations (ARO)
382.7
368.2
Current asset retirement obligations (ARO)
10.6
20.5
Total asset retirement obligations (ARO)
393.2
388.6
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
2023
2022
Asset retirement obligation as of 1 January
388.6
456.0
Decommissioning spend
-17.9
-70.5
Increase/-decrease in existing provisions
10.5
25.0
Amounts charged against provisions
-
-
Effects of change in the discount rate
-5.4
-37.0
Accretion expenses (unwinding of discount)
17.4
15.2
Reclassification and transfer
-
-
Asset retirement obligation as of 31 December
393.2
388.6
Net gain on disposal of licenses of USD 5.5 million
\u00a0
in the third quarter, was mainly related to DNO's sale of the 10 percent
\u00a0
working
interest in the East Foinaven license on the UKCS. The
\u00a0
transaction was completed on 14 July 2023 and
\u00a0
involved a net negative
consideration of USD 5.4 million from DNO and in return,
\u00a0
the buyer took over the ARO obligation. Consequently, as part of
\u00a0
the gain/loss
calculation, the related book value of the ARO provision
\u00a0
(USD 10.4 million) was derecognized from the
\u00a0
balance sheet.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
2023
2022
Non-current
Other long-term obligations
7.3
4.9
Total non-current other liabilities
7.3
4.9
Current
Accrued interest expense
2.8
2.8
Other provisions and charges
6.4
36.9
Total current other liabilities
9.1
39.8
Total other liabilities
16.5
44.7
Note 21
Trade and other payables
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_105": { "value": "
Accounting policies
Provisions for other liabilities
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.
The provisions are reviewed at each balance
\u00a0
sheet date and adjusted to reflect the current best estimate.
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_106": { "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
Years ended 31 December
USD million
2023
2022
Non-current
Other long-term obligations
7.3
4.9
Total non-current other liabilities
7.3
4.9
Current
Accrued interest expense
2.8
2.8
Other provisions and charges
6.4
36.9
Total current other liabilities
9.1
39.8
Total other liabilities
16.5
44.7
", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_107": { "value": "
Note 21
Trade and other payables
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
2023
2022
Trade payables
70.5
62.7
Public duties payable
4.3
4.1
Prepayments from customers
21.2
12.7
Overlift
1.2
9.0
Other accrued expenses
123.9
155.7
Total trade and other payables
221.1
244.1
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_108": { "value": "
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
14.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\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
2023
2022
Trade payables
70.5
62.7
Public duties payable
4.3
4.1
Prepayments from customers
21.2
12.7
Overlift
1.2
9.0
Other accrued expenses
123.9
155.7
Total trade and other payables
221.1
244.1
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 payable
\u00a0
relates to North Sea overlifted
volumes, valued at production cost including depreciation.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_109": { "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
Years ended 31 December
USD million
2023
2022
Trade payables
70.5
62.7
Public duties payable
4.3
4.1
Prepayments from customers
21.2
12.7
Overlift
1.2
9.0
Other accrued expenses
123.9
155.7
Total trade and other payables
221.1
244.1
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 payable
\u00a0
relates to North Sea overlifted
volumes, valued at production cost including depreciation.
", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_110": { "value": "
Accounting policies
Financial instruments
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
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 17.
\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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_111": { "value": "
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
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 17.
\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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_112": { "value": "
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_113": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
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.
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 2023
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 2022
\u00a0
and 2023 profit/-loss before income tax from oil and
\u00a0
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)
2023
+/- 15.0
\u00a0
+/- 77.9
2022
+/- 15.0
\u00a0
+/- 170.9
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 2023 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\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
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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)
2023
+ 10.0
6.0
2023
- 10.0
-6.0
2022
+ 10.0
-3.5
2022
- 10.0
3.5
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2023
+ 10.0
-36.7
2023
- 10.0
36.7
2022
+ 10.0
-19.0
2022
- 10.0
19.0
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2023
+ 10.0
0.3
2023
- 10.0
-0.3
2022
+ 10.0
-4.8
2022
- 10.0
4.8
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 2023. The Group is also exposed to interest
\u00a0
rate risk on its cash deposits held at floating
\u00a0
interest rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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.
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2023
+/- 200
+/-7.6
2022
+/- 200
+/-7.7
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 17. 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
\u00a0
basis for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 12) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made
\u00a0
on a regular basis pursuant to an approved
\u00a0
budget and work program. The cash
distributions anticipated to be received from Foxtrot
\u00a0
International will be sufficient to enable the Company
\u00a0
to meet all of its 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 2023 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. See also
\u00a0
Note 12 regarding the
Company\u2019s entry in West Africa.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
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
-
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2022
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
11.3
33.8
203.8
460.7
Other provisions and charges
-
18.4
22.2
-
-
Taxes payable
-
125.7
-
-
-
Trade and other payables
-
233.0
2.0
-
-
Total liabilities
-
388.4
58.0
203.8
460.7
* Face value of the bonds was USD 531.2 million at yearend 2023 (USD 531.2 million at yearend 2022).
For changes in liabilities arising from financing activities,
\u00a0
see Note 17.
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
2023
2022
Trade debtors (non-current portion) (Note 14)
129.8
-
Trade debtors (Note 14)
149.5
311.8
Other receivables (Note 14)
115.9
126.0
Tax receivables
\u00a0
-
25.8
Cash and cash equivalents
718.8
954.3
Total
\u00a0
1,114.1
1,417.9
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 14 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 2023
Trade debtors (nominal value) (Note 14)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2022
Trade debtors (nominal value) (Note 14)
-
132.7
58.1
55.9
63.1
2.0
311.8
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.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The Group monitors capital on the basis of
\u00a0
the equity ratio, which is calculated as total equity
\u00a0
divided by total assets. It is DNO\u2019s policy
that this ratio should be 30 percent or higher. The financial covenants
\u00a0
of the bond loans require a minimum of USD 40
\u00a0
million of liquidity
and that the Group maintains either an equity ratio
\u00a0
of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
There is also a restriction from 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
17. The equity ratio has improved primarily
\u00a0
due to a net profit in 2023. The 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 2023
\u00a0
and 2022.
Years ended 31 December
USD million
2023
2022
Total equity
1,234.8
1,369.4
Total assets
2,638.3
2,803.0
Equity ratio
46.8%
48.9%
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
\u00a0
within Level 1 that are observable for the asset
\u00a0
or liability, either directly 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
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)
17
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
17
166.2
166.2
130.9
-
35.0
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2022 - 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)
17
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
17
8.4
8.4
-
-
8.4
", "dimensions": { "concept": "ifrs-full:DisclosureOfMarketRiskExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_114": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
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.
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 2023
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 2022
\u00a0
and 2023 profit/-loss before income tax from oil and
\u00a0
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)
2023
+/- 15.0
\u00a0
+/- 77.9
2022
+/- 15.0
\u00a0
+/- 170.9
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 2023 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\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
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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)
2023
+ 10.0
6.0
2023
- 10.0
-6.0
2022
+ 10.0
-3.5
2022
- 10.0
3.5
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2023
+ 10.0
-36.7
2023
- 10.0
36.7
2022
+ 10.0
-19.0
2022
- 10.0
19.0
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2023
+ 10.0
0.3
2023
- 10.0
-0.3
2022
+ 10.0
-4.8
2022
- 10.0
4.8
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 2023. The Group is also exposed to interest
\u00a0
rate risk on its cash deposits held at floating
\u00a0
interest rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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.
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2023
+/- 200
+/-7.6
2022
+/- 200
+/-7.7
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 17. 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
\u00a0
basis for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 12) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made
\u00a0
on a regular basis pursuant to an approved
\u00a0
budget and work program. The cash
distributions anticipated to be received from Foxtrot
\u00a0
International will be sufficient to enable the Company
\u00a0
to meet all of its 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 2023 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. See also
\u00a0
Note 12 regarding the
Company\u2019s entry in West Africa.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
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
-
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2022
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
11.3
33.8
203.8
460.7
Other provisions and charges
-
18.4
22.2
-
-
Taxes payable
-
125.7
-
-
-
Trade and other payables
-
233.0
2.0
-
-
Total liabilities
-
388.4
58.0
203.8
460.7
* Face value of the bonds was USD 531.2 million at yearend 2023 (USD 531.2 million at yearend 2022).
For changes in liabilities arising from financing activities,
\u00a0
see Note 17.
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
2023
2022
Trade debtors (non-current portion) (Note 14)
129.8
-
Trade debtors (Note 14)
149.5
311.8
Other receivables (Note 14)
115.9
126.0
Tax receivables
\u00a0
-
25.8
Cash and cash equivalents
718.8
954.3
Total
\u00a0
1,114.1
1,417.9
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 14 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 2023
Trade debtors (nominal value) (Note 14)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2022
Trade debtors (nominal value) (Note 14)
-
132.7
58.1
55.9
63.1
2.0
311.8
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.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The Group monitors capital on the basis of
\u00a0
the equity ratio, which is calculated as total equity
\u00a0
divided by total assets. It is DNO\u2019s policy
that this ratio should be 30 percent or higher. The financial covenants
\u00a0
of the bond loans require a minimum of USD 40
\u00a0
million of liquidity
and that the Group maintains either an equity ratio
\u00a0
of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
There is also a restriction from 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
17. The equity ratio has improved primarily
\u00a0
due to a net profit in 2023. The 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 2023
\u00a0
and 2022.
Years ended 31 December
USD million
2023
2022
Total equity
1,234.8
1,369.4
Total assets
2,638.3
2,803.0
Equity ratio
46.8%
48.9%
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
\u00a0
within Level 1 that are observable for the asset
\u00a0
or liability, either directly 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
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)
17
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
17
166.2
166.2
130.9
-
35.0
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2022 - 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)
17
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
17
8.4
8.4
-
-
8.4
", "dimensions": { "concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_115": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
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.
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 2023
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 2022
\u00a0
and 2023 profit/-loss before income tax from oil and
\u00a0
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)
2023
+/- 15.0
\u00a0
+/- 77.9
2022
+/- 15.0
\u00a0
+/- 170.9
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 2023 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\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
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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)
2023
+ 10.0
6.0
2023
- 10.0
-6.0
2022
+ 10.0
-3.5
2022
- 10.0
3.5
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2023
+ 10.0
-36.7
2023
- 10.0
36.7
2022
+ 10.0
-19.0
2022
- 10.0
19.0
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2023
+ 10.0
0.3
2023
- 10.0
-0.3
2022
+ 10.0
-4.8
2022
- 10.0
4.8
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 2023. The Group is also exposed to interest
\u00a0
rate risk on its cash deposits held at floating
\u00a0
interest rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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.
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2023
+/- 200
+/-7.6
2022
+/- 200
+/-7.7
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 17. 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
\u00a0
basis for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 12) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made
\u00a0
on a regular basis pursuant to an approved
\u00a0
budget and work program. The cash
distributions anticipated to be received from Foxtrot
\u00a0
International will be sufficient to enable the Company
\u00a0
to meet all of its 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 2023 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. See also
\u00a0
Note 12 regarding the
Company\u2019s entry in West Africa.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
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
-
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2022
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
11.3
33.8
203.8
460.7
Other provisions and charges
-
18.4
22.2
-
-
Taxes payable
-
125.7
-
-
-
Trade and other payables
-
233.0
2.0
-
-
Total liabilities
-
388.4
58.0
203.8
460.7
* Face value of the bonds was USD 531.2 million at yearend 2023 (USD 531.2 million at yearend 2022).
For changes in liabilities arising from financing activities,
\u00a0
see Note 17.
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
2023
2022
Trade debtors (non-current portion) (Note 14)
129.8
-
Trade debtors (Note 14)
149.5
311.8
Other receivables (Note 14)
115.9
126.0
Tax receivables
\u00a0
-
25.8
Cash and cash equivalents
718.8
954.3
Total
\u00a0
1,114.1
1,417.9
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 14 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 2023
Trade debtors (nominal value) (Note 14)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2022
Trade debtors (nominal value) (Note 14)
-
132.7
58.1
55.9
63.1
2.0
311.8
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.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The Group monitors capital on the basis of
\u00a0
the equity ratio, which is calculated as total equity
\u00a0
divided by total assets. It is DNO\u2019s policy
that this ratio should be 30 percent or higher. The financial covenants
\u00a0
of the bond loans require a minimum of USD 40
\u00a0
million of liquidity
and that the Group maintains either an equity ratio
\u00a0
of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
There is also a restriction from 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
17. The equity ratio has improved primarily
\u00a0
due to a net profit in 2023. The 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 2023
\u00a0
and 2022.
Years ended 31 December
USD million
2023
2022
Total equity
1,234.8
1,369.4
Total assets
2,638.3
2,803.0
Equity ratio
46.8%
48.9%
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
\u00a0
within Level 1 that are observable for the asset
\u00a0
or liability, either directly 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
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)
17
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
17
166.2
166.2
130.9
-
35.0
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2022 - 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)
17
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
17
8.4
8.4
-
-
8.4
", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_116": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
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.
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 2023
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 2022
\u00a0
and 2023 profit/-loss before income tax from oil and
\u00a0
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)
2023
+/- 15.0
\u00a0
+/- 77.9
2022
+/- 15.0
\u00a0
+/- 170.9
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 2023 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\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
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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)
2023
+ 10.0
6.0
2023
- 10.0
-6.0
2022
+ 10.0
-3.5
2022
- 10.0
3.5
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2023
+ 10.0
-36.7
2023
- 10.0
36.7
2022
+ 10.0
-19.0
2022
- 10.0
19.0
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2023
+ 10.0
0.3
2023
- 10.0
-0.3
2022
+ 10.0
-4.8
2022
- 10.0
4.8
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 2023. The Group is also exposed to interest
\u00a0
rate risk on its cash deposits held at floating
\u00a0
interest rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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.
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2023
+/- 200
+/-7.6
2022
+/- 200
+/-7.7
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 17. 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
\u00a0
basis for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 12) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made
\u00a0
on a regular basis pursuant to an approved
\u00a0
budget and work program. The cash
distributions anticipated to be received from Foxtrot
\u00a0
International will be sufficient to enable the Company
\u00a0
to meet all of its 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 2023 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. See also
\u00a0
Note 12 regarding the
Company\u2019s entry in West Africa.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
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
-
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2022
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
11.3
33.8
203.8
460.7
Other provisions and charges
-
18.4
22.2
-
-
Taxes payable
-
125.7
-
-
-
Trade and other payables
-
233.0
2.0
-
-
Total liabilities
-
388.4
58.0
203.8
460.7
* Face value of the bonds was USD 531.2 million at yearend 2023 (USD 531.2 million at yearend 2022).
For changes in liabilities arising from financing activities,
\u00a0
see Note 17.
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
2023
2022
Trade debtors (non-current portion) (Note 14)
129.8
-
Trade debtors (Note 14)
149.5
311.8
Other receivables (Note 14)
115.9
126.0
Tax receivables
\u00a0
-
25.8
Cash and cash equivalents
718.8
954.3
Total
\u00a0
1,114.1
1,417.9
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 14 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 2023
Trade debtors (nominal value) (Note 14)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2022
Trade debtors (nominal value) (Note 14)
-
132.7
58.1
55.9
63.1
2.0
311.8
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.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The Group monitors capital on the basis of
\u00a0
the equity ratio, which is calculated as total equity
\u00a0
divided by total assets. It is DNO\u2019s policy
that this ratio should be 30 percent or higher. The financial covenants
\u00a0
of the bond loans require a minimum of USD 40
\u00a0
million of liquidity
and that the Group maintains either an equity ratio
\u00a0
of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
There is also a restriction from 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
17. The equity ratio has improved primarily
\u00a0
due to a net profit in 2023. The 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 2023
\u00a0
and 2022.
Years ended 31 December
USD million
2023
2022
Total equity
1,234.8
1,369.4
Total assets
2,638.3
2,803.0
Equity ratio
46.8%
48.9%
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
\u00a0
within Level 1 that are observable for the asset
\u00a0
or liability, either directly 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
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)
17
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
17
166.2
166.2
130.9
-
35.0
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2022 - 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)
17
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
17
8.4
8.4
-
-
8.4
", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_117": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
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.
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 2023
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 2022
\u00a0
and 2023 profit/-loss before income tax from oil and
\u00a0
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)
2023
+/- 15.0
\u00a0
+/- 77.9
2022
+/- 15.0
\u00a0
+/- 170.9
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 2023 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\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
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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)
2023
+ 10.0
6.0
2023
- 10.0
-6.0
2022
+ 10.0
-3.5
2022
- 10.0
3.5
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2023
+ 10.0
-36.7
2023
- 10.0
36.7
2022
+ 10.0
-19.0
2022
- 10.0
19.0
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2023
+ 10.0
0.3
2023
- 10.0
-0.3
2022
+ 10.0
-4.8
2022
- 10.0
4.8
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 2023. The Group is also exposed to interest
\u00a0
rate risk on its cash deposits held at floating
\u00a0
interest rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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.
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2023
+/- 200
+/-7.6
2022
+/- 200
+/-7.7
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 17. 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
\u00a0
basis for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 12) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made
\u00a0
on a regular basis pursuant to an approved
\u00a0
budget and work program. The cash
distributions anticipated to be received from Foxtrot
\u00a0
International will be sufficient to enable the Company
\u00a0
to meet all of its 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 2023 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. See also
\u00a0
Note 12 regarding the
Company\u2019s entry in West Africa.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
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
-
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2022
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
11.3
33.8
203.8
460.7
Other provisions and charges
-
18.4
22.2
-
-
Taxes payable
-
125.7
-
-
-
Trade and other payables
-
233.0
2.0
-
-
Total liabilities
-
388.4
58.0
203.8
460.7
* Face value of the bonds was USD 531.2 million at yearend 2023 (USD 531.2 million at yearend 2022).
For changes in liabilities arising from financing activities,
\u00a0
see Note 17.
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
2023
2022
Trade debtors (non-current portion) (Note 14)
129.8
-
Trade debtors (Note 14)
149.5
311.8
Other receivables (Note 14)
115.9
126.0
Tax receivables
\u00a0
-
25.8
Cash and cash equivalents
718.8
954.3
Total
\u00a0
1,114.1
1,417.9
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 14 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 2023
Trade debtors (nominal value) (Note 14)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2022
Trade debtors (nominal value) (Note 14)
-
132.7
58.1
55.9
63.1
2.0
311.8
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.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The Group monitors capital on the basis of
\u00a0
the equity ratio, which is calculated as total equity
\u00a0
divided by total assets. It is DNO\u2019s policy
that this ratio should be 30 percent or higher. The financial covenants
\u00a0
of the bond loans require a minimum of USD 40
\u00a0
million of liquidity
and that the Group maintains either an equity ratio
\u00a0
of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
There is also a restriction from 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
17. The equity ratio has improved primarily
\u00a0
due to a net profit in 2023. The 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 2023
\u00a0
and 2022.
Years ended 31 December
USD million
2023
2022
Total equity
1,234.8
1,369.4
Total assets
2,638.3
2,803.0
Equity ratio
46.8%
48.9%
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
\u00a0
within Level 1 that are observable for the asset
\u00a0
or liability, either directly 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
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)
17
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
17
166.2
166.2
130.9
-
35.0
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2022 - 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)
17
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
17
8.4
8.4
-
-
8.4
", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_118": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
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.
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 2023
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 2022
\u00a0
and 2023 profit/-loss before income tax from oil and
\u00a0
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)
2023
+/- 15.0
\u00a0
+/- 77.9
2022
+/- 15.0
\u00a0
+/- 170.9
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 2023 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\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
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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)
2023
+ 10.0
6.0
2023
- 10.0
-6.0
2022
+ 10.0
-3.5
2022
- 10.0
3.5
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2023
+ 10.0
-36.7
2023
- 10.0
36.7
2022
+ 10.0
-19.0
2022
- 10.0
19.0
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2023
+ 10.0
0.3
2023
- 10.0
-0.3
2022
+ 10.0
-4.8
2022
- 10.0
4.8
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 2023. The Group is also exposed to interest
\u00a0
rate risk on its cash deposits held at floating
\u00a0
interest rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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.
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2023
+/- 200
+/-7.6
2022
+/- 200
+/-7.7
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 17. 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
\u00a0
basis for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 12) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made
\u00a0
on a regular basis pursuant to an approved
\u00a0
budget and work program. The cash
distributions anticipated to be received from Foxtrot
\u00a0
International will be sufficient to enable the Company
\u00a0
to meet all of its 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 2023 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. See also
\u00a0
Note 12 regarding the
Company\u2019s entry in West Africa.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
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
-
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2022
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
11.3
33.8
203.8
460.7
Other provisions and charges
-
18.4
22.2
-
-
Taxes payable
-
125.7
-
-
-
Trade and other payables
-
233.0
2.0
-
-
Total liabilities
-
388.4
58.0
203.8
460.7
* Face value of the bonds was USD 531.2 million at yearend 2023 (USD 531.2 million at yearend 2022).
For changes in liabilities arising from financing activities,
\u00a0
see Note 17.
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
2023
2022
Trade debtors (non-current portion) (Note 14)
129.8
-
Trade debtors (Note 14)
149.5
311.8
Other receivables (Note 14)
115.9
126.0
Tax receivables
\u00a0
-
25.8
Cash and cash equivalents
718.8
954.3
Total
\u00a0
1,114.1
1,417.9
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 14 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 2023
Trade debtors (nominal value) (Note 14)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2022
Trade debtors (nominal value) (Note 14)
-
132.7
58.1
55.9
63.1
2.0
311.8
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.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The Group monitors capital on the basis of
\u00a0
the equity ratio, which is calculated as total equity
\u00a0
divided by total assets. It is DNO\u2019s policy
that this ratio should be 30 percent or higher. The financial covenants
\u00a0
of the bond loans require a minimum of USD 40
\u00a0
million of liquidity
and that the Group maintains either an equity ratio
\u00a0
of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
There is also a restriction from 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
17. The equity ratio has improved primarily
\u00a0
due to a net profit in 2023. The 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 2023
\u00a0
and 2022.
Years ended 31 December
USD million
2023
2022
Total equity
1,234.8
1,369.4
Total assets
2,638.3
2,803.0
Equity ratio
46.8%
48.9%
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
\u00a0
within Level 1 that are observable for the asset
\u00a0
or liability, either directly 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
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)
17
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
17
166.2
166.2
130.9
-
35.0
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2022 - 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)
17
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
17
8.4
8.4
-
-
8.4
", "dimensions": { "concept": "ifrs-full:DisclosureOfCreditRiskExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_119": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
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.
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 2023
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 2022
\u00a0
and 2023 profit/-loss before income tax from oil and
\u00a0
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)
2023
+/- 15.0
\u00a0
+/- 77.9
2022
+/- 15.0
\u00a0
+/- 170.9
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 2023 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\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
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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)
2023
+ 10.0
6.0
2023
- 10.0
-6.0
2022
+ 10.0
-3.5
2022
- 10.0
3.5
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2023
+ 10.0
-36.7
2023
- 10.0
36.7
2022
+ 10.0
-19.0
2022
- 10.0
19.0
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2023
+ 10.0
0.3
2023
- 10.0
-0.3
2022
+ 10.0
-4.8
2022
- 10.0
4.8
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 2023. The Group is also exposed to interest
\u00a0
rate risk on its cash deposits held at floating
\u00a0
interest rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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.
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2023
+/- 200
+/-7.6
2022
+/- 200
+/-7.7
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 17. 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
\u00a0
basis for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 12) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made
\u00a0
on a regular basis pursuant to an approved
\u00a0
budget and work program. The cash
distributions anticipated to be received from Foxtrot
\u00a0
International will be sufficient to enable the Company
\u00a0
to meet all of its 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 2023 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. See also
\u00a0
Note 12 regarding the
Company\u2019s entry in West Africa.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
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
-
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2022
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
11.3
33.8
203.8
460.7
Other provisions and charges
-
18.4
22.2
-
-
Taxes payable
-
125.7
-
-
-
Trade and other payables
-
233.0
2.0
-
-
Total liabilities
-
388.4
58.0
203.8
460.7
* Face value of the bonds was USD 531.2 million at yearend 2023 (USD 531.2 million at yearend 2022).
For changes in liabilities arising from financing activities,
\u00a0
see Note 17.
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
2023
2022
Trade debtors (non-current portion) (Note 14)
129.8
-
Trade debtors (Note 14)
149.5
311.8
Other receivables (Note 14)
115.9
126.0
Tax receivables
\u00a0
-
25.8
Cash and cash equivalents
718.8
954.3
Total
\u00a0
1,114.1
1,417.9
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 14 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 2023
Trade debtors (nominal value) (Note 14)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2022
Trade debtors (nominal value) (Note 14)
-
132.7
58.1
55.9
63.1
2.0
311.8
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.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The Group monitors capital on the basis of
\u00a0
the equity ratio, which is calculated as total equity
\u00a0
divided by total assets. It is DNO\u2019s policy
that this ratio should be 30 percent or higher. The financial covenants
\u00a0
of the bond loans require a minimum of USD 40
\u00a0
million of liquidity
and that the Group maintains either an equity ratio
\u00a0
of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
There is also a restriction from 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
17. The equity ratio has improved primarily
\u00a0
due to a net profit in 2023. The 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 2023
\u00a0
and 2022.
Years ended 31 December
USD million
2023
2022
Total equity
1,234.8
1,369.4
Total assets
2,638.3
2,803.0
Equity ratio
46.8%
48.9%
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
\u00a0
within Level 1 that are observable for the asset
\u00a0
or liability, either directly 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
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)
17
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
17
166.2
166.2
130.9
-
35.0
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2022 - 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)
17
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
17
8.4
8.4
-
-
8.4
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_120": { "value": "
\u00a0
\n
\u00a0
\n
\u00a0
\n
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.
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 2023
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 2022
\u00a0
and 2023 profit/-loss before income tax from oil and
\u00a0
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)
2023
+/- 15.0
\u00a0
+/- 77.9
2022
+/- 15.0
\u00a0
+/- 170.9
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 2023 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\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
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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)
2023
+ 10.0
6.0
2023
- 10.0
-6.0
2022
+ 10.0
-3.5
2022
- 10.0
3.5
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2023
+ 10.0
-36.7
2023
- 10.0
36.7
2022
+ 10.0
-19.0
2022
- 10.0
19.0
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2023
+ 10.0
0.3
2023
- 10.0
-0.3
2022
+ 10.0
-4.8
2022
- 10.0
4.8
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 2023. The Group is also exposed to interest
\u00a0
rate risk on its cash deposits held at floating
\u00a0
interest rates.
\u00a0
The following table illustrates the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2022 and
\u00a0
2023 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.
Increase/decrease
Effect on profit
in basis points
before tax (USD mill)
2023
+/- 200
+/-7.6
2022
+/- 200
+/-7.7
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 17. 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
\u00a0
basis for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 12) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made
\u00a0
on a regular basis pursuant to an approved
\u00a0
budget and work program. The cash
distributions anticipated to be received from Foxtrot
\u00a0
International will be sufficient to enable the Company
\u00a0
to meet all of its 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 2023 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. See also
\u00a0
Note 12 regarding the
Company\u2019s entry in West Africa.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
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
-
USD million
On
Less than
\u00a0
3 to 12
\u00a0
1 to 3
\u00a0
Over 3
\u00a0
At 31 December 2022
demand
3 months
\u00a0
months
\u00a0
years
\u00a0
years
\u00a0
Interest-bearing liabilities*
-
11.3
33.8
203.8
460.7
Other provisions and charges
-
18.4
22.2
-
-
Taxes payable
-
125.7
-
-
-
Trade and other payables
-
233.0
2.0
-
-
Total liabilities
-
388.4
58.0
203.8
460.7
* Face value of the bonds was USD 531.2 million at yearend 2023 (USD 531.2 million at yearend 2022).
For changes in liabilities arising from financing activities,
\u00a0
see Note 17.
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
2023
2022
Trade debtors (non-current portion) (Note 14)
129.8
-
Trade debtors (Note 14)
149.5
311.8
Other receivables (Note 14)
115.9
126.0
Tax receivables
\u00a0
-
25.8
Cash and cash equivalents
718.8
954.3
Total
\u00a0
1,114.1
1,417.9
Trade debtors from oil sales invoices in Kurdistan
The past due trade debtors are entirely related
\u00a0
to Kurdistan. Refer to Note 14 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 2023
Trade debtors (nominal value) (Note 14)
-
12.0
-
-
-
311.6
323.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2022
Trade debtors (nominal value) (Note 14)
-
132.7
58.1
55.9
63.1
2.0
311.8
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.
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
\u00a0
\n
The Group monitors capital on the basis of
\u00a0
the equity ratio, which is calculated as total equity
\u00a0
divided by total assets. It is DNO\u2019s policy
that this ratio should be 30 percent or higher. The financial covenants
\u00a0
of the bond loans require a minimum of USD 40
\u00a0
million of liquidity
and that the Group maintains either an equity ratio
\u00a0
of 30 percent or a total equity of a
\u00a0
minimum of USD 600 million.
\u00a0
There is also a restriction from 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
17. The equity ratio has improved primarily
\u00a0
due to a net profit in 2023. The 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 2023
\u00a0
and 2022.
Years ended 31 December
USD million
2023
2022
Total equity
1,234.8
1,369.4
Total assets
2,638.3
2,803.0
Equity ratio
46.8%
48.9%
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
\u00a0
within Level 1 that are observable for the asset
\u00a0
or liability, either directly 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
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)
17
392.0
392.0
31 December 2023
378.1
-
-
Interest-bearing liabilities (current)
17
166.2
166.2
130.9
-
35.0
Carrying amount
Financial
Fair value hierarchy
liabilities
at amortized
\u00a0
2022 - 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)
17
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
17
8.4
8.4
-
-
8.4
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_121": { "value": "
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
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_122": { "value": "
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen \u2013 Block 53, Block
\u00a0
43 and Block 32
The Ministry of Oil and Minerals (MOM or Ministry)
\u00a0
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 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 the
\u00a0
French Supreme Court.
\u00a0
DNO Yemen AS (DNO Yemen) was involved in a dispute with MOM with respect to DNO Yemen\u2019s relinquishment of Block 32 in 2016.
An arbitral award was rendered on 7 April
\u00a0
2021 in the Ministry\u2019s favor in the amount of USD
\u00a0
8.1 million (out of a USD 151 million
counterclaim) while the Contractor of the license was
\u00a0
awarded USD 5 million (out of a USD 14
\u00a0
million claim).
\u00a0
DNO Yemen was involved in a dispute with MOM with respect to DNO Yemen\u2019 relinquishment of Block 43 in 2016.
\u00a0
An arbitral award
was rendered on 18 February 2020 in DNO
\u00a0
Yemen\u2019s favor in the amount of USD 6.8 million (almost entirely dismissing the USD 131
million counterclaim of the MOM).
\u00a0
On 8 December 2022, the Oslo District Court
\u00a0
ruled that previously rendered arbitration awards
\u00a0
regarding Blocks 53 and 32 (above) are
enforceable against DNO Yemen in Norway. DNO Yemen appealed this decision, first to the Court of Appeal that substantially upheld
the District Court\u2019s ruling and thereafter to the Supreme
\u00a0
Court. The Supreme Court appeal was dismissed.
\u00a0
The Oslo District Court also
ruled that the previously rendered arbitration award
\u00a0
regarding Block 43 in favor of DNO Yemen is enforceable against the MOM in
Norway.
\u00a0
As part of the Block 43 arbitral award in 2020,
\u00a0
a cost recovery audit was mandated for
\u00a0
the years 2014 and 2015. In 2021, MOM filed
\u00a0
an
arbitration claim against DNO Yemen AS for allegedly over-recovered costs of USD
\u00a0
17.2 million from the Ministry in 2014 and
\u00a0
2015. On
24 July 2023, the arbitral award was rendered
\u00a0
in favor of DNO Yemen dismissing all claims by the MOM and ordering
\u00a0
the MOM to pay
all of DNO Yemen\u2019s legal fees and court administrative costs.
In 2023, therefore, the net amount of USD
\u00a0
29.2 million was paid by DNO Yemen to MOM in connection with arbitral
\u00a0
awards resolving
disputes regarding Block 53, 43 and 32 (described
\u00a0
above). DNO has taken action against a former
\u00a0
license partner to the amount paid, in
respect of which that partner is liable. The accounting
\u00a0
provision of USD 22.2 million, recognized at
\u00a0
yearend 2022 for these arbitral
awards was reversed following the payment.
\u00a0
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 2023 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 and payment
\u00a0
terms and conditions for
any future oil exports,
\u00a0
the Group\u2019s projected operational spend for 2024 comprising
\u00a0
of capital and exploration expenditures,
abandonment expenditures and operational expenditures
\u00a0
amounts
\u00a0
to USD 645 million. The projected operational spend reflects
\u00a0
the
Group\u2019s share of planned drilling and facility investments and
\u00a0
decommissioning plan in its licenses for 2024. These
\u00a0
work plans are
subject to revisions.
Guarantees related to assets in operation 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
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_123": { "value": "
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen \u2013 Block 53, Block
\u00a0
43 and Block 32
The Ministry of Oil and Minerals (MOM or Ministry)
\u00a0
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 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 the
\u00a0
French Supreme Court.
\u00a0
DNO Yemen AS (DNO Yemen) was involved in a dispute with MOM with respect to DNO Yemen\u2019s relinquishment of Block 32 in 2016.
An arbitral award was rendered on 7 April
\u00a0
2021 in the Ministry\u2019s favor in the amount of USD
\u00a0
8.1 million (out of a USD 151 million
counterclaim) while the Contractor of the license was
\u00a0
awarded USD 5 million (out of a USD 14
\u00a0
million claim).
\u00a0
DNO Yemen was involved in a dispute with MOM with respect to DNO Yemen\u2019 relinquishment of Block 43 in 2016.
\u00a0
An arbitral award
was rendered on 18 February 2020 in DNO
\u00a0
Yemen\u2019s favor in the amount of USD 6.8 million (almost entirely dismissing the USD 131
million counterclaim of the MOM).
\u00a0
On 8 December 2022, the Oslo District Court
\u00a0
ruled that previously rendered arbitration awards
\u00a0
regarding Blocks 53 and 32 (above) are
enforceable against DNO Yemen in Norway. DNO Yemen appealed this decision, first to the Court of Appeal that substantially upheld
the District Court\u2019s ruling and thereafter to the Supreme
\u00a0
Court. The Supreme Court appeal was dismissed.
\u00a0
The Oslo District Court also
ruled that the previously rendered arbitration award
\u00a0
regarding Block 43 in favor of DNO Yemen is enforceable against the MOM in
Norway.
\u00a0
As part of the Block 43 arbitral award in 2020,
\u00a0
a cost recovery audit was mandated for
\u00a0
the years 2014 and 2015. In 2021, MOM filed
\u00a0
an
arbitration claim against DNO Yemen AS for allegedly over-recovered costs of USD
\u00a0
17.2 million from the Ministry in 2014 and
\u00a0
2015. On
24 July 2023, the arbitral award was rendered
\u00a0
in favor of DNO Yemen dismissing all claims by the MOM and ordering
\u00a0
the MOM to pay
all of DNO Yemen\u2019s legal fees and court administrative costs.
In 2023, therefore, the net amount of USD
\u00a0
29.2 million was paid by DNO Yemen to MOM in connection with arbitral
\u00a0
awards resolving
disputes regarding Block 53, 43 and 32 (described
\u00a0
above). DNO has taken action against a former
\u00a0
license partner to the amount paid, in
respect of which that partner is liable. The accounting
\u00a0
provision of USD 22.2 million, recognized at
\u00a0
yearend 2022 for these arbitral
awards was reversed following the payment.
\u00a0
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 2023 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 and payment
\u00a0
terms and conditions for
any future oil exports,
\u00a0
the Group\u2019s projected operational spend for 2024 comprising
\u00a0
of capital and exploration expenditures,
abandonment expenditures and operational expenditures
\u00a0
amounts
\u00a0
to USD 645 million. The projected operational spend reflects
\u00a0
the
Group\u2019s share of planned drilling and facility investments and
\u00a0
decommissioning plan in its licenses for 2024. These
\u00a0
work plans are
subject to revisions.
Guarantees related to assets in operation 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
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_124": { "value": "
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen \u2013 Block 53, Block
\u00a0
43 and Block 32
The Ministry of Oil and Minerals (MOM or Ministry)
\u00a0
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 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 the
\u00a0
French Supreme Court.
\u00a0
DNO Yemen AS (DNO Yemen) was involved in a dispute with MOM with respect to DNO Yemen\u2019s relinquishment of Block 32 in 2016.
An arbitral award was rendered on 7 April
\u00a0
2021 in the Ministry\u2019s favor in the amount of USD
\u00a0
8.1 million (out of a USD 151 million
counterclaim) while the Contractor of the license was
\u00a0
awarded USD 5 million (out of a USD 14
\u00a0
million claim).
\u00a0
DNO Yemen was involved in a dispute with MOM with respect to DNO Yemen\u2019 relinquishment of Block 43 in 2016.
\u00a0
An arbitral award
was rendered on 18 February 2020 in DNO
\u00a0
Yemen\u2019s favor in the amount of USD 6.8 million (almost entirely dismissing the USD 131
million counterclaim of the MOM).
\u00a0
On 8 December 2022, the Oslo District Court
\u00a0
ruled that previously rendered arbitration awards
\u00a0
regarding Blocks 53 and 32 (above) are
enforceable against DNO Yemen in Norway. DNO Yemen appealed this decision, first to the Court of Appeal that substantially upheld
the District Court\u2019s ruling and thereafter to the Supreme
\u00a0
Court. The Supreme Court appeal was dismissed.
\u00a0
The Oslo District Court also
ruled that the previously rendered arbitration award
\u00a0
regarding Block 43 in favor of DNO Yemen is enforceable against the MOM in
Norway.
\u00a0
As part of the Block 43 arbitral award in 2020,
\u00a0
a cost recovery audit was mandated for
\u00a0
the years 2014 and 2015. In 2021, MOM filed
\u00a0
an
arbitration claim against DNO Yemen AS for allegedly over-recovered costs of USD
\u00a0
17.2 million from the Ministry in 2014 and
\u00a0
2015. On
24 July 2023, the arbitral award was rendered
\u00a0
in favor of DNO Yemen dismissing all claims by the MOM and ordering
\u00a0
the MOM to pay
all of DNO Yemen\u2019s legal fees and court administrative costs.
In 2023, therefore, the net amount of USD
\u00a0
29.2 million was paid by DNO Yemen to MOM in connection with arbitral
\u00a0
awards resolving
disputes regarding Block 53, 43 and 32 (described
\u00a0
above). DNO has taken action against a former
\u00a0
license partner to the amount paid, in
respect of which that partner is liable. The accounting
\u00a0
provision of USD 22.2 million, recognized at
\u00a0
yearend 2022 for these arbitral
awards was reversed following the payment.
\u00a0
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 2023 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 and payment
\u00a0
terms and conditions for
any future oil exports,
\u00a0
the Group\u2019s projected operational spend for 2024 comprising
\u00a0
of capital and exploration expenditures,
abandonment expenditures and operational expenditures
\u00a0
amounts
\u00a0
to USD 645 million. The projected operational spend reflects
\u00a0
the
Group\u2019s share of planned drilling and facility investments and
\u00a0
decommissioning plan in its licenses for 2024. These
\u00a0
work plans are
subject to revisions.
Guarantees related to assets in operation 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
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_125": { "value": "
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen \u2013 Block 53, Block
\u00a0
43 and Block 32
The Ministry of Oil and Minerals (MOM or Ministry)
\u00a0
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 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 the
\u00a0
French Supreme Court.
\u00a0
DNO Yemen AS (DNO Yemen) was involved in a dispute with MOM with respect to DNO Yemen\u2019s relinquishment of Block 32 in 2016.
An arbitral award was rendered on 7 April
\u00a0
2021 in the Ministry\u2019s favor in the amount of USD
\u00a0
8.1 million (out of a USD 151 million
counterclaim) while the Contractor of the license was
\u00a0
awarded USD 5 million (out of a USD 14
\u00a0
million claim).
\u00a0
DNO Yemen was involved in a dispute with MOM with respect to DNO Yemen\u2019 relinquishment of Block 43 in 2016.
\u00a0
An arbitral award
was rendered on 18 February 2020 in DNO
\u00a0
Yemen\u2019s favor in the amount of USD 6.8 million (almost entirely dismissing the USD 131
million counterclaim of the MOM).
\u00a0
On 8 December 2022, the Oslo District Court
\u00a0
ruled that previously rendered arbitration awards
\u00a0
regarding Blocks 53 and 32 (above) are
enforceable against DNO Yemen in Norway. DNO Yemen appealed this decision, first to the Court of Appeal that substantially upheld
the District Court\u2019s ruling and thereafter to the Supreme
\u00a0
Court. The Supreme Court appeal was dismissed.
\u00a0
The Oslo District Court also
ruled that the previously rendered arbitration award
\u00a0
regarding Block 43 in favor of DNO Yemen is enforceable against the MOM in
Norway.
\u00a0
As part of the Block 43 arbitral award in 2020,
\u00a0
a cost recovery audit was mandated for
\u00a0
the years 2014 and 2015. In 2021, MOM filed
\u00a0
an
arbitration claim against DNO Yemen AS for allegedly over-recovered costs of USD
\u00a0
17.2 million from the Ministry in 2014 and
\u00a0
2015. On
24 July 2023, the arbitral award was rendered
\u00a0
in favor of DNO Yemen dismissing all claims by the MOM and ordering
\u00a0
the MOM to pay
all of DNO Yemen\u2019s legal fees and court administrative costs.
In 2023, therefore, the net amount of USD
\u00a0
29.2 million was paid by DNO Yemen to MOM in connection with arbitral
\u00a0
awards resolving
disputes regarding Block 53, 43 and 32 (described
\u00a0
above). DNO has taken action against a former
\u00a0
license partner to the amount paid, in
respect of which that partner is liable. The accounting
\u00a0
provision of USD 22.2 million, recognized at
\u00a0
yearend 2022 for these arbitral
awards was reversed following the payment.
\u00a0
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 2023 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 and payment
\u00a0
terms and conditions for
any future oil exports,
\u00a0
the Group\u2019s projected operational spend for 2024 comprising
\u00a0
of capital and exploration expenditures,
abandonment expenditures and operational expenditures
\u00a0
amounts
\u00a0
to USD 645 million. The projected operational spend reflects
\u00a0
the
Group\u2019s share of planned drilling and facility investments and
\u00a0
decommissioning plan in its licenses for 2024. These
\u00a0
work plans are
subject to revisions.
Guarantees related to assets in operation 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
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_126": { "value": "
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\n
1 January - 31 December
2023
2022
Net profit/-loss attributable to ordinary equity holders of the parent (USD million)
18.6
384.9
Weighted average number of ordinary shares excluding treasury shares (millions)
980.04
975.43
Earnings per share, basic (USD per share)
0.02
0.39
Earnings per share, diluted (USD per share)
0.02
0.39
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 2023.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_127": { "value": "
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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 Exploration UK Limited
United Kingdom
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
DNO Oman Limited
Bermuda
100
DNO Oman Block 8 Limited
Guernsey
100
South Limited
\u00a0
Guernsey
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 (UK) Limited
United Kingdom
100
DNO North Sea (ROGB) Limited
United Kingdom
100
DNO North Sea (Energy) 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 LDC
Cayman Islands
33.33
The Group\u2019s operations in Kurdistan are carried out through
\u00a0
its subsidiary DNO Iraq AS, while activities on the NCS
\u00a0
are carried out
through DNO Norge AS and UKCS activities
\u00a0
are carried out through DNO North Sea (UK) Limited
\u00a0
and DNO North Sea (ROGB) Limited.
Activities in C\u00f4te d'Ivoire are carried out by Foxtrot
\u00a0
International LDC, in which the Company\u2019s indirect ownership
\u00a0
of 33.33 percent is
accounted for using the equity method. DNO
\u00a0
ASA, DNO Technical Services AS and DNO North Sea plc provide technical support and
services to the various companies in the Group. The
\u00a0
other subsidiaries from the table above had minimal
\u00a0
activity during the year. In
2023 DNO Oman Block 30 Limited was renamed
\u00a0
to South Limited and North Limited was liquidated.
", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "ID_128": { "value": "
Accounting policies
Significant events after the reporting date
Adjusting events are those providing evidence of
\u00a0
conditions existing at the end of the reporting period,
\u00a0
whereas non-adjusting events
are indicative of conditions arising after the reporting
\u00a0
period (the latter being disclosed where
\u00a0
material).
The Company\u2019s Board of Directors approve dividend payment
\u00a0
On 8 February 2024, the Company announced
\u00a0
that pursuant to the authorization granted at
\u00a0
the 2023 AGM, the Board of Directors has
approved a dividend payment of NOK 0.25 per
\u00a0
share. Payment of the dividend was made on 26 February
\u00a0
2024. This is considered a
non-adjusting event (see also parent company accounts).
DNO acquires interest in UK\u2019s Arran field, expands North
\u00a0
Sea portfolio
On 6 February 2024, the Company announced
\u00a0
that its wholly-owned subsidiary DNO Exploration
\u00a0
UK Limited has entered into an
agreement to acquire a 25 percent interest
\u00a0
in the Arran field on the UK Continental Shelf
\u00a0
from ONE-Dyas E&P Limited. The transaction
is expected to add some four million barrels of
\u00a0
oil equivalent net to DNO, of which 90 percent
\u00a0
gas. The cash consideration is USD 70
million plus a contingent consideration of up to USD
\u00a0
5 million if certain operational targets are
\u00a0
met. The effective date is set to 1 January
2024 and the transaction is expected to close in
\u00a0
the second quarter of 2024, subject to authorities\u2019
\u00a0
approval. This is considered a non-
adjusting event.
Redemption of bond DNO03
On 22 January 2024, DNO ASA fully completed a
\u00a0
USD 131.2 million call option redemption of
\u00a0
the DNO03 bond (ISIN: NO0010852643)
at redemption price of 100 percent plus accrued
\u00a0
interest.
\u00a0
DNO receives 14 awards in Norway's APA licensing round
\u00a0
On 16 January 2024, the Company announced
\u00a0
that its wholly-owned subsidiary DNO Norge
\u00a0
AS has been awarded participation in 14
exploration licenses, of which three are operatorships,
\u00a0
under Norway's APA 2023 licensing round. Of the 14 new licenses,
\u00a0
10 are in the
North Sea and four in the Norwegian Sea.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:5967007LIEEXZXH3K072", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } } } }