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"ID_8": {
"value": "Oslo,
15
Bijan Mossavar-Rahmani
Gunnar Hirsti
Elin Karfjell
Watson
Executive Chairman
Deputy Chairman
Director
Anita Marie Hjerkinn
\u00a0
Aarn\u00e6s
Bj\u00f8rn Dale
Director
Statement of compliance
The consolidated financial statements of
DNO ASA
prepared in accordance with International Financial
\u00a0
Reporting
Standards (IFRS) as adopted by the European
\u00a0
Union (EU) and
additional disclosure requirements in the Norwegian
\u00a0
Accounting
Act, effective as of 31 December 2022. The consolidated
\u00a0
financial
statements were approved by the Board of Directors
\u00a0
on 15 March
2023.
Basis for preparation
The consolidated financial statements have been
\u00a0
prepared on a
historical cost basis, with the following exemptions:
\u00a0
liabilities
related to share-based payments and investments in
\u00a0
equity
instruments classified as financial investments at fair value
through other comprehensive income are recognized
\u00a0
at fair value.
As permitted by International Accounting Standard
\u00a0
(IAS) 1
Presentation of Financial Statements
\u00a0
and in conformity with
industry practice, the expenses in the consolidated statements
\u00a0
of
comprehensive income are presented as a combination of
\u00a0
nature
and function as this gives the most relevant and
\u00a0
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.
Going concern
As required under the Norwegian Accounting Act,
\u00a0
the Company\u2019s
Board of Directors conducted a review of the
\u00a0
going concern
assumption considering all relevant information available
\u00a0
up to the
date the
DNO ASA
\u00a0
consolidated and Company accounts are
issued and taking into account all available information
\u00a0
about the
future covering at least 12 months from the end of
\u00a0
the reporting
period. The Board of Directors\u2019 review included
\u00a0
in particular
assessment of the Group\u2019s projected cash reserves and
\u00a0
access to
financing arrangements considering its operational
\u00a0
outlook and
work programs, while maintaining appropriate headroom
\u00a0
in
respect of liquidity and financial covenant compliance
\u00a0
throughout
the assessment period.
\u00a0
Following its review, the Board of Directors confirmed, pursuant to
the Norwegian Accounting Act section 3-3a, that the
\u00a0
requirements
of the going concern assumption are met and
\u00a0
that these financial
statements have been prepared on that basis.
\u25a0
Significant accounting estimates and assumptions
The preparation of the Group\u2019s financial statements requires
management to make judgments, estimates and assumptions
\u00a0
that
affect the reported amounts of revenues and expenses, assets
and liabilities, and the accompanying disclosures, and
\u00a0
the
disclosure of contingent liabilities at the reporting
\u00a0
date. Estimates
and assumptions are based on management\u2019s best knowledge
and historical experience and various other factors
\u00a0
that are
believed to be reasonable under the circumstances. Uncertainty
about these estimates and assumptions could
\u00a0
result in outcomes
that require a material adjustment to the carrying
\u00a0
amount of
assets or liabilities affected in future periods.
\u00a0
The key assumptions concerning the future and other
\u00a0
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 below. The Group based its assumptions and estimates
on parameters available when the Group financial
\u00a0
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
for the Group are:
\u00a0
Risks associated with operating in Kurdistan;
\u2022
Reserves and resources estimates;
\u2022
Contingencies, provisions and litigations;
\u2022
Impairment/reversal of impairment of oil and gas assets;
\u2022
Impairment of technical goodwill;
\u2022
Measurement of fair values;
\u2022
Acquisition accounting;
\u2022
Accounting for exploration costs;
\u00a0
and
\u2022
Notional corporate income tax/deferred taxation in Kurdistan.
\u00a0
Risks associated with operating in Kurdistan
DNO has interests in two licenses in Kurdistan
\u00a0
through Production
Sharing Contracts (PSCs) and has based its entitlement
calculations on the terms of these PSCs. In 2012,
\u00a0
the Federal
Government of Iraq (FGI) challenged the constitutional
\u00a0
validity of
the Kurdistan Oil and Gas Law No. 27/2007 (KOGL)
\u00a0
and the right
of the KRG to export oil independently of the
\u00a0
FGI.
\u00a0
The Company notes from public reports that on 15
\u00a0
February
2022, the Federal Supreme Court of Iraq (FSCI)
\u00a0
ruled on this
matter along with another related matter dating back
\u00a0
to 2019.
Reportedly, the FSCI found amongst other things that the KOGL
is unconstitutional, that the KRG is to hand over
\u00a0
all oil production
from areas located in the KRI to the FGI and that
\u00a0
the FGI has the
right to pursue the nullity of the oil contracts
\u00a0
concluded by the
KRG. DNO was not a party to the legal proceedings.
\u00a0
DNO has
learned via media reports that on 4 July 2022, a
\u00a0
commercial court
in Baghdad ruled that PSCs signed between the
\u00a0
KRG and four
international oil companies including DNO should
\u00a0
be voided.
Likewise, DNO notes from media reports that on
\u00a0
21 August 2022,
the KRG filed third party objections to the reported
\u00a0
4 July 2022
Baghdad rulings including those understood to concern
\u00a0
DNO.
These cases, along with other similar cases against
\u00a0
international
oil companies, are reported to be still pending.
\u00a0
Furthermore and
importantly, the KRG has issued repeated reassurances that the
PSCs remain valid. The KRG has also initiated legal
\u00a0
proceedings
against FGI in Erbil courts and there have been
\u00a0
several rulings in
Erbil courts affirming the validity of the PSCs. DNO notes
\u00a0
from
public reports that there is increased dialogue between
\u00a0
KRG and
FGI on oil related matters, in particular following
\u00a0
the 27 October
2022 federal parliamentary approval of a new federal
\u00a0
government
led by Prime Minister Mohammed Shia' Sabbar al-Sudani.
\u00a0
Since
then, DNO notes frequent media reports on regular
\u00a0
KRG and FGI
engagement to find a way forward, including by
\u00a0
way of adopting a
new federal oil and gas law. On 13 March 2023, it was announced
that the KRG had received a USD 275.5 million payment
\u00a0
from the
FGI pursuant to an agreement between the parties,
notwithstanding an FSCI ruling that deemed such payments
\u00a0
by a
previous government as \u201cwrong\u201d.
It is unclear how and when the KRG and the
\u00a0
FGI will permanently
address these matters. At present, normal operations
\u00a0
are
maintained at the Tawke and Baeshiqa licenses.
Due to disagreements between the FGI and the
\u00a0
KRG, economic
conditions in Kurdistan and limited oil export channels,
\u00a0
DNO has
historically faced constraints in fully monetizing the oil
\u00a0
it produces
in Kurdistan. There is no guarantee that oil and
\u00a0
gas can be
exported in sufficient quantities or at prices required
\u00a0
to sustain
DNO\u2019s operations and investment plans or that the Group
\u00a0
will
promptly receive its full entitlement payments for the oil
\u00a0
and gas it
delivers for export. Export sales have not always
\u00a0
followed the
PSC terms and there has been uncertainty related
\u00a0
to receipt of
payments but notwithstanding sometimes lengthy delays,
payments have ultimately been received by DNO.
\u00a0
See Note 18 for
more information.
DNO also notes the ongoing arbitration case,
\u00a0
commenced in
2014, by the FGI against the Turkish Government and its state-
owned pipeline operator BOTAS relating to the Iraq-Turkey
Pipeline. It is unclear if a ruling, when
\u00a0
it comes, may have an
impact on future transportation of Kurdish oil in said
\u00a0
pipeline.
Reserves and resources estimate
DNO\u2019s reserves and contingent resources are estimated
\u00a0
and
classified by the Company in accordance with the rules
\u00a0
and
guidelines of the Society of Petroleum Engineers (SPE)
\u00a0
and are in
conformity with requirements from the Oslo Stock Exchange
\u00a0
for
the reporting of reserves and resources.
\u00a0
All estimates of reserves and resources involve uncertainty.
Figures reported in Note 23 are the estimated proven
\u00a0
(1P),
proven and probable (2P) and proven, probable and
\u00a0
possible (3P)
quantities of oil and gas that can be recovered
\u00a0
from a field or
reservoir given the information available at yearend.
Important factors that could cause actual results to
\u00a0
differ from the
estimates include, but are not limited to: technical,
\u00a0
geological and
geotechnical conditions; economic and market conditions;
\u00a0
oil and
gas prices; changes in government regulations; political
development; interest rates; and currency exchange rates.
Specific parameters of uncertainty related to the
\u00a0
field/reservoir
include but are not limited to: reservoir pressure
\u00a0
and porosity;
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
cut-off and remaining reserves, which may change the
\u00a0
timing of
assumed decommissioning activities. Future changes to
estimated reserves can also have a material effect on
depreciation, impairment of oil and gas fields and
\u00a0
operating
results. The Group may also not be able to
\u00a0
commercially develop
its contingent resources that are used in impairment
\u00a0
assessments
or acquisition accounting where the fair value approach
\u00a0
is applied.
Contingencies, provisions and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or
more uncertain future event occurs or fails to occur. The
assessment of the existence and potential quantum of
contingencies inherently involves the exercise of
\u00a0
significant
judgment and the use of estimates regarding
\u00a0
the outcome of
future events. Management uses its judgment to evaluate
\u00a0
certain
provisions and legal disputes in order to ensure
\u00a0
the correct
accounting treatment. This includes the assessment
\u00a0
of future
asset retirement obligations (ARO), any provisions or
\u00a0
contingent
payments.
Asset retirement obligations
The Group has recognized significant provisions relating
\u00a0
to the
decommissioning of oil and gas assets at the end
\u00a0
of the
production period. Obligations associated with decommissioning
assets are recognized at present value of future expenditures
\u00a0
on
the date they incur.
\u00a0
At the initial recognition of an obligation, the
estimated cost is capitalized as property, plant and equipment
(PP&E) and depreciated over the useful life of the asset
\u00a0
(typically
by unit-of-production).
\u00a0
It is difficult to estimate the costs for decommissioning at
\u00a0
initial
recognition as these estimates are based on
\u00a0
currently applicable
laws and regulations,
\u00a0
and technology. Decommissioning activities
will normally take place in the distant future, and
\u00a0
the technology,
regulatory requirements and related costs may change.
\u00a0
The
energy transition may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated
decommissioning provisions.
\u00a0
Based on various scenario analysis
performed by the Company, management does not expect any
reasonable change in the expected timeframe to have
\u00a0
a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost
estimates (i.e., cash flows) remain unchanged. The estimates
cover expected removal concepts based on known technology
and, in the case of offshore decommissioning, estimated costs
\u00a0
of
maritime operations, hiring of heavy-lift barges
\u00a0
and drilling rigs. As
a result, the initial recognition of the liability and
\u00a0
the capitalized
cost associated with decommissioning obligations,
\u00a0
and the
subsequent adjustment of these balance sheet items, involve
\u00a0
the
application of significant judgement. Based on the
\u00a0
described
uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
Impairment/reversal of impairment of oil and gas
\u00a0
assets
DNO has recognized significant investments in development
\u00a0
and
production assets (classified under PP&E) and exploration
\u00a0
and
evaluation assets (classified under intangible assets)
\u00a0
in the
consolidated statements of financial position. Changes
\u00a0
in the
circumstances or expectations of future performance
\u00a0
of an
individual asset or a group of assets may be an
\u00a0
indicator that the
asset is impaired, requiring the carrying amount
\u00a0
to be written
down to its recoverable amount. Management must
\u00a0
determine
whether there are circumstances indicating a possible
\u00a0
impairment
of the Group\u2019s oil and gas assets. The estimation of
\u00a0
the
recoverable amount for the oil and gas assets includes
assessments of expected future cash flows and future
\u00a0
market
conditions, including entitlement production, future
\u00a0
oil and gas
prices, cost profiles, country risk factors (i.e., discount
\u00a0
rate) and
the date of expiration of the licenses.
\u00a0
Impairments,
\u00a0
other than those relating to goodwill, are
\u00a0
reversed if
the conditions for impairment are no longer present.
\u00a0
Evaluating
whether an asset is impaired or if an impairment
\u00a0
should be
reversed requires a high degree of judgment.
Impairment of technical goodwill
\u00a0
Although not an IFRS term, \u201ctechnical goodwill\u201d is
\u00a0
commonly
\u00a0
used
in the oil and gas industry to describe a category
\u00a0
of goodwill
arising as an offsetting amount to deferred tax recognized in
business combinations. DNO has recognized a significant
technical goodwill arising from business combinations.
\u00a0
There are
no specific IFRS guidelines about the allocation of technical
goodwill, and the Group has therefore applied the general
guidelines for allocating goodwill for the purpose
\u00a0
of impairment
testing. In general,
\u00a0
technical goodwill is allocated to a cash-
generating unit (CGU) or group of CGUs that give rise
\u00a0
to the
technical goodwill, while any residual goodwill may
\u00a0
be allocated
across all CGUs based on facts and circumstances
\u00a0
in the
business combination.
\u00a0
Goodwill is tested for impairment annually or more frequently
when there are impairment indicators. Moreover, goodwill is not
depreciated and hence, impairment of technical goodwill
\u00a0
is
expected on a recurring basis, unless there are positive
\u00a0
changes
in underlying assumptions that more than offset the production
from the CGU (or groups
\u00a0
of CGUs).
When performing the impairment test for technical
\u00a0
goodwill,
deferred tax recognized in relation to the acquired
\u00a0
assets in a
business combination reduces the net carrying value prior
\u00a0
to the
impairment charges. When deferred tax from the
\u00a0
initial recognition
decreases, more goodwill is exposed for impairment.
\u00a0
After initial
recognition, depreciation of values calculated in the purchase
price allocations from business combinations will result in
decreased deferred tax liability.
Climate considerations in impairment assessment
Climate change and transition to a lower carbon economy
\u00a0
is
considered in the impairment assessments. In
\u00a0
the context of
assessing the potential impact on the book values
\u00a0
related to the
Group\u2019s oil and gas assets, certain climate considerations
\u00a0
are
factored into the Group\u2019s estimation of cash flows that
\u00a0
are applied
in the calculation of recoverable amount. This includes
\u00a0
factoring in
current legislation in Norway and the UK (e.g.,
\u00a0
environmental
taxes/fees) and estimation of future levels of environmental
\u00a0
taxes.
An energy transition is likely to impact the future oil
\u00a0
and gas
prices which in turn may affect the recoverable amount
\u00a0
of the oil
and gas assets. Indirectly, climate considerations are also
assessed in the forecasting of oil and gas prices
\u00a0
where supply
and demand are considered. A significant reduction in the
Company\u2019s oil and gas price assumptions would result
\u00a0
in
impairments on certain production and development
\u00a0
assets
including intangible assets that are subject to impairment
assessment under IAS 36, but an opposite revision
\u00a0
in the price
assumptions would lead to limited impairment reversals
\u00a0
as most
of the impairments recognized were related to
\u00a0
impairment of
goodwill which cannot be reversed under IFRS.
In the context of testing robustness of the oil
\u00a0
and gas assets
against the scenarios from the International Energy Agency
\u00a0
(IEA),
the Company has applied the Net Zero Emissions
\u00a0
Scenario,
Announced Pledges Scenario and the Stated Policies
\u00a0
Scenario as
published by the IEA. These scenarios are commonly
\u00a0
applied by
peer companies and the Company believes are useful
\u00a0
to
investors and other stakeholders in assessing portfolio
\u00a0
resilience
across companies in the industry. For more details, see Note 9.
\u00a0
Measurement of fair values
Fair value is the price that would be received
\u00a0
to sell an asset or
paid to transfer a liability in an orderly transaction between
\u00a0
market
participants at the measurement date (IFRS 13
Fair Value
Measurement
). The fair value of an asset or a liability
\u00a0
is measured
using the assumptions that market participants would
\u00a0
use when
pricing the asset or liability, including assumptions about risk,
assuming that market participants act in their economic
\u00a0
best
interest. There are situations when the Group is required
\u00a0
to
measure fair values of non-financial assets and liabilities,
\u00a0
for
example when investing in equity instruments, in a business
combination including allocation of purchase price or when
\u00a0
the
Group measures the recoverable amount of an asset
\u00a0
at fair value
less costs to sell in an impairment testing situation.
\u00a0
Fair value measurement of a non-financial asset
\u00a0
takes into
account a market participant\u2019s ability to generate economic
benefits by using the asset in its highest and
\u00a0
best use or by
selling it to another market participant that would
\u00a0
use the asset in
its highest and best use.
\u00a0
The Group uses valuation techniques that are appropriate
\u00a0
in the
circumstances and for which sufficient data are available
\u00a0
to
measure fair value. The fair value of oil and gas assets
\u00a0
is
normally based on discounted cash flow models (income
approach), where the determination of different inputs
\u00a0
in the
model requires significant judgment from management,
\u00a0
as
described in the section above regarding impairment.
Acquisition accounting
The Group applies the acquisition method for transactions
involving business combinations and applies the principles
\u00a0
of the
acquisition method when an interest or an additional
\u00a0
interest is
acquired in a joint operation which constitutes a
\u00a0
business.
Application of the acquisition method may require significant
judgement in, among other matters, determining and measuring
the fair value of the transaction consideration including
\u00a0
contingent
consideration elements, identifying all assets acquired
\u00a0
and
liabilities assumed, establishing their fair values, determining
deferred taxes, and allocating the purchase price
\u00a0
accordingly,
including measurement and allocation of goodwill. The
judgements applied in acquisition accounting may
\u00a0
materially
affect the financial statements both in the transaction period
\u00a0
and
in future periods.
The assets acquired through business combinations are
recognized at fair values and, as such, are sensitive
\u00a0
to adverse
changes in a number of often volatile economic factors,
\u00a0
including
future oil and gas prices and the underlying
\u00a0
performance of the
assets.
Accounting for exploration costs
The Group\u2019s accounting policy is to temporarily capitalize drilling
expenditures related to exploration wells, pending an
\u00a0
evaluation
of potential oil and gas discoveries. If resources
\u00a0
are not
discovered, or if recovery of the resources is not
\u00a0
considered
technically or commercially viable, the costs of the exploration
wells are expensed in the income statement. Decisions
\u00a0
as to
whether an exploration well should remain capitalized
\u00a0
or
expensed during the period may have a material
\u00a0
effect on the
financial results
\u00a0
for the period.
Notional corporate income tax/deferred taxation
\u00a0
in Kurdistan
Under the terms of its PSCs in Kurdistan, DNO
\u00a0
is not required to
pay any corporate income taxes. The share of profit
\u00a0
oil which the
government is entitled to is deemed to include a
\u00a0
portion
representing the notional corporate income tax paid
\u00a0
by the
government on behalf of DNO. Current and deferred
\u00a0
taxation for
accounting purposes arising from such notional corporate
\u00a0
income
tax is not recognized for Kurdistan as it has
\u00a0
not been possible to
measure reliably such notional corporate income tax
\u00a0
paid on
behalf of DNO. This is an accounting presentational matter
\u00a0
and
there is no corporate income tax required
\u00a0
to be paid, see also
section Income taxes and Note 8.
\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 of
\u00a0
its subsidiaries.
The financial results of subsidiaries acquired or
\u00a0
sold during the
year are included in the consolidated financial statements
\u00a0
from
the date when the Company obtains control of the
\u00a0
subsidiary and
up to the date when the Company loses control
\u00a0
of the subsidiary.
The financial statements of the subsidiaries are prepared
\u00a0
for the
same reporting period as the parent company using
\u00a0
consistent
accounting policies. Where necessary, the accounting policies of
the subsidiaries have been adjusted to ensure consistency
\u00a0
with
the policies adopted by DNO. All intercompany balances
\u00a0
and
transactions have been eliminated upon consolidation.
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO
\u00a0
holds a long-term
interest which is jointly controlled by DNO and one
\u00a0
or more other
parties under a contractual arrangement in which
\u00a0
decisions about
the relevant activities require the unanimous
\u00a0
consent of the
parties sharing control. Such joint arrangements are classified
\u00a0
as
either joint operations or joint ventures.
Under IFRS 11
Joint Arrangements
, a joint operation is a joint
arrangement whereby the parties that have joint
\u00a0
control of the
arrangement have rights to the assets and obligations
\u00a0
for the
liabilities. Oil and gas licenses held by the Group
\u00a0
which are within
the scope of IFRS 11 have been classified as 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
A joint venture under IFRS 11, is a joint arrangement whereby the
parties that have joint control of the arrangement
\u00a0
have rights to
the net assets of the arrangement. Those parties are
\u00a0
called joint
venturers. Joint control is the contractually agreed sharing
\u00a0
of
control of an arrangement, which exists only when
\u00a0
decisions
about the relevant activities require unanimous
\u00a0
consent of the
parties sharing control.
\u00a0
The Group\u2019s investments in a joint venture are accounted
\u00a0
for
using the equity method. Under the equity method,
\u00a0
the investment
is initially recognized at cost. The carrying value of
\u00a0
the investment
is adjusted to recognize the Group\u2019s share of the net assets
\u00a0
of the
joint venture since the acquisition date. Goodwill relating
\u00a0
to the
joint venture is included in the carrying amount of
\u00a0
the investment
and is neither amortized nor individually tested
\u00a0
for impairment.
The income statement reflects the Group\u2019s share of the results
\u00a0
of
operations in the joint venture. On acquisition of
\u00a0
the investment,
any difference between the cost of the investment and
\u00a0
the
Group\u2019s share of the net fair value of the investee\u2019s identifiable
assets and liabilities is accounted for as: Goodwill
\u00a0
relating to a
joint venture and is included in the carrying
\u00a0
amount of the
investment; and any excess of the Group\u2019s share of
\u00a0
the net fair
value of the joint venture\u2019s profit or loss in the period
\u00a0
in which the
investment is acquired.
Appropriate adjustments to the Group\u2019s share of the joint
venture\u2019s profit or loss after acquisition are made in
\u00a0
order to
account for, for example, for depreciation of the depreciable
assets (and related deferred tax, if any) based
\u00a0
on their fair values
at the acquisition date.
Any change in OCI of those investees is presented
\u00a0
as part of the
Group\u2019s OCI. In addition, when there has been a change
recognized directly in the equity of the joint venture,
\u00a0
the Group
recognizes its share of any changes, when applicable,
\u00a0
in the
statement of changes in equity.
The aggregate of the Group\u2019s share of profit or loss
\u00a0
of a joint
venture represents profit or loss after tax and non-controlling
interests in the subsidiaries of the joint venture. The
\u00a0
financial
statements of the joint venture are prepared for
\u00a0
the same
reporting period as the Group. When necessary, adjustments are
made to bring the accounting policies in line
\u00a0
with those of the
Group (IFRS).
The impact of reciprocal interests between the
\u00a0
Group and its
investees is eliminated before the Group accounts
\u00a0
for its share;
the Group also reduces its equity and investment
\u00a0
balance by its
effective interest in its own shares.
For those licenses that are not deemed to be joint
\u00a0
arrangements
pursuant to the definition in IFRS 11, either because unanimous
consent is not required among the parties involved,
\u00a0
or no single
group of parties has joint control over the
\u00a0
activity, DNO
recognizes its share of related expenses, assets,
\u00a0
liabilities and
cash flows under the respective items in the Group\u2019s financial
statements in accordance with applicable IFRS
\u00a0
standards. In
determining whether each separate arrangement related
\u00a0
to
DNO\u2019s joint operations is within or outside the scope of
\u00a0
IFRS 11,
DNO considers the terms of relevant license agreements,
governmental concessions and other legal arrangements
impacting how and by whom each arrangement
\u00a0
is controlled.
\u25a0
Foreign currency translation and transactions
Functional currency
The consolidated financial statements are presented
\u00a0
in USD,
which is also DNO ASA\u2019s functional currency and presentation
Items included in the financial statements of each
\u00a0
subsidiary are
initially recorded in the subsidiary\u2019s functional currency, i.e., the
currency that best reflects the economic substance of
\u00a0
the
underlying events and circumstances relevant to
\u00a0
that subsidiary.
Transactions and balances
Foreign currency transactions are translated into functional
currency of the Company or subsidiaries using
\u00a0
the exchange
rates prevailing at the dates of the transactions. Financial
\u00a0
assets
and financial liabilities in foreign currencies are translated
\u00a0
into
functional currency at the balance sheet date exchange
\u00a0
rates.
Foreign exchange gains and losses resulting from
\u00a0
the settlement
of such transactions and from the translation of
\u00a0
monetary assets
and liabilities denominated in foreign currencies are
\u00a0
recognized in
profit or loss. Those arising in respect of financial
\u00a0
assets and
liabilities are recorded
\u00a0
on a net basis as a financial item.
Foreign exchange gains or losses relating to
\u00a0
changes in the fair
value of non-monetary financial assets classified as
\u00a0
equity
instruments are recognized directly in other comprehensive
income.
Subsidiaries
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 translation
differences taken directly to other comprehensive income. When
a foreign entity is sold, such translation differences are
recognized in profit or loss as part of the gain
\u00a0
or loss on the sale.
\u25a0
Classification in the statements of financial
position
Current assets and current liabilities include items
\u00a0
due less than
one year from the balance sheet date, and if
\u00a0
longer, items related
to the operating cycle. The current portion of non-current
\u00a0
liabilities
is included under current liabilities. Investments in shares held
\u00a0
for
trading are classified as current assets, while
\u00a0
strategic
investments are classified as non-current assets. Other
\u00a0
assets
and liabilities are classified as non-current assets
\u00a0
and non-current
liabilities.
\u25a0
Fair value
Fair value is the price that would be received to
\u00a0
sell an asset or
be paid to transfer a liability in an orderly transaction
\u00a0
between
market participants at the measurement date. The
\u00a0
fair value of an
asset or a liability is measured using the assumptions
\u00a0
that market
participants would use when pricing the asset
\u00a0
or liability,
assuming that market participants act in their economic
\u00a0
best
interest. All assets and liabilities for which fair
\u00a0
value is measured
or disclosed in the financial statements are categorized
\u00a0
within the
fair value hierarchy as follows:
\u00a0
\u2022
Level 1 - Quoted market prices in active markets
\u00a0
for identical
assets or liabilities
\u00a0
\u2022
Level 2 - Valuation techniques for which the lowest level input
that is significant to the fair value measurement is directly
\u00a0
or
indirectly observable
\u00a0
\u2022
Level 3 - Valuation techniques for which the lowest level input
that is significant to the fair value measurement is
unobservable.
Investments in equity instruments, where available,
\u00a0
are measured
at quoted market prices at the measurement date.
\u25a0
Property, plant and equipment
General
PP&E are recognized at historical cost and adjusted
\u00a0
for
depreciation, depletion and amortization (DD&A) and
\u00a0
impairment
Depreciation of PP&E other than oil and gas assets
\u00a0
are generally
depreciated on a straight-line basis over expected
\u00a0
useful lives,
normally varying from three to seven years. Expected
\u00a0
useful lives
are reviewed at each balance sheet date and, where
\u00a0
there are
changes in estimates, depreciation periods are changed
accordingly.
The carrying amount of the PP&E in the statements
\u00a0
of financial
position represents the cost less accumulated DD&A
\u00a0
and
accumulated impairment charges.
Ordinary repairs and maintenance costs, defined
\u00a0
as day-to-day
servicing costs, are charged to profit or loss during
\u00a0
the financial
period in which they are incurred. The cost of major
\u00a0
repairs and
maintenance is included in the asset\u2019s carrying amount
\u00a0
when it is
likely that the Group will derive future financial benefits
\u00a0
exceeding
the originally assessed standard of performance of
\u00a0
the existing
asset.
Gains and losses on disposals are determined
\u00a0
by comparing the
disposal proceeds with the carrying amount and
\u00a0
are included in
Assets held for sale are reported at the lower
\u00a0
of the carrying
amount and the fair value, less selling costs.
Exploration and development costs
\u00a0
Capitalized exploration expenditures are classified as
\u00a0
intangible
assets and reclassified to tangible assets (i.e.,
\u00a0
PP&E) at the start
of the development. For accounting purposes, an oil
\u00a0
and gas field
is considered to enter the development phase when
\u00a0
the technical
feasibility and commercial viability of extracting oil and gas
\u00a0
from
the field are demonstrable, normally at the time
\u00a0
of concept
selection. All costs of developing commercial oil
\u00a0
and gas fields
are capitalized, including indirect costs. Capitalized development
costs are classified as tangible assets. Pre-development
expenditures up until development project sanction in
\u00a0
general do
not meet the criteria for capitalization and are expensed
\u00a0
as
incurred.
Acquired license rights are recognized as intangible assets
\u00a0
at the
time of acquisition. Acquired license rights related
\u00a0
to fields in the
exploration phase remain as intangible assets when
\u00a0
the related
fields enter the development or production phase.
Oil and gas assets in production
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the
unit-of-production (UoP) method. The rate of depreciation
\u00a0
is equal
to the ratio of oil and gas production for
\u00a0
the period over the
estimated remaining 2P reserves at the beginning of
\u00a0
the period.
The future development expenditures necessary to bring
\u00a0
those
reserves into production are included in the
\u00a0
basis for depreciation
and are estimated by the management based
\u00a0
on current period-
end un-escalated price levels. The reserve basis used
\u00a0
for
depreciation purposes is updated at least once a year. Any
changes in the reserves affecting UoP calculations are reflected
prospectively.
Component cost accounting/decomposition
The Group allocates the amount initially recognized
\u00a0
in respect of
an item of PP&E to its significant parts and depreciates
\u00a0
separately
each such part over its useful life.
\u00a0
Borrowing costs
Interest costs directly attributable to the construction phase
\u00a0
of
PP&E assets are capitalized during the period required
\u00a0
to
complete and prepare the asset for its intended
\u00a0
use. Borrowing
costs consist of interest and other costs that the Group
\u00a0
incurs in
connection with the borrowing of funds.
\u00a0
Other borrowing costs are expensed when incurred.
\u00a0
The
capitalization of borrowing costs is recorded based
\u00a0
on the
average interest rate for the Group in the period.
\u00a0
The capitalized
borrowing costs cannot exceed the actual borrowing
\u00a0
costs in each
period.
Leases
The Group assesses at contract inception whether
\u00a0
a contract is,
or contains, a lease. That is, if the contract
\u00a0
conveys the right to
control the use of an identified asset for a period
\u00a0
of time in
exchange for consideration.
\u00a0
The Group applies a single recognition and measurement
approach for all leases, except for short-term leases (12
\u00a0
months
or less) and leases of low-value assets. Short
\u00a0
term leases and
leases of low value assets have not been reflected
\u00a0
in the balance
sheet but expensed or capitalized as incurred, depending
\u00a0
on the
activity in which the leased asset is used.
At the commencement date of a lease, the Group recognizes
\u00a0
a
liability to make lease payments and an asset representing
\u00a0
the
right to use the underlying asset (right-of-use (RoU)
\u00a0
asset) during
The RoU assets are measured to cost, less any
\u00a0
accumulated
depreciation and impairment losses, and adjusted
\u00a0
for any
remeasurement of lease liabilities. The RoU assets
\u00a0
are
depreciated linearly over the lifetime of the related lease
\u00a0
contract.
Lease liabilities are measured at the present value
\u00a0
of lease
payments to be made over the lease term. In
\u00a0
calculating the
present value of lease payments, the Group
\u00a0
uses the implicit
interest rate and if not readily determinable, its
\u00a0
incremental
borrowing rate at the lease commencement date.
Extension options are included in the lease liability
\u00a0
when, based
on the management\u2019s judgement, it is reasonably certain
\u00a0
that an
extension will be exercised.
When DNO, as the operator of a license, is considered
\u00a0
to have
the primary responsibility for the full lease payments
\u00a0
(e.g., a rig
lease where the lease agreement is entered into DNO\u2019s
\u00a0
name as
the operator of a license at the initial signing),
\u00a0
the lease liability
may be recognized on gross basis, rather than based
\u00a0
on DNO\u2019s
working interest share. DNO then derecognizes a portion
\u00a0
of the
RoU asset corresponding to the non-operator\u2019s
\u00a0
interests in the
license (presented under receivables).
In the consolidated statements of comprehensive
\u00a0
income,
operating lease costs, relating to contracts that contain
\u00a0
a lease,
are replaced by depreciation and interest expense.
In the consolidated cash flow, lease payments related to lease
liabilities recognized in accordance with IFRS 16,
\u00a0
are presented
as cash flow used in financing activities.
The Group\u2019s RoU assets mainly relate to office rent,
\u00a0
rig and
equipment. The Group also leases equipment
\u00a0
with contract terms
of one to three years but has elected to apply
\u00a0
the practical
expedient on low value assets and does not recognize
\u00a0
lease
liabilities or RoU assets and the leases are
\u00a0
instead expensed
when the costs are incurred.
\u25a0
Intangible assets
General
Intangible assets are stated at cost, less accumulated
amortization and accumulated impairment charges.
\u00a0
Intangible
assets include acquisition costs for oil and gas licenses,
expenditures on the exploration for oil and gas
\u00a0
resources,
technical goodwill and other intangible assets. Goodwill
\u00a0
is not
depreciated.
The useful lives of intangible assets are assessed
\u00a0
as either finite
or infinite. Amortization of intangible assets is
\u00a0
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 more often
\u00a0
if indicators
exist.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its
exploration and evaluation assets. All exploration
\u00a0
costs (including
purchase of seismic, geological and geophysical
\u00a0
costs and
general and administrative costs), except for acquisition
\u00a0
costs of
licenses and drilling costs of exploration wells, are
\u00a0
expensed as
incurred. Acquisition costs of licenses and drilling
\u00a0
costs of
exploration wells are temporarily capitalized pending
\u00a0
the
determination of oil and gas resources. These
\u00a0
costs include
directly attributable employee remuneration, materials and
\u00a0
fuel
used, rig costs and payments to contractors. Continued
capitalization of such costs is assessed for impairment
\u00a0
at each
reporting date. The main criterion is that there must
\u00a0
be plans for
future activity in the license or that a development
\u00a0
decision is
expected in the near future. If reserves or resources are
\u00a0
not
found, or if discoveries are assessed not technically
\u00a0
or
commercially recoverable, the costs of exploration wells and
licenses are expensed.
\u25a0
Impairment/reversal of impairment
At the end of each reporting period, the Group
\u00a0
assesses whether
there is any indication that an asset may be
\u00a0
impaired. If an
impairment indicator is concluded to exist, an impairment
\u00a0
test is
Indications of impairment may include a decline
\u00a0
in the long-term
oil and gas price (or short-term oil and gas price
\u00a0
for late-life oil
and gas fields), changes in future investments or significant
downward revision of reserve and resource estimates.
\u00a0
For the
purposes of impairment assessment, assets are grouped
\u00a0
at the
lowest levels for which there are separable identifiable
\u00a0
cash
inflows. For oil and gas assets, a CGU may be individual
\u00a0
oil and
gas fields, or a group of oil and gas
\u00a0
fields 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 asset. The
\u00a0
recoverable
amount is the higher of the asset\u2019s fair value less costs to
\u00a0
sell and
its value in use. Fair value less costs to sell
\u00a0
determined through
either the discounted cash flow method (income approach)
\u00a0
or the
market transactions method (market approach). The value
\u00a0
in use
can only be determined through the discounted cash
\u00a0
flow method.
A previously recognized impairment loss is reversed
\u00a0
through the
income statement if the circumstances that gave rise
\u00a0
to the
impairment no longer exist. It is not reversed
\u00a0
to an amount that
would be higher than if no impairment loss
\u00a0
had been recognized.
After such a reversal, the depreciation charge
\u00a0
is adjusted in future
periods to allocate the asset\u2019s revised carrying amount,
\u00a0
less any
residual value, on a systematic basis over its remaining
\u00a0
useful life.
Technical goodwill
Technical goodwill is tested for impairment annually or more
frequently when there are impairment indicators. Those
\u00a0
indicators
may be specific to an individual CGU or groups
\u00a0
of CGUs to which
the technical goodwill is related. When performing
\u00a0
the impairment
test for technical goodwill, deferred tax recognized
\u00a0
in relation to
the acquired licenses reduces the net carrying value prior
\u00a0
to the
impairment charges.
Impairment is recognized if the recoverable amount
\u00a0
of the CGU
(or groups
\u00a0
of CGUs) to which the technical goodwill is related
\u00a0
is
less than the carrying amount.
\u00a0
Impairment of goodwill cannot be reversed in future
\u00a0
periods.
\u25a0
Financial instruments
A financial instrument is any contract that gives
\u00a0
rise to a financial
asset of one entity and a financial liability or
\u00a0
equity instrument of
another entity. Financial instruments are initially recognized at fair
value. After initial recognition the measurement and accounting
treatment depend on the type of instrument and
\u00a0
classification.
Financial assets
Financial assets are classified at initial recognition
\u00a0
and
subsequently measured at:
\u2022
Amortized cost;
\u2022
Fair value through other comprehensive income (FVTOCI); and
\u00a0
\u2022
Fair value through profit or loss (FVTPL).
Financial assets at amortized cost
Financial assets are measured at amortized cost if
\u00a0
both of the
following conditions are met:
\u00a0
\u2022
The financial asset is held within a business
\u00a0
model with the
objective to hold financial assets in order to collect
\u00a0
contractual
\u2022
The contractual terms of the financial asset give
\u00a0
rise on
specified dates to cash flows that are solely payments
\u00a0
of
principal and interest on the principal amount outstanding.
Financial assets at amortized cost are subsequently
\u00a0
measured
using the effective interest rate (EIR) method and are
\u00a0
subject to
impairment. Gains and losses are recognized in profit
\u00a0
or loss
when the asset is derecognized, modified or impaired.
\u00a0
The
Group\u2019s financial assets at amortized cost include trade
\u00a0
and other
receivables.
Financial assets designated at FVTOCI
Upon initial recognition, equity investments can be
\u00a0
irrevocably
classified as equity instruments designated at
\u00a0
FVTOCI. Gains and
losses on these financial assets are not recycled
\u00a0
to profit or loss
at later periods. Equity instruments designated at
\u00a0
FVTOCI are not
subject to an impairment assessment.
Financial assets at FVTPL
Financial assets at FVTPL include financial assets held
\u00a0
for
trading, financial assets designated upon initial recognition
\u00a0
at
FVTPL or financial assets mandatorily required to be
\u00a0
measured at
fair value. Financial assets at FVTPL are carried
\u00a0
in the statements
of financial position at fair value with net changes
\u00a0
in fair value
recognized in profit or loss. Dividends on listed equity
\u00a0
investments
are also recognized as other income in profit
\u00a0
or loss when the
right of payment has been established. The Group
\u00a0
does not have
significant assets designated at FVTPL.
Derecognition of financial assets
A financial asset is derecognized when the Group:
\u2022
No longer has the right to receive cash flows from
\u00a0
the asset;
\u2022
Retains the right to receive cash flows from the asset
\u00a0
but has
assumed an obligation to pay them in full without
\u00a0
material
delay to a third party under a pass-through arrangement;
\u00a0
or
\u2022
Has transferred its rights to receive cash flows from
\u00a0
the asset
and either has transferred substantially all the risks
\u00a0
and
rewards of the asset or has neither transferred
\u00a0
nor retained
substantially all the risks and rewards of the asset
\u00a0
but has
transferred the control of the asset.
Impairment of financial assets
An allowance is recognized for expected credit
\u00a0
losses (ECLs) for
all debt instruments not held at FVTPL. ECLs are
\u00a0
based on the
difference between the contractual cash flows due in accordance
with the contract and all the cash flows that are
\u00a0
expected to be
received, discounted at an approximation of the original
\u00a0
effective
ECLs are recognized in two stages. For credit exposures
\u00a0
with no
significant increase in credit risk since initial recognition,
\u00a0
ECLs are
provided for credit losses that result from default events
\u00a0
that are
possible within the next 12 months. For credit exposures
\u00a0
with
significant increase in credit risk since initial recognition,
\u00a0
a loss
allowance is provided for credit losses expected
\u00a0
over the
remaining life of the exposure, irrespective of
\u00a0
the timing of the
For trade receivables, a simplified approach is applied
\u00a0
in
calculating ECLs. Changes in credit risk are not
\u00a0
tracked but
instead a loss allowance based on lifetime ECLs
\u00a0
at each reporting
date is recognized. Expected credit losses are based
\u00a0
on a
multifactor and holistic analysis and depend on
\u00a0
historical
experience with the customers adjusted for forward-looking
factors specific to the customers and the economic environment.
\u00a0
Financial assets are assessed with regards
\u00a0
to default when
contractual payments are past the established payment
\u00a0
due date
and there is internal or external information indicating
\u00a0
that the
Group is unlikely to receive the outstanding contractual
\u00a0
amounts
in full. A financial asset is written off when there is
\u00a0
no reasonable
expectation of recovering the contractual cash flows.
Further disclosures on impairment of financial assets
\u00a0
are provided
in Note 18.
Financial liabilities
Financial liabilities are classified at initial recognition as
\u00a0
financial
liabilities at FVTPL, loans and borrowings or payables.
\u00a0
All financial liabilities are recognized initially at
\u00a0
fair value and in
the case of loans/borrowings and payables, net
\u00a0
of directly
attributable transaction costs.
\u00a0
The Group\u2019s financial liabilities include trade and other payables
and loans.
The subsequent measurement of financial liabilities depends
\u00a0
on
the classification. No financial liabilities have been designated
\u00a0
at
FVTPL. Interest-bearing loans are after initial recognition
measured at amortized cost using the effective interest
\u00a0
rate
method. Gains and losses are recognized in
\u00a0
profit or loss when
the liabilities are derecognized as well as through
\u00a0
the amortization
process. Amortized cost is calculated by taking into account
\u00a0
any
discount or premium on acquisition and fees or
\u00a0
costs that are an
integral part of the effective interest rate. The amortization
\u00a0
cost is
included as finance expense in the statements of
\u00a0
comprehensive
income. This applies mainly to bond loans,
\u00a0
see Note 15.
\u00a0
A financial liability is derecognized when the obligation
\u00a0
under the
liability is discharged, cancelled or expires. When
\u00a0
an existing
financial liability is replaced by another from the
\u00a0
same lender on
substantially different terms, or the terms of an existing
\u00a0
liability are
substantially modified, such a modification is treated
\u00a0
as a
derecognition of the original liability and a recognition
\u00a0
of a new
liability. The difference in the respective carrying amounts is
recognized in the statements of comprehensive income.
Cash and cash equivalents
Cash and short-term deposits in the statements
\u00a0
of financial
position comprise cash held in banks, cash in
\u00a0
hand and short-
term deposits with an original maturity of three
\u00a0
months or less.
\u25a0
Equity
Ordinary shares
Ordinary shares are classified as equity. Costs directly
attributable to the issue of ordinary shares and
\u00a0
share options are
recognized as a reduction of equity, net of any tax effects.
Repurchase of share capital (treasury shares)
When share capital recognized as equity is repurchased,
\u00a0
the
amount of the consideration paid, which includes
\u00a0
directly
attributable costs, is net of any tax effects and is
\u00a0
recognized as a
deduction in equity. Repurchased shares are classified as
treasury shares and are presented as a deduction
\u00a0
from total
equity. When treasury shares are subsequently sold or reissued,
the amount received is recognized as an increase
\u00a0
in equity and
the resulting surplus or deficit of the transaction
\u00a0
is transferred
to/from retained earnings.
Dividend
Liability to pay a dividend is recognized when
\u00a0
the distribution is
authorized by the shareholders. A corresponding amount is
recognized directly in equity.
\u25a0
Financial income and expenses
Financial income comprises interest income; dividend
\u00a0
income;
gains on the disposal of financial investments; foreign
\u00a0
exchange
gains; changes in the fair value of financial assets through
\u00a0
profit
or loss; and other financial income. Interest income
\u00a0
is recognized
as it accrues in profit or loss using the effective interest
\u00a0
method.
Dividend income is recognized in the profit or
\u00a0
loss on the date that
the Group\u2019s right to receive payment is established,
\u00a0
which in the
case of quoted securities is the ex-dividend date.
Financial expenses comprise interest expenses on
\u00a0
loans;
unwinding of the discount on provisions; changes
\u00a0
in the fair value
of financial assets measured at FVTPL; impairment
\u00a0
losses
recognized on financial assets; foreign exchange
\u00a0
losses;
\u00a0
losses
on financial assets recognized in the profit or
\u00a0
loss; and other
financial expenses.
Foreign exchange gains or losses from financial
\u00a0
instruments are
reported as financial income or financial expenses.
\u25a0
Inventories
Inventories are valued at the lower of cost and
\u00a0
net realizable
value. Cost is determined by the first-in, first-out (FIFO)
\u00a0
method.
Net realizable value is the estimated selling price
\u00a0
in the ordinary
course of business, less the estimated costs of
\u00a0
completion and
estimated selling expenses.
\u25a0
Revenue recognition
Revenues presented in the consolidated statements 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 and gas,
\u00a0
which normally will be
when title passes at the point of delivery.
A liability (overlift) arises when the Group sells
\u00a0
more than its
share of the oil and gas production. Similarly, an asset (underlift)
arises when the sale is less than the Group\u2019s share
\u00a0
of the oil and
gas production.
In general, the overlift/underlift balances are valued
\u00a0
at production
cost including depreciation (the sales method). The movements
\u00a0
in
overlift/underlift are presented as an adjustment to
Cost of goods
sold
Tariff income from processing of oil and gas in the North Sea is
recognized as earned.
\u00a0
Other revenues are recognized when the goods
\u00a0
or services are
delivered and risk and control are transferred.
Revenue recognition in Kurdistan
DNO generates revenues in Kurdistan through the sale
\u00a0
of oil
produced from the Tawke license which is exported by pipeline
through Turkey. The title is considered to have passed on delivery
of oil to the export pipeline at Fish Khabur. In addition, pursuant
\u00a0
to
a receivables settlement agreement with the KRG
\u00a0
in August 2017,
DNO was entitled to production overrides (override)
\u00a0
representing
three percent of gross Tawke license revenues until 31 July 2022.
The Group recognizes revenues in Kurdistan in line
\u00a0
with the
invoiced oil sales and overrides following monthly
\u00a0
deliveries to the
KRG. The PSCs held by the Group are considered
\u00a0
to be within
the scope of the standard and sale of oil and gas
\u00a0
to customers is
recognized as
Revenue from contracts with customers
. Based on
business practice, the KRG is responsible for exporting
\u00a0
the oil
produced in Kurdistan and it is assessed that
\u00a0
DNO has a
customer relationship with the KRG. It is considered
\u00a0
that the
contracts with customers contain a single performance
\u00a0
obligation
which is considered to be delivery of produced oil
\u00a0
and gas to the
customer.
The price for oil deliveries to the KRG is
\u00a0
based on Brent prices
with adjustments for oil quality and transportation
\u00a0
fees.
\u25a0
Production Sharing Contracts (PSC)
A PSC is an agreement between a contractor
\u00a0
and a host
government, whereby the contractor bears all of
\u00a0
the risks and
costs of exploration, and if successful, costs of development
\u00a0
and
production in return for a stipulated share of production
\u00a0
from the
discovery.
The contractor recovers the sum of its investment
\u00a0
and operating
costs from a percentage of production (cost oil).
\u00a0
In addition, the
contractor is entitled to receive a share of production
\u00a0
in excess of
cost oil (profit oil). The sum of cost oil attributable
\u00a0
to the
contractor\u2019s share of costs and the share of
\u00a0
profit oil represents
the contractor\u2019s entitlement under a PSC.
\u00a0
The sum of royalties
and the government\u2019s share of profit oil, including that of a
government-controlled enterprise, represents the government
take under a PSC.
DNO presents its operations governed by PSCs according
\u00a0
to the
sales method and only recognizes its sales as
\u00a0
revenue after
deduction of government take.
\u25a0
Income taxes
Tax income/expense consists of taxes receivable/payable and
changes in deferred taxes.
\u00a0
Taxes receivable/payable are based
on the amounts receivable from or payable to the tax
\u00a0
authorities.
Deferred tax liability is calculated on all taxable temporary
differences unless there is a recognition exception. A deferred
\u00a0
tax
asset is recognized only to the extent that it
\u00a0
is probable that the
future taxable income will be available against which
\u00a0
the asset
can be utilized. Unrecognized deferred tax assets
\u00a0
are re-
assessed at each reporting date and are
\u00a0
recognized to the extent
that it has become probable that future taxable profits
\u00a0
will allow
the deferred tax asset to be recovered.
Deferred tax assets and deferred tax liabilities
\u00a0
are recognized
irrespective of when the differences are reversed.
\u00a0
They are
recognized at their nominal value and classified as non-current
assets/liabilities in the statements of financial position.
\u00a0
Deferred
tax assets and deferred tax liabilities are offset
\u00a0
in the statements
of financial position if there is a legal right
\u00a0
to settle current tax
amounts on a net basis and the deferred tax
\u00a0
amounts are levied
by the same taxing authority on the same entity or
\u00a0
different
entities that intend to realize the asset and settle the
\u00a0
liability at the
same time.
Tax payable and deferred tax are recognized directly in the equity
to the extent that they relate to items charged
\u00a0
directly to equity.
\u00a0
For treatment of tax in relation to business combinations,
\u00a0
see the
Business combinations section.
\u00a0
DNO\u2019s PSCs provide that the corporate income tax to which the
contractor is subject is deemed to have been paid to
\u00a0
the
government as part of the payment of profit
\u00a0
oil to the government
or its representatives. For accounting purposes, if
\u00a0
such notional
income tax is to be classified as income tax in
\u00a0
accordance with
IAS 12
Income Taxes
, the Group would present this as an income
tax expense with a corresponding increase in revenues.
Furthermore, it would be assessed whether any
\u00a0
deferred tax
asset or liability is required to be recognized
\u00a0
equal to the
difference between book values and the tax values of
\u00a0
the
qualifying assets and liabilities, multiplied by the applicable
\u00a0
tax
rate.
\u25a0
Business combinations
In accordance with IFRS 3
Business Combinations
, an acquisition
is considered a business combination, when the acquired
\u00a0
asset or
groups of assets constitute a business (i.e., an integrated
\u00a0
set of
operations and assets conducted and managed for
\u00a0
the purpose of
providing a return to the investors).
Acquired businesses are included in the financial statements
\u00a0
from
the transaction date. The transaction date is defined
\u00a0
as the date
on which the Group achieves control over the
\u00a0
financial and
operating assets. This date may differ from the actual
\u00a0
date on
which the assets are transferred.
For accounting purposes, the acquisition method is used
\u00a0
in
connection with the purchase of businesses. Acquisition
\u00a0
cost
equals the fair value of the assets used as
\u00a0
consideration,
including contingent consideration, equity instruments issued
\u00a0
and
liabilities assumed in connection with the transfer of
\u00a0
control.
Acquisition cost is measured against the fair value
\u00a0
of the acquired
assets and assumed liabilities. Identifiable intangible
\u00a0
assets are
included in connection with acquisitions if they
\u00a0
can be separated
from other assets or meet the legal contractual
\u00a0
criteria. If the
acquisition cost at the time of the acquisition exceeds
\u00a0
the fair
value of the acquired net assets (when
\u00a0
the acquiring entity
achieves control of the transferring entity), goodwill arises.
If the fair value of the acquired net assets exceeds
\u00a0
the acquisition
cost on the acquisition date, the excess amount
\u00a0
is taken to profit
or loss immediately.
Goodwill is allocated to the CGUs or groups of
\u00a0
CGUs that are
expected to benefit from synergy effects of the acquisition.
\u00a0
The
allocation of goodwill may vary depending on the
\u00a0
basis of its initial
recognition.
The goodwill that is recognized by the Group is related
\u00a0
to
technical goodwill and is recognized due to the requirement
\u00a0
to
recognize deferred tax for the difference between the assigned
fair values and the related tax base. The fair values of
\u00a0
the Group\u2019s
licenses in the North Sea are based on cash flows
\u00a0
after tax.
\u00a0
This
is because these licenses are sold only on an after-tax
\u00a0
basis. The
purchaser is therefore not entitled to a tax deduction
\u00a0
for the
consideration paid above the seller\u2019s tax values.
\u00a0
In accordance
with IAS 12, a provision is made for deferred
\u00a0
tax corresponding to
the tax rate multiplied by the difference between the fair
\u00a0
values of
the acquired assets and the transferred tax depreciation
\u00a0
basis.
\u00a0
The offsetting entry to this deferred tax is goodwill. Hence,
goodwill arises as a technical effect of deferred
\u00a0
tax. Technical
goodwill is tested for impairment separately for each
\u00a0
CGU which
gives rise to the technical goodwill. A CGU
\u00a0
may be individual oil
fields, or a group of oil fields that are
\u00a0
connected to the same
infrastructure/production facilities, or a license.
The estimation of fair value may be adjusted up
\u00a0
to 12 months
after the acquisition date if new information emerges
\u00a0
about facts
and circumstances that existed at the time of
\u00a0
the takeover and
which, had they been known, would have affected the
\u00a0
calculation
of the amounts that were included from that date.
Acquisition-related costs, except costs to issue debt or
\u00a0
equity
securities, are expensed as incurred. Taxes payable and deferred
taxes are recognized directly in the equity to
\u00a0
the extent that they
relate to items charged directly to the equity.
\u25a0
License acquisitions, farm-in/out and license
swaps
License acquisitions
\u00a0
For acquisition of oil and gas licenses, individual
\u00a0
assessment is
made whether the acquisition should be treated
\u00a0
as a business
combination or as an asset purchase. The
\u00a0
conclusion may
materially affect the financial statements both in the transaction
period and in future periods. 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.
Farm-in and farm-out
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. The farmee capitalizes or expenses
\u00a0
its costs as
incurred according to the accounting method it is
\u00a0
using. There are
no accruals for future commitments in farm-in/farm-out
agreements in the exploration and evaluation phase
\u00a0
and no profit
or loss is recognized by the farmor. In the development or
production phase, a farm-in/farm-out agreement will be
\u00a0
treated as
a transaction recorded at fair value as represented
\u00a0
by the costs
carried by the farmee. Any gain or loss arising from
\u00a0
the farm-
in/farm-out is recognized in the statements of comprehensive
License swaps
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
the fair value of
the asset divested,
\u00a0
can be reliably measured. In the exploration
phase, the Group normally recognizes license swaps based
\u00a0
on
historical cost basis. If the transaction is determined
\u00a0
to be a
business combination, the requirements of IFRS 3
\u00a0
apply.
\u25a0
Employee benefits
Pensions
The Group\u2019s pension obligations in Norway are limited
\u00a0
to certain
defined contribution plans which are paid to pension
\u00a0
insurance
plans and charged to profit or loss in the period
\u00a0
in which they are
incurred. Once the contributions are paid there are no
\u00a0
further
obligations.
Share-based payments
Cash-settled share-based payments are recognized in
\u00a0
the income
statement as expenses during the vesting period and
\u00a0
as a liability.
The liability is measured at fair value and revaluated
\u00a0
using the
Black & Scholes pricing model at each balance
\u00a0
sheet date and at
the date of settlement, with any change in the fair
\u00a0
value
recognized in the income statement for the period.
\u25a0
Provisions and contingent liabilities
A provision is recognized when the Group has
\u00a0
a present
obligation (legal or constructive) as a result of
\u00a0
a past event, there
is likely that an outflow of resources will be required
\u00a0
to settle the
obligation and a reliable estimate can be made
\u00a0
of the obligation
amount. When the Group expects some or
\u00a0
all of a provision to be
reimbursed, for example under an insurance contract,
\u00a0
the
reimbursement is recognized as a separate asset,
\u00a0
but only if the
reimbursement is certain. The expense related to any
\u00a0
provision is
presented in profit or loss, net of any reimbursement.
\u00a0
Provisions
are reviewed at each balance sheet date and
\u00a0
adjusted to reflect
the current best estimate.
The amount of the provision is the present value of
\u00a0
the risk-
adjusted expenditures expected to be required to settle
\u00a0
the
obligation, determined using the estimated risk-free interest
\u00a0
rate
and a credit margin as the discount rate. Where
\u00a0
discounting is
used, the carrying amount of the provision increases
\u00a0
in each
period to reflect the unwinding of the discount by
\u00a0
the passage of
time. This increase is recognized as other financial
\u00a0
expenses.
Contingent liabilities are not recognized but are
\u00a0
disclosed unless
the possibility of an outflow of resources is remote.
Asset retirement obligations
Provisions for ARO are initially recognized at the
\u00a0
present value of
the estimated future costs determined in accordance
\u00a0
with local
conditions and requirements.
A corresponding ARO asset (included in PP&E) of
\u00a0
an amount
equivalent to the provision is also recognized initially. This is
subsequently depreciated as part of the capital costs
\u00a0
of the
production and transportation facilities.
\u00a0
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 risk-free rate
\u00a0
used has a maturity
date that is expected to coincide with the time
\u00a0
the removal will be
affected and denominated in the same currency as the expected
future expenditures. According to IFRIC 1
Changes in Existing
Decommissioning, Restoration 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
\u00a0
a change in the
discount rate, are added to or deducted from the cost
\u00a0
of the
related asset. Changes in the estimated ARO provisions
\u00a0
impact
the ARO asset in the period in which the estimate
\u00a0
is revised.
\u25a0
Segment reporting
Management monitors the operating results of its operating
segments separately for the purpose of making decisions
\u00a0
about
resource allocation and performance assessment.
\u00a0
Segment
financial performance is evaluated based on the income
statements,
\u00a0
financial position as well as through other
\u00a0
key
performance indicators. For DNO, its operating segments
correspond to its reportable segments. The reportable
\u00a0
segments
provide products or services within a particular economic
environment that are subject to risks and returns
\u00a0
different from
those of components operating in other economic
\u00a0
environments.
The Group has identified its reportable segments
\u00a0
based on the
nature of the risk and return within its business
\u00a0
and by the
geographical location of the Group\u2019s assets and operations.
Transfer pricing between the segments and companies is set
using the arm\u2019s length principle in a manner similar to
transactions with third parties.
\u25a0
Earnings per share
Calculation of basic earnings per share is based
\u00a0
on the net profit
or loss attributable to ordinary shareholders using
\u00a0
the weighted
average number of shares outstanding during the
\u00a0
year after
deduction of the average number of treasury shares
\u00a0
held over the
period. The calculation of diluted earnings per share
\u00a0
is consistent
with the calculation of basic earnings per
\u00a0
share, while giving effect
to all dilutive potential ordinary shares that were
\u00a0
outstanding
during the period.
\u25a0
Related parties
Parties are related if one party has the ability
\u00a0
to directly, jointly or
indirectly control the other party or exercise significant
\u00a0
influence
over the party in making financial and operating
\u00a0
decisions.
Management is also considered to be a related
\u00a0
party.
\u00a0
Transactions between related parties are transfers of resources,
services or obligations, regardless of whether a
\u00a0
price is charged.
All transactions between the related parties are
\u00a0
recorded at
market value.
\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 for
\u00a0
the first time
in 2022 but are not considered to have any material
\u00a0
impact on the
Group\u2019s financial statements.
Basis for preparation
The consolidated financial statements have been
\u00a0
prepared on a
historical cost basis, with the following exemptions:
\u00a0
liabilities
related to share-based payments and investments in
\u00a0
equity
instruments classified as financial investments at fair value
through other comprehensive income are recognized
\u00a0
at fair value.
As permitted by International Accounting Standard
\u00a0
(IAS) 1
Presentation of Financial Statements
\u00a0
and in conformity with
industry practice, the expenses in the consolidated statements
\u00a0
of
comprehensive income are presented as a combination of
\u00a0
nature
and function as this gives the most relevant and
\u00a0
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.
Going concern
As required under the Norwegian Accounting Act,
\u00a0
the Company\u2019s
Board of Directors conducted a review of the
\u00a0
going concern
assumption considering all relevant information available
\u00a0
up to the
date the
DNO ASA
\u00a0
consolidated and Company accounts are
issued and taking into account all available information
\u00a0
about the
future covering at least 12 months from the end of
\u00a0
the reporting
period. The Board of Directors\u2019 review included
\u00a0
in particular
assessment of the Group\u2019s projected cash reserves and
\u00a0
access to
financing arrangements considering its operational
\u00a0
outlook and
work programs, while maintaining appropriate headroom
\u00a0
in
respect of liquidity and financial covenant compliance
\u00a0
throughout
the assessment period.
\u00a0
Following its review, the Board of Directors confirmed, pursuant to
the Norwegian Accounting Act section 3-3a, that the
\u00a0
requirements
of the going concern assumption are met and
\u00a0
that these financial
statements have been prepared on that basis.
The consolidated financial statements have been
\u00a0
prepared on a
historical cost basis, with the following exemptions:
\u00a0
liabilities
related to share-based payments and investments in
\u00a0
equity
instruments classified as financial investments at fair value
through other comprehensive income are recognized
\u00a0
at fair value.
As permitted by International Accounting Standard
\u00a0
(IAS) 1
Presentation of Financial Statements
\u00a0
and in conformity with
industry practice, the expenses in the consolidated statements
\u00a0
of
comprehensive income are presented as a combination of
\u00a0
nature
and function as this gives the most relevant and
\u00a0
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.
Going concern
As required under the Norwegian Accounting Act,
\u00a0
the Company\u2019s
Board of Directors conducted a review of the
\u00a0
going concern
assumption considering all relevant information available
\u00a0
up to the
date the
DNO ASA
\u00a0
consolidated and Company accounts are
issued and taking into account all available information
\u00a0
about the
future covering at least 12 months from the end of
\u00a0
the reporting
period. The Board of Directors\u2019 review included
\u00a0
in particular
assessment of the Group\u2019s projected cash reserves and
\u00a0
access to
financing arrangements considering its operational
\u00a0
outlook and
work programs, while maintaining appropriate headroom
\u00a0
in
respect of liquidity and financial covenant compliance
\u00a0
throughout
the assessment period.
\u00a0
Following its review, the Board of Directors confirmed, pursuant to
the Norwegian Accounting Act section 3-3a, that the
\u00a0
requirements
of the going concern assumption are met and
\u00a0
that these financial
statements have been prepared on that basis.
Significant accounting estimates and assumptions
The preparation of the Group\u2019s financial statements requires
management to make judgments, estimates and assumptions
\u00a0
that
affect the reported amounts of revenues and expenses, assets
and liabilities, and the accompanying disclosures, and
\u00a0
the
disclosure of contingent liabilities at the reporting
\u00a0
date. Estimates
and assumptions are based on management\u2019s best knowledge
and historical experience and various other factors
\u00a0
that are
believed to be reasonable under the circumstances. Uncertainty
about these estimates and assumptions could
\u00a0
result in outcomes
that require a material adjustment to the carrying
\u00a0
amount of
assets or liabilities affected in future periods.
\u00a0
The key assumptions concerning the future and other
\u00a0
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 below. The Group based its assumptions and estimates
on parameters available when the Group financial
\u00a0
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
for the Group are:
\u00a0
Risks associated with operating in Kurdistan;
\u2022
Reserves and resources estimates;
\u2022
Contingencies, provisions and litigations;
\u2022
Impairment/reversal of impairment of oil and gas assets;
\u2022
Impairment of technical goodwill;
\u2022
Measurement of fair values;
\u2022
Acquisition accounting;
\u2022
Accounting for exploration costs;
\u00a0
and
\u2022
Notional corporate income tax/deferred taxation in Kurdistan.
\u00a0
Risks associated with operating in Kurdistan
DNO has interests in two licenses in Kurdistan
\u00a0
through Production
Sharing Contracts (PSCs) and has based its entitlement
calculations on the terms of these PSCs. In 2012,
\u00a0
the Federal
Government of Iraq (FGI) challenged the constitutional
\u00a0
validity of
the Kurdistan Oil and Gas Law No. 27/2007 (KOGL)
\u00a0
and the right
of the KRG to export oil independently of the
\u00a0
FGI.
\u00a0
The Company notes from public reports that on 15
\u00a0
February
2022, the Federal Supreme Court of Iraq (FSCI)
\u00a0
ruled on this
matter along with another related matter dating back
\u00a0
to 2019.
Reportedly, the FSCI found amongst other things that the KOGL
is unconstitutional, that the KRG is to hand over
\u00a0
all oil production
from areas located in the KRI to the FGI and that
\u00a0
the FGI has the
right to pursue the nullity of the oil contracts
\u00a0
concluded by the
KRG. DNO was not a party to the legal proceedings.
\u00a0
DNO has
learned via media reports that on 4 July 2022, a
\u00a0
commercial court
in Baghdad ruled that PSCs signed between the
\u00a0
KRG and four
international oil companies including DNO should
\u00a0
be voided.
Likewise, DNO notes from media reports that on
\u00a0
21 August 2022,
the KRG filed third party objections to the reported
\u00a0
4 July 2022
Baghdad rulings including those understood to concern
\u00a0
DNO.
These cases, along with other similar cases against
\u00a0
international
oil companies, are reported to be still pending.
\u00a0
Furthermore and
importantly, the KRG has issued repeated reassurances that the
PSCs remain valid. The KRG has also initiated legal
\u00a0
proceedings
against FGI in Erbil courts and there have been
\u00a0
several rulings in
Erbil courts affirming the validity of the PSCs. DNO notes
\u00a0
from
public reports that there is increased dialogue between
\u00a0
KRG and
FGI on oil related matters, in particular following
\u00a0
the 27 October
2022 federal parliamentary approval of a new federal
\u00a0
government
led by Prime Minister Mohammed Shia' Sabbar al-Sudani.
\u00a0
Since
then, DNO notes frequent media reports on regular
\u00a0
KRG and FGI
engagement to find a way forward, including by
\u00a0
way of adopting a
new federal oil and gas law. On 13 March 2023, it was announced
that the KRG had received a USD 275.5 million payment
\u00a0
from the
FGI pursuant to an agreement between the parties,
notwithstanding an FSCI ruling that deemed such payments
\u00a0
by a
previous government as \u201cwrong\u201d.
It is unclear how and when the KRG and the
\u00a0
FGI will permanently
address these matters. At present, normal operations
\u00a0
are
maintained at the Tawke and Baeshiqa licenses.
Due to disagreements between the FGI and the
\u00a0
KRG, economic
conditions in Kurdistan and limited oil export channels,
\u00a0
DNO has
historically faced constraints in fully monetizing the oil
\u00a0
it produces
in Kurdistan. There is no guarantee that oil and
\u00a0
gas can be
exported in sufficient quantities or at prices required
\u00a0
to sustain
DNO\u2019s operations and investment plans or that the Group
\u00a0
will
promptly receive its full entitlement payments for the oil
\u00a0
and gas it
delivers for export. Export sales have not always
\u00a0
followed the
PSC terms and there has been uncertainty related
\u00a0
to receipt of
payments but notwithstanding sometimes lengthy delays,
payments have ultimately been received by DNO.
\u00a0
See Note 18 for
more information.
DNO also notes the ongoing arbitration case,
\u00a0
commenced in
2014, by the FGI against the Turkish Government and its state-
owned pipeline operator BOTAS relating to the Iraq-Turkey
Pipeline. It is unclear if a ruling, when
\u00a0
it comes, may have an
impact on future transportation of Kurdish oil in said
\u00a0
pipeline.
Reserves and resources estimate
DNO\u2019s reserves and contingent resources are estimated
\u00a0
and
classified by the Company in accordance with the rules
\u00a0
and
guidelines of the Society of Petroleum Engineers (SPE)
\u00a0
and are in
conformity with requirements from the Oslo Stock Exchange
\u00a0
for
the reporting of reserves and resources.
\u00a0
All estimates of reserves and resources involve uncertainty.
Figures reported in Note 23 are the estimated proven
\u00a0
(1P),
proven and probable (2P) and proven, probable and
\u00a0
possible (3P)
quantities of oil and gas that can be recovered
\u00a0
from a field or
reservoir given the information available at yearend.
Important factors that could cause actual results to
\u00a0
differ from the
estimates include, but are not limited to: technical,
\u00a0
geological and
geotechnical conditions; economic and market conditions;
\u00a0
oil and
gas prices; changes in government regulations; political
development; interest rates; and currency exchange rates.
Specific parameters of uncertainty related to the
\u00a0
field/reservoir
include but are not limited to: reservoir pressure
\u00a0
and porosity;
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
cut-off and remaining reserves, which may change the
\u00a0
timing of
assumed decommissioning activities. Future changes to
estimated reserves can also have a material effect on
depreciation, impairment of oil and gas fields and
\u00a0
operating
results. The Group may also not be able to
\u00a0
commercially develop
its contingent resources that are used in impairment
\u00a0
assessments
or acquisition accounting where the fair value approach
\u00a0
is applied.
Contingencies, provisions and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or
more uncertain future event occurs or fails to occur. The
assessment of the existence and potential quantum of
contingencies inherently involves the exercise of
\u00a0
significant
judgment and the use of estimates regarding
\u00a0
the outcome of
future events. Management uses its judgment to evaluate
\u00a0
certain
provisions and legal disputes in order to ensure
\u00a0
the correct
accounting treatment. This includes the assessment
\u00a0
of future
asset retirement obligations (ARO), any provisions or
\u00a0
contingent
payments.
Asset retirement obligations
The Group has recognized significant provisions relating
\u00a0
to the
decommissioning of oil and gas assets at the end
\u00a0
of the
production period. Obligations associated with decommissioning
assets are recognized at present value of future expenditures
\u00a0
on
the date they incur.
\u00a0
At the initial recognition of an obligation, the
estimated cost is capitalized as property, plant and equipment
(PP&E) and depreciated over the useful life of the asset
\u00a0
(typically
by unit-of-production).
\u00a0
It is difficult to estimate the costs for decommissioning at
\u00a0
initial
recognition as these estimates are based on
\u00a0
currently applicable
laws and regulations,
\u00a0
and technology. Decommissioning activities
will normally take place in the distant future, and
\u00a0
the technology,
regulatory requirements and related costs may change.
\u00a0
The
energy transition may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated
decommissioning provisions.
\u00a0
Based on various scenario analysis
performed by the Company, management does not expect any
reasonable change in the expected timeframe to have
\u00a0
a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost
estimates (i.e., cash flows) remain unchanged. The estimates
cover expected removal concepts based on known technology
and, in the case of offshore decommissioning, estimated costs
\u00a0
of
maritime operations, hiring of heavy-lift barges
\u00a0
and drilling rigs. As
a result, the initial recognition of the liability and
\u00a0
the capitalized
cost associated with decommissioning obligations,
\u00a0
and the
subsequent adjustment of these balance sheet items, involve
\u00a0
the
application of significant judgement. Based on the
\u00a0
described
uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
Impairment/reversal of impairment of oil and gas
\u00a0
assets
DNO has recognized significant investments in development
\u00a0
and
production assets (classified under PP&E) and exploration
\u00a0
and
evaluation assets (classified under intangible assets)
\u00a0
in the
consolidated statements of financial position. Changes
\u00a0
in the
circumstances or expectations of future performance
\u00a0
of an
individual asset or a group of assets may be an
\u00a0
indicator that the
asset is impaired, requiring the carrying amount
\u00a0
to be written
down to its recoverable amount. Management must
\u00a0
determine
whether there are circumstances indicating a possible
\u00a0
impairment
of the Group\u2019s oil and gas assets. The estimation of
\u00a0
the
recoverable amount for the oil and gas assets includes
assessments of expected future cash flows and future
\u00a0
market
conditions, including entitlement production, future
\u00a0
oil and gas
prices, cost profiles, country risk factors (i.e., discount
\u00a0
rate) and
the date of expiration of the licenses.
\u00a0
Impairments,
\u00a0
other than those relating to goodwill, are
\u00a0
reversed if
the conditions for impairment are no longer present.
\u00a0
Evaluating
whether an asset is impaired or if an impairment
\u00a0
should be
reversed requires a high degree of judgment.
Impairment of technical goodwill
\u00a0
Although not an IFRS term, \u201ctechnical goodwill\u201d is
\u00a0
commonly
\u00a0
used
in the oil and gas industry to describe a category
\u00a0
of goodwill
arising as an offsetting amount to deferred tax recognized in
business combinations. DNO has recognized a significant
technical goodwill arising from business combinations.
\u00a0
There are
no specific IFRS guidelines about the allocation of technical
goodwill, and the Group has therefore applied the general
guidelines for allocating goodwill for the purpose
\u00a0
of impairment
testing. In general,
\u00a0
technical goodwill is allocated to a cash-
generating unit (CGU) or group of CGUs that give rise
\u00a0
to the
technical goodwill, while any residual goodwill may
\u00a0
be allocated
across all CGUs based on facts and circumstances
\u00a0
in the
business combination.
\u00a0
Goodwill is tested for impairment annually or more frequently
when there are impairment indicators. Moreover, goodwill is not
depreciated and hence, impairment of technical goodwill
\u00a0
is
expected on a recurring basis, unless there are positive
\u00a0
changes
in underlying assumptions that more than offset the production
from the CGU (or groups
\u00a0
of CGUs).
When performing the impairment test for technical
\u00a0
goodwill,
deferred tax recognized in relation to the acquired
\u00a0
assets in a
business combination reduces the net carrying value prior
\u00a0
to the
impairment charges. When deferred tax from the
\u00a0
initial recognition
decreases, more goodwill is exposed for impairment.
\u00a0
After initial
recognition, depreciation of values calculated in the purchase
price allocations from business combinations will result in
decreased deferred tax liability.
Climate considerations in impairment assessment
Climate change and transition to a lower carbon economy
\u00a0
is
considered in the impairment assessments. In
\u00a0
the context of
assessing the potential impact on the book values
\u00a0
related to the
Group\u2019s oil and gas assets, certain climate considerations
\u00a0
are
factored into the Group\u2019s estimation of cash flows that
\u00a0
are applied
in the calculation of recoverable amount. This includes
\u00a0
factoring in
current legislation in Norway and the UK (e.g.,
\u00a0
environmental
taxes/fees) and estimation of future levels of environmental
\u00a0
taxes.
An energy transition is likely to impact the future oil
\u00a0
and gas
prices which in turn may affect the recoverable amount
\u00a0
of the oil
and gas assets. Indirectly, climate considerations are also
assessed in the forecasting of oil and gas prices
\u00a0
where supply
and demand are considered. A significant reduction in the
Company\u2019s oil and gas price assumptions would result
\u00a0
in
impairments on certain production and development
\u00a0
assets
including intangible assets that are subject to impairment
assessment under IAS 36, but an opposite revision
\u00a0
in the price
assumptions would lead to limited impairment reversals
\u00a0
as most
of the impairments recognized were related to
\u00a0
impairment of
goodwill which cannot be reversed under IFRS.
In the context of testing robustness of the oil
\u00a0
and gas assets
against the scenarios from the International Energy Agency
\u00a0
(IEA),
the Company has applied the Net Zero Emissions
\u00a0
Scenario,
Announced Pledges Scenario and the Stated Policies
\u00a0
Scenario as
published by the IEA. These scenarios are commonly
\u00a0
applied by
peer companies and the Company believes are useful
\u00a0
to
investors and other stakeholders in assessing portfolio
\u00a0
resilience
across companies in the industry. For more details, see Note 9.
\u00a0
Measurement of fair values
Fair value is the price that would be received
\u00a0
to sell an asset or
paid to transfer a liability in an orderly transaction between
\u00a0
market
participants at the measurement date (IFRS 13
Fair Value
Measurement
). The fair value of an asset or a liability
\u00a0
is measured
using the assumptions that market participants would
\u00a0
use when
pricing the asset or liability, including assumptions about risk,
assuming that market participants act in their economic
\u00a0
best
interest. There are situations when the Group is required
\u00a0
to
measure fair values of non-financial assets and liabilities,
\u00a0
for
example when investing in equity instruments, in a business
combination including allocation of purchase price or when
\u00a0
the
Group measures the recoverable amount of an asset
\u00a0
at fair value
less costs to sell in an impairment testing situation.
\u00a0
Fair value measurement of a non-financial asset
\u00a0
takes into
account a market participant\u2019s ability to generate economic
benefits by using the asset in its highest and
\u00a0
best use or by
selling it to another market participant that would
\u00a0
use the asset in
its highest and best use.
\u00a0
The Group uses valuation techniques that are appropriate
\u00a0
in the
circumstances and for which sufficient data are available
\u00a0
to
measure fair value. The fair value of oil and gas assets
\u00a0
is
normally based on discounted cash flow models (income
approach), where the determination of different inputs
\u00a0
in the
model requires significant judgment from management,
\u00a0
as
described in the section above regarding impairment.
Acquisition accounting
The Group applies the acquisition method for transactions
involving business combinations and applies the principles
\u00a0
of the
acquisition method when an interest or an additional
\u00a0
interest is
acquired in a joint operation which constitutes a
\u00a0
business.
Application of the acquisition method may require significant
judgement in, among other matters, determining and measuring
the fair value of the transaction consideration including
\u00a0
contingent
consideration elements, identifying all assets acquired
\u00a0
and
liabilities assumed, establishing their fair values, determining
deferred taxes, and allocating the purchase price
\u00a0
accordingly,
including measurement and allocation of goodwill. The
judgements applied in acquisition accounting may
\u00a0
materially
affect the financial statements both in the transaction period
\u00a0
and
in future periods.
The assets acquired through business combinations are
recognized at fair values and, as such, are sensitive
\u00a0
to adverse
changes in a number of often volatile economic factors,
\u00a0
including
future oil and gas prices and the underlying
\u00a0
performance of the
assets.
Accounting for exploration costs
The Group\u2019s accounting policy is to temporarily capitalize drilling
expenditures related to exploration wells, pending an
\u00a0
evaluation
of potential oil and gas discoveries. If resources
\u00a0
are not
discovered, or if recovery of the resources is not
\u00a0
considered
technically or commercially viable, the costs of the exploration
wells are expensed in the income statement. Decisions
\u00a0
as to
whether an exploration well should remain capitalized
\u00a0
or
expensed during the period may have a material
\u00a0
effect on the
financial results
\u00a0
for the period.
Notional corporate income tax/deferred taxation
\u00a0
in Kurdistan
Under the terms of its PSCs in Kurdistan, DNO
\u00a0
is not required to
pay any corporate income taxes. The share of profit
\u00a0
oil which the
government is entitled to is deemed to include a
\u00a0
portion
representing the notional corporate income tax paid
\u00a0
by the
government on behalf of DNO. Current and deferred
\u00a0
taxation for
accounting purposes arising from such notional corporate
\u00a0
income
tax is not recognized for Kurdistan as it has
\u00a0
not been possible to
measure reliably such notional corporate income tax
\u00a0
paid on
behalf of DNO. This is an accounting presentational matter
\u00a0
and
there is no corporate income tax required
\u00a0
to be paid, see also
section Income taxes and Note 8.
Contingencies, provisions and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or
more uncertain future event occurs or fails to occur. The
assessment of the existence and potential quantum of
contingencies inherently involves the exercise of
\u00a0
significant
judgment and the use of estimates regarding
\u00a0
the outcome of
future events. Management uses its judgment to evaluate
\u00a0
certain
provisions and legal disputes in order to ensure
\u00a0
the correct
accounting treatment. This includes the assessment
\u00a0
of future
asset retirement obligations (ARO), any provisions or
\u00a0
contingent
payments.
Asset retirement obligations
The Group has recognized significant provisions relating
\u00a0
to the
decommissioning of oil and gas assets at the end
\u00a0
of the
production period. Obligations associated with decommissioning
assets are recognized at present value of future expenditures
\u00a0
on
the date they incur.
\u00a0
At the initial recognition of an obligation, the
estimated cost is capitalized as property, plant and equipment
(PP&E) and depreciated over the useful life of the asset
\u00a0
(typically
by unit-of-production).
\u00a0
It is difficult to estimate the costs for decommissioning at
\u00a0
initial
recognition as these estimates are based on
\u00a0
currently applicable
laws and regulations,
\u00a0
and technology. Decommissioning activities
will normally take place in the distant future, and
\u00a0
the technology,
regulatory requirements and related costs may change.
\u00a0
The
energy transition may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated
decommissioning provisions.
\u00a0
Based on various scenario analysis
performed by the Company, management does not expect any
reasonable change in the expected timeframe to have
\u00a0
a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost
estimates (i.e., cash flows) remain unchanged. The estimates
cover expected removal concepts based on known technology
and, in the case of offshore decommissioning, estimated costs
\u00a0
of
maritime operations, hiring of heavy-lift barges
\u00a0
and drilling rigs. As
a result, the initial recognition of the liability and
\u00a0
the capitalized
cost associated with decommissioning obligations,
\u00a0
and the
subsequent adjustment of these balance sheet items, involve
\u00a0
the
application of significant judgement. Based on the
\u00a0
described
uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
Provisions and contingent liabilities
A provision is recognized when the Group has
\u00a0
a present
obligation (legal or constructive) as a result of
\u00a0
a past event, there
is likely that an outflow of resources will be required
\u00a0
to settle the
obligation and a reliable estimate can be made
\u00a0
of the obligation
amount. When the Group expects some or
\u00a0
all of a provision to be
reimbursed, for example under an insurance contract,
\u00a0
the
reimbursement is recognized as a separate asset,
\u00a0
but only if the
reimbursement is certain. The expense related to any
\u00a0
provision is
presented in profit or loss, net of any reimbursement.
\u00a0
Provisions
are reviewed at each balance sheet date and
\u00a0
adjusted to reflect
the current best estimate.
The amount of the provision is the present value of
\u00a0
the risk-
adjusted expenditures expected to be required to settle
\u00a0
the
obligation, determined using the estimated risk-free interest
\u00a0
rate
and a credit margin as the discount rate. Where
\u00a0
discounting is
used, the carrying amount of the provision increases
\u00a0
in each
period to reflect the unwinding of the discount by
\u00a0
the passage of
time. This increase is recognized as other financial
\u00a0
expenses.
Contingent liabilities are not recognized but are
\u00a0
disclosed unless
the possibility of an outflow of resources is remote.
Asset retirement obligations
Provisions for ARO are initially recognized at the
\u00a0
present value of
the estimated future costs determined in accordance
\u00a0
with local
conditions and requirements.
A corresponding ARO asset (included in PP&E) of
\u00a0
an amount
equivalent to the provision is also recognized initially. This is
subsequently depreciated as part of the capital costs
\u00a0
of the
production and transportation facilities.
\u00a0
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 risk-free rate
\u00a0
used has a maturity
date that is expected to coincide with the time
\u00a0
the removal will be
affected and denominated in the same currency as the expected
future expenditures. According to IFRIC 1
Changes in Existing
Decommissioning, Restoration 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
\u00a0
a change in the
discount rate, are added to or deducted from the cost
\u00a0
of the
related asset. Changes in the estimated ARO provisions
\u00a0
impact
the ARO asset in the period in which the estimate
\u00a0
is revised.
Contingencies, provisions and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or
more uncertain future event occurs or fails to occur. The
assessment of the existence and potential quantum of
contingencies inherently involves the exercise of
\u00a0
significant
judgment and the use of estimates regarding
\u00a0
the outcome of
future events. Management uses its judgment to evaluate
\u00a0
certain
provisions and legal disputes in order to ensure
\u00a0
the correct
accounting treatment. This includes the assessment
\u00a0
of future
asset retirement obligations (ARO), any provisions or
\u00a0
contingent
payments.
Asset retirement obligations
The Group has recognized significant provisions relating
\u00a0
to the
decommissioning of oil and gas assets at the end
\u00a0
of the
production period. Obligations associated with decommissioning
assets are recognized at present value of future expenditures
\u00a0
on
the date they incur.
\u00a0
At the initial recognition of an obligation, the
estimated cost is capitalized as property, plant and equipment
(PP&E) and depreciated over the useful life of the asset
\u00a0
(typically
by unit-of-production).
\u00a0
It is difficult to estimate the costs for decommissioning at
\u00a0
initial
recognition as these estimates are based on
\u00a0
currently applicable
laws and regulations,
\u00a0
and technology. Decommissioning activities
will normally take place in the distant future, and
\u00a0
the technology,
regulatory requirements and related costs may change.
\u00a0
The
energy transition may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated
decommissioning provisions.
\u00a0
Based on various scenario analysis
performed by the Company, management does not expect any
reasonable change in the expected timeframe to have
\u00a0
a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost
estimates (i.e., cash flows) remain unchanged. The estimates
cover expected removal concepts based on known technology
and, in the case of offshore decommissioning, estimated costs
\u00a0
of
maritime operations, hiring of heavy-lift barges
\u00a0
and drilling rigs. As
a result, the initial recognition of the liability and
\u00a0
the capitalized
cost associated with decommissioning obligations,
\u00a0
and the
subsequent adjustment of these balance sheet items, involve
\u00a0
the
application of significant judgement. Based on the
\u00a0
described
uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
Provisions and contingent liabilities
A provision is recognized when the Group has
\u00a0
a present
obligation (legal or constructive) as a result of
\u00a0
a past event, there
is likely that an outflow of resources will be required
\u00a0
to settle the
obligation and a reliable estimate can be made
\u00a0
of the obligation
amount. When the Group expects some or
\u00a0
all of a provision to be
reimbursed, for example under an insurance contract,
\u00a0
the
reimbursement is recognized as a separate asset,
\u00a0
but only if the
reimbursement is certain. The expense related to any
\u00a0
provision is
presented in profit or loss, net of any reimbursement.
\u00a0
Provisions
are reviewed at each balance sheet date and
\u00a0
adjusted to reflect
the current best estimate.
The amount of the provision is the present value of
\u00a0
the risk-
adjusted expenditures expected to be required to settle
\u00a0
the
obligation, determined using the estimated risk-free interest
\u00a0
rate
and a credit margin as the discount rate. Where
\u00a0
discounting is
used, the carrying amount of the provision increases
\u00a0
in each
period to reflect the unwinding of the discount by
\u00a0
the passage of
time. This increase is recognized as other financial
\u00a0
expenses.
Contingent liabilities are not recognized but are
\u00a0
disclosed unless
the possibility of an outflow of resources is remote.
Asset retirement obligations
Provisions for ARO are initially recognized at the
\u00a0
present value of
the estimated future costs determined in accordance
\u00a0
with local
conditions and requirements.
A corresponding ARO asset (included in PP&E) of
\u00a0
an amount
equivalent to the provision is also recognized initially. This is
subsequently depreciated as part of the capital costs
\u00a0
of the
production and transportation facilities.
\u00a0
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 risk-free rate
\u00a0
used has a maturity
date that is expected to coincide with the time
\u00a0
the removal will be
affected and denominated in the same currency as the expected
future expenditures. According to IFRIC 1
Changes in Existing
Decommissioning, Restoration 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
\u00a0
a change in the
discount rate, are added to or deducted from the cost
\u00a0
of the
related asset. Changes in the estimated ARO provisions
\u00a0
impact
the ARO asset in the period in which the estimate
\u00a0
is revised.
Asset retirement obligations
The Group has recognized significant provisions relating
\u00a0
to the
decommissioning of oil and gas assets at the end
\u00a0
of the
production period. Obligations associated with decommissioning
assets are recognized at present value of future expenditures
\u00a0
on
the date they incur.
\u00a0
At the initial recognition of an obligation, the
estimated cost is capitalized as property, plant and equipment
(PP&E) and depreciated over the useful life of the asset
\u00a0
(typically
by unit-of-production).
\u00a0
It is difficult to estimate the costs for decommissioning at
\u00a0
initial
recognition as these estimates are based on
\u00a0
currently applicable
laws and regulations,
\u00a0
and technology. Decommissioning activities
will normally take place in the distant future, and
\u00a0
the technology,
regulatory requirements and related costs may change.
\u00a0
The
energy transition may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated
decommissioning provisions.
\u00a0
Based on various scenario analysis
performed by the Company, management does not expect any
reasonable change in the expected timeframe to have
\u00a0
a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost
estimates (i.e., cash flows) remain unchanged. The estimates
cover expected removal concepts based on known technology
and, in the case of offshore decommissioning, estimated costs
\u00a0
of
maritime operations, hiring of heavy-lift barges
\u00a0
and drilling rigs. As
a result, the initial recognition of the liability and
\u00a0
the capitalized
cost associated with decommissioning obligations,
\u00a0
and the
subsequent adjustment of these balance sheet items, involve
\u00a0
the
application of significant judgement. Based on the
\u00a0
described
uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
Asset retirement obligations
The Group has recognized significant provisions relating
\u00a0
to the
decommissioning of oil and gas assets at the end
\u00a0
of the
production period. Obligations associated with decommissioning
assets are recognized at present value of future expenditures
\u00a0
on
the date they incur.
\u00a0
At the initial recognition of an obligation, the
estimated cost is capitalized as property, plant and equipment
(PP&E) and depreciated over the useful life of the asset
\u00a0
(typically
by unit-of-production).
\u00a0
It is difficult to estimate the costs for decommissioning at
\u00a0
initial
recognition as these estimates are based on
\u00a0
currently applicable
laws and regulations,
\u00a0
and technology. Decommissioning activities
will normally take place in the distant future, and
\u00a0
the technology,
regulatory requirements and related costs may change.
\u00a0
The
energy transition may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated
decommissioning provisions.
\u00a0
Based on various scenario analysis
performed by the Company, management does not expect any
reasonable change in the expected timeframe to have
\u00a0
a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost
estimates (i.e., cash flows) remain unchanged. The estimates
cover expected removal concepts based on known technology
and, in the case of offshore decommissioning, estimated costs
\u00a0
of
maritime operations, hiring of heavy-lift barges
\u00a0
and drilling rigs. As
a result, the initial recognition of the liability and
\u00a0
the capitalized
cost associated with decommissioning obligations,
\u00a0
and the
subsequent adjustment of these balance sheet items, involve
\u00a0
the
application of significant judgement. Based on the
\u00a0
described
uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
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 of
\u00a0
its subsidiaries.
The financial results of subsidiaries acquired or
\u00a0
sold during the
year are included in the consolidated financial statements
\u00a0
from
the date when the Company obtains control of the
\u00a0
subsidiary and
up to the date when the Company loses control
\u00a0
of the subsidiary.
The financial statements of the subsidiaries are prepared
\u00a0
for the
same reporting period as the parent company using
\u00a0
consistent
accounting policies. Where necessary, the accounting policies of
the subsidiaries have been adjusted to ensure consistency
\u00a0
with
the policies adopted by DNO. All intercompany balances
\u00a0
and
transactions have been eliminated upon consolidation.
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO
\u00a0
holds a long-term
interest which is jointly controlled by DNO and one
\u00a0
or more other
parties under a contractual arrangement in which
\u00a0
decisions about
the relevant activities require the unanimous
\u00a0
consent of the
parties sharing control. Such joint arrangements are classified
\u00a0
as
either joint operations or joint ventures.
Under IFRS 11
Joint Arrangements
, a joint operation is a joint
arrangement whereby the parties that have joint
\u00a0
control of the
arrangement have rights to the assets and obligations
\u00a0
for the
liabilities. Oil and gas licenses held by the Group
\u00a0
which are within
the scope of IFRS 11 have been classified as 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
A joint venture under IFRS 11, is a joint arrangement whereby the
parties that have joint control of the arrangement
\u00a0
have rights to
the net assets of the arrangement. Those parties are
\u00a0
called joint
venturers. Joint control is the contractually agreed sharing
\u00a0
of
control of an arrangement, which exists only when
\u00a0
decisions
about the relevant activities require unanimous
\u00a0
consent of the
parties sharing control.
\u00a0
The Group\u2019s investments in a joint venture are accounted
\u00a0
for
using the equity method. Under the equity method,
\u00a0
the investment
is initially recognized at cost. The carrying value of
\u00a0
the investment
is adjusted to recognize the Group\u2019s share of the net assets
\u00a0
of the
joint venture since the acquisition date. Goodwill relating
\u00a0
to the
joint venture is included in the carrying amount of
\u00a0
the investment
and is neither amortized nor individually tested
\u00a0
for impairment.
The income statement reflects the Group\u2019s share of the results
\u00a0
of
operations in the joint venture. On acquisition of
\u00a0
the investment,
any difference between the cost of the investment and
\u00a0
the
Group\u2019s share of the net fair value of the investee\u2019s identifiable
assets and liabilities is accounted for as: Goodwill
\u00a0
relating to a
joint venture and is included in the carrying
\u00a0
amount of the
investment; and any excess of the Group\u2019s share of
\u00a0
the net fair
value of the joint venture\u2019s profit or loss in the period
\u00a0
in which the
investment is acquired.
Appropriate adjustments to the Group\u2019s share of the joint
venture\u2019s profit or loss after acquisition are made in
\u00a0
order to
account for, for example, for depreciation of the depreciable
assets (and related deferred tax, if any) based
\u00a0
on their fair values
at the acquisition date.
Any change in OCI of those investees is presented
\u00a0
as part of the
Group\u2019s OCI. In addition, when there has been a change
recognized directly in the equity of the joint venture,
\u00a0
the Group
recognizes its share of any changes, when applicable,
\u00a0
in the
statement of changes in equity.
The aggregate of the Group\u2019s share of profit or loss
\u00a0
of a joint
venture represents profit or loss after tax and non-controlling
interests in the subsidiaries of the joint venture. The
\u00a0
financial
statements of the joint venture are prepared for
\u00a0
the same
reporting period as the Group. When necessary, adjustments are
made to bring the accounting policies in line
\u00a0
with those of the
Group (IFRS).
The impact of reciprocal interests between the
\u00a0
Group and its
investees is eliminated before the Group accounts
\u00a0
for its share;
the Group also reduces its equity and investment
\u00a0
balance by its
effective interest in its own shares.
For those licenses that are not deemed to be joint
\u00a0
arrangements
pursuant to the definition in IFRS 11, either because unanimous
consent is not required among the parties involved,
\u00a0
or no single
group of parties has joint control over the
\u00a0
activity, DNO
recognizes its share of related expenses, assets,
\u00a0
liabilities and
cash flows under the respective items in the Group\u2019s financial
statements in accordance with applicable IFRS
\u00a0
standards. In
determining whether each separate arrangement related
\u00a0
to
DNO\u2019s joint operations is within or outside the scope of
\u00a0
IFRS 11,
DNO considers the terms of relevant license agreements,
governmental concessions and other legal arrangements
impacting how and by whom each arrangement
\u00a0
is controlled.
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 of
\u00a0
its subsidiaries.
The financial results of subsidiaries acquired or
\u00a0
sold during the
year are included in the consolidated financial statements
\u00a0
from
the date when the Company obtains control of the
\u00a0
subsidiary and
up to the date when the Company loses control
\u00a0
of the subsidiary.
The financial statements of the subsidiaries are prepared
\u00a0
for the
same reporting period as the parent company using
\u00a0
consistent
accounting policies. Where necessary, the accounting policies of
the subsidiaries have been adjusted to ensure consistency
\u00a0
with
the policies adopted by DNO. All intercompany balances
\u00a0
and
transactions have been eliminated upon consolidation.
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO
\u00a0
holds a long-term
interest which is jointly controlled by DNO and one
\u00a0
or more other
parties under a contractual arrangement in which
\u00a0
decisions about
the relevant activities require the unanimous
\u00a0
consent of the
parties sharing control. Such joint arrangements are classified
\u00a0
as
either joint operations or joint ventures.
Under IFRS 11
Joint Arrangements
, a joint operation is a joint
arrangement whereby the parties that have joint
\u00a0
control of the
arrangement have rights to the assets and obligations
\u00a0
for the
liabilities. Oil and gas licenses held by the Group
\u00a0
which are within
the scope of IFRS 11 have been classified as 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
A joint venture under IFRS 11, is a joint arrangement whereby the
parties that have joint control of the arrangement
\u00a0
have rights to
the net assets of the arrangement. Those parties are
\u00a0
called joint
venturers. Joint control is the contractually agreed sharing
\u00a0
of
control of an arrangement, which exists only when
\u00a0
decisions
about the relevant activities require unanimous
\u00a0
consent of the
parties sharing control.
\u00a0
The Group\u2019s investments in a joint venture are accounted
\u00a0
for
using the equity method. Under the equity method,
\u00a0
the investment
is initially recognized at cost. The carrying value of
\u00a0
the investment
is adjusted to recognize the Group\u2019s share of the net assets
\u00a0
of the
joint venture since the acquisition date. Goodwill relating
\u00a0
to the
joint venture is included in the carrying amount of
\u00a0
the investment
and is neither amortized nor individually tested
\u00a0
for impairment.
The income statement reflects the Group\u2019s share of the results
\u00a0
of
operations in the joint venture. On acquisition of
\u00a0
the investment,
any difference between the cost of the investment and
\u00a0
the
Group\u2019s share of the net fair value of the investee\u2019s identifiable
assets and liabilities is accounted for as: Goodwill
\u00a0
relating to a
joint venture and is included in the carrying
\u00a0
amount of the
investment; and any excess of the Group\u2019s share of
\u00a0
the net fair
value of the joint venture\u2019s profit or loss in the period
\u00a0
in which the
investment is acquired.
Appropriate adjustments to the Group\u2019s share of the joint
venture\u2019s profit or loss after acquisition are made in
\u00a0
order to
account for, for example, for depreciation of the depreciable
assets (and related deferred tax, if any) based
\u00a0
on their fair values
at the acquisition date.
Any change in OCI of those investees is presented
\u00a0
as part of the
Group\u2019s OCI. In addition, when there has been a change
recognized directly in the equity of the joint venture,
\u00a0
the Group
recognizes its share of any changes, when applicable,
\u00a0
in the
statement of changes in equity.
The aggregate of the Group\u2019s share of profit or loss
\u00a0
of a joint
venture represents profit or loss after tax and non-controlling
interests in the subsidiaries of the joint venture. The
\u00a0
financial
statements of the joint venture are prepared for
\u00a0
the same
reporting period as the Group. When necessary, adjustments are
made to bring the accounting policies in line
\u00a0
with those of the
Group (IFRS).
The impact of reciprocal interests between the
\u00a0
Group and its
investees is eliminated before the Group accounts
\u00a0
for its share;
the Group also reduces its equity and investment
\u00a0
balance by its
effective interest in its own shares.
For those licenses that are not deemed to be joint
\u00a0
arrangements
pursuant to the definition in IFRS 11, either because unanimous
consent is not required among the parties involved,
\u00a0
or no single
group of parties has joint control over the
\u00a0
activity, DNO
recognizes its share of related expenses, assets,
\u00a0
liabilities and
cash flows under the respective items in the Group\u2019s financial
statements in accordance with applicable IFRS
\u00a0
standards. In
determining whether each separate arrangement related
\u00a0
to
DNO\u2019s joint operations is within or outside the scope of
\u00a0
IFRS 11,
DNO considers the terms of relevant license agreements,
governmental concessions and other legal arrangements
impacting how and by whom each arrangement
\u00a0
is controlled.
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO
\u00a0
holds a long-term
interest which is jointly controlled by DNO and one
\u00a0
or more other
parties under a contractual arrangement in which
\u00a0
decisions about
the relevant activities require the unanimous
\u00a0
consent of the
parties sharing control. Such joint arrangements are classified
\u00a0
as
either joint operations or joint ventures.
Under IFRS 11
Joint Arrangements
, a joint operation is a joint
arrangement whereby the parties that have joint
\u00a0
control of the
arrangement have rights to the assets and obligations
\u00a0
for the
liabilities. Oil and gas licenses held by the Group
\u00a0
which are within
the scope of IFRS 11 have been classified as 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
A joint venture under IFRS 11, is a joint arrangement whereby the
parties that have joint control of the arrangement
\u00a0
have rights to
the net assets of the arrangement. Those parties are
\u00a0
called joint
venturers. Joint control is the contractually agreed sharing
\u00a0
of
control of an arrangement, which exists only when
\u00a0
decisions
about the relevant activities require unanimous
\u00a0
consent of the
parties sharing control.
\u00a0
The Group\u2019s investments in a joint venture are accounted
\u00a0
for
using the equity method. Under the equity method,
\u00a0
the investment
is initially recognized at cost. The carrying value of
\u00a0
the investment
is adjusted to recognize the Group\u2019s share of the net assets
\u00a0
of the
joint venture since the acquisition date. Goodwill relating
\u00a0
to the
joint venture is included in the carrying amount of
\u00a0
the investment
and is neither amortized nor individually tested
\u00a0
for impairment.
The income statement reflects the Group\u2019s share of the results
\u00a0
of
operations in the joint venture. On acquisition of
\u00a0
the investment,
any difference between the cost of the investment and
\u00a0
the
Group\u2019s share of the net fair value of the investee\u2019s identifiable
assets and liabilities is accounted for as: Goodwill
\u00a0
relating to a
joint venture and is included in the carrying
\u00a0
amount of the
investment; and any excess of the Group\u2019s share of
\u00a0
the net fair
value of the joint venture\u2019s profit or loss in the period
\u00a0
in which the
investment is acquired.
Appropriate adjustments to the Group\u2019s share of the joint
venture\u2019s profit or loss after acquisition are made in
\u00a0
order to
account for, for example, for depreciation of the depreciable
assets (and related deferred tax, if any) based
\u00a0
on their fair values
at the acquisition date.
Any change in OCI of those investees is presented
\u00a0
as part of the
Group\u2019s OCI. In addition, when there has been a change
recognized directly in the equity of the joint venture,
\u00a0
the Group
recognizes its share of any changes, when applicable,
\u00a0
in the
statement of changes in equity.
The aggregate of the Group\u2019s share of profit or loss
\u00a0
of a joint
venture represents profit or loss after tax and non-controlling
interests in the subsidiaries of the joint venture. The
\u00a0
financial
statements of the joint venture are prepared for
\u00a0
the same
reporting period as the Group. When necessary, adjustments are
made to bring the accounting policies in line
\u00a0
with those of the
Group (IFRS).
The impact of reciprocal interests between the
\u00a0
Group and its
investees is eliminated before the Group accounts
\u00a0
for its share;
the Group also reduces its equity and investment
\u00a0
balance by its
effective interest in its own shares.
For those licenses that are not deemed to be joint
\u00a0
arrangements
pursuant to the definition in IFRS 11, either because unanimous
consent is not required among the parties involved,
\u00a0
or no single
group of parties has joint control over the
\u00a0
activity, DNO
recognizes its share of related expenses, assets,
\u00a0
liabilities and
cash flows under the respective items in the Group\u2019s financial
statements in accordance with applicable IFRS
\u00a0
standards. In
determining whether each separate arrangement related
\u00a0
to
DNO\u2019s joint operations is within or outside the scope of
\u00a0
IFRS 11,
DNO considers the terms of relevant license agreements,
governmental concessions and other legal arrangements
impacting how and by whom each arrangement
\u00a0
is controlled.
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO
\u00a0
holds a long-term
interest which is jointly controlled by DNO and one
\u00a0
or more other
parties under a contractual arrangement in which
\u00a0
decisions about
the relevant activities require the unanimous
\u00a0
consent of the
parties sharing control. Such joint arrangements are classified
\u00a0
as
either joint operations or joint ventures.
Under IFRS 11
Joint Arrangements
, a joint operation is a joint
arrangement whereby the parties that have joint
\u00a0
control of the
arrangement have rights to the assets and obligations
\u00a0
for the
liabilities. Oil and gas licenses held by the Group
\u00a0
which are within
the scope of IFRS 11 have been classified as 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
A joint venture under IFRS 11, is a joint arrangement whereby the
parties that have joint control of the arrangement
\u00a0
have rights to
the net assets of the arrangement. Those parties are
\u00a0
called joint
venturers. Joint control is the contractually agreed sharing
\u00a0
of
control of an arrangement, which exists only when
\u00a0
decisions
about the relevant activities require unanimous
\u00a0
consent of the
parties sharing control.
\u00a0
The Group\u2019s investments in a joint venture are accounted
\u00a0
for
using the equity method. Under the equity method,
\u00a0
the investment
is initially recognized at cost. The carrying value of
\u00a0
the investment
is adjusted to recognize the Group\u2019s share of the net assets
\u00a0
of the
joint venture since the acquisition date. Goodwill relating
\u00a0
to the
joint venture is included in the carrying amount of
\u00a0
the investment
and is neither amortized nor individually tested
\u00a0
for impairment.
The income statement reflects the Group\u2019s share of the results
\u00a0
of
operations in the joint venture. On acquisition of
\u00a0
the investment,
any difference between the cost of the investment and
\u00a0
the
Group\u2019s share of the net fair value of the investee\u2019s identifiable
assets and liabilities is accounted for as: Goodwill
\u00a0
relating to a
joint venture and is included in the carrying
\u00a0
amount of the
investment; and any excess of the Group\u2019s share of
\u00a0
the net fair
value of the joint venture\u2019s profit or loss in the period
\u00a0
in which the
investment is acquired.
Appropriate adjustments to the Group\u2019s share of the joint
venture\u2019s profit or loss after acquisition are made in
\u00a0
order to
account for, for example, for depreciation of the depreciable
assets (and related deferred tax, if any) based
\u00a0
on their fair values
at the acquisition date.
Any change in OCI of those investees is presented
\u00a0
as part of the
Group\u2019s OCI. In addition, when there has been a change
recognized directly in the equity of the joint venture,
\u00a0
the Group
recognizes its share of any changes, when applicable,
\u00a0
in the
statement of changes in equity.
The aggregate of the Group\u2019s share of profit or loss
\u00a0
of a joint
venture represents profit or loss after tax and non-controlling
interests in the subsidiaries of the joint venture. The
\u00a0
financial
statements of the joint venture are prepared for
\u00a0
the same
reporting period as the Group. When necessary, adjustments are
made to bring the accounting policies in line
\u00a0
with those of the
Group (IFRS).
The impact of reciprocal interests between the
\u00a0
Group and its
investees is eliminated before the Group accounts
\u00a0
for its share;
the Group also reduces its equity and investment
\u00a0
balance by its
effective interest in its own shares.
For those licenses that are not deemed to be joint
\u00a0
arrangements
pursuant to the definition in IFRS 11, either because unanimous
consent is not required among the parties involved,
\u00a0
or no single
group of parties has joint control over the
\u00a0
activity, DNO
recognizes its share of related expenses, assets,
\u00a0
liabilities and
cash flows under the respective items in the Group\u2019s financial
statements in accordance with applicable IFRS
\u00a0
standards. In
determining whether each separate arrangement related
\u00a0
to
DNO\u2019s joint operations is within or outside the scope of
\u00a0
IFRS 11,
DNO considers the terms of relevant license agreements,
governmental concessions and other legal arrangements
impacting how and by whom each arrangement
\u00a0
is controlled.
Foreign currency translation and transactions
Functional currency
The consolidated financial statements are presented
\u00a0
in USD,
which is also DNO ASA\u2019s functional currency and presentation
Items included in the financial statements of each
\u00a0
subsidiary are
initially recorded in the subsidiary\u2019s functional currency, i.e., the
currency that best reflects the economic substance of
\u00a0
the
underlying events and circumstances relevant to
\u00a0
that subsidiary.
Transactions and balances
Foreign currency transactions are translated into functional
currency of the Company or subsidiaries using
\u00a0
the exchange
rates prevailing at the dates of the transactions. Financial
\u00a0
assets
and financial liabilities in foreign currencies are translated
\u00a0
into
functional currency at the balance sheet date exchange
\u00a0
rates.
Foreign exchange gains and losses resulting from
\u00a0
the settlement
of such transactions and from the translation of
\u00a0
monetary assets
and liabilities denominated in foreign currencies are
\u00a0
recognized in
profit or loss. Those arising in respect of financial
\u00a0
assets and
liabilities are recorded
\u00a0
on a net basis as a financial item.
Foreign exchange gains or losses relating to
\u00a0
changes in the fair
value of non-monetary financial assets classified as
\u00a0
equity
instruments are recognized directly in other comprehensive
income.
Subsidiaries
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 translation
differences taken directly to other comprehensive income. When
a foreign entity is sold, such translation differences are
recognized in profit or loss as part of the gain
\u00a0
or loss on the sale.
Functional currency
The consolidated financial statements are presented
\u00a0
in USD,
which is also DNO ASA\u2019s functional currency and presentation
Items included in the financial statements of each
\u00a0
subsidiary are
initially recorded in the subsidiary\u2019s functional currency, i.e., the
currency that best reflects the economic substance of
\u00a0
the
underlying events and circumstances relevant to
\u00a0
that subsidiary.
Classification in the statements of financial
position
Current assets and current liabilities include items
\u00a0
due less than
one year from the balance sheet date, and if
\u00a0
longer, items related
to the operating cycle. The current portion of non-current
\u00a0
liabilities
is included under current liabilities. Investments in shares held
\u00a0
for
trading are classified as current assets, while
\u00a0
strategic
investments are classified as non-current assets. Other
\u00a0
assets
and liabilities are classified as non-current assets
\u00a0
and non-current
liabilities.
Fair value
Fair value is the price that would be received to
\u00a0
sell an asset or
be paid to transfer a liability in an orderly transaction
\u00a0
between
market participants at the measurement date. The
\u00a0
fair value of an
asset or a liability is measured using the assumptions
\u00a0
that market
participants would use when pricing the asset
\u00a0
or liability,
assuming that market participants act in their economic
\u00a0
best
interest. All assets and liabilities for which fair
\u00a0
value is measured
or disclosed in the financial statements are categorized
\u00a0
within the
fair value hierarchy as follows:
\u00a0
\u2022
Level 1 - Quoted market prices in active markets
\u00a0
for identical
assets or liabilities
\u00a0
\u2022
Level 2 - Valuation techniques for which the lowest level input
that is significant to the fair value measurement is directly
\u00a0
or
indirectly observable
\u00a0
\u2022
Level 3 - Valuation techniques for which the lowest level input
that is significant to the fair value measurement is
unobservable.
Investments in equity instruments, where available,
\u00a0
are measured
at quoted market prices at the measurement date.
Property, plant and equipment
General
PP&E are recognized at historical cost and adjusted
\u00a0
for
depreciation, depletion and amortization (DD&A) and
\u00a0
impairment
Depreciation of PP&E other than oil and gas assets
\u00a0
are generally
depreciated on a straight-line basis over expected
\u00a0
useful lives,
normally varying from three to seven years. Expected
\u00a0
useful lives
are reviewed at each balance sheet date and, where
\u00a0
there are
changes in estimates, depreciation periods are changed
accordingly.
The carrying amount of the PP&E in the statements
\u00a0
of financial
position represents the cost less accumulated DD&A
\u00a0
and
accumulated impairment charges.
Ordinary repairs and maintenance costs, defined
\u00a0
as day-to-day
servicing costs, are charged to profit or loss during
\u00a0
the financial
period in which they are incurred. The cost of major
\u00a0
repairs and
maintenance is included in the asset\u2019s carrying amount
\u00a0
when it is
likely that the Group will derive future financial benefits
\u00a0
exceeding
the originally assessed standard of performance of
\u00a0
the existing
asset.
Gains and losses on disposals are determined
\u00a0
by comparing the
disposal proceeds with the carrying amount and
\u00a0
are included in
Assets held for sale are reported at the lower
\u00a0
of the carrying
amount and the fair value, less selling costs.
Exploration and development costs
\u00a0
Capitalized exploration expenditures are classified as
\u00a0
intangible
assets and reclassified to tangible assets (i.e.,
\u00a0
PP&E) at the start
of the development. For accounting purposes, an oil
\u00a0
and gas field
is considered to enter the development phase when
\u00a0
the technical
feasibility and commercial viability of extracting oil and gas
\u00a0
from
the field are demonstrable, normally at the time
\u00a0
of concept
selection. All costs of developing commercial oil
\u00a0
and gas fields
are capitalized, including indirect costs. Capitalized development
costs are classified as tangible assets. Pre-development
expenditures up until development project sanction in
\u00a0
general do
not meet the criteria for capitalization and are expensed
\u00a0
as
incurred.
Acquired license rights are recognized as intangible assets
\u00a0
at the
time of acquisition. Acquired license rights related
\u00a0
to fields in the
exploration phase remain as intangible assets when
\u00a0
the related
fields enter the development or production phase.
Oil and gas assets in production
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the
unit-of-production (UoP) method. The rate of depreciation
\u00a0
is equal
to the ratio of oil and gas production for
\u00a0
the period over the
estimated remaining 2P reserves at the beginning of
\u00a0
the period.
The future development expenditures necessary to bring
\u00a0
those
reserves into production are included in the
\u00a0
basis for depreciation
and are estimated by the management based
\u00a0
on current period-
end un-escalated price levels. The reserve basis used
\u00a0
for
depreciation purposes is updated at least once a year. Any
changes in the reserves affecting UoP calculations are reflected
prospectively.
Component cost accounting/decomposition
The Group allocates the amount initially recognized
\u00a0
in respect of
an item of PP&E to its significant parts and depreciates
\u00a0
separately
each such part over its useful life.
\u00a0
Borrowing costs
Interest costs directly attributable to the construction phase
\u00a0
of
PP&E assets are capitalized during the period required
\u00a0
to
complete and prepare the asset for its intended
\u00a0
use. Borrowing
costs consist of interest and other costs that the Group
\u00a0
incurs in
connection with the borrowing of funds.
\u00a0
Other borrowing costs are expensed when incurred.
\u00a0
The
capitalization of borrowing costs is recorded based
\u00a0
on the
average interest rate for the Group in the period.
\u00a0
The capitalized
borrowing costs cannot exceed the actual borrowing
\u00a0
costs in each
period.
Leases
The Group assesses at contract inception whether
\u00a0
a contract is,
or contains, a lease. That is, if the contract
\u00a0
conveys the right to
control the use of an identified asset for a period
\u00a0
of time in
exchange for consideration.
\u00a0
The Group applies a single recognition and measurement
approach for all leases, except for short-term leases (12
\u00a0
months
or less) and leases of low-value assets. Short
\u00a0
term leases and
leases of low value assets have not been reflected
\u00a0
in the balance
sheet but expensed or capitalized as incurred, depending
\u00a0
on the
activity in which the leased asset is used.
At the commencement date of a lease, the Group recognizes
\u00a0
a
liability to make lease payments and an asset representing
\u00a0
the
right to use the underlying asset (right-of-use (RoU)
\u00a0
asset) during
The RoU assets are measured to cost, less any
\u00a0
accumulated
depreciation and impairment losses, and adjusted
\u00a0
for any
remeasurement of lease liabilities. The RoU assets
\u00a0
are
depreciated linearly over the lifetime of the related lease
\u00a0
contract.
Lease liabilities are measured at the present value
\u00a0
of lease
payments to be made over the lease term. In
\u00a0
calculating the
present value of lease payments, the Group
\u00a0
uses the implicit
interest rate and if not readily determinable, its
\u00a0
incremental
borrowing rate at the lease commencement date.
Extension options are included in the lease liability
\u00a0
when, based
on the management\u2019s judgement, it is reasonably certain
\u00a0
that an
extension will be exercised.
When DNO, as the operator of a license, is considered
\u00a0
to have
the primary responsibility for the full lease payments
\u00a0
(e.g., a rig
lease where the lease agreement is entered into DNO\u2019s
\u00a0
name as
the operator of a license at the initial signing),
\u00a0
the lease liability
may be recognized on gross basis, rather than based
\u00a0
on DNO\u2019s
working interest share. DNO then derecognizes a portion
\u00a0
of the
RoU asset corresponding to the non-operator\u2019s
\u00a0
interests in the
license (presented under receivables).
In the consolidated statements of comprehensive
\u00a0
income,
operating lease costs, relating to contracts that contain
\u00a0
a lease,
are replaced by depreciation and interest expense.
In the consolidated cash flow, lease payments related to lease
liabilities recognized in accordance with IFRS 16,
\u00a0
are presented
as cash flow used in financing activities.
The Group\u2019s RoU assets mainly relate to office rent,
\u00a0
rig and
equipment. The Group also leases equipment
\u00a0
with contract terms
of one to three years but has elected to apply
\u00a0
the practical
expedient on low value assets and does not recognize
\u00a0
lease
liabilities or RoU assets and the leases are
\u00a0
instead expensed
when the costs are incurred.
Depreciation of PP&E other than oil and gas assets
\u00a0
are generally
depreciated on a straight-line basis over expected
\u00a0
useful lives,
normally varying from three to seven years. Expected
\u00a0
useful lives
are reviewed at each balance sheet date and, where
\u00a0
there are
changes in estimates, depreciation periods are changed
accordingly.
Ordinary repairs and maintenance costs, defined
\u00a0
as day-to-day
servicing costs, are charged to profit or loss during
\u00a0
the financial
period in which they are incurred. The cost of major
\u00a0
repairs and
maintenance is included in the asset\u2019s carrying amount
\u00a0
when it is
likely that the Group will derive future financial benefits
\u00a0
exceeding
the originally assessed standard of performance of
\u00a0
the existing
asset.
Assets held for sale are reported at the lower
\u00a0
of the carrying
amount and the fair value, less selling costs.
Oil and gas assets in production
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the
unit-of-production (UoP) method. The rate of depreciation
\u00a0
is equal
to the ratio of oil and gas production for
\u00a0
the period over the
estimated remaining 2P reserves at the beginning of
\u00a0
the period.
The future development expenditures necessary to bring
\u00a0
those
reserves into production are included in the
\u00a0
basis for depreciation
and are estimated by the management based
\u00a0
on current period-
end un-escalated price levels. The reserve basis used
\u00a0
for
depreciation purposes is updated at least once a year. Any
changes in the reserves affecting UoP calculations are reflected
prospectively.
Borrowing costs
Interest costs directly attributable to the construction phase
\u00a0
of
PP&E assets are capitalized during the period required
\u00a0
to
complete and prepare the asset for its intended
\u00a0
use. Borrowing
costs consist of interest and other costs that the Group
\u00a0
incurs in
connection with the borrowing of funds.
\u00a0
Other borrowing costs are expensed when incurred.
\u00a0
The
capitalization of borrowing costs is recorded based
\u00a0
on the
average interest rate for the Group in the period.
\u00a0
The capitalized
borrowing costs cannot exceed the actual borrowing
\u00a0
costs in each
period.
Leases
The Group assesses at contract inception whether
\u00a0
a contract is,
or contains, a lease. That is, if the contract
\u00a0
conveys the right to
control the use of an identified asset for a period
\u00a0
of time in
exchange for consideration.
\u00a0
The Group applies a single recognition and measurement
approach for all leases, except for short-term leases (12
\u00a0
months
or less) and leases of low-value assets. Short
\u00a0
term leases and
leases of low value assets have not been reflected
\u00a0
in the balance
sheet but expensed or capitalized as incurred, depending
\u00a0
on the
activity in which the leased asset is used.
At the commencement date of a lease, the Group recognizes
\u00a0
a
liability to make lease payments and an asset representing
\u00a0
the
right to use the underlying asset (right-of-use (RoU)
\u00a0
asset) during
The RoU assets are measured to cost, less any
\u00a0
accumulated
depreciation and impairment losses, and adjusted
\u00a0
for any
remeasurement of lease liabilities. The RoU assets
\u00a0
are
depreciated linearly over the lifetime of the related lease
\u00a0
contract.
Lease liabilities are measured at the present value
\u00a0
of lease
payments to be made over the lease term. In
\u00a0
calculating the
present value of lease payments, the Group
\u00a0
uses the implicit
interest rate and if not readily determinable, its
\u00a0
incremental
borrowing rate at the lease commencement date.
Extension options are included in the lease liability
\u00a0
when, based
on the management\u2019s judgement, it is reasonably certain
\u00a0
that an
extension will be exercised.
When DNO, as the operator of a license, is considered
\u00a0
to have
the primary responsibility for the full lease payments
\u00a0
(e.g., a rig
lease where the lease agreement is entered into DNO\u2019s
\u00a0
name as
the operator of a license at the initial signing),
\u00a0
the lease liability
may be recognized on gross basis, rather than based
\u00a0
on DNO\u2019s
working interest share. DNO then derecognizes a portion
\u00a0
of the
RoU asset corresponding to the non-operator\u2019s
\u00a0
interests in the
license (presented under receivables).
In the consolidated statements of comprehensive
\u00a0
income,
operating lease costs, relating to contracts that contain
\u00a0
a lease,
are replaced by depreciation and interest expense.
In the consolidated cash flow, lease payments related to lease
liabilities recognized in accordance with IFRS 16,
\u00a0
are presented
as cash flow used in financing activities.
The Group\u2019s RoU assets mainly relate to office rent,
\u00a0
rig and
equipment. The Group also leases equipment
\u00a0
with contract terms
of one to three years but has elected to apply
\u00a0
the practical
expedient on low value assets and does not recognize
\u00a0
lease
liabilities or RoU assets and the leases are
\u00a0
instead expensed
when the costs are incurred.
Intangible assets
General
Intangible assets are stated at cost, less accumulated
amortization and accumulated impairment charges.
\u00a0
Intangible
assets include acquisition costs for oil and gas licenses,
expenditures on the exploration for oil and gas
\u00a0
resources,
technical goodwill and other intangible assets. Goodwill
\u00a0
is not
depreciated.
The useful lives of intangible assets are assessed
\u00a0
as either finite
or infinite. Amortization of intangible assets is
\u00a0
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 more often
\u00a0
if indicators
exist.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its
exploration and evaluation assets. All exploration
\u00a0
costs (including
purchase of seismic, geological and geophysical
\u00a0
costs and
general and administrative costs), except for acquisition
\u00a0
costs of
licenses and drilling costs of exploration wells, are
\u00a0
expensed as
incurred. Acquisition costs of licenses and drilling
\u00a0
costs of
exploration wells are temporarily capitalized pending
\u00a0
the
determination of oil and gas resources. These
\u00a0
costs include
directly attributable employee remuneration, materials and
\u00a0
fuel
used, rig costs and payments to contractors. Continued
capitalization of such costs is assessed for impairment
\u00a0
at each
reporting date. The main criterion is that there must
\u00a0
be plans for
future activity in the license or that a development
\u00a0
decision is
expected in the near future. If reserves or resources are
\u00a0
not
found, or if discoveries are assessed not technically
\u00a0
or
commercially recoverable, the costs of exploration wells and
licenses are expensed.
\u25a0
Impairment/reversal of impairment
At the end of each reporting period, the Group
\u00a0
assesses whether
there is any indication that an asset may be
\u00a0
impaired. If an
impairment indicator is concluded to exist, an impairment
\u00a0
test is
Indications of impairment may include a decline
\u00a0
in the long-term
oil and gas price (or short-term oil and gas price
\u00a0
for late-life oil
and gas fields), changes in future investments or significant
downward revision of reserve and resource estimates.
\u00a0
For the
purposes of impairment assessment, assets are grouped
\u00a0
at the
lowest levels for which there are separable identifiable
\u00a0
cash
inflows. For oil and gas assets, a CGU may be individual
\u00a0
oil and
gas fields, or a group of oil and gas
\u00a0
fields 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 asset. The
\u00a0
recoverable
amount is the higher of the asset\u2019s fair value less costs to
\u00a0
sell and
its value in use. Fair value less costs to sell
\u00a0
determined through
either the discounted cash flow method (income approach)
\u00a0
or the
market transactions method (market approach). The value
\u00a0
in use
can only be determined through the discounted cash
\u00a0
flow method.
A previously recognized impairment loss is reversed
\u00a0
through the
income statement if the circumstances that gave rise
\u00a0
to the
impairment no longer exist. It is not reversed
\u00a0
to an amount that
would be higher than if no impairment loss
\u00a0
had been recognized.
After such a reversal, the depreciation charge
\u00a0
is adjusted in future
periods to allocate the asset\u2019s revised carrying amount,
\u00a0
less any
residual value, on a systematic basis over its remaining
\u00a0
useful life.
Technical goodwill
Technical goodwill is tested for impairment annually or more
frequently when there are impairment indicators. Those
\u00a0
indicators
may be specific to an individual CGU or groups
\u00a0
of CGUs to which
the technical goodwill is related. When performing
\u00a0
the impairment
test for technical goodwill, deferred tax recognized
\u00a0
in relation to
the acquired licenses reduces the net carrying value prior
\u00a0
to the
impairment charges.
Impairment is recognized if the recoverable amount
\u00a0
of the CGU
(or groups
\u00a0
of CGUs) to which the technical goodwill is related
\u00a0
is
less than the carrying amount.
\u00a0
Impairment of goodwill cannot be reversed in future
\u00a0
periods.
Intangible assets
General
Intangible assets are stated at cost, less accumulated
amortization and accumulated impairment charges.
\u00a0
Intangible
assets include acquisition costs for oil and gas licenses,
expenditures on the exploration for oil and gas
\u00a0
resources,
technical goodwill and other intangible assets. Goodwill
\u00a0
is not
depreciated.
The useful lives of intangible assets are assessed
\u00a0
as either finite
or infinite. Amortization of intangible assets is
\u00a0
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 more often
\u00a0
if indicators
exist.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its
exploration and evaluation assets. All exploration
\u00a0
costs (including
purchase of seismic, geological and geophysical
\u00a0
costs and
general and administrative costs), except for acquisition
\u00a0
costs of
licenses and drilling costs of exploration wells, are
\u00a0
expensed as
incurred. Acquisition costs of licenses and drilling
\u00a0
costs of
exploration wells are temporarily capitalized pending
\u00a0
the
determination of oil and gas resources. These
\u00a0
costs include
directly attributable employee remuneration, materials and
\u00a0
fuel
used, rig costs and payments to contractors. Continued
capitalization of such costs is assessed for impairment
\u00a0
at each
reporting date. The main criterion is that there must
\u00a0
be plans for
future activity in the license or that a development
\u00a0
decision is
expected in the near future. If reserves or resources are
\u00a0
not
found, or if discoveries are assessed not technically
\u00a0
or
commercially recoverable, the costs of exploration wells and
licenses are expensed.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its
exploration and evaluation assets. All exploration
\u00a0
costs (including
purchase of seismic, geological and geophysical
\u00a0
costs and
general and administrative costs), except for acquisition
\u00a0
costs of
licenses and drilling costs of exploration wells, are
\u00a0
expensed as
incurred. Acquisition costs of licenses and drilling
\u00a0
costs of
exploration wells are temporarily capitalized pending
\u00a0
the
determination of oil and gas resources. These
\u00a0
costs include
directly attributable employee remuneration, materials and
\u00a0
fuel
used, rig costs and payments to contractors. Continued
capitalization of such costs is assessed for impairment
\u00a0
at each
reporting date. The main criterion is that there must
\u00a0
be plans for
future activity in the license or that a development
\u00a0
decision is
expected in the near future. If reserves or resources are
\u00a0
not
found, or if discoveries are assessed not technically
\u00a0
or
commercially recoverable, the costs of exploration wells and
licenses are expensed.
Exploration and development costs
\u00a0
Capitalized exploration expenditures are classified as
\u00a0
intangible
assets and reclassified to tangible assets (i.e.,
\u00a0
PP&E) at the start
of the development. For accounting purposes, an oil
\u00a0
and gas field
is considered to enter the development phase when
\u00a0
the technical
feasibility and commercial viability of extracting oil and gas
\u00a0
from
the field are demonstrable, normally at the time
\u00a0
of concept
selection. All costs of developing commercial oil
\u00a0
and gas fields
are capitalized, including indirect costs. Capitalized development
costs are classified as tangible assets. Pre-development
expenditures up until development project sanction in
\u00a0
general do
not meet the criteria for capitalization and are expensed
\u00a0
as
incurred.
Acquired license rights are recognized as intangible assets
\u00a0
at the
time of acquisition. Acquired license rights related
\u00a0
to fields in the
exploration phase remain as intangible assets when
\u00a0
the related
fields enter the development or production phase.
Impairment/reversal of impairment
At the end of each reporting period, the Group
\u00a0
assesses whether
there is any indication that an asset may be
\u00a0
impaired. If an
impairment indicator is concluded to exist, an impairment
\u00a0
test is
Indications of impairment may include a decline
\u00a0
in the long-term
oil and gas price (or short-term oil and gas price
\u00a0
for late-life oil
and gas fields), changes in future investments or significant
downward revision of reserve and resource estimates.
\u00a0
For the
purposes of impairment assessment, assets are grouped
\u00a0
at the
lowest levels for which there are separable identifiable
\u00a0
cash
inflows. For oil and gas assets, a CGU may be individual
\u00a0
oil and
gas fields, or a group of oil and gas
\u00a0
fields 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 asset. The
\u00a0
recoverable
amount is the higher of the asset\u2019s fair value less costs to
\u00a0
sell and
its value in use. Fair value less costs to sell
\u00a0
determined through
either the discounted cash flow method (income approach)
\u00a0
or the
market transactions method (market approach). The value
\u00a0
in use
can only be determined through the discounted cash
\u00a0
flow method.
A previously recognized impairment loss is reversed
\u00a0
through the
income statement if the circumstances that gave rise
\u00a0
to the
impairment no longer exist. It is not reversed
\u00a0
to an amount that
would be higher than if no impairment loss
\u00a0
had been recognized.
After such a reversal, the depreciation charge
\u00a0
is adjusted in future
periods to allocate the asset\u2019s revised carrying amount,
\u00a0
less any
residual value, on a systematic basis over its remaining
\u00a0
useful life.
Technical goodwill
Technical goodwill is tested for impairment annually or more
frequently when there are impairment indicators. Those
\u00a0
indicators
may be specific to an individual CGU or groups
\u00a0
of CGUs to which
the technical goodwill is related. When performing
\u00a0
the impairment
test for technical goodwill, deferred tax recognized
\u00a0
in relation to
the acquired licenses reduces the net carrying value prior
\u00a0
to the
impairment charges.
Impairment is recognized if the recoverable amount
\u00a0
of the CGU
(or groups
\u00a0
of CGUs) to which the technical goodwill is related
\u00a0
is
less than the carrying amount.
\u00a0
Impairment of goodwill cannot be reversed in future
\u00a0
periods.
Impairment/reversal of impairment
At the end of each reporting period, the Group
\u00a0
assesses whether
there is any indication that an asset may be
\u00a0
impaired. If an
impairment indicator is concluded to exist, an impairment
\u00a0
test is
Indications of impairment may include a decline
\u00a0
in the long-term
oil and gas price (or short-term oil and gas price
\u00a0
for late-life oil
and gas fields), changes in future investments or significant
downward revision of reserve and resource estimates.
\u00a0
For the
purposes of impairment assessment, assets are grouped
\u00a0
at the
lowest levels for which there are separable identifiable
\u00a0
cash
inflows. For oil and gas assets, a CGU may be individual
\u00a0
oil and
gas fields, or a group of oil and gas
\u00a0
fields 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 asset. The
\u00a0
recoverable
amount is the higher of the asset\u2019s fair value less costs to
\u00a0
sell and
its value in use. Fair value less costs to sell
\u00a0
determined through
either the discounted cash flow method (income approach)
\u00a0
or the
market transactions method (market approach). The value
\u00a0
in use
can only be determined through the discounted cash
\u00a0
flow method.
A previously recognized impairment loss is reversed
\u00a0
through the
income statement if the circumstances that gave rise
\u00a0
to the
impairment no longer exist. It is not reversed
\u00a0
to an amount that
would be higher than if no impairment loss
\u00a0
had been recognized.
After such a reversal, the depreciation charge
\u00a0
is adjusted in future
periods to allocate the asset\u2019s revised carrying amount,
\u00a0
less any
residual value, on a systematic basis over its remaining
\u00a0
useful life.
Technical goodwill
Technical goodwill is tested for impairment annually or more
frequently when there are impairment indicators. Those
\u00a0
indicators
may be specific to an individual CGU or groups
\u00a0
of CGUs to which
the technical goodwill is related. When performing
\u00a0
the impairment
test for technical goodwill, deferred tax recognized
\u00a0
in relation to
the acquired licenses reduces the net carrying value prior
\u00a0
to the
impairment charges.
Impairment is recognized if the recoverable amount
\u00a0
of the CGU
(or groups
\u00a0
of CGUs) to which the technical goodwill is related
\u00a0
is
less than the carrying amount.
\u00a0
Impairment of goodwill cannot be reversed in future
\u00a0
periods.
Technical goodwill
Technical goodwill is tested for impairment annually or more
frequently when there are impairment indicators. Those
\u00a0
indicators
may be specific to an individual CGU or groups
\u00a0
of CGUs to which
the technical goodwill is related. When performing
\u00a0
the impairment
test for technical goodwill, deferred tax recognized
\u00a0
in relation to
the acquired licenses reduces the net carrying value prior
\u00a0
to the
impairment charges.
Impairment is recognized if the recoverable amount
\u00a0
of the CGU
(or groups
\u00a0
of CGUs) to which the technical goodwill is related
\u00a0
is
less than the carrying amount.
\u00a0
Impairment of goodwill cannot be reversed in future
\u00a0
periods.
Financial instruments
A financial instrument is any contract that gives
\u00a0
rise to a financial
asset of one entity and a financial liability or
\u00a0
equity instrument of
another entity. Financial instruments are initially recognized at fair
value. After initial recognition the measurement and accounting
treatment depend on the type of instrument and
\u00a0
classification.
Financial assets
Financial assets are classified at initial recognition
\u00a0
and
subsequently measured at:
\u2022
Amortized cost;
\u2022
Fair value through other comprehensive income (FVTOCI); and
\u00a0
\u2022
Fair value through profit or loss (FVTPL).
Financial assets at amortized cost
Financial assets are measured at amortized cost if
\u00a0
both of the
following conditions are met:
\u00a0
\u2022
The financial asset is held within a business
\u00a0
model with the
objective to hold financial assets in order to collect
\u00a0
contractual
\u2022
The contractual terms of the financial asset give
\u00a0
rise on
specified dates to cash flows that are solely payments
\u00a0
of
principal and interest on the principal amount outstanding.
Financial assets at amortized cost are subsequently
\u00a0
measured
using the effective interest rate (EIR) method and are
\u00a0
subject to
impairment. Gains and losses are recognized in profit
\u00a0
or loss
when the asset is derecognized, modified or impaired.
\u00a0
The
Group\u2019s financial assets at amortized cost include trade
\u00a0
and other
receivables.
Financial assets designated at FVTOCI
Upon initial recognition, equity investments can be
\u00a0
irrevocably
classified as equity instruments designated at
\u00a0
FVTOCI. Gains and
losses on these financial assets are not recycled
\u00a0
to profit or loss
at later periods. Equity instruments designated at
\u00a0
FVTOCI are not
subject to an impairment assessment.
Financial assets at FVTPL
Financial assets at FVTPL include financial assets held
\u00a0
for
trading, financial assets designated upon initial recognition
\u00a0
at
FVTPL or financial assets mandatorily required to be
\u00a0
measured at
fair value. Financial assets at FVTPL are carried
\u00a0
in the statements
of financial position at fair value with net changes
\u00a0
in fair value
recognized in profit or loss. Dividends on listed equity
\u00a0
investments
are also recognized as other income in profit
\u00a0
or loss when the
right of payment has been established. The Group
\u00a0
does not have
significant assets designated at FVTPL.
Derecognition of financial assets
A financial asset is derecognized when the Group:
\u2022
No longer has the right to receive cash flows from
\u00a0
the asset;
\u2022
Retains the right to receive cash flows from the asset
\u00a0
but has
assumed an obligation to pay them in full without
\u00a0
material
delay to a third party under a pass-through arrangement;
\u00a0
or
\u2022
Has transferred its rights to receive cash flows from
\u00a0
the asset
and either has transferred substantially all the risks
\u00a0
and
rewards of the asset or has neither transferred
\u00a0
nor retained
substantially all the risks and rewards of the asset
\u00a0
but has
transferred the control of the asset.
Impairment of financial assets
An allowance is recognized for expected credit
\u00a0
losses (ECLs) for
all debt instruments not held at FVTPL. ECLs are
\u00a0
based on the
difference between the contractual cash flows due in accordance
with the contract and all the cash flows that are
\u00a0
expected to be
received, discounted at an approximation of the original
\u00a0
effective
ECLs are recognized in two stages. For credit exposures
\u00a0
with no
significant increase in credit risk since initial recognition,
\u00a0
ECLs are
provided for credit losses that result from default events
\u00a0
that are
possible within the next 12 months. For credit exposures
\u00a0
with
significant increase in credit risk since initial recognition,
\u00a0
a loss
allowance is provided for credit losses expected
\u00a0
over the
remaining life of the exposure, irrespective of
\u00a0
the timing of the
For trade receivables, a simplified approach is applied
\u00a0
in
calculating ECLs. Changes in credit risk are not
\u00a0
tracked but
instead a loss allowance based on lifetime ECLs
\u00a0
at each reporting
date is recognized. Expected credit losses are based
\u00a0
on a
multifactor and holistic analysis and depend on
\u00a0
historical
experience with the customers adjusted for forward-looking
factors specific to the customers and the economic environment.
\u00a0
Financial assets are assessed with regards
\u00a0
to default when
contractual payments are past the established payment
\u00a0
due date
and there is internal or external information indicating
\u00a0
that the
Group is unlikely to receive the outstanding contractual
\u00a0
amounts
in full. A financial asset is written off when there is
\u00a0
no reasonable
expectation of recovering the contractual cash flows.
Further disclosures on impairment of financial assets
\u00a0
are provided
in Note 18.
Financial liabilities
Financial liabilities are classified at initial recognition as
\u00a0
financial
liabilities at FVTPL, loans and borrowings or payables.
\u00a0
All financial liabilities are recognized initially at
\u00a0
fair value and in
the case of loans/borrowings and payables, net
\u00a0
of directly
attributable transaction costs.
\u00a0
The Group\u2019s financial liabilities include trade and other payables
and loans.
The subsequent measurement of financial liabilities depends
\u00a0
on
the classification. No financial liabilities have been designated
\u00a0
at
FVTPL. Interest-bearing loans are after initial recognition
measured at amortized cost using the effective interest
\u00a0
rate
method. Gains and losses are recognized in
\u00a0
profit or loss when
the liabilities are derecognized as well as through
\u00a0
the amortization
process. Amortized cost is calculated by taking into account
\u00a0
any
discount or premium on acquisition and fees or
\u00a0
costs that are an
integral part of the effective interest rate. The amortization
\u00a0
cost is
included as finance expense in the statements of
\u00a0
comprehensive
income. This applies mainly to bond loans,
\u00a0
see Note 15.
\u00a0
A financial liability is derecognized when the obligation
\u00a0
under the
liability is discharged, cancelled or expires. When
\u00a0
an existing
financial liability is replaced by another from the
\u00a0
same lender on
substantially different terms, or the terms of an existing
\u00a0
liability are
substantially modified, such a modification is treated
\u00a0
as a
derecognition of the original liability and a recognition
\u00a0
of a new
liability. The difference in the respective carrying amounts is
recognized in the statements of comprehensive income.
Cash and cash equivalents
Cash and short-term deposits in the statements
\u00a0
of financial
position comprise cash held in banks, cash in
\u00a0
hand and short-
term deposits with an original maturity of three
\u00a0
months or less.
Financial assets
Financial assets are classified at initial recognition
\u00a0
and
subsequently measured at:
\u2022
Amortized cost;
\u2022
Fair value through other comprehensive income (FVTOCI); and
\u00a0
\u2022
Fair value through profit or loss (FVTPL).
Financial assets at amortized cost
Financial assets are measured at amortized cost if
\u00a0
both of the
following conditions are met:
\u00a0
\u2022
The financial asset is held within a business
\u00a0
model with the
objective to hold financial assets in order to collect
\u00a0
contractual
\u2022
The contractual terms of the financial asset give
\u00a0
rise on
specified dates to cash flows that are solely payments
\u00a0
of
principal and interest on the principal amount outstanding.
Financial assets at amortized cost are subsequently
\u00a0
measured
using the effective interest rate (EIR) method and are
\u00a0
subject to
impairment. Gains and losses are recognized in profit
\u00a0
or loss
when the asset is derecognized, modified or impaired.
\u00a0
The
Group\u2019s financial assets at amortized cost include trade
\u00a0
and other
receivables.
Financial assets designated at FVTOCI
Upon initial recognition, equity investments can be
\u00a0
irrevocably
classified as equity instruments designated at
\u00a0
FVTOCI. Gains and
losses on these financial assets are not recycled
\u00a0
to profit or loss
at later periods. Equity instruments designated at
\u00a0
FVTOCI are not
subject to an impairment assessment.
Financial assets at FVTPL
Financial assets at FVTPL include financial assets held
\u00a0
for
trading, financial assets designated upon initial recognition
\u00a0
at
FVTPL or financial assets mandatorily required to be
\u00a0
measured at
fair value. Financial assets at FVTPL are carried
\u00a0
in the statements
of financial position at fair value with net changes
\u00a0
in fair value
recognized in profit or loss. Dividends on listed equity
\u00a0
investments
are also recognized as other income in profit
\u00a0
or loss when the
right of payment has been established. The Group
\u00a0
does not have
significant assets designated at FVTPL.
Derecognition of financial assets
A financial asset is derecognized when the Group:
\u2022
No longer has the right to receive cash flows from
\u00a0
the asset;
\u2022
Retains the right to receive cash flows from the asset
\u00a0
but has
assumed an obligation to pay them in full without
\u00a0
material
delay to a third party under a pass-through arrangement;
\u00a0
or
\u2022
Has transferred its rights to receive cash flows from
\u00a0
the asset
and either has transferred substantially all the risks
\u00a0
and
rewards of the asset or has neither transferred
\u00a0
nor retained
substantially all the risks and rewards of the asset
\u00a0
but has
transferred the control of the asset.
Impairment of financial assets
An allowance is recognized for expected credit
\u00a0
losses (ECLs) for
all debt instruments not held at FVTPL. ECLs are
\u00a0
based on the
difference between the contractual cash flows due in accordance
with the contract and all the cash flows that are
\u00a0
expected to be
received, discounted at an approximation of the original
\u00a0
effective
ECLs are recognized in two stages. For credit exposures
\u00a0
with no
significant increase in credit risk since initial recognition,
\u00a0
ECLs are
provided for credit losses that result from default events
\u00a0
that are
possible within the next 12 months. For credit exposures
\u00a0
with
significant increase in credit risk since initial recognition,
\u00a0
a loss
allowance is provided for credit losses expected
\u00a0
over the
remaining life of the exposure, irrespective of
\u00a0
the timing of the
For trade receivables, a simplified approach is applied
\u00a0
in
calculating ECLs. Changes in credit risk are not
\u00a0
tracked but
instead a loss allowance based on lifetime ECLs
\u00a0
at each reporting
date is recognized. Expected credit losses are based
\u00a0
on a
multifactor and holistic analysis and depend on
\u00a0
historical
experience with the customers adjusted for forward-looking
factors specific to the customers and the economic environment.
\u00a0
Financial assets are assessed with regards
\u00a0
to default when
contractual payments are past the established payment
\u00a0
due date
and there is internal or external information indicating
\u00a0
that the
Group is unlikely to receive the outstanding contractual
\u00a0
amounts
in full. A financial asset is written off when there is
\u00a0
no reasonable
expectation of recovering the contractual cash flows.
Further disclosures on impairment of financial assets
\u00a0
are provided
in Note 18.
Derecognition of financial assets
A financial asset is derecognized when the Group:
\u2022
No longer has the right to receive cash flows from
\u00a0
the asset;
\u2022
Retains the right to receive cash flows from the asset
\u00a0
but has
assumed an obligation to pay them in full without
\u00a0
material
delay to a third party under a pass-through arrangement;
\u00a0
or
\u2022
Has transferred its rights to receive cash flows from
\u00a0
the asset
and either has transferred substantially all the risks
\u00a0
and
rewards of the asset or has neither transferred
\u00a0
nor retained
substantially all the risks and rewards of the asset
\u00a0
but has
transferred the control of the asset.
A financial liability is derecognized when the obligation
\u00a0
under the
liability is discharged, cancelled or expires. When
\u00a0
an existing
financial liability is replaced by another from the
\u00a0
same lender on
substantially different terms, or the terms of an existing
\u00a0
liability are
substantially modified, such a modification is treated
\u00a0
as a
derecognition of the original liability and a recognition
\u00a0
of a new
liability. The difference in the respective carrying amounts is
recognized in the statements of comprehensive income.
Impairment of financial assets
An allowance is recognized for expected credit
\u00a0
losses (ECLs) for
all debt instruments not held at FVTPL. ECLs are
\u00a0
based on the
difference between the contractual cash flows due in accordance
with the contract and all the cash flows that are
\u00a0
expected to be
received, discounted at an approximation of the original
\u00a0
effective
ECLs are recognized in two stages. For credit exposures
\u00a0
with no
significant increase in credit risk since initial recognition,
\u00a0
ECLs are
provided for credit losses that result from default events
\u00a0
that are
possible within the next 12 months. For credit exposures
\u00a0
with
significant increase in credit risk since initial recognition,
\u00a0
a loss
allowance is provided for credit losses expected
\u00a0
over the
remaining life of the exposure, irrespective of
\u00a0
the timing of the
For trade receivables, a simplified approach is applied
\u00a0
in
calculating ECLs. Changes in credit risk are not
\u00a0
tracked but
instead a loss allowance based on lifetime ECLs
\u00a0
at each reporting
date is recognized. Expected credit losses are based
\u00a0
on a
multifactor and holistic analysis and depend on
\u00a0
historical
experience with the customers adjusted for forward-looking
factors specific to the customers and the economic environment.
\u00a0
Financial assets are assessed with regards
\u00a0
to default when
contractual payments are past the established payment
\u00a0
due date
and there is internal or external information indicating
\u00a0
that the
Group is unlikely to receive the outstanding contractual
\u00a0
amounts
in full. A financial asset is written off when there is
\u00a0
no reasonable
expectation of recovering the contractual cash flows.
Further disclosures on impairment of financial assets
\u00a0
are provided
in Note 18.
Impairment of financial assets
An allowance is recognized for expected credit
\u00a0
losses (ECLs) for
all debt instruments not held at FVTPL. ECLs are
\u00a0
based on the
difference between the contractual cash flows due in accordance
with the contract and all the cash flows that are
\u00a0
expected to be
received, discounted at an approximation of the original
\u00a0
effective
ECLs are recognized in two stages. For credit exposures
\u00a0
with no
significant increase in credit risk since initial recognition,
\u00a0
ECLs are
provided for credit losses that result from default events
\u00a0
that are
possible within the next 12 months. For credit exposures
\u00a0
with
significant increase in credit risk since initial recognition,
\u00a0
a loss
allowance is provided for credit losses expected
\u00a0
over the
remaining life of the exposure, irrespective of
\u00a0
the timing of the
For trade receivables, a simplified approach is applied
\u00a0
in
calculating ECLs. Changes in credit risk are not
\u00a0
tracked but
instead a loss allowance based on lifetime ECLs
\u00a0
at each reporting
date is recognized. Expected credit losses are based
\u00a0
on a
multifactor and holistic analysis and depend on
\u00a0
historical
experience with the customers adjusted for forward-looking
factors specific to the customers and the economic environment.
\u00a0
Financial assets are assessed with regards
\u00a0
to default when
contractual payments are past the established payment
\u00a0
due date
and there is internal or external information indicating
\u00a0
that the
Group is unlikely to receive the outstanding contractual
\u00a0
amounts
in full. A financial asset is written off when there is
\u00a0
no reasonable
expectation of recovering the contractual cash flows.
Further disclosures on impairment of financial assets
\u00a0
are provided
in Note 18.
Financial liabilities
Financial liabilities are classified at initial recognition as
\u00a0
financial
liabilities at FVTPL, loans and borrowings or payables.
\u00a0
All financial liabilities are recognized initially at
\u00a0
fair value and in
the case of loans/borrowings and payables, net
\u00a0
of directly
attributable transaction costs.
\u00a0
The Group\u2019s financial liabilities include trade and other payables
and loans.
The subsequent measurement of financial liabilities depends
\u00a0
on
the classification. No financial liabilities have been designated
\u00a0
at
FVTPL. Interest-bearing loans are after initial recognition
measured at amortized cost using the effective interest
\u00a0
rate
method. Gains and losses are recognized in
\u00a0
profit or loss when
the liabilities are derecognized as well as through
\u00a0
the amortization
process. Amortized cost is calculated by taking into account
\u00a0
any
discount or premium on acquisition and fees or
\u00a0
costs that are an
integral part of the effective interest rate. The amortization
\u00a0
cost is
included as finance expense in the statements of
\u00a0
comprehensive
income. This applies mainly to bond loans,
\u00a0
see Note 15.
\u00a0
A financial liability is derecognized when the obligation
\u00a0
under the
liability is discharged, cancelled or expires. When
\u00a0
an existing
financial liability is replaced by another from the
\u00a0
same lender on
substantially different terms, or the terms of an existing
\u00a0
liability are
substantially modified, such a modification is treated
\u00a0
as a
derecognition of the original liability and a recognition
\u00a0
of a new
liability. The difference in the respective carrying amounts is
recognized in the statements of comprehensive income.
Financial liabilities are classified at initial recognition as
\u00a0
financial
liabilities at FVTPL, loans and borrowings or payables.
\u00a0
All financial liabilities are recognized initially at
\u00a0
fair value and in
the case of loans/borrowings and payables, net
\u00a0
of directly
attributable transaction costs.
\u00a0
The Group\u2019s financial liabilities include trade and other payables
and loans.
The subsequent measurement of financial liabilities depends
\u00a0
on
the classification. No financial liabilities have been designated
\u00a0
at
FVTPL. Interest-bearing loans are after initial recognition
measured at amortized cost using the effective interest
\u00a0
rate
method. Gains and losses are recognized in
\u00a0
profit or loss when
the liabilities are derecognized as well as through
\u00a0
the amortization
process. Amortized cost is calculated by taking into account
\u00a0
any
discount or premium on acquisition and fees or
\u00a0
costs that are an
integral part of the effective interest rate. The amortization
\u00a0
cost is
included as finance expense in the statements of
\u00a0
comprehensive
income. This applies mainly to bond loans,
\u00a0
see Note 15.
\u00a0
A financial liability is derecognized when the obligation
\u00a0
under the
liability is discharged, cancelled or expires. When
\u00a0
an existing
financial liability is replaced by another from the
\u00a0
same lender on
substantially different terms, or the terms of an existing
\u00a0
liability are
substantially modified, such a modification is treated
\u00a0
as a
derecognition of the original liability and a recognition
\u00a0
of a new
liability. The difference in the respective carrying amounts is
recognized in the statements of comprehensive income.
Cash and cash equivalents
Cash and short-term deposits in the statements
\u00a0
of financial
position comprise cash held in banks, cash in
\u00a0
hand and short-
term deposits with an original maturity of three
\u00a0
months or less.
Cash and cash equivalents
Cash and short-term deposits in the statements
\u00a0
of financial
position comprise cash held in banks, cash in
\u00a0
hand and short-
term deposits with an original maturity of three
\u00a0
months or less.
Equity
Ordinary shares
Ordinary shares are classified as equity. Costs directly
attributable to the issue of ordinary shares and
\u00a0
share options are
recognized as a reduction of equity, net of any tax effects.
Repurchase of share capital (treasury shares)
When share capital recognized as equity is repurchased,
\u00a0
the
amount of the consideration paid, which includes
\u00a0
directly
attributable costs, is net of any tax effects and is
\u00a0
recognized as a
deduction in equity. Repurchased shares are classified as
treasury shares and are presented as a deduction
\u00a0
from total
equity. When treasury shares are subsequently sold or reissued,
the amount received is recognized as an increase
\u00a0
in equity and
the resulting surplus or deficit of the transaction
\u00a0
is transferred
to/from retained earnings.
Dividend
Liability to pay a dividend is recognized when
\u00a0
the distribution is
authorized by the shareholders. A corresponding amount is
recognized directly in equity.
Repurchase of share capital (treasury shares)
When share capital recognized as equity is repurchased,
\u00a0
the
amount of the consideration paid, which includes
\u00a0
directly
attributable costs, is net of any tax effects and is
\u00a0
recognized as a
deduction in equity. Repurchased shares are classified as
treasury shares and are presented as a deduction
\u00a0
from total
equity. When treasury shares are subsequently sold or reissued,
the amount received is recognized as an increase
\u00a0
in equity and
the resulting surplus or deficit of the transaction
\u00a0
is transferred
to/from retained earnings.
Dividend
Liability to pay a dividend is recognized when
\u00a0
the distribution is
authorized by the shareholders. A corresponding amount is
recognized directly in equity.
Financial income and expenses
Financial income comprises interest income; dividend
\u00a0
income;
gains on the disposal of financial investments; foreign
\u00a0
exchange
gains; changes in the fair value of financial assets through
\u00a0
profit
or loss; and other financial income. Interest income
\u00a0
is recognized
as it accrues in profit or loss using the effective interest
\u00a0
method.
Dividend income is recognized in the profit or
\u00a0
loss on the date that
the Group\u2019s right to receive payment is established,
\u00a0
which in the
case of quoted securities is the ex-dividend date.
Financial expenses comprise interest expenses on
\u00a0
loans;
unwinding of the discount on provisions; changes
\u00a0
in the fair value
of financial assets measured at FVTPL; impairment
\u00a0
losses
recognized on financial assets; foreign exchange
\u00a0
losses;
\u00a0
losses
on financial assets recognized in the profit or
\u00a0
loss; and other
financial expenses.
Foreign exchange gains or losses from financial
\u00a0
instruments are
reported as financial income or financial expenses.
Financial income comprises interest income; dividend
\u00a0
income;
gains on the disposal of financial investments; foreign
\u00a0
exchange
gains; changes in the fair value of financial assets through
\u00a0
profit
or loss; and other financial income. Interest income
\u00a0
is recognized
as it accrues in profit or loss using the effective interest
\u00a0
method.
Dividend income is recognized in the profit or
\u00a0
loss on the date that
the Group\u2019s right to receive payment is established,
\u00a0
which in the
case of quoted securities is the ex-dividend date.
Financial expenses comprise interest expenses on
\u00a0
loans;
unwinding of the discount on provisions; changes
\u00a0
in the fair value
of financial assets measured at FVTPL; impairment
\u00a0
losses
recognized on financial assets; foreign exchange
\u00a0
losses;
\u00a0
losses
on financial assets recognized in the profit or
\u00a0
loss; and other
financial expenses.
Financial expenses comprise interest expenses on
\u00a0
loans;
unwinding of the discount on provisions; changes
\u00a0
in the fair value
of financial assets measured at FVTPL; impairment
\u00a0
losses
recognized on financial assets; foreign exchange
\u00a0
losses;
\u00a0
losses
on financial assets recognized in the profit or
\u00a0
loss; and other
financial expenses.
Inventories
Inventories are valued at the lower of cost and
\u00a0
net realizable
value. Cost is determined by the first-in, first-out (FIFO)
\u00a0
method.
Net realizable value is the estimated selling price
\u00a0
in the ordinary
course of business, less the estimated costs of
\u00a0
completion and
estimated selling expenses.
Revenue recognition
Revenues presented in the consolidated statements 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 and gas,
\u00a0
which normally will be
when title passes at the point of delivery.
A liability (overlift) arises when the Group sells
\u00a0
more than its
share of the oil and gas production. Similarly, an asset (underlift)
arises when the sale is less than the Group\u2019s share
\u00a0
of the oil and
gas production.
In general, the overlift/underlift balances are valued
\u00a0
at production
cost including depreciation (the sales method). The movements
\u00a0
in
overlift/underlift are presented as an adjustment to
Cost of goods
sold
Tariff income from processing of oil and gas in the North Sea is
recognized as earned.
\u00a0
Other revenues are recognized when the goods
\u00a0
or services are
delivered and risk and control are transferred.
Revenue recognition in Kurdistan
DNO generates revenues in Kurdistan through the sale
\u00a0
of oil
produced from the Tawke license which is exported by pipeline
through Turkey. The title is considered to have passed on delivery
of oil to the export pipeline at Fish Khabur. In addition, pursuant
\u00a0
to
a receivables settlement agreement with the KRG
\u00a0
in August 2017,
DNO was entitled to production overrides (override)
\u00a0
representing
three percent of gross Tawke license revenues until 31 July 2022.
The Group recognizes revenues in Kurdistan in line
\u00a0
with the
invoiced oil sales and overrides following monthly
\u00a0
deliveries to the
KRG. The PSCs held by the Group are considered
\u00a0
to be within
the scope of the standard and sale of oil and gas
\u00a0
to customers is
recognized as
Revenue from contracts with customers
. Based on
business practice, the KRG is responsible for exporting
\u00a0
the oil
produced in Kurdistan and it is assessed that
\u00a0
DNO has a
customer relationship with the KRG. It is considered
\u00a0
that the
contracts with customers contain a single performance
\u00a0
obligation
which is considered to be delivery of produced oil
\u00a0
and gas to the
customer.
The price for oil deliveries to the KRG is
\u00a0
based on Brent prices
with adjustments for oil quality and transportation
\u00a0
fees.
Production Sharing Contracts (PSC)
A PSC is an agreement between a contractor
\u00a0
and a host
government, whereby the contractor bears all of
\u00a0
the risks and
costs of exploration, and if successful, costs of development
\u00a0
and
production in return for a stipulated share of production
\u00a0
from the
discovery.
The contractor recovers the sum of its investment
\u00a0
and operating
costs from a percentage of production (cost oil).
\u00a0
In addition, the
contractor is entitled to receive a share of production
\u00a0
in excess of
cost oil (profit oil). The sum of cost oil attributable
\u00a0
to the
contractor\u2019s share of costs and the share of
\u00a0
profit oil represents
the contractor\u2019s entitlement under a PSC.
\u00a0
The sum of royalties
and the government\u2019s share of profit oil, including that of a
government-controlled enterprise, represents the government
take under a PSC.
DNO presents its operations governed by PSCs according
\u00a0
to the
sales method and only recognizes its sales as
\u00a0
revenue after
deduction of government take.
Income taxes
Tax income/expense consists of taxes receivable/payable and
changes in deferred taxes.
\u00a0
Taxes receivable/payable are based
on the amounts receivable from or payable to the tax
\u00a0
authorities.
Deferred tax liability is calculated on all taxable temporary
differences unless there is a recognition exception. A deferred
\u00a0
tax
asset is recognized only to the extent that it
\u00a0
is probable that the
future taxable income will be available against which
\u00a0
the asset
can be utilized. Unrecognized deferred tax assets
\u00a0
are re-
assessed at each reporting date and are
\u00a0
recognized to the extent
that it has become probable that future taxable profits
\u00a0
will allow
the deferred tax asset to be recovered.
Deferred tax assets and deferred tax liabilities
\u00a0
are recognized
irrespective of when the differences are reversed.
\u00a0
They are
recognized at their nominal value and classified as non-current
assets/liabilities in the statements of financial position.
\u00a0
Deferred
tax assets and deferred tax liabilities are offset
\u00a0
in the statements
of financial position if there is a legal right
\u00a0
to settle current tax
amounts on a net basis and the deferred tax
\u00a0
amounts are levied
by the same taxing authority on the same entity or
\u00a0
different
entities that intend to realize the asset and settle the
\u00a0
liability at the
same time.
Tax payable and deferred tax are recognized directly in the equity
to the extent that they relate to items charged
\u00a0
directly to equity.
\u00a0
For treatment of tax in relation to business combinations,
\u00a0
see the
Business combinations section.
\u00a0
DNO\u2019s PSCs provide that the corporate income tax to which the
contractor is subject is deemed to have been paid to
\u00a0
the
government as part of the payment of profit
\u00a0
oil to the government
or its representatives. For accounting purposes, if
\u00a0
such notional
income tax is to be classified as income tax in
\u00a0
accordance with
IAS 12
Income Taxes
, the Group would present this as an income
tax expense with a corresponding increase in revenues.
Furthermore, it would be assessed whether any
\u00a0
deferred tax
asset or liability is required to be recognized
\u00a0
equal to the
difference between book values and the tax values of
\u00a0
the
qualifying assets and liabilities, multiplied by the applicable
\u00a0
tax
rate.
Income taxes
Tax income/expense consists of taxes receivable/payable and
changes in deferred taxes.
\u00a0
Taxes receivable/payable are based
on the amounts receivable from or payable to the tax
\u00a0
authorities.
Deferred tax liability is calculated on all taxable temporary
differences unless there is a recognition exception. A deferred
\u00a0
tax
asset is recognized only to the extent that it
\u00a0
is probable that the
future taxable income will be available against which
\u00a0
the asset
can be utilized. Unrecognized deferred tax assets
\u00a0
are re-
assessed at each reporting date and are
\u00a0
recognized to the extent
that it has become probable that future taxable profits
\u00a0
will allow
the deferred tax asset to be recovered.
Deferred tax assets and deferred tax liabilities
\u00a0
are recognized
irrespective of when the differences are reversed.
\u00a0
They are
recognized at their nominal value and classified as non-current
assets/liabilities in the statements of financial position.
\u00a0
Deferred
tax assets and deferred tax liabilities are offset
\u00a0
in the statements
of financial position if there is a legal right
\u00a0
to settle current tax
amounts on a net basis and the deferred tax
\u00a0
amounts are levied
by the same taxing authority on the same entity or
\u00a0
different
entities that intend to realize the asset and settle the
\u00a0
liability at the
same time.
Tax payable and deferred tax are recognized directly in the equity
to the extent that they relate to items charged
\u00a0
directly to equity.
\u00a0
For treatment of tax in relation to business combinations,
\u00a0
see the
Business combinations section.
\u00a0
DNO\u2019s PSCs provide that the corporate income tax to which the
contractor is subject is deemed to have been paid to
\u00a0
the
government as part of the payment of profit
\u00a0
oil to the government
or its representatives. For accounting purposes, if
\u00a0
such notional
income tax is to be classified as income tax in
\u00a0
accordance with
IAS 12
Income Taxes
, the Group would present this as an income
tax expense with a corresponding increase in revenues.
Furthermore, it would be assessed whether any
\u00a0
deferred tax
asset or liability is required to be recognized
\u00a0
equal to the
difference between book values and the tax values of
\u00a0
the
qualifying assets and liabilities, multiplied by the applicable
\u00a0
tax
rate.
Notional corporate income tax/deferred taxation
\u00a0
in Kurdistan
Under the terms of its PSCs in Kurdistan, DNO
\u00a0
is not required to
pay any corporate income taxes. The share of profit
\u00a0
oil which the
government is entitled to is deemed to include a
\u00a0
portion
representing the notional corporate income tax paid
\u00a0
by the
government on behalf of DNO. Current and deferred
\u00a0
taxation for
accounting purposes arising from such notional corporate
\u00a0
income
tax is not recognized for Kurdistan as it has
\u00a0
not been possible to
measure reliably such notional corporate income tax
\u00a0
paid on
behalf of DNO. This is an accounting presentational matter
\u00a0
and
there is no corporate income tax required
\u00a0
to be paid, see also
section Income taxes and Note 8.
DNO\u2019s PSCs provide that the corporate income tax to which the
contractor is subject is deemed to have been paid to
\u00a0
the
government as part of the payment of profit
\u00a0
oil to the government
or its representatives. For accounting purposes, if
\u00a0
such notional
income tax is to be classified as income tax in
\u00a0
accordance with
IAS 12
Income Taxes
, the Group would present this as an income
tax expense with a corresponding increase in revenues.
Furthermore, it would be assessed whether any
\u00a0
deferred tax
asset or liability is required to be recognized
\u00a0
equal to the
difference between book values and the tax values of
\u00a0
the
qualifying assets and liabilities, multiplied by the applicable
\u00a0
tax
rate.
Business combinations
In accordance with IFRS 3
Business Combinations
, an acquisition
is considered a business combination, when the acquired
\u00a0
asset or
groups of assets constitute a business (i.e., an integrated
\u00a0
set of
operations and assets conducted and managed for
\u00a0
the purpose of
providing a return to the investors).
Acquired businesses are included in the financial statements
\u00a0
from
the transaction date. The transaction date is defined
\u00a0
as the date
on which the Group achieves control over the
\u00a0
financial and
operating assets. This date may differ from the actual
\u00a0
date on
which the assets are transferred.
For accounting purposes, the acquisition method is used
\u00a0
in
connection with the purchase of businesses. Acquisition
\u00a0
cost
equals the fair value of the assets used as
\u00a0
consideration,
including contingent consideration, equity instruments issued
\u00a0
and
liabilities assumed in connection with the transfer of
\u00a0
control.
Acquisition cost is measured against the fair value
\u00a0
of the acquired
assets and assumed liabilities. Identifiable intangible
\u00a0
assets are
included in connection with acquisitions if they
\u00a0
can be separated
from other assets or meet the legal contractual
\u00a0
criteria. If the
acquisition cost at the time of the acquisition exceeds
\u00a0
the fair
value of the acquired net assets (when
\u00a0
the acquiring entity
achieves control of the transferring entity), goodwill arises.
If the fair value of the acquired net assets exceeds
\u00a0
the acquisition
cost on the acquisition date, the excess amount
\u00a0
is taken to profit
or loss immediately.
Goodwill is allocated to the CGUs or groups of
\u00a0
CGUs that are
expected to benefit from synergy effects of the acquisition.
\u00a0
The
allocation of goodwill may vary depending on the
\u00a0
basis of its initial
recognition.
The goodwill that is recognized by the Group is related
\u00a0
to
technical goodwill and is recognized due to the requirement
\u00a0
to
recognize deferred tax for the difference between the assigned
fair values and the related tax base. The fair values of
\u00a0
the Group\u2019s
licenses in the North Sea are based on cash flows
\u00a0
after tax.
\u00a0
This
is because these licenses are sold only on an after-tax
\u00a0
basis. The
purchaser is therefore not entitled to a tax deduction
\u00a0
for the
consideration paid above the seller\u2019s tax values.
\u00a0
In accordance
with IAS 12, a provision is made for deferred
\u00a0
tax corresponding to
the tax rate multiplied by the difference between the fair
\u00a0
values of
the acquired assets and the transferred tax depreciation
\u00a0
basis.
\u00a0
The offsetting entry to this deferred tax is goodwill. Hence,
goodwill arises as a technical effect of deferred
\u00a0
tax. Technical
goodwill is tested for impairment separately for each
\u00a0
CGU which
gives rise to the technical goodwill. A CGU
\u00a0
may be individual oil
fields, or a group of oil fields that are
\u00a0
connected to the same
infrastructure/production facilities, or a license.
The estimation of fair value may be adjusted up
\u00a0
to 12 months
after the acquisition date if new information emerges
\u00a0
about facts
and circumstances that existed at the time of
\u00a0
the takeover and
which, had they been known, would have affected the
\u00a0
calculation
of the amounts that were included from that date.
Acquisition-related costs, except costs to issue debt or
\u00a0
equity
securities, are expensed as incurred. Taxes payable and deferred
taxes are recognized directly in the equity to
\u00a0
the extent that they
relate to items charged directly to the equity.
\u25a0
License acquisitions, farm-in/out and license
swaps
License acquisitions
\u00a0
For acquisition of oil and gas licenses, individual
\u00a0
assessment is
made whether the acquisition should be treated
\u00a0
as a business
combination or as an asset purchase. The
\u00a0
conclusion may
materially affect the financial statements both in the transaction
period and in future periods. 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.
Farm-in and farm-out
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. The farmee capitalizes or expenses
\u00a0
its costs as
incurred according to the accounting method it is
\u00a0
using. There are
no accruals for future commitments in farm-in/farm-out
agreements in the exploration and evaluation phase
\u00a0
and no profit
or loss is recognized by the farmor. In the development or
production phase, a farm-in/farm-out agreement will be
\u00a0
treated as
a transaction recorded at fair value as represented
\u00a0
by the costs
carried by the farmee. Any gain or loss arising from
\u00a0
the farm-
in/farm-out is recognized in the statements of comprehensive
License swaps
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
the fair value of
the asset divested,
\u00a0
can be reliably measured. In the exploration
phase, the Group normally recognizes license swaps based
\u00a0
on
historical cost basis. If the transaction is determined
\u00a0
to be a
business combination, the requirements of IFRS 3
\u00a0
apply.
Business combinations
In accordance with IFRS 3
Business Combinations
, an acquisition
is considered a business combination, when the acquired
\u00a0
asset or
groups of assets constitute a business (i.e., an integrated
\u00a0
set of
operations and assets conducted and managed for
\u00a0
the purpose of
providing a return to the investors).
Acquired businesses are included in the financial statements
\u00a0
from
the transaction date. The transaction date is defined
\u00a0
as the date
on which the Group achieves control over the
\u00a0
financial and
operating assets. This date may differ from the actual
\u00a0
date on
which the assets are transferred.
For accounting purposes, the acquisition method is used
\u00a0
in
connection with the purchase of businesses. Acquisition
\u00a0
cost
equals the fair value of the assets used as
\u00a0
consideration,
including contingent consideration, equity instruments issued
\u00a0
and
liabilities assumed in connection with the transfer of
\u00a0
control.
Acquisition cost is measured against the fair value
\u00a0
of the acquired
assets and assumed liabilities. Identifiable intangible
\u00a0
assets are
included in connection with acquisitions if they
\u00a0
can be separated
from other assets or meet the legal contractual
\u00a0
criteria. If the
acquisition cost at the time of the acquisition exceeds
\u00a0
the fair
value of the acquired net assets (when
\u00a0
the acquiring entity
achieves control of the transferring entity), goodwill arises.
If the fair value of the acquired net assets exceeds
\u00a0
the acquisition
cost on the acquisition date, the excess amount
\u00a0
is taken to profit
or loss immediately.
Goodwill is allocated to the CGUs or groups of
\u00a0
CGUs that are
expected to benefit from synergy effects of the acquisition.
\u00a0
The
allocation of goodwill may vary depending on the
\u00a0
basis of its initial
recognition.
The goodwill that is recognized by the Group is related
\u00a0
to
technical goodwill and is recognized due to the requirement
\u00a0
to
recognize deferred tax for the difference between the assigned
fair values and the related tax base. The fair values of
\u00a0
the Group\u2019s
licenses in the North Sea are based on cash flows
\u00a0
after tax.
\u00a0
This
is because these licenses are sold only on an after-tax
\u00a0
basis. The
purchaser is therefore not entitled to a tax deduction
\u00a0
for the
consideration paid above the seller\u2019s tax values.
\u00a0
In accordance
with IAS 12, a provision is made for deferred
\u00a0
tax corresponding to
the tax rate multiplied by the difference between the fair
\u00a0
values of
the acquired assets and the transferred tax depreciation
\u00a0
basis.
\u00a0
The offsetting entry to this deferred tax is goodwill. Hence,
goodwill arises as a technical effect of deferred
\u00a0
tax. Technical
goodwill is tested for impairment separately for each
\u00a0
CGU which
gives rise to the technical goodwill. A CGU
\u00a0
may be individual oil
fields, or a group of oil fields that are
\u00a0
connected to the same
infrastructure/production facilities, or a license.
The estimation of fair value may be adjusted up
\u00a0
to 12 months
after the acquisition date if new information emerges
\u00a0
about facts
and circumstances that existed at the time of
\u00a0
the takeover and
which, had they been known, would have affected the
\u00a0
calculation
of the amounts that were included from that date.
Acquisition-related costs, except costs to issue debt or
\u00a0
equity
securities, are expensed as incurred. Taxes payable and deferred
taxes are recognized directly in the equity to
\u00a0
the extent that they
relate to items charged directly to the equity.
Acquisition accounting
The Group applies the acquisition method for transactions
involving business combinations and applies the principles
\u00a0
of the
acquisition method when an interest or an additional
\u00a0
interest is
acquired in a joint operation which constitutes a
\u00a0
business.
Application of the acquisition method may require significant
judgement in, among other matters, determining and measuring
the fair value of the transaction consideration including
\u00a0
contingent
consideration elements, identifying all assets acquired
\u00a0
and
liabilities assumed, establishing their fair values, determining
deferred taxes, and allocating the purchase price
\u00a0
accordingly,
including measurement and allocation of goodwill. The
judgements applied in acquisition accounting may
\u00a0
materially
affect the financial statements both in the transaction period
\u00a0
and
in future periods.
The assets acquired through business combinations are
recognized at fair values and, as such, are sensitive
\u00a0
to adverse
changes in a number of often volatile economic factors,
\u00a0
including
future oil and gas prices and the underlying
\u00a0
performance of the
assets.
Employee benefits
Pensions
The Group\u2019s pension obligations in Norway are limited
\u00a0
to certain
defined contribution plans which are paid to pension
\u00a0
insurance
plans and charged to profit or loss in the period
\u00a0
in which they are
incurred. Once the contributions are paid there are no
\u00a0
further
obligations.
Share-based payments
Cash-settled share-based payments are recognized in
\u00a0
the income
statement as expenses during the vesting period and
\u00a0
as a liability.
The liability is measured at fair value and revaluated
\u00a0
using the
Black & Scholes pricing model at each balance
\u00a0
sheet date and at
the date of settlement, with any change in the fair
\u00a0
value
recognized in the income statement for the period.
Share-based payments
Cash-settled share-based payments are recognized in
\u00a0
the income
statement as expenses during the vesting period and
\u00a0
as a liability.
The liability is measured at fair value and revaluated
\u00a0
using the
Black & Scholes pricing model at each balance
\u00a0
sheet date and at
the date of settlement, with any change in the fair
\u00a0
value
recognized in the income statement for the period.
Segment reporting
Management monitors the operating results of its operating
segments separately for the purpose of making decisions
\u00a0
about
resource allocation and performance assessment.
\u00a0
Segment
financial performance is evaluated based on the income
statements,
\u00a0
financial position as well as through other
\u00a0
key
performance indicators. For DNO, its operating segments
correspond to its reportable segments. The reportable
\u00a0
segments
provide products or services within a particular economic
environment that are subject to risks and returns
\u00a0
different from
those of components operating in other economic
\u00a0
environments.
The Group has identified its reportable segments
\u00a0
based on the
nature of the risk and return within its business
\u00a0
and by the
geographical location of the Group\u2019s assets and operations.
Transfer pricing between the segments and companies is set
using the arm\u2019s length principle in a manner similar to
transactions with third parties.
Earnings per share
Calculation of basic earnings per share is based
\u00a0
on the net profit
or loss attributable to ordinary shareholders using
\u00a0
the weighted
average number of shares outstanding during the
\u00a0
year after
deduction of the average number of treasury shares
\u00a0
held over the
period. The calculation of diluted earnings per share
\u00a0
is consistent
with the calculation of basic earnings per
\u00a0
share, while giving effect
to all dilutive potential ordinary shares that were
\u00a0
outstanding
during the period.
Related parties
Parties are related if one party has the ability
\u00a0
to directly, jointly or
indirectly control the other party or exercise significant
\u00a0
influence
over the party in making financial and operating
\u00a0
decisions.
Management is also considered to be a related
\u00a0
party.
\u00a0
Transactions between related parties are transfers of resources,
services or obligations, regardless of whether a
\u00a0
price is charged.
All transactions between the related parties are
\u00a0
recorded at
market value.
Changes in accounting policies
The accounting policies adopted are consistent with
\u00a0
those of the
previous financial year.
\u00a0
Other amendments and interpretations may apply for
\u00a0
the first time
in 2022 but are not considered to have any material
\u00a0
impact on the
Group\u2019s financial statements.
The Group identifies and reports its segments based
\u00a0
on information provided to the executive management
\u00a0
and the Board of Directors
who are considered to collectively be the Chief
\u00a0
Operating Decision Maker. The segment information is used as the
\u00a0
basis for allocation of
resources and decision making. The Group has
\u00a0
identified its reportable segments based on
\u00a0
the nature of the risks and returns within its
business and by the location of the Group\u2019s assets and
\u00a0
operations. Inter-segment sales are based on
\u00a0
the arm\u2019s length principle and are
eliminated at the consolidated level. Segment profit/-loss
\u00a0
includes profit/-loss from inter-segment sales.
\u00a0
The Group reports the following three operating
\u00a0
segments: Kurdistan, the North Sea (which includes
\u00a0
the Group\u2019s oil and gas activities in
Norway and the UK) and West Africa (which represents
\u00a0
the Group\u2019s equity accounted investment in C\u00f4te d'Ivoire,
\u00a0
see Note 10). The
operating segments correspond to the reportable
\u00a0
segments. Remaining operating segments are
\u00a0
included in the Other category based
on a materiality assessment.
\u00a0
The country-by-country reporting for companies in
\u00a0
extractive industries in line with the Norwegian
\u00a0
Accounting Act can be found in page
87 of this report.
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
10
-
-
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
9
-
-371.3
-
-
-371.3
-
-371.3
Exploration expenses
6
-
-96.5
-
-
-96.5
-
-96.5
Operating profit/-loss
567.6
-120.2
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
-64.4
-85.0
Tax income/-expense
8
-
38.4
-
-
38.4
-
38.4
578.0
-114.5
6.1
-8.6
461.1
-77.1
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
688.0
2,803.0
Non-current liabilities
68.1
391.8
-
-
459.9
528.4
988.4
Current liabilities
97.5
284.3
-
41.6
423.4
21.9
445.3
Total liabilities
165.6
676.1
-
41.6
883.3
550.3
1,433.6
USD million
Total
Un-
Full-Year ending
West
reporting
allocated/
Total
31 December 2021
Note
Kurdistan
North Sea
Africa
Other
segments
eliminated
Group
COMPREHENSIVE INCOME INFORMATION
Revenues
3
594.3
409.8
-
-
1,004.1
-
1,004.1
Inter-segment sales
-
2.6
-
-
2.6
-2.6
-
Production costs
-99.6
-119.5
-
-
-219.1
0.3
-218.8
Movement in overlift/underlift
-
-18.3
-
-
-18.3
-
-18.3
Depreciation, depletion and amortization
-121.2
-81.7
-
-
-202.9
-3.1
-206.0
Cost of goods sold
4
-220.9
-219.4
-
-
-440.3
-2.7
-443.1
Gross profit
373.4
193.0
-
-
566.4
-5.4
561.0
Share of profit/-loss from Joint Venture
10
-
-
-
-
-
-
-
Other income
-
-
-
-
0.5
-
0.5
Administrative expenses
\u00a0
5
-0.3
-8.5
-
-1.8
-10.6
-5.6
-16.2
Other operating expenses
5
-2.2
-
-
-9.8
-12.0
-
-12.0
Impairment of oil and gas assets
9
-
-80.1
-
-
-80.1
-
-80.1
Exploration expenses
6
-2.8
-129.6
-
-
-132.3
-
-132.3
Operating profit/-loss
368.1
-24.8
-
-11.6
331.8
-11.0
320.9
Net financial income/-expense
7
22.7
-35.7
-
1.0
-12.0
-88.8
-100.7
Tax income/-expense
8
-
-15.9
-
-0.3
-16.3
-
-16.3
390.8
-76.4
-
-10.9
303.5
-99.7
203.9
FINANCIAL POSITION INFORMATION
Non-current assets
679.8
964.1
-
-
1,643.9
26.6
1,670.5
Current assets
372.2
367.1
-
11.5
750.8
526.5
1,277.3
Total assets
1,052.0
1,331.2
-
11.5
2,394.7
553.1
2,947.8
Non-current liabilities
63.2
691.2
-
-
754.4
788.8
1,543.2
Current liabilities
78.0
248.5
-
36.3
362.8
23.0
385.8
Total liabilities
141.2
939.8
-
36.3
1,117.2
811.7
1,929.0
1 January - 31 December
Total
USD million
2022
2021
2022
2021
2022
2021
Sale of oil
820.1
594.3
241.0
233.8
1,061.1
828.1
Sale of gas
-
-
281.1
151.3
281.1
151.3
Sale of natural gas liquids (NGL)
-
-
29.1
21.3
29.1
21.3
Tariff income
-
-
5.8
3.4
5.8
3.4
Total revenues from contracts with customers
820.1
594.3
556.9
409.8
1,377.0
1,004.1
Sale of oil (bopd)
25,933
28,091
6,341
8,493
32,273
36,583
Sale of gas (boepd)
-
-
4,800
4,344
4,800
4,344
Sale of natural gas liquids (NGL) (boepd)
-
-
1,370
1,244
1,370
1,244
Total sales volume (boepd)
25,933
28,091
12,511
14,080
38,444
42,171
1 January - 31 December
Total
USD million
2022
2021
2022
2021
2022
2021
Sale of oil
820.1
594.3
241.0
233.8
1,061.1
828.1
Sale of gas
-
-
281.1
151.3
281.1
151.3
Sale of natural gas liquids (NGL)
-
-
29.1
21.3
29.1
21.3
Tariff income
-
-
5.8
3.4
5.8
3.4
Total revenues from contracts with customers
820.1
594.3
556.9
409.8
1,377.0
1,004.1
Sale of oil (bopd)
25,933
28,091
6,341
8,493
32,273
36,583
Sale of gas (boepd)
-
-
4,800
4,344
4,800
4,344
Sale of natural gas liquids (NGL) (boepd)
-
-
1,370
1,244
1,370
1,244
Total sales volume (boepd)
25,933
28,091
12,511
14,080
38,444
42,171
Note 4
Cost of goods sold/Inventory
1 January - 31 December
USD million
2022
2021
Lifting costs
-222.1
-184.2
Tariff and transportation expenses
-30.2
-34.5
Production costs based on produced volumes
-252.3
-218.8
Movement in overlift/underlift
8.1
-18.3
Production costs based on sold volumes
-244.2
-237.0
Depreciation, depletion and amortization
-216.7
-206.0
Total cost of goods sold
-460.9
-443.1
Lifting costs consist of expenses related to the production
\u00a0
of oil and gas, including operation and maintenance of
\u00a0
installations, well
intervention activities and insurances. The lifting
\u00a0
costs in 2022 included a provision for obsolete inventory
\u00a0
of USD 2.9 million related to
North Sea (2021 lifting costs included a reversal
\u00a0
of provision for obsolete inventory of USD 1
\u00a0
million related to Kurdistan). Tariff and
transportation expenses consist of charges incurred
\u00a0
by the Group in the North Sea for the use of
\u00a0
infrastructure owned by other
companies.
Years ended 31 December
USD million
2022
2021
Spare parts
47.0
35.8
Total inventory
47.0
35.8
Total inventory of USD 47 million at yearend 2022 was related to Kurdistan (USD 33.7
\u00a0
million) and the North Sea (USD 13.3 million).
1 January - 31 December
USD million
2022
2021
Salaries, bonuses, etc.
-55.2
-56.2
Employer's payroll tax expenses
-5.1
-5.4
Pensions
-4.1
-3.8
Other personnel costs
-5.8
-4.2
General and administration expenses
-32.5
-42.3
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
84.8
95.5
Total administrative expenses
-17.9
-16.2
Other expenses
-7.7
-12.0
Total other operating expenses
-7.7
-12.0
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 2022 were mainly related to provisions
\u00a0
in Yemen, see Note 19.
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.1 million expensed
\u00a0
in 2022 (USD 3.8 million in
2021). 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 2022, the Company\u2019s liability for synthetic
\u00a0
shares as part of other variable remuneration amounted
\u00a0
to USD 5.4 million (USD
2.2 million at yearend 2021). 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
2022
2021
Outstanding as of 1 January
3,178,536
2,837,151
Granted during the year
9,471,309
1,321,431
Forfeited/reversed during the year
37,099
71,374
Settled during the year
1,159,108
908,672
Outstanding as of 31 December
11,453,638
3,178,536
Unrestricted as of 31 December
834,872
462,214
Weighted average remaining contractual life for the synthetic shares (years)
2.43
2.78
Weighted average settlement price for synthetic shares settled during the year (NOK)
12.56
10.83
Settlement price for synthetic shares at the end of the year (NOK)
11.81
10.46
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2022
2021
Managing Director
Salary
-0.64
-0.69
Bonus
-0.26
-0.08
Pension
-0.02
-0.02
Other remuneration
-0.17
-0.07
Remuneration to Managing Director
-1.09
-0.85
Other executive management
Salary
-1.99
-3.24
Bonus
-0.15
-0.70
Pension
-0.08
-0.13
Other remuneration
-0.59
-0.55
Remuneration to other executive management
-2.81
-4.63
Total remuneration to executive management
-3.90
-5.48
Number of managers included
6
8
Total remuneration to Board of Directors
-1.17
-1.10
Total remuneration to Board of Directors and executive management
-5.07
-6.58
Total remuneration of USD 2.4 million (not included in the above table) was paid in 2022
\u00a0
to Nicholas Whiteley and Tom Allan, former
members of the executive management. For further details
\u00a0
on remuneration to the executive management,
\u00a0
see Note 3 in the parent
Shares and options held by Board of Directors
\u00a0
and executive management
Years ended 31 December
Directors and executive management
Bijan Mossavar-Rahmani, Executive Chairman*
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
-
-
-
-
Bj\u00f8rn Dale, Managing Director
-
-
-
-
Chris Spencer, Chief Operating Officer (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
35,750
-
25,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* At yearend 2022, Bijan Mossavar-Rahmani held interests in the Company through a nominee account held by Goldman Sachs & Co. LLC. At yearend 2021, Mr. Mossavar-
Rahmani held indirect interest in the Company through his shareholdings in RAK Petroleum plc (see also Note 11 for more details).
\u00a0
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.
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2022
2021
Auditor fees
-0.71
-0.84
Other financial auditing
-0.04
-0.04
Tax advisory services
-0.08
-0.10
Other advisory services
-
-
Total auditor fees
-0.82
-0.98
1 January - 31 December
USD million
2022
2021
Exploration expenses (G&G and field surveys)
-10.2
-19.1
Seismic costs
-18.5
-37.6
Exploration expenses capitalized in previous years carried to cost
-3.9
-13.4
Exploration expenses capitalized during the year carried to cost
-48.3
-40.7
Other exploration expenses
-15.6
-21.5
Total exploration expenses
-96.5
-132.3
Exploration expenses in 2022 were related to exploration
\u00a0
activities in the North Sea, including expensing
\u00a0
of exploration wells
(Edinburgh, Overly and Uer wells) and seismic purchase.
\u00a0
Exploration expenses in 2021 were related to
\u00a0
exploration activities in the
North Sea, including expensing of exploration wells
\u00a0
(Black Vulture, Gomez and Mugnetind wells) and seismic
\u00a0
purchase.
Note 7
Financial income and financial expenses
1 January - 31 December
USD million
2022
2021
Interest income
12.9
1.7
Other financial income
1.0
24.3
Currency exchange gains recognized in the income statement (net)
-
-
Financial income
13.9
26.0
Interest expenses
-57.5
-74.2
Currency exchange loss recognized in the income statement (net)
-6.6
-5.8
Other financial expenses
-34.8
-46.8
Financial expenses
-98.9
-126.7
Net financial income/-expenses
-85.0
-100.7
Other financial expenses in 2022 were mainly related
\u00a0
to the accretion expenses (i.e., unwinding of discount
\u00a0
related to the ARO
provisions and lease liabilities, see Note 16),
\u00a0
amortization of borrowing issue costs and incurred put
\u00a0
option premium. Other financial
expenses and other financial income in 2021 also
\u00a0
included accounting effects from IFRS 9 assessments
\u00a0
related to the Tawke license
arrears from 2020 and 2021 entitlement and override
\u00a0
invoices (presented gross).
Note 4
Cost of goods sold/Inventory
1 January - 31 December
USD million
2022
2021
Lifting costs
-222.1
-184.2
Tariff and transportation expenses
-30.2
-34.5
Production costs based on produced volumes
-252.3
-218.8
Movement in overlift/underlift
8.1
-18.3
Production costs based on sold volumes
-244.2
-237.0
Depreciation, depletion and amortization
-216.7
-206.0
Total cost of goods sold
-460.9
-443.1
Lifting costs consist of expenses related to the production
\u00a0
of oil and gas, including operation and maintenance of
\u00a0
installations, well
intervention activities and insurances. The lifting
\u00a0
costs in 2022 included a provision for obsolete inventory
\u00a0
of USD 2.9 million related to
North Sea (2021 lifting costs included a reversal
\u00a0
of provision for obsolete inventory of USD 1
\u00a0
million related to Kurdistan). Tariff and
transportation expenses consist of charges incurred
\u00a0
by the Group in the North Sea for the use of
\u00a0
infrastructure owned by other
companies.
Years ended 31 December
USD million
2022
2021
Spare parts
47.0
35.8
Total inventory
47.0
35.8
Total inventory of USD 47 million at yearend 2022 was related to Kurdistan (USD 33.7
\u00a0
million) and the North Sea (USD 13.3 million).
1 January - 31 December
USD million
2022
2021
Salaries, bonuses, etc.
-55.2
-56.2
Employer's payroll tax expenses
-5.1
-5.4
Pensions
-4.1
-3.8
Other personnel costs
-5.8
-4.2
General and administration expenses
-32.5
-42.3
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
84.8
95.5
Total administrative expenses
-17.9
-16.2
Other expenses
-7.7
-12.0
Total other operating expenses
-7.7
-12.0
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 2022 were mainly related to provisions
\u00a0
in Yemen, see Note 19.
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.1 million expensed
\u00a0
in 2022 (USD 3.8 million in
2021). 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 2022, the Company\u2019s liability for synthetic
\u00a0
shares as part of other variable remuneration amounted
\u00a0
to USD 5.4 million (USD
2.2 million at yearend 2021). 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
2022
2021
Outstanding as of 1 January
3,178,536
2,837,151
Granted during the year
9,471,309
1,321,431
Forfeited/reversed during the year
37,099
71,374
Settled during the year
1,159,108
908,672
Outstanding as of 31 December
11,453,638
3,178,536
Unrestricted as of 31 December
834,872
462,214
Weighted average remaining contractual life for the synthetic shares (years)
2.43
2.78
Weighted average settlement price for synthetic shares settled during the year (NOK)
12.56
10.83
Settlement price for synthetic shares at the end of the year (NOK)
11.81
10.46
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2022
2021
Managing Director
Salary
-0.64
-0.69
Bonus
-0.26
-0.08
Pension
-0.02
-0.02
Other remuneration
-0.17
-0.07
Remuneration to Managing Director
-1.09
-0.85
Other executive management
Salary
-1.99
-3.24
Bonus
-0.15
-0.70
Pension
-0.08
-0.13
Other remuneration
-0.59
-0.55
Remuneration to other executive management
-2.81
-4.63
Total remuneration to executive management
-3.90
-5.48
Number of managers included
6
8
Total remuneration to Board of Directors
-1.17
-1.10
Total remuneration to Board of Directors and executive management
-5.07
-6.58
Total remuneration of USD 2.4 million (not included in the above table) was paid in 2022
\u00a0
to Nicholas Whiteley and Tom Allan, former
members of the executive management. For further details
\u00a0
on remuneration to the executive management,
\u00a0
see Note 3 in the parent
Shares and options held by Board of Directors
\u00a0
and executive management
Years ended 31 December
Directors and executive management
Bijan Mossavar-Rahmani, Executive Chairman*
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
-
-
-
-
Bj\u00f8rn Dale, Managing Director
-
-
-
-
Chris Spencer, Chief Operating Officer (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
35,750
-
25,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* At yearend 2022, Bijan Mossavar-Rahmani held interests in the Company through a nominee account held by Goldman Sachs & Co. LLC. At yearend 2021, Mr. Mossavar-
Rahmani held indirect interest in the Company through his shareholdings in RAK Petroleum plc (see also Note 11 for more details).
\u00a0
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.
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2022
2021
Auditor fees
-0.71
-0.84
Other financial auditing
-0.04
-0.04
Tax advisory services
-0.08
-0.10
Other advisory services
-
-
Total auditor fees
-0.82
-0.98
1 January - 31 December
USD million
2022
2021
Exploration expenses (G&G and field surveys)
-10.2
-19.1
Seismic costs
-18.5
-37.6
Exploration expenses capitalized in previous years carried to cost
-3.9
-13.4
Exploration expenses capitalized during the year carried to cost
-48.3
-40.7
Other exploration expenses
-15.6
-21.5
Total exploration expenses
-96.5
-132.3
Exploration expenses in 2022 were related to exploration
\u00a0
activities in the North Sea, including expensing
\u00a0
of exploration wells
(Edinburgh, Overly and Uer wells) and seismic purchase.
\u00a0
Exploration expenses in 2021 were related to
\u00a0
exploration activities in the
North Sea, including expensing of exploration wells
\u00a0
(Black Vulture, Gomez and Mugnetind wells) and seismic
\u00a0
purchase.
Note 7
Financial income and financial expenses
1 January - 31 December
USD million
2022
2021
Interest income
12.9
1.7
Other financial income
1.0
24.3
Currency exchange gains recognized in the income statement (net)
-
-
Financial income
13.9
26.0
Interest expenses
-57.5
-74.2
Currency exchange loss recognized in the income statement (net)
-6.6
-5.8
Other financial expenses
-34.8
-46.8
Financial expenses
-98.9
-126.7
Net financial income/-expenses
-85.0
-100.7
Other financial expenses in 2022 were mainly related
\u00a0
to the accretion expenses (i.e., unwinding of discount
\u00a0
related to the ARO
provisions and lease liabilities, see Note 16),
\u00a0
amortization of borrowing issue costs and incurred put
\u00a0
option premium. Other financial
expenses and other financial income in 2021 also
\u00a0
included accounting effects from IFRS 9 assessments
\u00a0
related to the Tawke license
arrears from 2020 and 2021 entitlement and override
\u00a0
invoices (presented gross).
Note 4
Cost of goods sold/Inventory
1 January - 31 December
USD million
2022
2021
Lifting costs
-222.1
-184.2
Tariff and transportation expenses
-30.2
-34.5
Production costs based on produced volumes
-252.3
-218.8
Movement in overlift/underlift
8.1
-18.3
Production costs based on sold volumes
-244.2
-237.0
Depreciation, depletion and amortization
-216.7
-206.0
Total cost of goods sold
-460.9
-443.1
Lifting costs consist of expenses related to the production
\u00a0
of oil and gas, including operation and maintenance of
\u00a0
installations, well
intervention activities and insurances. The lifting
\u00a0
costs in 2022 included a provision for obsolete inventory
\u00a0
of USD 2.9 million related to
North Sea (2021 lifting costs included a reversal
\u00a0
of provision for obsolete inventory of USD 1
\u00a0
million related to Kurdistan). Tariff and
transportation expenses consist of charges incurred
\u00a0
by the Group in the North Sea for the use of
\u00a0
infrastructure owned by other
companies.
Years ended 31 December
USD million
2022
2021
Spare parts
47.0
35.8
Total inventory
47.0
35.8
Total inventory of USD 47 million at yearend 2022 was related to Kurdistan (USD 33.7
\u00a0
million) and the North Sea (USD 13.3 million).
Note 4
Cost of goods sold/Inventory
1 January - 31 December
USD million
2022
2021
Lifting costs
-222.1
-184.2
Tariff and transportation expenses
-30.2
-34.5
Production costs based on produced volumes
-252.3
-218.8
Movement in overlift/underlift
8.1
-18.3
Production costs based on sold volumes
-244.2
-237.0
Depreciation, depletion and amortization
-216.7
-206.0
Total cost of goods sold
-460.9
-443.1
Lifting costs consist of expenses related to the production
\u00a0
of oil and gas, including operation and maintenance of
\u00a0
installations, well
intervention activities and insurances. The lifting
\u00a0
costs in 2022 included a provision for obsolete inventory
\u00a0
of USD 2.9 million related to
North Sea (2021 lifting costs included a reversal
\u00a0
of provision for obsolete inventory of USD 1
\u00a0
million related to Kurdistan). Tariff and
transportation expenses consist of charges incurred
\u00a0
by the Group in the North Sea for the use of
\u00a0
infrastructure owned by other
companies.
Years ended 31 December
USD million
2022
2021
Spare parts
47.0
35.8
Total inventory
47.0
35.8
Total inventory of USD 47 million at yearend 2022 was related to Kurdistan (USD 33.7
\u00a0
million) and the North Sea (USD 13.3 million).
1 January - 31 December
USD million
2022
2021
Salaries, bonuses, etc.
-55.2
-56.2
Employer's payroll tax expenses
-5.1
-5.4
Pensions
-4.1
-3.8
Other personnel costs
-5.8
-4.2
General and administration expenses
-32.5
-42.3
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
84.8
95.5
Total administrative expenses
-17.9
-16.2
Other expenses
-7.7
-12.0
Total other operating expenses
-7.7
-12.0
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 2022 were mainly related to provisions
\u00a0
in Yemen, see Note 19.
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.1 million expensed
\u00a0
in 2022 (USD 3.8 million in
2021). 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 2022, the Company\u2019s liability for synthetic
\u00a0
shares as part of other variable remuneration amounted
\u00a0
to USD 5.4 million (USD
2.2 million at yearend 2021). 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
2022
2021
Outstanding as of 1 January
3,178,536
2,837,151
Granted during the year
9,471,309
1,321,431
Forfeited/reversed during the year
37,099
71,374
Settled during the year
1,159,108
908,672
Outstanding as of 31 December
11,453,638
3,178,536
Unrestricted as of 31 December
834,872
462,214
Weighted average remaining contractual life for the synthetic shares (years)
2.43
2.78
Weighted average settlement price for synthetic shares settled during the year (NOK)
12.56
10.83
Settlement price for synthetic shares at the end of the year (NOK)
11.81
10.46
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2022
2021
Managing Director
Salary
-0.64
-0.69
Bonus
-0.26
-0.08
Pension
-0.02
-0.02
Other remuneration
-0.17
-0.07
Remuneration to Managing Director
-1.09
-0.85
Other executive management
Salary
-1.99
-3.24
Bonus
-0.15
-0.70
Pension
-0.08
-0.13
Other remuneration
-0.59
-0.55
Remuneration to other executive management
-2.81
-4.63
Total remuneration to executive management
-3.90
-5.48
Number of managers included
6
8
Total remuneration to Board of Directors
-1.17
-1.10
Total remuneration to Board of Directors and executive management
-5.07
-6.58
Total remuneration of USD 2.4 million (not included in the above table) was paid in 2022
\u00a0
to Nicholas Whiteley and Tom Allan, former
members of the executive management. For further details
\u00a0
on remuneration to the executive management,
\u00a0
see Note 3 in the parent
Shares and options held by Board of Directors
\u00a0
and executive management
Years ended 31 December
Directors and executive management
Bijan Mossavar-Rahmani, Executive Chairman*
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
-
-
-
-
Bj\u00f8rn Dale, Managing Director
-
-
-
-
Chris Spencer, Chief Operating Officer (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
35,750
-
25,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* At yearend 2022, Bijan Mossavar-Rahmani held interests in the Company through a nominee account held by Goldman Sachs & Co. LLC. At yearend 2021, Mr. Mossavar-
Rahmani held indirect interest in the Company through his shareholdings in RAK Petroleum plc (see also Note 11 for more details).
\u00a0
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.
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2022
2021
Auditor fees
-0.71
-0.84
Other financial auditing
-0.04
-0.04
Tax advisory services
-0.08
-0.10
Other advisory services
-
-
Total auditor fees
-0.82
-0.98
1 January - 31 December
USD million
2022
2021
Salaries, bonuses, etc.
-55.2
-56.2
Employer's payroll tax expenses
-5.1
-5.4
Pensions
-4.1
-3.8
Other personnel costs
-5.8
-4.2
General and administration expenses
-32.5
-42.3
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
84.8
95.5
Total administrative expenses
-17.9
-16.2
Other expenses
-7.7
-12.0
Total other operating expenses
-7.7
-12.0
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 2022 were mainly related to provisions
\u00a0
in Yemen, see Note 19.
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.1 million expensed
\u00a0
in 2022 (USD 3.8 million in
2021). 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 2022, the Company\u2019s liability for synthetic
\u00a0
shares as part of other variable remuneration amounted
\u00a0
to USD 5.4 million (USD
2.2 million at yearend 2021). 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
2022
2021
Outstanding as of 1 January
3,178,536
2,837,151
Granted during the year
9,471,309
1,321,431
Forfeited/reversed during the year
37,099
71,374
Settled during the year
1,159,108
908,672
Outstanding as of 31 December
11,453,638
3,178,536
Unrestricted as of 31 December
834,872
462,214
Weighted average remaining contractual life for the synthetic shares (years)
2.43
2.78
Weighted average settlement price for synthetic shares settled during the year (NOK)
12.56
10.83
Settlement price for synthetic shares at the end of the year (NOK)
11.81
10.46
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2022
2021
Managing Director
Salary
-0.64
-0.69
Bonus
-0.26
-0.08
Pension
-0.02
-0.02
Other remuneration
-0.17
-0.07
Remuneration to Managing Director
-1.09
-0.85
Other executive management
Salary
-1.99
-3.24
Bonus
-0.15
-0.70
Pension
-0.08
-0.13
Other remuneration
-0.59
-0.55
Remuneration to other executive management
-2.81
-4.63
Total remuneration to executive management
-3.90
-5.48
Number of managers included
6
8
Total remuneration to Board of Directors
-1.17
-1.10
Total remuneration to Board of Directors and executive management
-5.07
-6.58
Total remuneration of USD 2.4 million (not included in the above table) was paid in 2022
\u00a0
to Nicholas Whiteley and Tom Allan, former
members of the executive management. For further details
\u00a0
on remuneration to the executive management,
\u00a0
see Note 3 in the parent
Shares and options held by Board of Directors
\u00a0
and executive management
Years ended 31 December
Directors and executive management
Bijan Mossavar-Rahmani, Executive Chairman*
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
-
-
-
-
Bj\u00f8rn Dale, Managing Director
-
-
-
-
Chris Spencer, Chief Operating Officer (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
35,750
-
25,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* At yearend 2022, Bijan Mossavar-Rahmani held interests in the Company through a nominee account held by Goldman Sachs & Co. LLC. At yearend 2021, Mr. Mossavar-
Rahmani held indirect interest in the Company through his shareholdings in RAK Petroleum plc (see also Note 11 for more details).
\u00a0
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.
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2022
2021
Auditor fees
-0.71
-0.84
Other financial auditing
-0.04
-0.04
Tax advisory services
-0.08
-0.10
Other advisory services
-
-
Total auditor fees
-0.82
-0.98
1 January - 31 December
USD million
2022
2021
Salaries, bonuses, etc.
-55.2
-56.2
Employer's payroll tax expenses
-5.1
-5.4
Pensions
-4.1
-3.8
Other personnel costs
-5.8
-4.2
General and administration expenses
-32.5
-42.3
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
84.8
95.5
Total administrative expenses
-17.9
-16.2
Other expenses
-7.7
-12.0
Total other operating expenses
-7.7
-12.0
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 2022 were mainly related to provisions
\u00a0
in Yemen, see Note 19.
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.1 million expensed
\u00a0
in 2022 (USD 3.8 million in
2021). 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 2022, the Company\u2019s liability for synthetic
\u00a0
shares as part of other variable remuneration amounted
\u00a0
to USD 5.4 million (USD
2.2 million at yearend 2021). 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
2022
2021
Outstanding as of 1 January
3,178,536
2,837,151
Granted during the year
9,471,309
1,321,431
Forfeited/reversed during the year
37,099
71,374
Settled during the year
1,159,108
908,672
Outstanding as of 31 December
11,453,638
3,178,536
Unrestricted as of 31 December
834,872
462,214
Weighted average remaining contractual life for the synthetic shares (years)
2.43
2.78
Weighted average settlement price for synthetic shares settled during the year (NOK)
12.56
10.83
Settlement price for synthetic shares at the end of the year (NOK)
11.81
10.46
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2022
2021
Managing Director
Salary
-0.64
-0.69
Bonus
-0.26
-0.08
Pension
-0.02
-0.02
Other remuneration
-0.17
-0.07
Remuneration to Managing Director
-1.09
-0.85
Other executive management
Salary
-1.99
-3.24
Bonus
-0.15
-0.70
Pension
-0.08
-0.13
Other remuneration
-0.59
-0.55
Remuneration to other executive management
-2.81
-4.63
Total remuneration to executive management
-3.90
-5.48
Number of managers included
6
8
Total remuneration to Board of Directors
-1.17
-1.10
Total remuneration to Board of Directors and executive management
-5.07
-6.58
Total remuneration of USD 2.4 million (not included in the above table) was paid in 2022
\u00a0
to Nicholas Whiteley and Tom Allan, former
members of the executive management. For further details
\u00a0
on remuneration to the executive management,
\u00a0
see Note 3 in the parent
Shares and options held by Board of Directors
\u00a0
and executive management
Years ended 31 December
Directors and executive management
Bijan Mossavar-Rahmani, Executive Chairman*
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
-
-
-
-
Bj\u00f8rn Dale, Managing Director
-
-
-
-
Chris Spencer, Chief Operating Officer (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
35,750
-
25,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* At yearend 2022, Bijan Mossavar-Rahmani held interests in the Company through a nominee account held by Goldman Sachs & Co. LLC. At yearend 2021, Mr. Mossavar-
Rahmani held indirect interest in the Company through his shareholdings in RAK Petroleum plc (see also Note 11 for more details).
\u00a0
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.
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2022
2021
Auditor fees
-0.71
-0.84
Other financial auditing
-0.04
-0.04
Tax advisory services
-0.08
-0.10
Other advisory services
-
-
Total auditor fees
-0.82
-0.98
1 January - 31 December
USD million
2022
2021
Salaries, bonuses, etc.
-55.2
-56.2
Employer's payroll tax expenses
-5.1
-5.4
Pensions
-4.1
-3.8
Other personnel costs
-5.8
-4.2
General and administration expenses
-32.5
-42.3
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
84.8
95.5
Total administrative expenses
-17.9
-16.2
Other expenses
-7.7
-12.0
Total other operating expenses
-7.7
-12.0
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 2022 were mainly related to provisions
\u00a0
in Yemen, see Note 19.
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.1 million expensed
\u00a0
in 2022 (USD 3.8 million in
2021). 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 2022, the Company\u2019s liability for synthetic
\u00a0
shares as part of other variable remuneration amounted
\u00a0
to USD 5.4 million (USD
2.2 million at yearend 2021). 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
2022
2021
Outstanding as of 1 January
3,178,536
2,837,151
Granted during the year
9,471,309
1,321,431
Forfeited/reversed during the year
37,099
71,374
Settled during the year
1,159,108
908,672
Outstanding as of 31 December
11,453,638
3,178,536
Unrestricted as of 31 December
834,872
462,214
Weighted average remaining contractual life for the synthetic shares (years)
2.43
2.78
Weighted average settlement price for synthetic shares settled during the year (NOK)
12.56
10.83
Settlement price for synthetic shares at the end of the year (NOK)
11.81
10.46
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2022
2021
Managing Director
Salary
-0.64
-0.69
Bonus
-0.26
-0.08
Pension
-0.02
-0.02
Other remuneration
-0.17
-0.07
Remuneration to Managing Director
-1.09
-0.85
Other executive management
Salary
-1.99
-3.24
Bonus
-0.15
-0.70
Pension
-0.08
-0.13
Other remuneration
-0.59
-0.55
Remuneration to other executive management
-2.81
-4.63
Total remuneration to executive management
-3.90
-5.48
Number of managers included
6
8
Total remuneration to Board of Directors
-1.17
-1.10
Total remuneration to Board of Directors and executive management
-5.07
-6.58
Total remuneration of USD 2.4 million (not included in the above table) was paid in 2022
\u00a0
to Nicholas Whiteley and Tom Allan, former
members of the executive management. For further details
\u00a0
on remuneration to the executive management,
\u00a0
see Note 3 in the parent
Shares and options held by Board of Directors
\u00a0
and executive management
Years ended 31 December
Directors and executive management
Bijan Mossavar-Rahmani, Executive Chairman*
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
-
-
-
-
Bj\u00f8rn Dale, Managing Director
-
-
-
-
Chris Spencer, Chief Operating Officer (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
35,750
-
25,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* At yearend 2022, Bijan Mossavar-Rahmani held interests in the Company through a nominee account held by Goldman Sachs & Co. LLC. At yearend 2021, Mr. Mossavar-
Rahmani held indirect interest in the Company through his shareholdings in RAK Petroleum plc (see also Note 11 for more details).
\u00a0
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.
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2022
2021
Auditor fees
-0.71
-0.84
Other financial auditing
-0.04
-0.04
Tax advisory services
-0.08
-0.10
Other advisory services
-
-
Total auditor fees
-0.82
-0.98
1 January - 31 December
USD million
2022
2021
Salaries, bonuses, etc.
-55.2
-56.2
Employer's payroll tax expenses
-5.1
-5.4
Pensions
-4.1
-3.8
Other personnel costs
-5.8
-4.2
General and administration expenses
-32.5
-42.3
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
84.8
95.5
Total administrative expenses
-17.9
-16.2
Other expenses
-7.7
-12.0
Total other operating expenses
-7.7
-12.0
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 2022 were mainly related to provisions
\u00a0
in Yemen, see Note 19.
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.1 million expensed
\u00a0
in 2022 (USD 3.8 million in
2021). 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 2022, the Company\u2019s liability for synthetic
\u00a0
shares as part of other variable remuneration amounted
\u00a0
to USD 5.4 million (USD
2.2 million at yearend 2021). 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
2022
2021
Outstanding as of 1 January
3,178,536
2,837,151
Granted during the year
9,471,309
1,321,431
Forfeited/reversed during the year
37,099
71,374
Settled during the year
1,159,108
908,672
Outstanding as of 31 December
11,453,638
3,178,536
Unrestricted as of 31 December
834,872
462,214
Weighted average remaining contractual life for the synthetic shares (years)
2.43
2.78
Weighted average settlement price for synthetic shares settled during the year (NOK)
12.56
10.83
Settlement price for synthetic shares at the end of the year (NOK)
11.81
10.46
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2022
2021
Managing Director
Salary
-0.64
-0.69
Bonus
-0.26
-0.08
Pension
-0.02
-0.02
Other remuneration
-0.17
-0.07
Remuneration to Managing Director
-1.09
-0.85
Other executive management
Salary
-1.99
-3.24
Bonus
-0.15
-0.70
Pension
-0.08
-0.13
Other remuneration
-0.59
-0.55
Remuneration to other executive management
-2.81
-4.63
Total remuneration to executive management
-3.90
-5.48
Number of managers included
6
8
Total remuneration to Board of Directors
-1.17
-1.10
Total remuneration to Board of Directors and executive management
-5.07
-6.58
Total remuneration of USD 2.4 million (not included in the above table) was paid in 2022
\u00a0
to Nicholas Whiteley and Tom Allan, former
members of the executive management. For further details
\u00a0
on remuneration to the executive management,
\u00a0
see Note 3 in the parent
Shares and options held by Board of Directors
\u00a0
and executive management
Years ended 31 December
Directors and executive management
Bijan Mossavar-Rahmani, Executive Chairman*
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
-
-
-
-
Bj\u00f8rn Dale, Managing Director
-
-
-
-
Chris Spencer, Chief Operating Officer (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
35,750
-
25,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* At yearend 2022, Bijan Mossavar-Rahmani held interests in the Company through a nominee account held by Goldman Sachs & Co. LLC. At yearend 2021, Mr. Mossavar-
Rahmani held indirect interest in the Company through his shareholdings in RAK Petroleum plc (see also Note 11 for more details).
\u00a0
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.
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2022
2021
Auditor fees
-0.71
-0.84
Other financial auditing
-0.04
-0.04
Tax advisory services
-0.08
-0.10
Other advisory services
-
-
Total auditor fees
-0.82
-0.98
1 January - 31 December
USD million
2022
2021
Salaries, bonuses, etc.
-55.2
-56.2
Employer's payroll tax expenses
-5.1
-5.4
Pensions
-4.1
-3.8
Other personnel costs
-5.8
-4.2
General and administration expenses
-32.5
-42.3
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
84.8
95.5
Total administrative expenses
-17.9
-16.2
Other expenses
-7.7
-12.0
Total other operating expenses
-7.7
-12.0
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 2022 were mainly related to provisions
\u00a0
in Yemen, see Note 19.
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.1 million expensed
\u00a0
in 2022 (USD 3.8 million in
2021). 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 2022, the Company\u2019s liability for synthetic
\u00a0
shares as part of other variable remuneration amounted
\u00a0
to USD 5.4 million (USD
2.2 million at yearend 2021). 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
2022
2021
Outstanding as of 1 January
3,178,536
2,837,151
Granted during the year
9,471,309
1,321,431
Forfeited/reversed during the year
37,099
71,374
Settled during the year
1,159,108
908,672
Outstanding as of 31 December
11,453,638
3,178,536
Unrestricted as of 31 December
834,872
462,214
Weighted average remaining contractual life for the synthetic shares (years)
2.43
2.78
Weighted average settlement price for synthetic shares settled during the year (NOK)
12.56
10.83
Settlement price for synthetic shares at the end of the year (NOK)
11.81
10.46
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2022
2021
Managing Director
Salary
-0.64
-0.69
Bonus
-0.26
-0.08
Pension
-0.02
-0.02
Other remuneration
-0.17
-0.07
Remuneration to Managing Director
-1.09
-0.85
Other executive management
Salary
-1.99
-3.24
Bonus
-0.15
-0.70
Pension
-0.08
-0.13
Other remuneration
-0.59
-0.55
Remuneration to other executive management
-2.81
-4.63
Total remuneration to executive management
-3.90
-5.48
Number of managers included
6
8
Total remuneration to Board of Directors
-1.17
-1.10
Total remuneration to Board of Directors and executive management
-5.07
-6.58
Total remuneration of USD 2.4 million (not included in the above table) was paid in 2022
\u00a0
to Nicholas Whiteley and Tom Allan, former
members of the executive management. For further details
\u00a0
on remuneration to the executive management,
\u00a0
see Note 3 in the parent
Shares and options held by Board of Directors
\u00a0
and executive management
Years ended 31 December
Directors and executive management
Bijan Mossavar-Rahmani, Executive Chairman*
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
-
-
-
-
Bj\u00f8rn Dale, Managing Director
-
-
-
-
Chris Spencer, Chief Operating Officer (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
35,750
-
25,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* At yearend 2022, Bijan Mossavar-Rahmani held interests in the Company through a nominee account held by Goldman Sachs & Co. LLC. At yearend 2021, Mr. Mossavar-
Rahmani held indirect interest in the Company through his shareholdings in RAK Petroleum plc (see also Note 11 for more details).
\u00a0
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.
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2022
2021
Auditor fees
-0.71
-0.84
Other financial auditing
-0.04
-0.04
Tax advisory services
-0.08
-0.10
Other advisory services
-
-
Total auditor fees
-0.82
-0.98
1 January - 31 December
USD million
2022
2021
Exploration expenses (G&G and field surveys)
-10.2
-19.1
Seismic costs
-18.5
-37.6
Exploration expenses capitalized in previous years carried to cost
-3.9
-13.4
Exploration expenses capitalized during the year carried to cost
-48.3
-40.7
Other exploration expenses
-15.6
-21.5
Total exploration expenses
-96.5
-132.3
Exploration expenses in 2022 were related to exploration
\u00a0
activities in the North Sea, including expensing
\u00a0
of exploration wells
(Edinburgh, Overly and Uer wells) and seismic purchase.
\u00a0
Exploration expenses in 2021 were related to
\u00a0
exploration activities in the
North Sea, including expensing of exploration wells
\u00a0
(Black Vulture, Gomez and Mugnetind wells) and seismic
\u00a0
purchase.
Note 7
Financial income and financial expenses
1 January - 31 December
USD million
2022
2021
Interest income
12.9
1.7
Other financial income
1.0
24.3
Currency exchange gains recognized in the income statement (net)
-
-
Financial income
13.9
26.0
Interest expenses
-57.5
-74.2
Currency exchange loss recognized in the income statement (net)
-6.6
-5.8
Other financial expenses
-34.8
-46.8
Financial expenses
-98.9
-126.7
Net financial income/-expenses
-85.0
-100.7
Other financial expenses in 2022 were mainly related
\u00a0
to the accretion expenses (i.e., unwinding of discount
\u00a0
related to the ARO
provisions and lease liabilities, see Note 16),
\u00a0
amortization of borrowing issue costs and incurred put
\u00a0
option premium. Other financial
expenses and other financial income in 2021 also
\u00a0
included accounting effects from IFRS 9 assessments
\u00a0
related to the Tawke license
arrears from 2020 and 2021 entitlement and override
\u00a0
invoices (presented gross).
Note 7
Financial income and financial expenses
1 January - 31 December
USD million
2022
2021
Interest income
12.9
1.7
Other financial income
1.0
24.3
Currency exchange gains recognized in the income statement (net)
-
-
Financial income
13.9
26.0
Interest expenses
-57.5
-74.2
Currency exchange loss recognized in the income statement (net)
-6.6
-5.8
Other financial expenses
-34.8
-46.8
Financial expenses
-98.9
-126.7
Net financial income/-expenses
-85.0
-100.7
Other financial expenses in 2022 were mainly related
\u00a0
to the accretion expenses (i.e., unwinding of discount
\u00a0
related to the ARO
provisions and lease liabilities, see Note 16),
\u00a0
amortization of borrowing issue costs and incurred put
\u00a0
option premium. Other financial
expenses and other financial income in 2021 also
\u00a0
included accounting effects from IFRS 9 assessments
\u00a0
related to the Tawke license
arrears from 2020 and 2021 entitlement and override
\u00a0
invoices (presented gross).
Note 7
Financial income and financial expenses
1 January - 31 December
USD million
2022
2021
Interest income
12.9
1.7
Other financial income
1.0
24.3
Currency exchange gains recognized in the income statement (net)
-
-
Financial income
13.9
26.0
Interest expenses
-57.5
-74.2
Currency exchange loss recognized in the income statement (net)
-6.6
-5.8
Other financial expenses
-34.8
-46.8
Financial expenses
-98.9
-126.7
Net financial income/-expenses
-85.0
-100.7
Other financial expenses in 2022 were mainly related
\u00a0
to the accretion expenses (i.e., unwinding of discount
\u00a0
related to the ARO
provisions and lease liabilities, see Note 16),
\u00a0
amortization of borrowing issue costs and incurred put
\u00a0
option premium. Other financial
expenses and other financial income in 2021 also
\u00a0
included accounting effects from IFRS 9 assessments
\u00a0
related to the Tawke license
arrears from 2020 and 2021 entitlement and override
\u00a0
invoices (presented gross).
Note 7
Financial income and financial expenses
1 January - 31 December
USD million
2022
2021
Interest income
12.9
1.7
Other financial income
1.0
24.3
Currency exchange gains recognized in the income statement (net)
-
-
Financial income
13.9
26.0
Interest expenses
-57.5
-74.2
Currency exchange loss recognized in the income statement (net)
-6.6
-5.8
Other financial expenses
-34.8
-46.8
Financial expenses
-98.9
-126.7
Net financial income/-expenses
-85.0
-100.7
Other financial expenses in 2022 were mainly related
\u00a0
to the accretion expenses (i.e., unwinding of discount
\u00a0
related to the ARO
provisions and lease liabilities, see Note 16),
\u00a0
amortization of borrowing issue costs and incurred put
\u00a0
option premium. Other financial
expenses and other financial income in 2021 also
\u00a0
included accounting effects from IFRS 9 assessments
\u00a0
related to the Tawke license
arrears from 2020 and 2021 entitlement and override
\u00a0
invoices (presented gross).
Note 7
Financial income and financial expenses
1 January - 31 December
USD million
2022
2021
Interest income
12.9
1.7
Other financial income
1.0
24.3
Currency exchange gains recognized in the income statement (net)
-
-
Financial income
13.9
26.0
Interest expenses
-57.5
-74.2
Currency exchange loss recognized in the income statement (net)
-6.6
-5.8
Other financial expenses
-34.8
-46.8
Financial expenses
-98.9
-126.7
Net financial income/-expenses
-85.0
-100.7
Other financial expenses in 2022 were mainly related
\u00a0
to the accretion expenses (i.e., unwinding of discount
\u00a0
related to the ARO
provisions and lease liabilities, see Note 16),
\u00a0
amortization of borrowing issue costs and incurred put
\u00a0
option premium. Other financial
expenses and other financial income in 2021 also
\u00a0
included accounting effects from IFRS 9 assessments
\u00a0
related to the Tawke license
arrears from 2020 and 2021 entitlement and override
\u00a0
invoices (presented gross).
Note 7
Financial income and financial expenses
1 January - 31 December
USD million
2022
2021
Interest income
12.9
1.7
Other financial income
1.0
24.3
Currency exchange gains recognized in the income statement (net)
-
-
Financial income
13.9
26.0
Interest expenses
-57.5
-74.2
Currency exchange loss recognized in the income statement (net)
-6.6
-5.8
Other financial expenses
-34.8
-46.8
Financial expenses
-98.9
-126.7
Net financial income/-expenses
-85.0
-100.7
Other financial expenses in 2022 were mainly related
\u00a0
to the accretion expenses (i.e., unwinding of discount
\u00a0
related to the ARO
provisions and lease liabilities, see Note 16),
\u00a0
amortization of borrowing issue costs and incurred put
\u00a0
option premium. Other financial
expenses and other financial income in 2021 also
\u00a0
included accounting effects from IFRS 9 assessments
\u00a0
related to the Tawke license
arrears from 2020 and 2021 entitlement and override
\u00a0
invoices (presented gross).
Note 7
Financial income and financial expenses
1 January - 31 December
USD million
2022
2021
Interest income
12.9
1.7
Other financial income
1.0
24.3
Currency exchange gains recognized in the income statement (net)
-
-
Financial income
13.9
26.0
Interest expenses
-57.5
-74.2
Currency exchange loss recognized in the income statement (net)
-6.6
-5.8
Other financial expenses
-34.8
-46.8
Financial expenses
-98.9
-126.7
Net financial income/-expenses
-85.0
-100.7
Other financial expenses in 2022 were mainly related
\u00a0
to the accretion expenses (i.e., unwinding of discount
\u00a0
related to the ARO
provisions and lease liabilities, see Note 16),
\u00a0
amortization of borrowing issue costs and incurred put
\u00a0
option premium. Other financial
expenses and other financial income in 2021 also
\u00a0
included accounting effects from IFRS 9 assessments
\u00a0
related to the Tawke license
arrears from 2020 and 2021 entitlement and override
\u00a0
invoices (presented gross).
Tax income/-expense
1 January - 31 December
USD million
2022
2021
Changes in deferred taxes
162.9
-115.2
Income taxes receivable/-payable
-124.5
98.9
Total tax income/-expense
38.4
-16.3
Income tax receivable/-payable
Years ended 31 December
USD million
2022
2021
Tax receivables
25.8
21.1
Income taxes payable
-125.7
-33.1
Net tax receivable/-payable
-99.9
-11.9
The tax balances relate to the activity on the Norwegian
\u00a0
Continental Shelf (NCS) and the UK Continental
\u00a0
Shelf (UKCS). The current tax
receivable relates to tax refunds of decommissioning
\u00a0
spend on the UKCS expected to be received
\u00a0
during the third quarter of 2023. The
current income taxes payable relates to taxable
\u00a0
profits in 2022 on the NCS and will be
\u00a0
paid during first half of 2023.
\u00a0
In June 2022, the Norwegian Parliament approved
\u00a0
certain changes to the taxation of oil and gas
\u00a0
companies operating on the NCS,
effective from 1 January 2022. The companies can expense
\u00a0
investments immediately in the special tax
\u00a0
basis and receive a cash refund
of the tax value of losses in the special tax basis.
\u00a0
The uplift on investments is discontinued
\u00a0
but will apply to the investments covered by
the temporary changes, as approved by the parliament
\u00a0
in June 2020. The ordinary corporate tax is deductible
\u00a0
in the special tax basis
and to maintain a combined marginal tax rate of
\u00a0
78 percent, the special tax rate is increased
\u00a0
to 71.8 percent. Losses in the corporate tax
basis are not eligible for refund but can be
\u00a0
carried forward. The tax value of unused uplift
\u00a0
and carried forward losses as of yearend 2021
will be paid out in connection with the 2022 tax assessment
\u00a0
in November 2023 or offset tax installments on 2022
\u00a0
taxable profits.
In December 2022, the Norwegian Parliament approved
\u00a0
a change to the uplift under the temporary tax
\u00a0
rules applying to PDOs delivered
by the end of 2022, from 17.69 percent to 12.4
\u00a0
percent, effective from 1 January 2023. The change to
\u00a0
the uplift adversely impacts the
economics of development projects under the temporary
\u00a0
rules.
During 2022, DNO received tax refunds of USD 17.7
\u00a0
million in the UK in relation to decommissioning
\u00a0
spend for 2021. In Norway, DNO
paid net USD 38.9 million which consisted of repayment
\u00a0
of refunds received during the second half of
\u00a0
2021 and the first three tax
installments on 2022 taxable profits.
Reconciliation of tax income/-expense
1 January - 31 December
USD million
2022
2021
Profit/-loss before income tax
346.5
220.1
Expected income tax according to nominal tax rate in Norway, 22 percent
-108.1
-52.4
Expected income tax according to nominal petroleum tax rate in Norway,
\u00a0
78 percent
43.3
24.3
Expected income tax according to nominal tax outside Norway
33.5
7.4
Foreign exchange variations between functional and tax currency
2.5
-4.5
Adjustment of previous years
0.7
0.2
Adjustment of deferred tax assets not recognized
-62.3
-31.0
Other items including other permanent differences
116.2
35.3
Change in tax rate
12.4
4.6
Tax income/-expense
38.4
-16.3
Effective income tax rate
-11.1%
-7.4%
Taxes charged to equity
-
-
Expected income tax related to activities on the NCS and
\u00a0
outside Norway is positive as the petroleum
\u00a0
activities in Norway and the UK
generated a loss before tax. Other items above
\u00a0
consist mainly of permanent differences on impairments
\u00a0
which are not tax deductible,
and permanent differences on tax exempted profits/losses
\u00a0
from upstream activities outside of Norway carried
\u00a0
out by the Company\u2019s
Norwegian subsidiaries.
Tax effects on temporary differences
Years ended 31 December
USD million
2022
2021
Tangible assets
-195.8
-351.5
Intangible assets (including capitalized exploration expenses)
-76.9
-168.0
ARO provisions
226.2
266.6
Losses carried forward
167.6
155.5
Non-deductible interests carried forward
26.5
29.4
Other temporary differences
-0.9
-8.1
Net deferred tax assets/-liabilities
146.8
-76.0
Valuation allowance
-209.1
-162.0
Net deferred tax assets/-liabilities
-62.4
-238.0
Recognized deferred tax assets
-
29.3
Recognized deferred tax liabilities
-62.4
-267.3
A valuation allowance was recognized relating to carried
\u00a0
forward losses in Norway (ordinary tax regime)
\u00a0
and the UK due to the
uncertainty regarding future taxable profits.
Under the terms of the PSCs in Kurdistan, the
\u00a0
Company\u2019s subsidiary DNO Iraq AS is not required
\u00a0
to pay any corporate income taxes.
The share of profit oil which the government
\u00a0
is entitled to is deemed to include a portion
\u00a0
representing the notional corporate income tax
paid by the government on behalf of DNO Iraq
\u00a0
AS. Current and deferred taxation arising
\u00a0
from such notional corporate income tax is not
calculated for Kurdistan, as there is uncertainty related
\u00a0
to the tax laws of the KRG and there is
\u00a0
currently no well-established tax regime
for international oil companies. As such, it has not
\u00a0
been possible to reliably measure such notional
\u00a0
corporate income taxes deemed to
have been paid on behalf of DNO Iraq AS.
\u00a0
This is an accounting presentational issue and
\u00a0
there is no outstanding tax required to be paid
by DNO Iraq AS. See also Note 1.
\u00a0
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 (19 percent) and
\u00a0
the UKCS (40 percent). In the UK, the tax rate
\u00a0
in the
ordinary tax regime will increase to 25 percent
\u00a0
from April 2023. Additionally, in May 2022 the Energy Profits Levy (EPL) was
\u00a0
introduced
which is a new 25 percent temporary levy on oil
\u00a0
and gas ring fence profits, adjusted for decommissioning
\u00a0
spend. The rate will increase
to 35 percent from 1 January 2023. EPL did not
\u00a0
affect the 2022 results as the UK companies were loss-making.
\u00a0
The changes in tax
rates have not had any impact as deferred
\u00a0
tax asset has not been recognized on carried
\u00a0
forward losses and temporary differences in
the UK.
Reconciliation of change in deferred tax assets/-liabilities
Years ended 31 December
USD million
2022
2021
Net deferred tax assets/-liabilities at 1 January
-238.0
-131.4
Change in deferred taxes in the income statement
162.9
-115.2
Reclassification from/-to tax receivable
-15.3
-
Currency and other movements
28.0
8.6
Net deferred tax assets/-liabilities at 31 December
-62.4
-238.0
Reconciliation of change in tax receivable/-payable
Years ended 31 December
USD million
2022
2021
Net tax receivable/-payable at 1 January
-11.9
63.1
Tax receivable/-payable related to transactions
\u00a0
posted directly to balance sheet
0.9
3.7
Tax receivable/-payable in the income statement
-124.5
98.9
Tax payment/-refund
21.2
-174.7
Prior period adjustment
-0.5
-
Reclassification to/-from deferred tax asset
15.3
-
Currency and other movements
-0.4
-3.0
Net tax receivable/-payable at 31 December
-99.9
-11.9
Tax income/-expense
1 January - 31 December
USD million
2022
2021
Changes in deferred taxes
162.9
-115.2
Income taxes receivable/-payable
-124.5
98.9
Total tax income/-expense
38.4
-16.3
Income tax receivable/-payable
Years ended 31 December
USD million
2022
2021
Tax receivables
25.8
21.1
Income taxes payable
-125.7
-33.1
Net tax receivable/-payable
-99.9
-11.9
The tax balances relate to the activity on the Norwegian
\u00a0
Continental Shelf (NCS) and the UK Continental
\u00a0
Shelf (UKCS). The current tax
receivable relates to tax refunds of decommissioning
\u00a0
spend on the UKCS expected to be received
\u00a0
during the third quarter of 2023. The
current income taxes payable relates to taxable
\u00a0
profits in 2022 on the NCS and will be
\u00a0
paid during first half of 2023.
\u00a0
In June 2022, the Norwegian Parliament approved
\u00a0
certain changes to the taxation of oil and gas
\u00a0
companies operating on the NCS,
effective from 1 January 2022. The companies can expense
\u00a0
investments immediately in the special tax
\u00a0
basis and receive a cash refund
of the tax value of losses in the special tax basis.
\u00a0
The uplift on investments is discontinued
\u00a0
but will apply to the investments covered by
the temporary changes, as approved by the parliament
\u00a0
in June 2020. The ordinary corporate tax is deductible
\u00a0
in the special tax basis
and to maintain a combined marginal tax rate of
\u00a0
78 percent, the special tax rate is increased
\u00a0
to 71.8 percent. Losses in the corporate tax
basis are not eligible for refund but can be
\u00a0
carried forward. The tax value of unused uplift
\u00a0
and carried forward losses as of yearend 2021
will be paid out in connection with the 2022 tax assessment
\u00a0
in November 2023 or offset tax installments on 2022
\u00a0
taxable profits.
In December 2022, the Norwegian Parliament approved
\u00a0
a change to the uplift under the temporary tax
\u00a0
rules applying to PDOs delivered
by the end of 2022, from 17.69 percent to 12.4
\u00a0
percent, effective from 1 January 2023. The change to
\u00a0
the uplift adversely impacts the
economics of development projects under the temporary
\u00a0
rules.
During 2022, DNO received tax refunds of USD 17.7
\u00a0
million in the UK in relation to decommissioning
\u00a0
spend for 2021. In Norway, DNO
paid net USD 38.9 million which consisted of repayment
\u00a0
of refunds received during the second half of
\u00a0
2021 and the first three tax
installments on 2022 taxable profits.
Reconciliation of tax income/-expense
1 January - 31 December
USD million
2022
2021
Profit/-loss before income tax
346.5
220.1
Expected income tax according to nominal tax rate in Norway, 22 percent
-108.1
-52.4
Expected income tax according to nominal petroleum tax rate in Norway,
\u00a0
78 percent
43.3
24.3
Expected income tax according to nominal tax outside Norway
33.5
7.4
Foreign exchange variations between functional and tax currency
2.5
-4.5
Adjustment of previous years
0.7
0.2
Adjustment of deferred tax assets not recognized
-62.3
-31.0
Other items including other permanent differences
116.2
35.3
Change in tax rate
12.4
4.6
Tax income/-expense
38.4
-16.3
Effective income tax rate
-11.1%
-7.4%
Taxes charged to equity
-
-
Expected income tax related to activities on the NCS and
\u00a0
outside Norway is positive as the petroleum
\u00a0
activities in Norway and the UK
generated a loss before tax. Other items above
\u00a0
consist mainly of permanent differences on impairments
\u00a0
which are not tax deductible,
and permanent differences on tax exempted profits/losses
\u00a0
from upstream activities outside of Norway carried
\u00a0
out by the Company\u2019s
Norwegian subsidiaries.
Tax effects on temporary differences
Years ended 31 December
USD million
2022
2021
Tangible assets
-195.8
-351.5
Intangible assets (including capitalized exploration expenses)
-76.9
-168.0
ARO provisions
226.2
266.6
Losses carried forward
167.6
155.5
Non-deductible interests carried forward
26.5
29.4
Other temporary differences
-0.9
-8.1
Net deferred tax assets/-liabilities
146.8
-76.0
Valuation allowance
-209.1
-162.0
Net deferred tax assets/-liabilities
-62.4
-238.0
Recognized deferred tax assets
-
29.3
Recognized deferred tax liabilities
-62.4
-267.3
A valuation allowance was recognized relating to carried
\u00a0
forward losses in Norway (ordinary tax regime)
\u00a0
and the UK due to the
uncertainty regarding future taxable profits.
Under the terms of the PSCs in Kurdistan, the
\u00a0
Company\u2019s subsidiary DNO Iraq AS is not required
\u00a0
to pay any corporate income taxes.
The share of profit oil which the government
\u00a0
is entitled to is deemed to include a portion
\u00a0
representing the notional corporate income tax
paid by the government on behalf of DNO Iraq
\u00a0
AS. Current and deferred taxation arising
\u00a0
from such notional corporate income tax is not
calculated for Kurdistan, as there is uncertainty related
\u00a0
to the tax laws of the KRG and there is
\u00a0
currently no well-established tax regime
for international oil companies. As such, it has not
\u00a0
been possible to reliably measure such notional
\u00a0
corporate income taxes deemed to
have been paid on behalf of DNO Iraq AS.
\u00a0
This is an accounting presentational issue and
\u00a0
there is no outstanding tax required to be paid
by DNO Iraq AS. See also Note 1.
\u00a0
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 (19 percent) and
\u00a0
the UKCS (40 percent). In the UK, the tax rate
\u00a0
in the
ordinary tax regime will increase to 25 percent
\u00a0
from April 2023. Additionally, in May 2022 the Energy Profits Levy (EPL) was
\u00a0
introduced
which is a new 25 percent temporary levy on oil
\u00a0
and gas ring fence profits, adjusted for decommissioning
\u00a0
spend. The rate will increase
to 35 percent from 1 January 2023. EPL did not
\u00a0
affect the 2022 results as the UK companies were loss-making.
\u00a0
The changes in tax
rates have not had any impact as deferred
\u00a0
tax asset has not been recognized on carried
\u00a0
forward losses and temporary differences in
the UK.
Reconciliation of change in deferred tax assets/-liabilities
Years ended 31 December
USD million
2022
2021
Net deferred tax assets/-liabilities at 1 January
-238.0
-131.4
Change in deferred taxes in the income statement
162.9
-115.2
Reclassification from/-to tax receivable
-15.3
-
Currency and other movements
28.0
8.6
Net deferred tax assets/-liabilities at 31 December
-62.4
-238.0
Reconciliation of change in tax receivable/-payable
Years ended 31 December
USD million
2022
2021
Net tax receivable/-payable at 1 January
-11.9
63.1
Tax receivable/-payable related to transactions
\u00a0
posted directly to balance sheet
0.9
3.7
Tax receivable/-payable in the income statement
-124.5
98.9
Tax payment/-refund
21.2
-174.7
Prior period adjustment
-0.5
-
Reclassification to/-from deferred tax asset
15.3
-
Currency and other movements
-0.4
-3.0
Net tax receivable/-payable at 31 December
-99.9
-11.9
Tax income/-expense
1 January - 31 December
USD million
2022
2021
Changes in deferred taxes
162.9
-115.2
Income taxes receivable/-payable
-124.5
98.9
Total tax income/-expense
38.4
-16.3
Income tax receivable/-payable
Years ended 31 December
USD million
2022
2021
Tax receivables
25.8
21.1
Income taxes payable
-125.7
-33.1
Net tax receivable/-payable
-99.9
-11.9
The tax balances relate to the activity on the Norwegian
\u00a0
Continental Shelf (NCS) and the UK Continental
\u00a0
Shelf (UKCS). The current tax
receivable relates to tax refunds of decommissioning
\u00a0
spend on the UKCS expected to be received
\u00a0
during the third quarter of 2023. The
current income taxes payable relates to taxable
\u00a0
profits in 2022 on the NCS and will be
\u00a0
paid during first half of 2023.
\u00a0
In June 2022, the Norwegian Parliament approved
\u00a0
certain changes to the taxation of oil and gas
\u00a0
companies operating on the NCS,
effective from 1 January 2022. The companies can expense
\u00a0
investments immediately in the special tax
\u00a0
basis and receive a cash refund
of the tax value of losses in the special tax basis.
\u00a0
The uplift on investments is discontinued
\u00a0
but will apply to the investments covered by
the temporary changes, as approved by the parliament
\u00a0
in June 2020. The ordinary corporate tax is deductible
\u00a0
in the special tax basis
and to maintain a combined marginal tax rate of
\u00a0
78 percent, the special tax rate is increased
\u00a0
to 71.8 percent. Losses in the corporate tax
basis are not eligible for refund but can be
\u00a0
carried forward. The tax value of unused uplift
\u00a0
and carried forward losses as of yearend 2021
will be paid out in connection with the 2022 tax assessment
\u00a0
in November 2023 or offset tax installments on 2022
\u00a0
taxable profits.
In December 2022, the Norwegian Parliament approved
\u00a0
a change to the uplift under the temporary tax
\u00a0
rules applying to PDOs delivered
by the end of 2022, from 17.69 percent to 12.4
\u00a0
percent, effective from 1 January 2023. The change to
\u00a0
the uplift adversely impacts the
economics of development projects under the temporary
\u00a0
rules.
During 2022, DNO received tax refunds of USD 17.7
\u00a0
million in the UK in relation to decommissioning
\u00a0
spend for 2021. In Norway, DNO
paid net USD 38.9 million which consisted of repayment
\u00a0
of refunds received during the second half of
\u00a0
2021 and the first three tax
installments on 2022 taxable profits.
Reconciliation of tax income/-expense
1 January - 31 December
USD million
2022
2021
Profit/-loss before income tax
346.5
220.1
Expected income tax according to nominal tax rate in Norway, 22 percent
-108.1
-52.4
Expected income tax according to nominal petroleum tax rate in Norway,
\u00a0
78 percent
43.3
24.3
Expected income tax according to nominal tax outside Norway
33.5
7.4
Foreign exchange variations between functional and tax currency
2.5
-4.5
Adjustment of previous years
0.7
0.2
Adjustment of deferred tax assets not recognized
-62.3
-31.0
Other items including other permanent differences
116.2
35.3
Change in tax rate
12.4
4.6
Tax income/-expense
38.4
-16.3
Effective income tax rate
-11.1%
-7.4%
Taxes charged to equity
-
-
Expected income tax related to activities on the NCS and
\u00a0
outside Norway is positive as the petroleum
\u00a0
activities in Norway and the UK
generated a loss before tax. Other items above
\u00a0
consist mainly of permanent differences on impairments
\u00a0
which are not tax deductible,
and permanent differences on tax exempted profits/losses
\u00a0
from upstream activities outside of Norway carried
\u00a0
out by the Company\u2019s
Norwegian subsidiaries.
Tax effects on temporary differences
Years ended 31 December
USD million
2022
2021
Tangible assets
-195.8
-351.5
Intangible assets (including capitalized exploration expenses)
-76.9
-168.0
ARO provisions
226.2
266.6
Losses carried forward
167.6
155.5
Non-deductible interests carried forward
26.5
29.4
Other temporary differences
-0.9
-8.1
Net deferred tax assets/-liabilities
146.8
-76.0
Valuation allowance
-209.1
-162.0
Net deferred tax assets/-liabilities
-62.4
-238.0
Recognized deferred tax assets
-
29.3
Recognized deferred tax liabilities
-62.4
-267.3
A valuation allowance was recognized relating to carried
\u00a0
forward losses in Norway (ordinary tax regime)
\u00a0
and the UK due to the
uncertainty regarding future taxable profits.
Under the terms of the PSCs in Kurdistan, the
\u00a0
Company\u2019s subsidiary DNO Iraq AS is not required
\u00a0
to pay any corporate income taxes.
The share of profit oil which the government
\u00a0
is entitled to is deemed to include a portion
\u00a0
representing the notional corporate income tax
paid by the government on behalf of DNO Iraq
\u00a0
AS. Current and deferred taxation arising
\u00a0
from such notional corporate income tax is not
calculated for Kurdistan, as there is uncertainty related
\u00a0
to the tax laws of the KRG and there is
\u00a0
currently no well-established tax regime
for international oil companies. As such, it has not
\u00a0
been possible to reliably measure such notional
\u00a0
corporate income taxes deemed to
have been paid on behalf of DNO Iraq AS.
\u00a0
This is an accounting presentational issue and
\u00a0
there is no outstanding tax required to be paid
by DNO Iraq AS. See also Note 1.
\u00a0
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 (19 percent) and
\u00a0
the UKCS (40 percent). In the UK, the tax rate
\u00a0
in the
ordinary tax regime will increase to 25 percent
\u00a0
from April 2023. Additionally, in May 2022 the Energy Profits Levy (EPL) was
\u00a0
introduced
which is a new 25 percent temporary levy on oil
\u00a0
and gas ring fence profits, adjusted for decommissioning
\u00a0
spend. The rate will increase
to 35 percent from 1 January 2023. EPL did not
\u00a0
affect the 2022 results as the UK companies were loss-making.
\u00a0
The changes in tax
rates have not had any impact as deferred
\u00a0
tax asset has not been recognized on carried
\u00a0
forward losses and temporary differences in
the UK.
Reconciliation of change in deferred tax assets/-liabilities
Years ended 31 December
USD million
2022
2021
Net deferred tax assets/-liabilities at 1 January
-238.0
-131.4
Change in deferred taxes in the income statement
162.9
-115.2
Reclassification from/-to tax receivable
-15.3
-
Currency and other movements
28.0
8.6
Net deferred tax assets/-liabilities at 31 December
-62.4
-238.0
Reconciliation of change in tax receivable/-payable
Years ended 31 December
USD million
2022
2021
Net tax receivable/-payable at 1 January
-11.9
63.1
Tax receivable/-payable related to transactions
\u00a0
posted directly to balance sheet
0.9
3.7
Tax receivable/-payable in the income statement
-124.5
98.9
Tax payment/-refund
21.2
-174.7
Prior period adjustment
-0.5
-
Reclassification to/-from deferred tax asset
15.3
-
Currency and other movements
-0.4
-3.0
Net tax receivable/-payable at 31 December
-99.9
-11.9
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
Disposals acquisition costs
-
4.6
4.6
-
0.4
5.0
Disposals depreciation/impairments
-
-4.6
-4.6
-
-0.2
-4.8
Depreciation of RoU recognized against ARO
-
-
-
-
-6.7
-6.7
Impairments (net)
-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
14.3
34.2
3,479.0
Accumulated impairments
-140.6
-332.0
-472.7
-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
Depreciation method
UoP
* Includes changes in estimate of asset retirement, see Note 16.
** Transfers was 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
\u00a0
to cost of goods sold in the statements of comprehensive
\u00a0
income.
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2022 - USD million
Goodwill
interest
assets
assets
Total
As of 1 January 2022
Acquisition costs
456.8
98.1
368.4
14.6
481.1
938.0
Accumulated impairments
-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
Disposals cost price
-
-
-
-
-
-
Disposals impairments/depreciation
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-
-52.2
-
-52.2
-52.2
Impairments
-21.5
0.0
-0.0
-
0.0
-21.5
Depreciation
-
-1.9
-
-1.1
-3.0
-3.0
Closing net book amount
56.1
18.8
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
-
-269.3
-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
* Transfers was related to reclassification of the book value of Brasse license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
PROPERTY, PLANT AND EQUIPMENT
Total
Development
Production
oil & gas
Other
RoU
2021 - USD million
assets
assets
assets
PP&E
assets
Total
As of 1 January 2021
Acquisition costs
152.0
3,037.0
3,189.0
13.7
22.9
3,225.6
Accumulated impairments
-42.1
-358.6
-400.7
-0.1
-
-400.8
Accumulated depreciation
-
-1,632.3
-1,632.3
-11.7
-6.7
-1,650.6
Net book amount
109.9
1,046.1
1,155.9
2.0
16.2
1,174.1
Period ended 31 December 2021
Opening net book amount
109.9
1,046.1
1,155.9
2.0
16.2
1,174.1
Translation differences
-3.0
-15.8
-18.8
-
-1.7
-20.6
Additions*
15.5
190.6
206.2
0.2
14.6
221.0
Transfers**
125.7
4.0
129.7
-
-
129.7
Disposal cost price
-
-440.4
-440.4
-
-2.6
-443.0
Disposal impairments/depreciations
-
440.4
440.4
-
2.6
443.0
Depreciation of RoU recognized against ARO
-
-
-
-
-4.6
-4.6
Impairments
-
-11.6
-11.6
-
-
-11.6
Depreciation
-
-198.2
-198.2
-1.1
-3.9
-203.2
Closing net book amount
248.2
1,015.2
1,263.3
1.0
20.6
1,284.9
As of 31 December 2021
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
1,015.2
1,263.3
1.0
20.6
1,284.9
Depreciation method
UoP
Linear (3-7 years)
* Includes changes in estimate of asset retirement, see Note 16.
** Transfers was related to reclassification of the book value of Baeshiqa license from
\u00a0
exploration phase (intangible assets) to development phase
\u00a0
(tangible assets) and reclassification of the book value of Berling (previously named Iris/Hades).
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2021 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2021
Acquisition costs
474.3
97.1
389.2
14.3
500.5
974.9
Accumulated impairments/exploration write-offs
-312.3
-7.7
-108.3
-
-116.0
-428.3
Accumulated depreciation
-
-66.4
-
-9.5
-75.9
-75.9
Net book amount
162.0
23.0
280.9
4.7
308.6
470.6
Period ended 31 December 2021
Opening net book amount
162.0
23.0
280.9
4.7
308.6
470.6
Translation differences
-5.3
-
-9.6
0.2
-9.4
-14.7
Additions
-
1.0
85.3
0.4
86.7
86.8
Additions through license acquisition*
-
35.2
35.2
35.2
Transfers**
-
-
-125.7
-
-125.7
-125.7
Disposal cost price
-
-
-6.0
-0.3
-6.3
-6.3
Disposal impairments/depreciations
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-1.1
-53.0
-54.1
-54.1
Impairments
-68.5
-
-
-
-
-68.5
Depreciation
-
-1.8
-
-1.0
-2.8
-2.8
Closing net book amount
88.2
21.1
207.1
4.0
232.3
320.6
As of 31 December 2021
Acquisition costs
456.8
98.1
368.4
14.6
481.2
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
4.0
232.4
320.6
Depreciation method
UoP
Linear (3-7 years)
* Addition through license acquisition was related to DNO's acquisition of ExxonMobil's remaining 32 percent interest in the
\u00a0
Baeshiqa license, approved
\u00a0
by the KRG in August 2021.
\u00a0
** Transfers was related to reclassification of the book value of Baeshiqa license from
\u00a0
exploration phase (intangible assets) to development phase
\u00a0
(tangible assets) and reclassification of the book value of Berling (previously named Iris/Hades).
Impairment testing
At each reporting date, the Group assesses whether
\u00a0
there is an indication that an asset may be
\u00a0
impaired. An assessment of the
recoverable amount is made when an impairment
\u00a0
indicator exists. Goodwill is tested for impairment
\u00a0
annually or more frequently when
there are impairment indicators. Impairment is recognized
\u00a0
when the carrying amount of an asset or
\u00a0
a CGU, including associated
goodwill, exceeds the recoverable amount. The recoverable
\u00a0
amount is the higher of the asset\u2019s fair value
\u00a0
less cost to sell and the value
in use. Impairment assessment of DNO\u2019s assets in Kurdistan
\u00a0
is based on the value in use approach. For
\u00a0
oil and gas assets and goodwill
recognized in relation to the acquisition of Faroe
\u00a0
Petroleum Plc, the impairment assessment is
\u00a0
based on the fair value approach (level 3
in fair value hierarchy, IFRS 13). For both the value in use and fair value,
\u00a0
the impairment testing is performed based on
\u00a0
discounted cash
flows. The expected future cash flows are discounted
\u00a0
to the net present value by applying a
\u00a0
discount rate after tax. Cash flows are
projected for the estimated lifetime of the fields or
\u00a0
license, which may exceed periods longer
\u00a0
than five years.
\u00a0
Below is an overview of the key assumptions
\u00a0
applied for impairment assessment purposes as of
\u00a0
31 December 2022.
\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 2022 were
\u00a0
as follows (yearend 2021 in
brackets):
2023
2024
2025
2026
Brent (USD/bbl)
86.6 (76.9)
88.5 (70.4)
85.0 (68.3)
78.4 (70.0)
NBP (pence/therm)
289.0 (158.3)
179.4 (77.4)
126.4 (65.5)
102.9 (57.6)
For periods after year 2026, 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 2022).
\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 23.
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 2022 was 16.1
\u00a0
percent (13.6 percent at
yearend 2021) for the Kurdistan assets. For the
\u00a0
fair value calculations, the relevant post-tax
\u00a0
nominal discount rates at yearend 2022
was 8.4 percent for the North Sea assets (7.7 percent
\u00a0
at yearend 2021).
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
2021). 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
2022, was USD/NOK 9.5 for the years 2023
\u00a0
and 2024 and thereafter kept
constant at USD/NOK 9.0 from the year 2025 onwards.
Impairment charge and reversal
The following table shows the recoverable amounts
\u00a0
and net impairment charges or reversal for
\u00a0
the CGUs which were impaired in 2022
and 2021, and how it was recognized in
\u00a0
the income statement and the balance sheet.
Full-Year ended 31 December 2022
Income statement:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
Tax
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
(post-tax)
Goodwill
assets
equipment
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
Full-Year ended 31 December 2021
Income statement:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
Tax
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
(post-tax)
Goodwill
assets
equipment
effects
Fenja, North Sea
54.0
-9.7
-9.7
-9.7
-
-
-
-0.1
Trym area, North Sea
9.0
-7.7
-7.7
-7.7
-
-
-
-0.3
Ula area, North Sea
158.0
-51.1
-51.1
-51.1
-
-
-
0.4
Oselvar, North Sea
-
1.5
-1.2
0.3
-
-
1.5
-1.2
-
Schooner and Ketch, North Sea
-
-11.2
4.1
-7.1
-
-
-11.2
4.1
-
Other CGUs, North Sea
-
-1.9
-
-1.9
-
-
-1.9
-
-
Total
-80.1
2.9
-77.2
-68.5
-
-11.6
2.9
-
During 2022, a total impairment charge of USD 371.3
\u00a0
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
Revised reserves and resource estimates, and cost profiles
\u00a0
(Ula area CGU);
\u2022
Revision in the cost estimate for decommissioning (Schooner
\u00a0
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).
During 2021, a total impairment charge of USD
\u00a0
80.1 million (USD 77.2 million post-tax) was
\u00a0
recognized, mainly driven by:
\u00a0
\u2022
Revised reserves and resource estimates (Fenja development);
\u00a0
\u2022
Revised reserves and resource estimates, and cost profiles
\u00a0
(Ula area CGU, Trym area CGU); and
\u2022
Revision in the cost estimate for decommissioning (Schooner
\u00a0
and Ketch fields, Oselvar field, and other
\u00a0
CGUs).
Sensitivities
The table below illustrates how the net profit/-loss
\u00a0
in 2022 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
-
-12
Reserves (2P) and resources (2C)
-
-1
Discount rate (WACC)
-
-
Currency rate (USD/NOK)
-
-3
Climate considerations in impairment assessment
Certain climate considerations are factored into the Group\u2019s
\u00a0
estimation of cash flows that are applied in the
\u00a0
calculation of recoverable
amount. This includes factoring in current legislation (e.g.,
\u00a0
environmental taxes/fees) and estimation of
\u00a0
future levels of environmental
taxes. For DNO\u2019s oil and gas assets on the NCS,
\u00a0
carbon pricing is in line with current legislation and
\u00a0
reflects the operator\u2019s 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 CO
2
\u00a0
tax) to NOK 2,000 per tonne (in 2020 real
\u00a0
terms) is expected by 2030. In Kurdistan, the
\u00a0
KRG introduced in 2021 a
requirement for oil companies to put plans in place
\u00a0
to curb gas flaring to reduce emissions.
\u00a0
The Company has run sensitivities for its
Kurdistan oil assets with the CO2 tax assumptions as
\u00a0
described in the scenarios described by the
\u00a0
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 oil
\u00a0
and gas prices where supply and demand
\u00a0
are
considered. A significant reduction in the Company\u2019s oil
\u00a0
and gas price assumptions would result in impairments
\u00a0
on certain production
and development assets including intangible assets that
\u00a0
are subject to impairment assessment under IAS
\u00a0
36, but an opposite revision in
the price assumptions would only lead to limited
\u00a0
impairment reversals as most of the impairments
\u00a0
recognized by the Group were related
to impairment of goodwill which cannot be reversed
\u00a0
under IFRS.
\u00a0
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 scenarios outlined by the IEA, namely
\u00a0
the Net Zero Emissions Scenario by 2050, 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 2021
\u00a0
real terms), and for the sensitivity
calculation a linear development between average
\u00a0
actual 2022 and 2030, as well as between
\u00a0
2030 and 2050 have been applied. The
table below summarizes how the reported net profit would
\u00a0
be impacted by an increase (+) or decrease
\u00a0
(-) in impairment charge using
the oil and gas price assumptions in the following
\u00a0
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
82
95
8.5
-
64
60
7.9
-
Net Zero Emissions by 2050
35
24
4.6
-44
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;
\u00a0
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
\u00a0
and economic cut-off (in brackets) dates were applied
\u00a0
in relation to yearend 2022
impairment assessments; the Ula area CGU have
\u00a0
license expiry dates that ranges between 2027
\u00a0
and 2036 (economic cut-off assumed
to be at the end of 2026); the Ringhorne
\u00a0
East license expires in 2030 (2046); the Brage
\u00a0
license expires in 2030 (2028); the Trym license
expires in 2027 (2026); the Alve license expires
\u00a0
in 2029 (2029); an application for extension
\u00a0
of the Marulk license from 2025 to 2026 has
been submitted and is pending approval (2026);
\u00a0
the Vilje license expires in 2032 (2040); the Fenja
\u00a0
license expires in 2039 (2037); and
the Berling license expires in 2023 (2033, application
\u00a0
for license extension was included in the PDO
\u00a0
submission, subject to approval).
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
Disposals acquisition costs
-
4.6
4.6
-
0.4
5.0
Disposals depreciation/impairments
-
-4.6
-4.6
-
-0.2
-4.8
Depreciation of RoU recognized against ARO
-
-
-
-
-6.7
-6.7
Impairments (net)
-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
14.3
34.2
3,479.0
Accumulated impairments
-140.6
-332.0
-472.7
-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
Depreciation method
UoP
* Includes changes in estimate of asset retirement, see Note 16.
** Transfers was 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
\u00a0
to cost of goods sold in the statements of comprehensive
\u00a0
income.
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2022 - USD million
Goodwill
interest
assets
assets
Total
As of 1 January 2022
Acquisition costs
456.8
98.1
368.4
14.6
481.1
938.0
Accumulated impairments
-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
Disposals cost price
-
-
-
-
-
-
Disposals impairments/depreciation
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-
-52.2
-
-52.2
-52.2
Impairments
-21.5
0.0
-0.0
-
0.0
-21.5
Depreciation
-
-1.9
-
-1.1
-3.0
-3.0
Closing net book amount
56.1
18.8
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
-
-269.3
-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
* Transfers was related to reclassification of the book value of Brasse license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
PROPERTY, PLANT AND EQUIPMENT
Total
Development
Production
oil & gas
Other
RoU
2021 - USD million
assets
assets
assets
PP&E
assets
Total
As of 1 January 2021
Acquisition costs
152.0
3,037.0
3,189.0
13.7
22.9
3,225.6
Accumulated impairments
-42.1
-358.6
-400.7
-0.1
-
-400.8
Accumulated depreciation
-
-1,632.3
-1,632.3
-11.7
-6.7
-1,650.6
Net book amount
109.9
1,046.1
1,155.9
2.0
16.2
1,174.1
Period ended 31 December 2021
Opening net book amount
109.9
1,046.1
1,155.9
2.0
16.2
1,174.1
Translation differences
-3.0
-15.8
-18.8
-
-1.7
-20.6
Additions*
15.5
190.6
206.2
0.2
14.6
221.0
Transfers**
125.7
4.0
129.7
-
-
129.7
Disposal cost price
-
-440.4
-440.4
-
-2.6
-443.0
Disposal impairments/depreciations
-
440.4
440.4
-
2.6
443.0
Depreciation of RoU recognized against ARO
-
-
-
-
-4.6
-4.6
Impairments
-
-11.6
-11.6
-
-
-11.6
Depreciation
-
-198.2
-198.2
-1.1
-3.9
-203.2
Closing net book amount
248.2
1,015.2
1,263.3
1.0
20.6
1,284.9
As of 31 December 2021
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
1,015.2
1,263.3
1.0
20.6
1,284.9
Depreciation method
UoP
Linear (3-7 years)
* Includes changes in estimate of asset retirement, see Note 16.
** Transfers was related to reclassification of the book value of Baeshiqa license from
\u00a0
exploration phase (intangible assets) to development phase
\u00a0
(tangible assets) and reclassification of the book value of Berling (previously named Iris/Hades).
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2021 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2021
Acquisition costs
474.3
97.1
389.2
14.3
500.5
974.9
Accumulated impairments/exploration write-offs
-312.3
-7.7
-108.3
-
-116.0
-428.3
Accumulated depreciation
-
-66.4
-
-9.5
-75.9
-75.9
Net book amount
162.0
23.0
280.9
4.7
308.6
470.6
Period ended 31 December 2021
Opening net book amount
162.0
23.0
280.9
4.7
308.6
470.6
Translation differences
-5.3
-
-9.6
0.2
-9.4
-14.7
Additions
-
1.0
85.3
0.4
86.7
86.8
Additions through license acquisition*
-
35.2
35.2
35.2
Transfers**
-
-
-125.7
-
-125.7
-125.7
Disposal cost price
-
-
-6.0
-0.3
-6.3
-6.3
Disposal impairments/depreciations
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-1.1
-53.0
-54.1
-54.1
Impairments
-68.5
-
-
-
-
-68.5
Depreciation
-
-1.8
-
-1.0
-2.8
-2.8
Closing net book amount
88.2
21.1
207.1
4.0
232.3
320.6
As of 31 December 2021
Acquisition costs
456.8
98.1
368.4
14.6
481.2
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
4.0
232.4
320.6
Depreciation method
UoP
Linear (3-7 years)
* Addition through license acquisition was related to DNO's acquisition of ExxonMobil's remaining 32 percent interest in the
\u00a0
Baeshiqa license, approved
\u00a0
by the KRG in August 2021.
\u00a0
** Transfers was related to reclassification of the book value of Baeshiqa license from
\u00a0
exploration phase (intangible assets) to development phase
\u00a0
(tangible assets) and reclassification of the book value of Berling (previously named Iris/Hades).
Impairment testing
At each reporting date, the Group assesses whether
\u00a0
there is an indication that an asset may be
\u00a0
impaired. An assessment of the
recoverable amount is made when an impairment
\u00a0
indicator exists. Goodwill is tested for impairment
\u00a0
annually or more frequently when
there are impairment indicators. Impairment is recognized
\u00a0
when the carrying amount of an asset or
\u00a0
a CGU, including associated
goodwill, exceeds the recoverable amount. The recoverable
\u00a0
amount is the higher of the asset\u2019s fair value
\u00a0
less cost to sell and the value
in use. Impairment assessment of DNO\u2019s assets in Kurdistan
\u00a0
is based on the value in use approach. For
\u00a0
oil and gas assets and goodwill
recognized in relation to the acquisition of Faroe
\u00a0
Petroleum Plc, the impairment assessment is
\u00a0
based on the fair value approach (level 3
in fair value hierarchy, IFRS 13). For both the value in use and fair value,
\u00a0
the impairment testing is performed based on
\u00a0
discounted cash
flows. The expected future cash flows are discounted
\u00a0
to the net present value by applying a
\u00a0
discount rate after tax. Cash flows are
projected for the estimated lifetime of the fields or
\u00a0
license, which may exceed periods longer
\u00a0
than five years.
\u00a0
Below is an overview of the key assumptions
\u00a0
applied for impairment assessment purposes as of
\u00a0
31 December 2022.
\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 2022 were
\u00a0
as follows (yearend 2021 in
brackets):
2023
2024
2025
2026
Brent (USD/bbl)
86.6 (76.9)
88.5 (70.4)
85.0 (68.3)
78.4 (70.0)
NBP (pence/therm)
289.0 (158.3)
179.4 (77.4)
126.4 (65.5)
102.9 (57.6)
For periods after year 2026, 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 2022).
\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 23.
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 2022 was 16.1
\u00a0
percent (13.6 percent at
yearend 2021) for the Kurdistan assets. For the
\u00a0
fair value calculations, the relevant post-tax
\u00a0
nominal discount rates at yearend 2022
was 8.4 percent for the North Sea assets (7.7 percent
\u00a0
at yearend 2021).
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
2021). 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
2022, was USD/NOK 9.5 for the years 2023
\u00a0
and 2024 and thereafter kept
constant at USD/NOK 9.0 from the year 2025 onwards.
Impairment charge and reversal
The following table shows the recoverable amounts
\u00a0
and net impairment charges or reversal for
\u00a0
the CGUs which were impaired in 2022
and 2021, and how it was recognized in
\u00a0
the income statement and the balance sheet.
Full-Year ended 31 December 2022
Income statement:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
Tax
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
(post-tax)
Goodwill
assets
equipment
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
Full-Year ended 31 December 2021
Income statement:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
Tax
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
(post-tax)
Goodwill
assets
equipment
effects
Fenja, North Sea
54.0
-9.7
-9.7
-9.7
-
-
-
-0.1
Trym area, North Sea
9.0
-7.7
-7.7
-7.7
-
-
-
-0.3
Ula area, North Sea
158.0
-51.1
-51.1
-51.1
-
-
-
0.4
Oselvar, North Sea
-
1.5
-1.2
0.3
-
-
1.5
-1.2
-
Schooner and Ketch, North Sea
-
-11.2
4.1
-7.1
-
-
-11.2
4.1
-
Other CGUs, North Sea
-
-1.9
-
-1.9
-
-
-1.9
-
-
Total
-80.1
2.9
-77.2
-68.5
-
-11.6
2.9
-
During 2022, a total impairment charge of USD 371.3
\u00a0
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
Revised reserves and resource estimates, and cost profiles
\u00a0
(Ula area CGU);
\u2022
Revision in the cost estimate for decommissioning (Schooner
\u00a0
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).
During 2021, a total impairment charge of USD
\u00a0
80.1 million (USD 77.2 million post-tax) was
\u00a0
recognized, mainly driven by:
\u00a0
\u2022
Revised reserves and resource estimates (Fenja development);
\u00a0
\u2022
Revised reserves and resource estimates, and cost profiles
\u00a0
(Ula area CGU, Trym area CGU); and
\u2022
Revision in the cost estimate for decommissioning (Schooner
\u00a0
and Ketch fields, Oselvar field, and other
\u00a0
CGUs).
Sensitivities
The table below illustrates how the net profit/-loss
\u00a0
in 2022 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
-
-12
Reserves (2P) and resources (2C)
-
-1
Discount rate (WACC)
-
-
Currency rate (USD/NOK)
-
-3
Climate considerations in impairment assessment
Certain climate considerations are factored into the Group\u2019s
\u00a0
estimation of cash flows that are applied in the
\u00a0
calculation of recoverable
amount. This includes factoring in current legislation (e.g.,
\u00a0
environmental taxes/fees) and estimation of
\u00a0
future levels of environmental
taxes. For DNO\u2019s oil and gas assets on the NCS,
\u00a0
carbon pricing is in line with current legislation and
\u00a0
reflects the operator\u2019s 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 CO
2
\u00a0
tax) to NOK 2,000 per tonne (in 2020 real
\u00a0
terms) is expected by 2030. In Kurdistan, the
\u00a0
KRG introduced in 2021 a
requirement for oil companies to put plans in place
\u00a0
to curb gas flaring to reduce emissions.
\u00a0
The Company has run sensitivities for its
Kurdistan oil assets with the CO2 tax assumptions as
\u00a0
described in the scenarios described by the
\u00a0
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 oil
\u00a0
and gas prices where supply and demand
\u00a0
are
considered. A significant reduction in the Company\u2019s oil
\u00a0
and gas price assumptions would result in impairments
\u00a0
on certain production
and development assets including intangible assets that
\u00a0
are subject to impairment assessment under IAS
\u00a0
36, but an opposite revision in
the price assumptions would only lead to limited
\u00a0
impairment reversals as most of the impairments
\u00a0
recognized by the Group were related
to impairment of goodwill which cannot be reversed
\u00a0
under IFRS.
\u00a0
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 scenarios outlined by the IEA, namely
\u00a0
the Net Zero Emissions Scenario by 2050, 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 2021
\u00a0
real terms), and for the sensitivity
calculation a linear development between average
\u00a0
actual 2022 and 2030, as well as between
\u00a0
2030 and 2050 have been applied. The
table below summarizes how the reported net profit would
\u00a0
be impacted by an increase (+) or decrease
\u00a0
(-) in impairment charge using
the oil and gas price assumptions in the following
\u00a0
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
82
95
8.5
-
64
60
7.9
-
Net Zero Emissions by 2050
35
24
4.6
-44
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;
\u00a0
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
\u00a0
and economic cut-off (in brackets) dates were applied
\u00a0
in relation to yearend 2022
impairment assessments; the Ula area CGU have
\u00a0
license expiry dates that ranges between 2027
\u00a0
and 2036 (economic cut-off assumed
to be at the end of 2026); the Ringhorne
\u00a0
East license expires in 2030 (2046); the Brage
\u00a0
license expires in 2030 (2028); the Trym license
expires in 2027 (2026); the Alve license expires
\u00a0
in 2029 (2029); an application for extension
\u00a0
of the Marulk license from 2025 to 2026 has
been submitted and is pending approval (2026);
\u00a0
the Vilje license expires in 2032 (2040); the Fenja
\u00a0
license expires in 2039 (2037); and
the Berling license expires in 2023 (2033, application
\u00a0
for license extension was included in the PDO
\u00a0
submission, subject to approval).
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
Disposals acquisition costs
-
4.6
4.6
-
0.4
5.0
Disposals depreciation/impairments
-
-4.6
-4.6
-
-0.2
-4.8
Depreciation of RoU recognized against ARO
-
-
-
-
-6.7
-6.7
Impairments (net)
-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
14.3
34.2
3,479.0
Accumulated impairments
-140.6
-332.0
-472.7
-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
Depreciation method
UoP
* Includes changes in estimate of asset retirement, see Note 16.
** Transfers was 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
\u00a0
to cost of goods sold in the statements of comprehensive
\u00a0
income.
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2022 - USD million
Goodwill
interest
assets
assets
Total
As of 1 January 2022
Acquisition costs
456.8
98.1
368.4
14.6
481.1
938.0
Accumulated impairments
-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
Disposals cost price
-
-
-
-
-
-
Disposals impairments/depreciation
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-
-52.2
-
-52.2
-52.2
Impairments
-21.5
0.0
-0.0
-
0.0
-21.5
Depreciation
-
-1.9
-
-1.1
-3.0
-3.0
Closing net book amount
56.1
18.8
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
-
-269.3
-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
* Transfers was related to reclassification of the book value of Brasse license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
PROPERTY, PLANT AND EQUIPMENT
Total
Development
Production
oil & gas
Other
RoU
2021 - USD million
assets
assets
assets
PP&E
assets
Total
As of 1 January 2021
Acquisition costs
152.0
3,037.0
3,189.0
13.7
22.9
3,225.6
Accumulated impairments
-42.1
-358.6
-400.7
-0.1
-
-400.8
Accumulated depreciation
-
-1,632.3
-1,632.3
-11.7
-6.7
-1,650.6
Net book amount
109.9
1,046.1
1,155.9
2.0
16.2
1,174.1
Period ended 31 December 2021
Opening net book amount
109.9
1,046.1
1,155.9
2.0
16.2
1,174.1
Translation differences
-3.0
-15.8
-18.8
-
-1.7
-20.6
Additions*
15.5
190.6
206.2
0.2
14.6
221.0
Transfers**
125.7
4.0
129.7
-
-
129.7
Disposal cost price
-
-440.4
-440.4
-
-2.6
-443.0
Disposal impairments/depreciations
-
440.4
440.4
-
2.6
443.0
Depreciation of RoU recognized against ARO
-
-
-
-
-4.6
-4.6
Impairments
-
-11.6
-11.6
-
-
-11.6
Depreciation
-
-198.2
-198.2
-1.1
-3.9
-203.2
Closing net book amount
248.2
1,015.2
1,263.3
1.0
20.6
1,284.9
As of 31 December 2021
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
1,015.2
1,263.3
1.0
20.6
1,284.9
Depreciation method
UoP
Linear (3-7 years)
* Includes changes in estimate of asset retirement, see Note 16.
** Transfers was related to reclassification of the book value of Baeshiqa license from
\u00a0
exploration phase (intangible assets) to development phase
\u00a0
(tangible assets) and reclassification of the book value of Berling (previously named Iris/Hades).
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2021 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2021
Acquisition costs
474.3
97.1
389.2
14.3
500.5
974.9
Accumulated impairments/exploration write-offs
-312.3
-7.7
-108.3
-
-116.0
-428.3
Accumulated depreciation
-
-66.4
-
-9.5
-75.9
-75.9
Net book amount
162.0
23.0
280.9
4.7
308.6
470.6
Period ended 31 December 2021
Opening net book amount
162.0
23.0
280.9
4.7
308.6
470.6
Translation differences
-5.3
-
-9.6
0.2
-9.4
-14.7
Additions
-
1.0
85.3
0.4
86.7
86.8
Additions through license acquisition*
-
35.2
35.2
35.2
Transfers**
-
-
-125.7
-
-125.7
-125.7
Disposal cost price
-
-
-6.0
-0.3
-6.3
-6.3
Disposal impairments/depreciations
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-1.1
-53.0
-54.1
-54.1
Impairments
-68.5
-
-
-
-
-68.5
Depreciation
-
-1.8
-
-1.0
-2.8
-2.8
Closing net book amount
88.2
21.1
207.1
4.0
232.3
320.6
As of 31 December 2021
Acquisition costs
456.8
98.1
368.4
14.6
481.2
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
4.0
232.4
320.6
Depreciation method
UoP
Linear (3-7 years)
* Addition through license acquisition was related to DNO's acquisition of ExxonMobil's remaining 32 percent interest in the
\u00a0
Baeshiqa license, approved
\u00a0
by the KRG in August 2021.
\u00a0
** Transfers was related to reclassification of the book value of Baeshiqa license from
\u00a0
exploration phase (intangible assets) to development phase
\u00a0
(tangible assets) and reclassification of the book value of Berling (previously named Iris/Hades).
Impairment testing
At each reporting date, the Group assesses whether
\u00a0
there is an indication that an asset may be
\u00a0
impaired. An assessment of the
recoverable amount is made when an impairment
\u00a0
indicator exists. Goodwill is tested for impairment
\u00a0
annually or more frequently when
there are impairment indicators. Impairment is recognized
\u00a0
when the carrying amount of an asset or
\u00a0
a CGU, including associated
goodwill, exceeds the recoverable amount. The recoverable
\u00a0
amount is the higher of the asset\u2019s fair value
\u00a0
less cost to sell and the value
in use. Impairment assessment of DNO\u2019s assets in Kurdistan
\u00a0
is based on the value in use approach. For
\u00a0
oil and gas assets and goodwill
recognized in relation to the acquisition of Faroe
\u00a0
Petroleum Plc, the impairment assessment is
\u00a0
based on the fair value approach (level 3
in fair value hierarchy, IFRS 13). For both the value in use and fair value,
\u00a0
the impairment testing is performed based on
\u00a0
discounted cash
flows. The expected future cash flows are discounted
\u00a0
to the net present value by applying a
\u00a0
discount rate after tax. Cash flows are
projected for the estimated lifetime of the fields or
\u00a0
license, which may exceed periods longer
\u00a0
than five years.
\u00a0
Below is an overview of the key assumptions
\u00a0
applied for impairment assessment purposes as of
\u00a0
31 December 2022.
\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 2022 were
\u00a0
as follows (yearend 2021 in
brackets):
2023
2024
2025
2026
Brent (USD/bbl)
86.6 (76.9)
88.5 (70.4)
85.0 (68.3)
78.4 (70.0)
NBP (pence/therm)
289.0 (158.3)
179.4 (77.4)
126.4 (65.5)
102.9 (57.6)
For periods after year 2026, 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 2022).
\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 23.
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 2022 was 16.1
\u00a0
percent (13.6 percent at
yearend 2021) for the Kurdistan assets. For the
\u00a0
fair value calculations, the relevant post-tax
\u00a0
nominal discount rates at yearend 2022
was 8.4 percent for the North Sea assets (7.7 percent
\u00a0
at yearend 2021).
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
2021). 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
2022, was USD/NOK 9.5 for the years 2023
\u00a0
and 2024 and thereafter kept
constant at USD/NOK 9.0 from the year 2025 onwards.
Impairment charge and reversal
The following table shows the recoverable amounts
\u00a0
and net impairment charges or reversal for
\u00a0
the CGUs which were impaired in 2022
and 2021, and how it was recognized in
\u00a0
the income statement and the balance sheet.
Full-Year ended 31 December 2022
Income statement:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
Tax
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
(post-tax)
Goodwill
assets
equipment
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
Full-Year ended 31 December 2021
Income statement:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
Tax
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
(post-tax)
Goodwill
assets
equipment
effects
Fenja, North Sea
54.0
-9.7
-9.7
-9.7
-
-
-
-0.1
Trym area, North Sea
9.0
-7.7
-7.7
-7.7
-
-
-
-0.3
Ula area, North Sea
158.0
-51.1
-51.1
-51.1
-
-
-
0.4
Oselvar, North Sea
-
1.5
-1.2
0.3
-
-
1.5
-1.2
-
Schooner and Ketch, North Sea
-
-11.2
4.1
-7.1
-
-
-11.2
4.1
-
Other CGUs, North Sea
-
-1.9
-
-1.9
-
-
-1.9
-
-
Total
-80.1
2.9
-77.2
-68.5
-
-11.6
2.9
-
During 2022, a total impairment charge of USD 371.3
\u00a0
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
Revised reserves and resource estimates, and cost profiles
\u00a0
(Ula area CGU);
\u2022
Revision in the cost estimate for decommissioning (Schooner
\u00a0
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).
During 2021, a total impairment charge of USD
\u00a0
80.1 million (USD 77.2 million post-tax) was
\u00a0
recognized, mainly driven by:
\u00a0
\u2022
Revised reserves and resource estimates (Fenja development);
\u00a0
\u2022
Revised reserves and resource estimates, and cost profiles
\u00a0
(Ula area CGU, Trym area CGU); and
\u2022
Revision in the cost estimate for decommissioning (Schooner
\u00a0
and Ketch fields, Oselvar field, and other
\u00a0
CGUs).
Sensitivities
The table below illustrates how the net profit/-loss
\u00a0
in 2022 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
-
-12
Reserves (2P) and resources (2C)
-
-1
Discount rate (WACC)
-
-
Currency rate (USD/NOK)
-
-3
Climate considerations in impairment assessment
Certain climate considerations are factored into the Group\u2019s
\u00a0
estimation of cash flows that are applied in the
\u00a0
calculation of recoverable
amount. This includes factoring in current legislation (e.g.,
\u00a0
environmental taxes/fees) and estimation of
\u00a0
future levels of environmental
taxes. For DNO\u2019s oil and gas assets on the NCS,
\u00a0
carbon pricing is in line with current legislation and
\u00a0
reflects the operator\u2019s 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 CO
2
\u00a0
tax) to NOK 2,000 per tonne (in 2020 real
\u00a0
terms) is expected by 2030. In Kurdistan, the
\u00a0
KRG introduced in 2021 a
requirement for oil companies to put plans in place
\u00a0
to curb gas flaring to reduce emissions.
\u00a0
The Company has run sensitivities for its
Kurdistan oil assets with the CO2 tax assumptions as
\u00a0
described in the scenarios described by the
\u00a0
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 oil
\u00a0
and gas prices where supply and demand
\u00a0
are
considered. A significant reduction in the Company\u2019s oil
\u00a0
and gas price assumptions would result in impairments
\u00a0
on certain production
and development assets including intangible assets that
\u00a0
are subject to impairment assessment under IAS
\u00a0
36, but an opposite revision in
the price assumptions would only lead to limited
\u00a0
impairment reversals as most of the impairments
\u00a0
recognized by the Group were related
to impairment of goodwill which cannot be reversed
\u00a0
under IFRS.
\u00a0
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 scenarios outlined by the IEA, namely
\u00a0
the Net Zero Emissions Scenario by 2050, 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 2021
\u00a0
real terms), and for the sensitivity
calculation a linear development between average
\u00a0
actual 2022 and 2030, as well as between
\u00a0
2030 and 2050 have been applied. The
table below summarizes how the reported net profit would
\u00a0
be impacted by an increase (+) or decrease
\u00a0
(-) in impairment charge using
the oil and gas price assumptions in the following
\u00a0
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
82
95
8.5
-
64
60
7.9
-
Net Zero Emissions by 2050
35
24
4.6
-44
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;
\u00a0
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
\u00a0
and economic cut-off (in brackets) dates were applied
\u00a0
in relation to yearend 2022
impairment assessments; the Ula area CGU have
\u00a0
license expiry dates that ranges between 2027
\u00a0
and 2036 (economic cut-off assumed
to be at the end of 2026); the Ringhorne
\u00a0
East license expires in 2030 (2046); the Brage
\u00a0
license expires in 2030 (2028); the Trym license
expires in 2027 (2026); the Alve license expires
\u00a0
in 2029 (2029); an application for extension
\u00a0
of the Marulk license from 2025 to 2026 has
been submitted and is pending approval (2026);
\u00a0
the Vilje license expires in 2032 (2040); the Fenja
\u00a0
license expires in 2039 (2037); and
the Berling license expires in 2023 (2033, application
\u00a0
for license extension was included in the PDO
\u00a0
submission, subject to approval).
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
Disposals acquisition costs
-
4.6
4.6
-
0.4
5.0
Disposals depreciation/impairments
-
-4.6
-4.6
-
-0.2
-4.8
Depreciation of RoU recognized against ARO
-
-
-
-
-6.7
-6.7
Impairments (net)
-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
14.3
34.2
3,479.0
Accumulated impairments
-140.6
-332.0
-472.7
-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
Depreciation method
UoP
* Includes changes in estimate of asset retirement, see Note 16.
** Transfers was 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
\u00a0
to cost of goods sold in the statements of comprehensive
\u00a0
income.
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2022 - USD million
Goodwill
interest
assets
assets
Total
As of 1 January 2022
Acquisition costs
456.8
98.1
368.4
14.6
481.1
938.0
Accumulated impairments
-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
Disposals cost price
-
-
-
-
-
-
Disposals impairments/depreciation
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-
-52.2
-
-52.2
-52.2
Impairments
-21.5
0.0
-0.0
-
0.0
-21.5
Depreciation
-
-1.9
-
-1.1
-3.0
-3.0
Closing net book amount
56.1
18.8
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
-
-269.3
-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
* Transfers was related to reclassification of the book value of Brasse license from exploration
\u00a0
phase (intangible assets) to development phase (tangible assets).
PROPERTY, PLANT AND EQUIPMENT
Total
Development
Production
oil & gas
Other
RoU
2021 - USD million
assets
assets
assets
PP&E
assets
Total
As of 1 January 2021
Acquisition costs
152.0
3,037.0
3,189.0
13.7
22.9
3,225.6
Accumulated impairments
-42.1
-358.6
-400.7
-0.1
-
-400.8
Accumulated depreciation
-
-1,632.3
-1,632.3
-11.7
-6.7
-1,650.6
Net book amount
109.9
1,046.1
1,155.9
2.0
16.2
1,174.1
Period ended 31 December 2021
Opening net book amount
109.9
1,046.1
1,155.9
2.0
16.2
1,174.1
Translation differences
-3.0
-15.8
-18.8
-
-1.7
-20.6
Additions*
15.5
190.6
206.2
0.2
14.6
221.0
Transfers**
125.7
4.0
129.7
-
-
129.7
Disposal cost price
-
-440.4
-440.4
-
-2.6
-443.0
Disposal impairments/depreciations
-
440.4
440.4
-
2.6
443.0
Depreciation of RoU recognized against ARO
-
-
-
-
-4.6
-4.6
Impairments
-
-11.6
-11.6
-
-
-11.6
Depreciation
-
-198.2
-198.2
-1.1
-3.9
-203.2
Closing net book amount
248.2
1,015.2
1,263.3
1.0
20.6
1,284.9
As of 31 December 2021
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
1,015.2
1,263.3
1.0
20.6
1,284.9
Depreciation method
UoP
Linear (3-7 years)
* Includes changes in estimate of asset retirement, see Note 16.
** Transfers was related to reclassification of the book value of Baeshiqa license from
\u00a0
exploration phase (intangible assets) to development phase
\u00a0
(tangible assets) and reclassification of the book value of Berling (previously named Iris/Hades).
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2021 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2021
Acquisition costs
474.3
97.1
389.2
14.3
500.5
974.9
Accumulated impairments/exploration write-offs
-312.3
-7.7
-108.3
-
-116.0
-428.3
Accumulated depreciation
-
-66.4
-
-9.5
-75.9
-75.9
Net book amount
162.0
23.0
280.9
4.7
308.6
470.6
Period ended 31 December 2021
Opening net book amount
162.0
23.0
280.9
4.7
308.6
470.6
Translation differences
-5.3
-
-9.6
0.2
-9.4
-14.7
Additions
-
1.0
85.3
0.4
86.7
86.8
Additions through license acquisition*
-
35.2
35.2
35.2
Transfers**
-
-
-125.7
-
-125.7
-125.7
Disposal cost price
-
-
-6.0
-0.3
-6.3
-6.3
Disposal impairments/depreciations
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-1.1
-53.0
-54.1
-54.1
Impairments
-68.5
-
-
-
-
-68.5
Depreciation
-
-1.8
-
-1.0
-2.8
-2.8
Closing net book amount
88.2
21.1
207.1
4.0
232.3
320.6
As of 31 December 2021
Acquisition costs
456.8
98.1
368.4
14.6
481.2
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
4.0
232.4
320.6
Depreciation method
UoP
Linear (3-7 years)
* Addition through license acquisition was related to DNO's acquisition of ExxonMobil's remaining 32 percent interest in the
\u00a0
Baeshiqa license, approved
\u00a0
by the KRG in August 2021.
\u00a0
** Transfers was related to reclassification of the book value of Baeshiqa license from
\u00a0
exploration phase (intangible assets) to development phase
\u00a0
(tangible assets) and reclassification of the book value of Berling (previously named Iris/Hades).
Impairment testing
At each reporting date, the Group assesses whether
\u00a0
there is an indication that an asset may be
\u00a0
impaired. An assessment of the
recoverable amount is made when an impairment
\u00a0
indicator exists. Goodwill is tested for impairment
\u00a0
annually or more frequently when
there are impairment indicators. Impairment is recognized
\u00a0
when the carrying amount of an asset or
\u00a0
a CGU, including associated
goodwill, exceeds the recoverable amount. The recoverable
\u00a0
amount is the higher of the asset\u2019s fair value
\u00a0
less cost to sell and the value
in use. Impairment assessment of DNO\u2019s assets in Kurdistan
\u00a0
is based on the value in use approach. For
\u00a0
oil and gas assets and goodwill
recognized in relation to the acquisition of Faroe
\u00a0
Petroleum Plc, the impairment assessment is
\u00a0
based on the fair value approach (level 3
in fair value hierarchy, IFRS 13). For both the value in use and fair value,
\u00a0
the impairment testing is performed based on
\u00a0
discounted cash
flows. The expected future cash flows are discounted
\u00a0
to the net present value by applying a
\u00a0
discount rate after tax. Cash flows are
projected for the estimated lifetime of the fields or
\u00a0
license, which may exceed periods longer
\u00a0
than five years.
\u00a0
Below is an overview of the key assumptions
\u00a0
applied for impairment assessment purposes as of
\u00a0
31 December 2022.
\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 2022 were
\u00a0
as follows (yearend 2021 in
brackets):
2023
2024
2025
2026
Brent (USD/bbl)
86.6 (76.9)
88.5 (70.4)
85.0 (68.3)
78.4 (70.0)
NBP (pence/therm)
289.0 (158.3)
179.4 (77.4)
126.4 (65.5)
102.9 (57.6)
For periods after year 2026, 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 2022).
\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 23.
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 2022 was 16.1
\u00a0
percent (13.6 percent at
yearend 2021) for the Kurdistan assets. For the
\u00a0
fair value calculations, the relevant post-tax
\u00a0
nominal discount rates at yearend 2022
was 8.4 percent for the North Sea assets (7.7 percent
\u00a0
at yearend 2021).
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
2021). 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
2022, was USD/NOK 9.5 for the years 2023
\u00a0
and 2024 and thereafter kept
constant at USD/NOK 9.0 from the year 2025 onwards.
Impairment charge and reversal
The following table shows the recoverable amounts
\u00a0
and net impairment charges or reversal for
\u00a0
the CGUs which were impaired in 2022
and 2021, and how it was recognized in
\u00a0
the income statement and the balance sheet.
Full-Year ended 31 December 2022
Income statement:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
Tax
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
(post-tax)
Goodwill
assets
equipment
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
Full-Year ended 31 December 2021
Income statement:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
Tax
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
(post-tax)
Goodwill
assets
equipment
effects
Fenja, North Sea
54.0
-9.7
-9.7
-9.7
-
-
-
-0.1
Trym area, North Sea
9.0
-7.7
-7.7
-7.7
-
-
-
-0.3
Ula area, North Sea
158.0
-51.1
-51.1
-51.1
-
-
-
0.4
Oselvar, North Sea
-
1.5
-1.2
0.3
-
-
1.5
-1.2
-
Schooner and Ketch, North Sea
-
-11.2
4.1
-7.1
-
-
-11.2
4.1
-
Other CGUs, North Sea
-
-1.9
-
-1.9
-
-
-1.9
-
-
Total
-80.1
2.9
-77.2
-68.5
-
-11.6
2.9
-
During 2022, a total impairment charge of USD 371.3
\u00a0
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
Revised reserves and resource estimates, and cost profiles
\u00a0
(Ula area CGU);
\u2022
Revision in the cost estimate for decommissioning (Schooner
\u00a0
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).
During 2021, a total impairment charge of USD
\u00a0
80.1 million (USD 77.2 million post-tax) was
\u00a0
recognized, mainly driven by:
\u00a0
\u2022
Revised reserves and resource estimates (Fenja development);
\u00a0
\u2022
Revised reserves and resource estimates, and cost profiles
\u00a0
(Ula area CGU, Trym area CGU); and
\u2022
Revision in the cost estimate for decommissioning (Schooner
\u00a0
and Ketch fields, Oselvar field, and other
\u00a0
CGUs).
Sensitivities
The table below illustrates how the net profit/-loss
\u00a0
in 2022 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
-
-12
Reserves (2P) and resources (2C)
-
-1
Discount rate (WACC)
-
-
Currency rate (USD/NOK)
-
-3
Climate considerations in impairment assessment
Certain climate considerations are factored into the Group\u2019s
\u00a0
estimation of cash flows that are applied in the
\u00a0
calculation of recoverable
amount. This includes factoring in current legislation (e.g.,
\u00a0
environmental taxes/fees) and estimation of
\u00a0
future levels of environmental
taxes. For DNO\u2019s oil and gas assets on the NCS,
\u00a0
carbon pricing is in line with current legislation and
\u00a0
reflects the operator\u2019s 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 CO
2
\u00a0
tax) to NOK 2,000 per tonne (in 2020 real
\u00a0
terms) is expected by 2030. In Kurdistan, the
\u00a0
KRG introduced in 2021 a
requirement for oil companies to put plans in place
\u00a0
to curb gas flaring to reduce emissions.
\u00a0
The Company has run sensitivities for its
Kurdistan oil assets with the CO2 tax assumptions as
\u00a0
described in the scenarios described by the
\u00a0
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 oil
\u00a0
and gas prices where supply and demand
\u00a0
are
considered. A significant reduction in the Company\u2019s oil
\u00a0
and gas price assumptions would result in impairments
\u00a0
on certain production
and development assets including intangible assets that
\u00a0
are subject to impairment assessment under IAS
\u00a0
36, but an opposite revision in
the price assumptions would only lead to limited
\u00a0
impairment reversals as most of the impairments
\u00a0
recognized by the Group were related
to impairment of goodwill which cannot be reversed
\u00a0
under IFRS.
\u00a0
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 scenarios outlined by the IEA, namely
\u00a0
the Net Zero Emissions Scenario by 2050, 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 2021
\u00a0
real terms), and for the sensitivity
calculation a linear development between average
\u00a0
actual 2022 and 2030, as well as between
\u00a0
2030 and 2050 have been applied. The
table below summarizes how the reported net profit would
\u00a0
be impacted by an increase (+) or decrease
\u00a0
(-) in impairment charge using
the oil and gas price assumptions in the following
\u00a0
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
82
95
8.5
-
64
60
7.9
-
Net Zero Emissions by 2050
35
24
4.6
-44
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;
\u00a0
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
\u00a0
and economic cut-off (in brackets) dates were applied
\u00a0
in relation to yearend 2022
impairment assessments; the Ula area CGU have
\u00a0
license expiry dates that ranges between 2027
\u00a0
and 2036 (economic cut-off assumed
to be at the end of 2026); the Ringhorne
\u00a0
East license expires in 2030 (2046); the Brage
\u00a0
license expires in 2030 (2028); the Trym license
expires in 2027 (2026); the Alve license expires
\u00a0
in 2029 (2029); an application for extension
\u00a0
of the Marulk license from 2025 to 2026 has
been submitted and is pending approval (2026);
\u00a0
the Vilje license expires in 2032 (2040); the Fenja
\u00a0
license expires in 2039 (2037); and
the Berling license expires in 2023 (2033, application
\u00a0
for license extension was included in the PDO
\u00a0
submission, subject to approval).
Acquisition of Mondoil Enterprises
\u00a0
LLC
On 11 October 2022, the Company completed the transaction with RAK
\u00a0
Petroleum plc (RAK Petroleum) for transferring
\u00a0
shares in
Mondoil Enterprises LLC (Mondoil Enterprises) to DNO
\u00a0
ASA (see also Note 11). The transaction was entered on 22 August 2022
\u00a0
with
effective date 1 January 2022 and the Company issued
\u00a0
78.94 million new shares to RAK Petroleum as
\u00a0
consideration (consideration
shares). Following transaction completion, the Company
\u00a0
holds 100 percent of the shares in Mondoil
\u00a0
Enterprises. Mondoil Enterprises
owns 50 percent of Mondoil C\u00f4te d\u2019Ivoire LLC
\u00a0
(Mondoil C\u00f4te d\u2019Ivoire), which, in turn, owns
\u00a0
66.66 percent in the privately-held Foxtrot
International LDC (Foxtrot International), resulting in the
\u00a0
Company\u2019s indirect 33.33 percent interest in Foxtrot
\u00a0
International. Foxtrot
International holds a 27.27 percent interest in and
\u00a0
operatorship of Block CI-27 offshore C\u00f4te d\u2019Ivoire, which
\u00a0
contains the Foxtrot gas
field, the Mahi gas field, the Marlin oil and gas field
\u00a0
and the Manta gas field. Foxtrot International
\u00a0
also operates an exploration license
offshore C\u00f4te d\u2019Ivoire, Block CI-12, in which it holds
\u00a0
a 24 percent interest.
\u00a0
The acquisition date for accounting purposes corresponds
\u00a0
to the completion of the transaction on 11 October 2022. A purchase price
allocation (PPA) has been performed to allocate the value of consideration
\u00a0
shares to fair value of assets acquired and liabilities
assumed. The PPA was performed as of the completion date, 11 October 2022. The 11 October closing share price at Oslo Stock
Exchange (NOK 13.27/USD 1.24) and the closing
\u00a0
currency exchange rate (USD/NOK 10.7205) were
\u00a0
used as a basis for measuring the
value of the consideration shares, as set forth below.
\u00a0
The following table summarizes the PPA and acquisition cost as recorded
\u00a0
as at transaction completion date:
\u00a0
Purchase price allocation (PPA)
As at transaction
USD million
completion date
Consideration shares
78,943,763
Share price at closing date (USD/share)
1.24
Consideraton in the form of equity instruments issued at fair value
97.7
Transaction fees
1.3
Total consideration
99.0
Carrying amount of proportional net assets acquired (of Foxtrot International)
63.8
Fair value uplift of proportional net assets acquired (of Foxtrot International)
12.9
Cash and cash equivalents (of Mondoil Enterprises)
21.5
Total proportional identifiable net assets at fair value
98.2
Goodwill
0.8
The provisional fair values from the table above are based
\u00a0
on currently available information about fair values
\u00a0
as of the completion date.
If new information becomes available within 12
\u00a0
months from this date (measurement period), the
\u00a0
Group may change the fair value
assessment in the PPA. Eventual changes in fair values will be recorded
\u00a0
retrospectively from the completion date.
\u00a0
Financial information of Foxtrot International as of
\u00a0
yearend 2022
The Company\u2019s indirect 33.33 percent interest in Foxtrot
\u00a0
International is treated in accordance with
\u00a0
IFRS 11 and IAS 28
Investments in
Associates and Joint Ventures
\u00a0
(i.e., the Group\u2019s interest in Mondoil C\u00f4te d\u2019Ivoire/Foxtrot
\u00a0
International is accounted for using the equity
method) and disclose in the table below the summarised
\u00a0
financial information of Foxtrot International as an associate/joint
\u00a0
venture (IAS
28) in terms of summarised financial information.
\u00a0
Foxtrot International's summarized statement of financial position
Year ended 31 December
USD million
2022
Non-current assets
216.5
Current assets
67.3
Total assets
283.7
Non-current liabilities
67.1
Current liabilities
30.0
Total liabilities
97.2
Equity
186.6
Group's share of net assets (33.33 percent)
62.2
Goodwill
0.8
Fair value uplift on PP&E and ARO (net of related deferred tax)
13.0
Carrying amount Investment in Joint Venture
76.1
Foxtrot International's summarized statement of comprehensive income
1 January -
\u00a0
31 December
USD million
2022
Revenues
28.8
Expenses
-4.2
Depreciation
-8.0
Other income/finance income
3.5
Tax income/-expense
-
Net profit/-loss
20.1
Group's share of net profit (33.33 percent)
6.7
Depletion of fair value uplift of PP&E and ARO (net of related deferred tax)
-0.7
Share of profit/-loss from Joint Venture
6.0
As at transaction
Year ended 31
Movement in the carrying amount of Investment in Joint Venture
completion date
USD million
2022
2022
Opening balance
-
77.5
Acquired share of Joint Venture's carrying amount
63.8
-
Acquired fair value uplift of PP&E and ARO (net of related deferred tax)
12.9
-
Goodwill
0.8
-
Share of profit/-loss from Joint Venture
-
6.0
Equity contribution into Joint Venture
-
4.2
Dividends from Joint Venture
-
-11.5
Carrying amount Investment in Joint Venture
77.5
76.1
Acquisition of Mondoil Enterprises
\u00a0
LLC
On 11 October 2022, the Company completed the transaction with RAK
\u00a0
Petroleum plc (RAK Petroleum) for transferring
\u00a0
shares in
Mondoil Enterprises LLC (Mondoil Enterprises) to DNO
\u00a0
ASA (see also Note 11). The transaction was entered on 22 August 2022
\u00a0
with
effective date 1 January 2022 and the Company issued
\u00a0
78.94 million new shares to RAK Petroleum as
\u00a0
consideration (consideration
shares). Following transaction completion, the Company
\u00a0
holds 100 percent of the shares in Mondoil
\u00a0
Enterprises. Mondoil Enterprises
owns 50 percent of Mondoil C\u00f4te d\u2019Ivoire LLC
\u00a0
(Mondoil C\u00f4te d\u2019Ivoire), which, in turn, owns
\u00a0
66.66 percent in the privately-held Foxtrot
International LDC (Foxtrot International), resulting in the
\u00a0
Company\u2019s indirect 33.33 percent interest in Foxtrot
\u00a0
International. Foxtrot
International holds a 27.27 percent interest in and
\u00a0
operatorship of Block CI-27 offshore C\u00f4te d\u2019Ivoire, which
\u00a0
contains the Foxtrot gas
field, the Mahi gas field, the Marlin oil and gas field
\u00a0
and the Manta gas field. Foxtrot International
\u00a0
also operates an exploration license
offshore C\u00f4te d\u2019Ivoire, Block CI-12, in which it holds
\u00a0
a 24 percent interest.
\u00a0
The acquisition date for accounting purposes corresponds
\u00a0
to the completion of the transaction on 11 October 2022. A purchase price
allocation (PPA) has been performed to allocate the value of consideration
\u00a0
shares to fair value of assets acquired and liabilities
assumed. The PPA was performed as of the completion date, 11 October 2022. The 11 October closing share price at Oslo Stock
Exchange (NOK 13.27/USD 1.24) and the closing
\u00a0
currency exchange rate (USD/NOK 10.7205) were
\u00a0
used as a basis for measuring the
value of the consideration shares, as set forth below.
\u00a0
The following table summarizes the PPA and acquisition cost as recorded
\u00a0
as at transaction completion date:
\u00a0
Purchase price allocation (PPA)
As at transaction
USD million
completion date
Consideration shares
78,943,763
Share price at closing date (USD/share)
1.24
Consideraton in the form of equity instruments issued at fair value
97.7
Transaction fees
1.3
Total consideration
99.0
Carrying amount of proportional net assets acquired (of Foxtrot International)
63.8
Fair value uplift of proportional net assets acquired (of Foxtrot International)
12.9
Cash and cash equivalents (of Mondoil Enterprises)
21.5
Total proportional identifiable net assets at fair value
98.2
Goodwill
0.8
The provisional fair values from the table above are based
\u00a0
on currently available information about fair values
\u00a0
as of the completion date.
If new information becomes available within 12
\u00a0
months from this date (measurement period), the
\u00a0
Group may change the fair value
assessment in the PPA. Eventual changes in fair values will be recorded
\u00a0
retrospectively from the completion date.
\u00a0
Financial information of Foxtrot International as of
\u00a0
yearend 2022
The Company\u2019s indirect 33.33 percent interest in Foxtrot
\u00a0
International is treated in accordance with
\u00a0
IFRS 11 and IAS 28
Investments in
Associates and Joint Ventures
\u00a0
(i.e., the Group\u2019s interest in Mondoil C\u00f4te d\u2019Ivoire/Foxtrot
\u00a0
International is accounted for using the equity
method) and disclose in the table below the summarised
\u00a0
financial information of Foxtrot International as an associate/joint
\u00a0
venture (IAS
28) in terms of summarised financial information.
\u00a0
Foxtrot International's summarized statement of financial position
Year ended 31 December
USD million
2022
Non-current assets
216.5
Current assets
67.3
Total assets
283.7
Non-current liabilities
67.1
Current liabilities
30.0
Total liabilities
97.2
Equity
186.6
Group's share of net assets (33.33 percent)
62.2
Goodwill
0.8
Fair value uplift on PP&E and ARO (net of related deferred tax)
13.0
Carrying amount Investment in Joint Venture
76.1
Foxtrot International's summarized statement of comprehensive income
1 January -
\u00a0
31 December
USD million
2022
Revenues
28.8
Expenses
-4.2
Depreciation
-8.0
Other income/finance income
3.5
Tax income/-expense
-
Net profit/-loss
20.1
Group's share of net profit (33.33 percent)
6.7
Depletion of fair value uplift of PP&E and ARO (net of related deferred tax)
-0.7
Share of profit/-loss from Joint Venture
6.0
As at transaction
Year ended 31
Movement in the carrying amount of Investment in Joint Venture
completion date
USD million
2022
2022
Opening balance
-
77.5
Acquired share of Joint Venture's carrying amount
63.8
-
Acquired fair value uplift of PP&E and ARO (net of related deferred tax)
12.9
-
Goodwill
0.8
-
Share of profit/-loss from Joint Venture
-
6.0
Equity contribution into Joint Venture
-
4.2
Dividends from Joint Venture
-
-11.5
Carrying amount Investment in Joint Venture
77.5
76.1
Note 11
Financial investments
Financial investments are comprised of equity instruments
\u00a0
and are recorded at fair value (market price, where
\u00a0
available) at the end of
the reporting period. Fair value changes are included
\u00a0
in other comprehensive income (FVTOCI), see Note 1
\u00a0
for details.
\u00a0
Years ended 31 December
USD million
2022
2021
Book value as of 1 January
16.2
12.6
Fair value changes through other comprehensive income (FVTOCI)
14.2
3.6
Disposal
-30.4
-
Book value as of 31 December
-
16.2
Financial investments include the following:
USD million
2022
2021
Listed shares:
RAK Petroleum plc
-
16.2
Total financial investments
-
16.2
Prior to the completion of the agreement entered
\u00a0
between DNO and RAK Petroleum in October 2022 (see
\u00a0
Note 10), the Company held
a total of 15,849,737 (5.1 percent) shares in RAK
\u00a0
Petroleum. RAK Petroleum was listed on the Oslo
\u00a0
Stock Exchange and was the
largest shareholder in DNO ASA with 44.94 percent
\u00a0
of the total issued shares. As part of the all-share
\u00a0
transaction with RAK Petroleum,
on 19 October 2022, RAK Petroleum distributed
\u00a0
by way of a capital repayment the entirety of
\u00a0
its DNO ASA shareholding, including the
transaction consideration shares, to its shareholders, which
\u00a0
also included DNO ASA. Following the distribution,
\u00a0
the Company had
26,269,183 own shares which were retained as
\u00a0
treasury shares and the Company\u2019s investment in RAK
\u00a0
Petroleum was simultaneously
derecognized from the balance sheet.
Change in fair value prior to transaction completion
\u00a0
was recognized in other comprehensive income
\u00a0
with USD 14.2 million in 2022 (USD
3.6 million in 2021).
Note 11
Financial investments
Financial investments are comprised of equity instruments
\u00a0
and are recorded at fair value (market price, where
\u00a0
available) at the end of
the reporting period. Fair value changes are included
\u00a0
in other comprehensive income (FVTOCI), see Note 1
\u00a0
for details.
\u00a0
Years ended 31 December
USD million
2022
2021
Book value as of 1 January
16.2
12.6
Fair value changes through other comprehensive income (FVTOCI)
14.2
3.6
Disposal
-30.4
-
Book value as of 31 December
-
16.2
Financial investments include the following:
USD million
2022
2021
Listed shares:
RAK Petroleum plc
-
16.2
Total financial investments
-
16.2
Prior to the completion of the agreement entered
\u00a0
between DNO and RAK Petroleum in October 2022 (see
\u00a0
Note 10), the Company held
a total of 15,849,737 (5.1 percent) shares in RAK
\u00a0
Petroleum. RAK Petroleum was listed on the Oslo
\u00a0
Stock Exchange and was the
largest shareholder in DNO ASA with 44.94 percent
\u00a0
of the total issued shares. As part of the all-share
\u00a0
transaction with RAK Petroleum,
on 19 October 2022, RAK Petroleum distributed
\u00a0
by way of a capital repayment the entirety of
\u00a0
its DNO ASA shareholding, including the
transaction consideration shares, to its shareholders, which
\u00a0
also included DNO ASA. Following the distribution,
\u00a0
the Company had
26,269,183 own shares which were retained as
\u00a0
treasury shares and the Company\u2019s investment in RAK
\u00a0
Petroleum was simultaneously
derecognized from the balance sheet.
Change in fair value prior to transaction completion
\u00a0
was recognized in other comprehensive income
\u00a0
with USD 14.2 million in 2022 (USD
3.6 million in 2021).
Note 11
Financial investments
Financial investments are comprised of equity instruments
\u00a0
and are recorded at fair value (market price, where
\u00a0
available) at the end of
the reporting period. Fair value changes are included
\u00a0
in other comprehensive income (FVTOCI), see Note 1
\u00a0
for details.
\u00a0
Years ended 31 December
USD million
2022
2021
Book value as of 1 January
16.2
12.6
Fair value changes through other comprehensive income (FVTOCI)
14.2
3.6
Disposal
-30.4
-
Book value as of 31 December
-
16.2
Financial investments include the following:
USD million
2022
2021
Listed shares:
RAK Petroleum plc
-
16.2
Total financial investments
-
16.2
Prior to the completion of the agreement entered
\u00a0
between DNO and RAK Petroleum in October 2022 (see
\u00a0
Note 10), the Company held
a total of 15,849,737 (5.1 percent) shares in RAK
\u00a0
Petroleum. RAK Petroleum was listed on the Oslo
\u00a0
Stock Exchange and was the
largest shareholder in DNO ASA with 44.94 percent
\u00a0
of the total issued shares. As part of the all-share
\u00a0
transaction with RAK Petroleum,
on 19 October 2022, RAK Petroleum distributed
\u00a0
by way of a capital repayment the entirety of
\u00a0
its DNO ASA shareholding, including the
transaction consideration shares, to its shareholders, which
\u00a0
also included DNO ASA. Following the distribution,
\u00a0
the Company had
26,269,183 own shares which were retained as
\u00a0
treasury shares and the Company\u2019s investment in RAK
\u00a0
Petroleum was simultaneously
derecognized from the balance sheet.
Change in fair value prior to transaction completion
\u00a0
was recognized in other comprehensive income
\u00a0
with USD 14.2 million in 2022 (USD
3.6 million in 2021).
Financial risk management, objectives and policies
Overview
The Group\u2019s principal financial liabilities are comprised of interest-bearing
\u00a0
liabilities and trade and other payables. The
\u00a0
main purpose of
these financial liabilities is to finance DNO\u2019s operations. The
\u00a0
Group\u2019s principal financial assets include trade
\u00a0
and other receivables, tax
receivables and cash and cash equivalents.
\u00a0
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. In 2022, the Group had gas price
\u00a0
put options in place with strike prices of
GBP 79 -110 pence per therm, securing approximately 75 percent of after-tax
\u00a0
profit from estimated 2022 gas production.
\u00a0
The Group
had no oil and gas price hedging arrangements
\u00a0
at yearend 2022.
\u00a0
The following table illustrates the impact on reported 2021
\u00a0
and 2022 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 9 for a
sensitivity analysis related to the impairment
\u00a0
assessment of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
2022
+/- 15.0
2021
+/- 15.0
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 2022 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2021 and
\u00a0
2022 from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP exchange rates,
\u00a0
with all other variables held
constant. The other currencies (e.g., AED, IQD) are not
\u00a0
included as the exposure is deemed immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2022
+ 10.0
-3.5
2022
- 10.0
3.5
2021
+ 10.0
-5.9
2021
- 10.0
5.9
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2022
+ 10.0
-19.0
2022
- 10.0
19.0
2021
+ 10.0
1.4
2021
- 10.0
-1.4
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2022
+ 10.0
-4.8
2022
- 10.0
4.8
2021
+ 10.0
-3.6
2021
- 10.0
3.6
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 2022. 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 2021 and
\u00a0
2022 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)
2022
+/- 200
+/-7.7
2021
+/- 200
+/-14.8
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 and
\u00a0
other financial resources to maintain financial
\u00a0
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 15. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 10) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made on
\u00a0
a regular basis pursuant to an approved budget
\u00a0
and work program.
\u00a0
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 in 2022
\u00a0
derived primarily from production in the Tawke license in Kurdistan and
from several licenses in the North Sea. The Group
\u00a0
actively seeks to reduce such risk through
\u00a0
organic growth and asset acquisitions
aimed at further diversifying its revenue sources.
\u00a0
See also Note 10 regarding the Company\u2019s entry in
\u00a0
West Africa.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
USD million
On
At 31 December 2022
demand
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
USD million
On
At 31 December 2021
demand
Interest-bearing liabilities*
16.9
60.8
510.4
545.3
Other provisions and charges
18.6
16.2
Taxes payable
-
12.6
20.5
-
-
Trade and other payables
1.9
210.4
3.0
Total liabilities
1.9
258.5
100.5
510.4
545.3
* Face value of the bonds was USD 531.2 million at yearend 2022 (USD 794.9 million at yearend 2021).
For changes in liabilities arising from financing activities,
\u00a0
see Note 15.
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
2022
2021
Trade debtors (non-current portion) (Note 12)
-
18.2
Trade debtors (Note 12)
311.8
344.4
Other receivables (Note 12)
126.0
139.4
25.8
21.1
Cash and cash equivalents
954.3
736.6
1,417.9
1,259.7
Trade debtors
The impairment model in IFRS 9 is based on
\u00a0
the premise of providing for expected credit
\u00a0
losses. Expected credit losses (ECL) under
IFRS 9 are based on the difference between the contractual
\u00a0
cash flows due in accordance with the contract and
\u00a0
all the cash flows that
are expected to be received, discounted at an
\u00a0
approximation of the original effective interest rate.
\u00a0
Measurement of ECLs under IFRS 9
shall reflect an unbiased and probability-weighted
\u00a0
amount that is determined by evaluating the range
\u00a0
of possible outcomes as well as
incorporating the time value of money. The entity should consider reasonable and
\u00a0
supportable information about past events, current
conditions and reasonable and supportable forecasts
\u00a0
of future economic conditions when measuring expected
\u00a0
credit losses.
Trade debtors from oil sales invoices in Kurdistan
Normal payment terms apply to amounts owed to
\u00a0
DNO by the KRG for oil sales and override invoices
\u00a0
from the Tawke and the Baeshiqa
license in Kurdistan. Since late 2015, DNO received
\u00a0
the payment due to it from oil sales and overrides
\u00a0
on a monthly basis from the KRG
At yearend 2020, the Group had accumulated
\u00a0
a receivable against the KRG of USD 259
\u00a0
million after certain 2019 and 2020 entitlement
and override payments to the Group and other
\u00a0
Kurdistan oil exporters were withheld early in
\u00a0
2020 by the KRG in connection with the
hardships and uncertainties brought about by
\u00a0
the Covid-19 pandemic. Entitlement payments resumed
\u00a0
in March 2020 and override
payments in early 2021. A payment plan was
\u00a0
put in place by the KRG in December
\u00a0
2020 and subsequently revised in May 2021
\u00a0
to pay
the outstanding arrears. As a part of the May 2021
\u00a0
revision, the KRG also informed the international
\u00a0
oil companies that all invoices,
including towards the arrears, will be settled within 60
\u00a0
days of the end of the respective production
\u00a0
month. During 2022, the outstanding
arrears were reduced from USD 169 million
\u00a0
at the start of the year to USD 2 million
\u00a0
at yearend, not including any interest. The Company
continues to work to collect the remaining balances
\u00a0
and expects to be paid accordingly.
\u00a0
Over the course of 2022, KRG payments to
\u00a0
international oil companies were increasingly delayed.
\u00a0
At the time of issuing this report, the
invoices related to August and September 2022 oil
\u00a0
deliveries were paid in January and March
\u00a0
2023, respectively. The Company is in
dialogue with the KRG, seeking timely payments to
\u00a0
support timely investments. Moreover, in September 2022, the KRG proposed
\u00a0
a
change in the previously agreed pricing formula for
\u00a0
oil such that prices should, with effect from 1 September
\u00a0
2022, be based on the
purported price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been accepted
\u00a0
by DNO and the Company
continues to invoice the KRG for oil sales based
\u00a0
on the previously agreed pricing formula (including
\u00a0
the September 2022 invoice) until
such time that protocols are put in place to ensure
\u00a0
that realized prices are transparent, based on arms-length
\u00a0
transactions and subject
to third-party audit. The payment for the September oil
\u00a0
delivery received after yearend reflects the formula
\u00a0
proposed and unilaterally
applied by the KRG in September 2022 resulting in an
\u00a0
approximately USD 11/bbl reduction in realized price compared to current pricing
formula based on Dated Brent. The payment received
\u00a0
was USD 5.2 million (net to DNO) lower than
\u00a0
invoiced. The Company is in
continuing dialogue with the KRG to resolve this
\u00a0
matter and collect outstanding balances. The Company
\u00a0
estimates that using the KRG
proposed prices, the impact of the change in pricing
\u00a0
would have resulted in approximately USD
\u00a0
23 million lower revenues compared to
the reported September through December 2022 Kurdistan
\u00a0
revenues.
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 2022
Trade debtors (nominal value) (Note 12)
-
132.7
58.1
55.9
63.1
2.0
311.8
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2021
Trade debtors (nominal value) (Note 12)
-
131.6
61.9
-
-
169.1
362.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Total trade debtors of USD 311.8 million at yearend 2022 relate mainly to the Tawke license, see Note 12 for details.
\u00a0
Cash deposits
Credit risk from balances with banks and financial
\u00a0
institutions is managed by the Group\u2019s treasury function.
\u00a0
The Group limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the 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
15. The equity ratio has improved primarily
\u00a0
due to a net profit in 2022. 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 2022 and
\u00a0
2021.
Years ended 31 December
USD million
2022
2021
Total equity
1,369.4
1,018.8
Total assets
2,803.0
2,947.8
Equity ratio
48.9%
34.6%
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 assets and financial liabilities,
\u00a0
including their levels in the fair
value hierarchy. It does not include the carrying amounts and fair value
\u00a0
information for financial assets and financial liabilities
\u00a0
not
measured or disclosed at fair value if the carrying
\u00a0
amount is a reasonable approximation of
\u00a0
fair value.
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2022 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
-
-
-
31 December 2022
-
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
15
-
8.4
8.4
-
8.4
* Financial assets designated at FVTOCI with no recycling of cumulative gains and losses upon derecognition
\u00a0
(equity instruments).
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2021 - USD million
Note
at FVTOCI
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
16.2
-
16.2
31 December 2021
16.2
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
873.4
873.4
31 December 2021
824.2
-
95.0
Interest-bearing liabilities (current)
15
-
-
-
-
-
-
Years ended 31 December
USD million
2022
2021
Trade debtors (non-current portion)
-
18.2
Other long-term receivables
-
1.3
Total other non-current receivables
-
19.4
Trade debtors
311.8
344.4
Underlift
14.0
17.2
Other short-term receivables
111.9
122.2
Total trade and other receivables
437.8
483.8
Total book value of trade debtors of USD 311.8 million at yearend 2022 relate mainly to outstanding invoices for Kurdistan
\u00a0
oil deliveries
for the months August through December 2022 (USD
\u00a0
295.9 million).
\u00a0
In September 2022, the KRG proposed a change in
\u00a0
the previously agreed pricing formula for oil
\u00a0
such that prices should, with effect from
1 September 2022, be based on the purported
\u00a0
actual price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been
accepted by DNO and the Company continues to invoice
\u00a0
the KRG for oil sales based on the previously
\u00a0
agreed pricing formula (including
the September 2022 invoice) until such time that protocols
\u00a0
are put in place to ensure that realized
\u00a0
prices are transparent, based on
arms-length transactions and subject to third-party audit.
\u00a0
See Note 18 regarding trade debtors from
\u00a0
oil sales in Kurdistan. See also Note
25 regarding payments received from the KRG
\u00a0
after yearend.
The underlift receivable of USD 14 million as
\u00a0
of 31 December 2022 relates to North Sea
\u00a0
underlifted volumes. Other short-term
receivables mainly relate to items of working capital
\u00a0
in licenses in Kurdistan and the North Sea
\u00a0
and accrual for earned income not
invoiced in the North Sea.
Years ended 31 December
USD million
2022
2021
Trade debtors (non-current portion)
-
18.2
Other long-term receivables
-
1.3
Total other non-current receivables
-
19.4
Trade debtors
311.8
344.4
Underlift
14.0
17.2
Other short-term receivables
111.9
122.2
Total trade and other receivables
437.8
483.8
Total book value of trade debtors of USD 311.8 million at yearend 2022 relate mainly to outstanding invoices for Kurdistan
\u00a0
oil deliveries
for the months August through December 2022 (USD
\u00a0
295.9 million).
\u00a0
In September 2022, the KRG proposed a change in
\u00a0
the previously agreed pricing formula for oil
\u00a0
such that prices should, with effect from
1 September 2022, be based on the purported
\u00a0
actual price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been
accepted by DNO and the Company continues to invoice
\u00a0
the KRG for oil sales based on the previously
\u00a0
agreed pricing formula (including
the September 2022 invoice) until such time that protocols
\u00a0
are put in place to ensure that realized
\u00a0
prices are transparent, based on
arms-length transactions and subject to third-party audit.
\u00a0
See Note 18 regarding trade debtors from
\u00a0
oil sales in Kurdistan. See also Note
25 regarding payments received from the KRG
\u00a0
after yearend.
The underlift receivable of USD 14 million as
\u00a0
of 31 December 2022 relates to North Sea
\u00a0
underlifted volumes. Other short-term
receivables mainly relate to items of working capital
\u00a0
in licenses in Kurdistan and the North Sea
\u00a0
and accrual for earned income not
invoiced in the North Sea.
Years ended 31 December
USD million
2022
2021
Trade debtors (non-current portion)
-
18.2
Other long-term receivables
-
1.3
Total other non-current receivables
-
19.4
Trade debtors
311.8
344.4
Underlift
14.0
17.2
Other short-term receivables
111.9
122.2
Total trade and other receivables
437.8
483.8
Total book value of trade debtors of USD 311.8 million at yearend 2022 relate mainly to outstanding invoices for Kurdistan
\u00a0
oil deliveries
for the months August through December 2022 (USD
\u00a0
295.9 million).
\u00a0
In September 2022, the KRG proposed a change in
\u00a0
the previously agreed pricing formula for oil
\u00a0
such that prices should, with effect from
1 September 2022, be based on the purported
\u00a0
actual price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been
accepted by DNO and the Company continues to invoice
\u00a0
the KRG for oil sales based on the previously
\u00a0
agreed pricing formula (including
the September 2022 invoice) until such time that protocols
\u00a0
are put in place to ensure that realized
\u00a0
prices are transparent, based on
arms-length transactions and subject to third-party audit.
\u00a0
See Note 18 regarding trade debtors from
\u00a0
oil sales in Kurdistan. See also Note
25 regarding payments received from the KRG
\u00a0
after yearend.
The underlift receivable of USD 14 million as
\u00a0
of 31 December 2022 relates to North Sea
\u00a0
underlifted volumes. Other short-term
receivables mainly relate to items of working capital
\u00a0
in licenses in Kurdistan and the North Sea
\u00a0
and accrual for earned income not
invoiced in the North Sea.
Years ended 31 December
USD million
2022
2021
Trade debtors (non-current portion)
-
18.2
Other long-term receivables
-
1.3
Total other non-current receivables
-
19.4
Trade debtors
311.8
344.4
Underlift
14.0
17.2
Other short-term receivables
111.9
122.2
Total trade and other receivables
437.8
483.8
Total book value of trade debtors of USD 311.8 million at yearend 2022 relate mainly to outstanding invoices for Kurdistan
\u00a0
oil deliveries
for the months August through December 2022 (USD
\u00a0
295.9 million).
\u00a0
In September 2022, the KRG proposed a change in
\u00a0
the previously agreed pricing formula for oil
\u00a0
such that prices should, with effect from
1 September 2022, be based on the purported
\u00a0
actual price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been
accepted by DNO and the Company continues to invoice
\u00a0
the KRG for oil sales based on the previously
\u00a0
agreed pricing formula (including
the September 2022 invoice) until such time that protocols
\u00a0
are put in place to ensure that realized
\u00a0
prices are transparent, based on
arms-length transactions and subject to third-party audit.
\u00a0
See Note 18 regarding trade debtors from
\u00a0
oil sales in Kurdistan. See also Note
25 regarding payments received from the KRG
\u00a0
after yearend.
The underlift receivable of USD 14 million as
\u00a0
of 31 December 2022 relates to North Sea
\u00a0
underlifted volumes. Other short-term
receivables mainly relate to items of working capital
\u00a0
in licenses in Kurdistan and the North Sea
\u00a0
and accrual for earned income not
invoiced in the North Sea.
Note 13
Cash and cash equivalents
Years ended 31 December
USD million
2022
2021
Cash and cash equivalents, restricted
22.5
15.8
Cash and cash equivalents, non-restricted
931.8
720.8
Total cash and cash equivalents
954.3
736.6
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 2022.
Included in the non-restricted cash and cash equivalents
\u00a0
as of 31 December 2022 is USD 408.7
\u00a0
million held on fixed interest time
deposit contracts with different duration and maturity dates
\u00a0
up to 23 January 2023.
Note 13
Cash and cash equivalents
Years ended 31 December
USD million
2022
2021
Cash and cash equivalents, restricted
22.5
15.8
Cash and cash equivalents, non-restricted
931.8
720.8
Total cash and cash equivalents
954.3
736.6
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 2022.
Included in the non-restricted cash and cash equivalents
\u00a0
as of 31 December 2022 is USD 408.7
\u00a0
million held on fixed interest time
deposit contracts with different duration and maturity dates
\u00a0
up to 23 January 2023.
Note 13
Cash and cash equivalents
Years ended 31 December
USD million
2022
2021
Cash and cash equivalents, restricted
22.5
15.8
Cash and cash equivalents, non-restricted
931.8
720.8
Total cash and cash equivalents
954.3
736.6
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 2022.
Included in the non-restricted cash and cash equivalents
\u00a0
as of 31 December 2022 is USD 408.7
\u00a0
million held on fixed interest time
deposit contracts with different duration and maturity dates
\u00a0
up to 23 January 2023.
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2021
975,433
32.9
-
32.9
Treasury shares sold/-purchased
-
-
-
-
As of 31 December 2021
975,433
32.9
-
32.9
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2022
975,433
32.9
0.0
32.9
Treasury shares sold/-purchased
-36,369
-
-0.9
-0.9
Share capital increase*
78,944
1.8
-
1.8
As of 31 December 2022
1,018,008
34.8
-0.9
33.9
* See Note 10 for information and details
At the 2022 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 24,385,818 which corresponds
\u00a0
to 97,543,373 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 2023 AGM, and not beyond
\u00a0
30 June 2023.
\u00a0
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital
\u00a0
by up to NOK 24,385,818 which
corresponds to 97,543,373 new shares. The authorization
\u00a0
was time-limited until the 2023 AGM, and not
\u00a0
beyond 30 June 2023.
\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 increased
\u00a0
by up to
NOK 24,385,818. The authorization is valid until
\u00a0
the 2023 AGM, but not beyond 30 June 2023.
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 2022
AGM until the date of the 2023 AGM. Following
\u00a0
this, the Board of Directors decided to distribute
\u00a0
quarterly dividends of NOK 0.25 in
August and November 2022, as well as in
\u00a0
February 2023.
At an Extraordinary General Meeting (EGM) in
\u00a0
September 2022, a proposal to increase the Company\u2019s
\u00a0
share capital received support
of over 99 percent of the votes cast. In accordance
\u00a0
with the EGM approval and a transaction
\u00a0
agreement, DNO in October 2022 issued
78,943,763 new shares to RAK Petroleum, its then largest
\u00a0
shareholder, as consideration for the transfer of West Africa assets between
the companies. Pursuant to the transaction agreement,
\u00a0
RAK Petroleum proceeded to distribute its
\u00a0
entire DNO shareholding, including
the consideration shares, to its shareholders. As a
\u00a0
shareholder of RAK Petroleum (5.1 percent), DNO
\u00a0
received 26,269,183 own shares
to be retained as treasury shares. The total shares outstanding
\u00a0
following the completion of the transaction increased
\u00a0
to 1,054,376,509,
each with a nominal value of NOK 0.25.
In December 2022, DNO announced the initiation
\u00a0
of a share buyback program through which
\u00a0
the Company would repurchase up to
53,107,326 shares, representing approximately five percent
\u00a0
of total shares outstanding, for a maximum
\u00a0
total consideration of USD 80
million. The buyback program was based upon
\u00a0
the authorization to acquire treasury shares
\u00a0
granted to the Board of Directors at the
2022 AGM.
Interest
The Company's shareholders as of 31 December 2022
Shares
(percent)
Goldman Sachs & Co. LLC
131,926,545
12.51
Euroclear Bank S.A./N.V.
93,818,919
8.90
Folketrygdfondet
44,490,590
4.22
RAK Gas LLC
34,311,403
3.25
State Street Bank and Trust Comp
28,018,325
2.66
The Bank of New York Mellon
25,336,833
2.40
BNP Paribas
24,188,187
2.29
The Bank of New York Mellon SA/NV
15,017,836
1.42
Clearstream Banking S.A
14,083,236
1.34
CACEIS Bank
14,054,243
1.33
HSBC Bank Plc
13,888,921
1.32
JPMorgan Chase Bank
10,886,384
1.03
Citibank
10,275,813
0.97
The Bank of New York Mellon
9,285,363
0.88
State Street Bank and Trust Comp
9,059,036
0.86
Saxo Bank A/S
8,611,705
0.82
Salt Value AS
8,495,200
0.81
The Northern Trust Comp
8,193,045
0.78
Citibank
7,263,451
0.69
Morgan Stanley & Co. International
7,093,637
0.67
Other shareholders
499,708,654
47.39
Total number of shares excluding treasury shares
1,018,007,326
96.55
Treasury shares as of 31 December 2022 (DNO ASA)
36,369,183
3.45
Total number of outstanding shares
1,054,376,509
100.00
Dividends of USD 72 million were distributed in 2022
\u00a0
(USD 21.8 million in 2021). See Note 25
\u00a0
for dividend approved
on 9 February 2023. See also Note 5 for shares
\u00a0
held by Board of Directors and executive
\u00a0
management.
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2021
975,433
32.9
-
32.9
Treasury shares sold/-purchased
-
-
-
-
As of 31 December 2021
975,433
32.9
-
32.9
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2022
975,433
32.9
0.0
32.9
Treasury shares sold/-purchased
-36,369
-
-0.9
-0.9
Share capital increase*
78,944
1.8
-
1.8
As of 31 December 2022
1,018,008
34.8
-0.9
33.9
* See Note 10 for information and details
At the 2022 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 24,385,818 which corresponds
\u00a0
to 97,543,373 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 2023 AGM, and not beyond
\u00a0
30 June 2023.
\u00a0
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital
\u00a0
by up to NOK 24,385,818 which
corresponds to 97,543,373 new shares. The authorization
\u00a0
was time-limited until the 2023 AGM, and not
\u00a0
beyond 30 June 2023.
\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 increased
\u00a0
by up to
NOK 24,385,818. The authorization is valid until
\u00a0
the 2023 AGM, but not beyond 30 June 2023.
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 2022
AGM until the date of the 2023 AGM. Following
\u00a0
this, the Board of Directors decided to distribute
\u00a0
quarterly dividends of NOK 0.25 in
August and November 2022, as well as in
\u00a0
February 2023.
At an Extraordinary General Meeting (EGM) in
\u00a0
September 2022, a proposal to increase the Company\u2019s
\u00a0
share capital received support
of over 99 percent of the votes cast. In accordance
\u00a0
with the EGM approval and a transaction
\u00a0
agreement, DNO in October 2022 issued
78,943,763 new shares to RAK Petroleum, its then largest
\u00a0
shareholder, as consideration for the transfer of West Africa assets between
the companies. Pursuant to the transaction agreement,
\u00a0
RAK Petroleum proceeded to distribute its
\u00a0
entire DNO shareholding, including
the consideration shares, to its shareholders. As a
\u00a0
shareholder of RAK Petroleum (5.1 percent), DNO
\u00a0
received 26,269,183 own shares
to be retained as treasury shares. The total shares outstanding
\u00a0
following the completion of the transaction increased
\u00a0
to 1,054,376,509,
each with a nominal value of NOK 0.25.
In December 2022, DNO announced the initiation
\u00a0
of a share buyback program through which
\u00a0
the Company would repurchase up to
53,107,326 shares, representing approximately five percent
\u00a0
of total shares outstanding, for a maximum
\u00a0
total consideration of USD 80
million. The buyback program was based upon
\u00a0
the authorization to acquire treasury shares
\u00a0
granted to the Board of Directors at the
2022 AGM.
Interest
The Company's shareholders as of 31 December 2022
Shares
(percent)
Goldman Sachs & Co. LLC
131,926,545
12.51
Euroclear Bank S.A./N.V.
93,818,919
8.90
Folketrygdfondet
44,490,590
4.22
RAK Gas LLC
34,311,403
3.25
State Street Bank and Trust Comp
28,018,325
2.66
The Bank of New York Mellon
25,336,833
2.40
BNP Paribas
24,188,187
2.29
The Bank of New York Mellon SA/NV
15,017,836
1.42
Clearstream Banking S.A
14,083,236
1.34
CACEIS Bank
14,054,243
1.33
HSBC Bank Plc
13,888,921
1.32
JPMorgan Chase Bank
10,886,384
1.03
Citibank
10,275,813
0.97
The Bank of New York Mellon
9,285,363
0.88
State Street Bank and Trust Comp
9,059,036
0.86
Saxo Bank A/S
8,611,705
0.82
Salt Value AS
8,495,200
0.81
The Northern Trust Comp
8,193,045
0.78
Citibank
7,263,451
0.69
Morgan Stanley & Co. International
7,093,637
0.67
Other shareholders
499,708,654
47.39
Total number of shares excluding treasury shares
1,018,007,326
96.55
Treasury shares as of 31 December 2022 (DNO ASA)
36,369,183
3.45
Total number of outstanding shares
1,054,376,509
100.00
Dividends of USD 72 million were distributed in 2022
\u00a0
(USD 21.8 million in 2021). See Note 25
\u00a0
for dividend approved
on 9 February 2023. See also Note 5 for shares
\u00a0
held by Board of Directors and executive
\u00a0
management.
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2021
975,433
32.9
-
32.9
Treasury shares sold/-purchased
-
-
-
-
As of 31 December 2021
975,433
32.9
-
32.9
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2022
975,433
32.9
0.0
32.9
Treasury shares sold/-purchased
-36,369
-
-0.9
-0.9
Share capital increase*
78,944
1.8
-
1.8
As of 31 December 2022
1,018,008
34.8
-0.9
33.9
* See Note 10 for information and details
At the 2022 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 24,385,818 which corresponds
\u00a0
to 97,543,373 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 2023 AGM, and not beyond
\u00a0
30 June 2023.
\u00a0
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital
\u00a0
by up to NOK 24,385,818 which
corresponds to 97,543,373 new shares. The authorization
\u00a0
was time-limited until the 2023 AGM, and not
\u00a0
beyond 30 June 2023.
\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 increased
\u00a0
by up to
NOK 24,385,818. The authorization is valid until
\u00a0
the 2023 AGM, but not beyond 30 June 2023.
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 2022
AGM until the date of the 2023 AGM. Following
\u00a0
this, the Board of Directors decided to distribute
\u00a0
quarterly dividends of NOK 0.25 in
August and November 2022, as well as in
\u00a0
February 2023.
At an Extraordinary General Meeting (EGM) in
\u00a0
September 2022, a proposal to increase the Company\u2019s
\u00a0
share capital received support
of over 99 percent of the votes cast. In accordance
\u00a0
with the EGM approval and a transaction
\u00a0
agreement, DNO in October 2022 issued
78,943,763 new shares to RAK Petroleum, its then largest
\u00a0
shareholder, as consideration for the transfer of West Africa assets between
the companies. Pursuant to the transaction agreement,
\u00a0
RAK Petroleum proceeded to distribute its
\u00a0
entire DNO shareholding, including
the consideration shares, to its shareholders. As a
\u00a0
shareholder of RAK Petroleum (5.1 percent), DNO
\u00a0
received 26,269,183 own shares
to be retained as treasury shares. The total shares outstanding
\u00a0
following the completion of the transaction increased
\u00a0
to 1,054,376,509,
each with a nominal value of NOK 0.25.
In December 2022, DNO announced the initiation
\u00a0
of a share buyback program through which
\u00a0
the Company would repurchase up to
53,107,326 shares, representing approximately five percent
\u00a0
of total shares outstanding, for a maximum
\u00a0
total consideration of USD 80
million. The buyback program was based upon
\u00a0
the authorization to acquire treasury shares
\u00a0
granted to the Board of Directors at the
2022 AGM.
Interest
The Company's shareholders as of 31 December 2022
Shares
(percent)
Goldman Sachs & Co. LLC
131,926,545
12.51
Euroclear Bank S.A./N.V.
93,818,919
8.90
Folketrygdfondet
44,490,590
4.22
RAK Gas LLC
34,311,403
3.25
State Street Bank and Trust Comp
28,018,325
2.66
The Bank of New York Mellon
25,336,833
2.40
BNP Paribas
24,188,187
2.29
The Bank of New York Mellon SA/NV
15,017,836
1.42
Clearstream Banking S.A
14,083,236
1.34
CACEIS Bank
14,054,243
1.33
HSBC Bank Plc
13,888,921
1.32
JPMorgan Chase Bank
10,886,384
1.03
Citibank
10,275,813
0.97
The Bank of New York Mellon
9,285,363
0.88
State Street Bank and Trust Comp
9,059,036
0.86
Saxo Bank A/S
8,611,705
0.82
Salt Value AS
8,495,200
0.81
The Northern Trust Comp
8,193,045
0.78
Citibank
7,263,451
0.69
Morgan Stanley & Co. International
7,093,637
0.67
Other shareholders
499,708,654
47.39
Total number of shares excluding treasury shares
1,018,007,326
96.55
Treasury shares as of 31 December 2022 (DNO ASA)
36,369,183
3.45
Total number of outstanding shares
1,054,376,509
100.00
Dividends of USD 72 million were distributed in 2022
\u00a0
(USD 21.8 million in 2021). See Note 25
\u00a0
for dividend approved
on 9 February 2023. See also Note 5 for shares
\u00a0
held by Board of Directors and executive
\u00a0
management.
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2021
975,433
32.9
-
32.9
Treasury shares sold/-purchased
-
-
-
-
As of 31 December 2021
975,433
32.9
-
32.9
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2022
975,433
32.9
0.0
32.9
Treasury shares sold/-purchased
-36,369
-
-0.9
-0.9
Share capital increase*
78,944
1.8
-
1.8
As of 31 December 2022
1,018,008
34.8
-0.9
33.9
* See Note 10 for information and details
At the 2022 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 24,385,818 which corresponds
\u00a0
to 97,543,373 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 2023 AGM, and not beyond
\u00a0
30 June 2023.
\u00a0
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital
\u00a0
by up to NOK 24,385,818 which
corresponds to 97,543,373 new shares. The authorization
\u00a0
was time-limited until the 2023 AGM, and not
\u00a0
beyond 30 June 2023.
\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 increased
\u00a0
by up to
NOK 24,385,818. The authorization is valid until
\u00a0
the 2023 AGM, but not beyond 30 June 2023.
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 2022
AGM until the date of the 2023 AGM. Following
\u00a0
this, the Board of Directors decided to distribute
\u00a0
quarterly dividends of NOK 0.25 in
August and November 2022, as well as in
\u00a0
February 2023.
At an Extraordinary General Meeting (EGM) in
\u00a0
September 2022, a proposal to increase the Company\u2019s
\u00a0
share capital received support
of over 99 percent of the votes cast. In accordance
\u00a0
with the EGM approval and a transaction
\u00a0
agreement, DNO in October 2022 issued
78,943,763 new shares to RAK Petroleum, its then largest
\u00a0
shareholder, as consideration for the transfer of West Africa assets between
the companies. Pursuant to the transaction agreement,
\u00a0
RAK Petroleum proceeded to distribute its
\u00a0
entire DNO shareholding, including
the consideration shares, to its shareholders. As a
\u00a0
shareholder of RAK Petroleum (5.1 percent), DNO
\u00a0
received 26,269,183 own shares
to be retained as treasury shares. The total shares outstanding
\u00a0
following the completion of the transaction increased
\u00a0
to 1,054,376,509,
each with a nominal value of NOK 0.25.
In December 2022, DNO announced the initiation
\u00a0
of a share buyback program through which
\u00a0
the Company would repurchase up to
53,107,326 shares, representing approximately five percent
\u00a0
of total shares outstanding, for a maximum
\u00a0
total consideration of USD 80
million. The buyback program was based upon
\u00a0
the authorization to acquire treasury shares
\u00a0
granted to the Board of Directors at the
2022 AGM.
Interest
The Company's shareholders as of 31 December 2022
Shares
(percent)
Goldman Sachs & Co. LLC
131,926,545
12.51
Euroclear Bank S.A./N.V.
93,818,919
8.90
Folketrygdfondet
44,490,590
4.22
RAK Gas LLC
34,311,403
3.25
State Street Bank and Trust Comp
28,018,325
2.66
The Bank of New York Mellon
25,336,833
2.40
BNP Paribas
24,188,187
2.29
The Bank of New York Mellon SA/NV
15,017,836
1.42
Clearstream Banking S.A
14,083,236
1.34
CACEIS Bank
14,054,243
1.33
HSBC Bank Plc
13,888,921
1.32
JPMorgan Chase Bank
10,886,384
1.03
Citibank
10,275,813
0.97
The Bank of New York Mellon
9,285,363
0.88
State Street Bank and Trust Comp
9,059,036
0.86
Saxo Bank A/S
8,611,705
0.82
Salt Value AS
8,495,200
0.81
The Northern Trust Comp
8,193,045
0.78
Citibank
7,263,451
0.69
Morgan Stanley & Co. International
7,093,637
0.67
Other shareholders
499,708,654
47.39
Total number of shares excluding treasury shares
1,018,007,326
96.55
Treasury shares as of 31 December 2022 (DNO ASA)
36,369,183
3.45
Total number of outstanding shares
1,054,376,509
100.00
Dividends of USD 72 million were distributed in 2022
\u00a0
(USD 21.8 million in 2021). See Note 25
\u00a0
for dividend approved
on 9 February 2023. See also Note 5 for shares
\u00a0
held by Board of Directors and executive
\u00a0
management.
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2022
2021
2022
2021
Non-current
Bond loan (ISIN NO0010852643)
DNO03
USD
150.7
8.375
29.05.24
9.0
131.5
410.2
131.2
394.9
Bond loan (ISIN NO0011088593)
DNO04
USD
400.0
7.875
09.09.26
8.8
375.8
414.0
400.0
400.0
Capitalized borrowing issue costs
-11.3
-16.5
Reserve based lending facility
-
USD
350.0
see below
see below
-
26.6
95.0
26.6
95.0
Total non-current interest-bearing liabilities
533.9
919.2
546.4
873.4
Current
Reserve based lending facility (current)
-
NOK
350.0
see below
see below
-
8.4
-
8.4
-
Total current interest-bearing liabilities
8.4
-
8.4
-
Total interest-bearing liabilities
542.3
919.2
554.8
873.4
During 2022, DNO ASA acquired USD 263.7 million
\u00a0
of DNO03 bonds at a price range of
\u00a0
99 to 103.35 percent of par plus accrued
interest. Facility and carrying amount for the bonds
\u00a0
is shown net of bonds held by the Company.
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.
The Group has a reserve-based lending (RBL)
\u00a0
facility for its Norway and UK production licenses
\u00a0
with a total facility limit of USD 350
million which is available for both debt and issuance
\u00a0
of letters of credit. In addition, there is an
\u00a0
uncommitted accordion option of USD
350 million. Interest charged on utilizations is based
\u00a0
on LIBOR plus a margin ranging from 2.75
\u00a0
to 3.25 percent. The facility will amortize
over the loan life with a final maturity date
\u00a0
of 7 November 2026. The entities that participate
\u00a0
in the facility are required to submit
quarterly a liquidity test and maintain a consolidated
\u00a0
net debt divided by EBITDAX ratio of maximum
\u00a0
3.50. The security under the RBL
includes, without limitation, a pledge over the
\u00a0
shares in DNO North Sea plc and its subsidiaries,
\u00a0
assignment of claims under shareholder
loans, intra-group loans and insurances, a pledge
\u00a0
of certain bank accounts and mortgages over
\u00a0
the license interests. There are also
restrictions on loans and dividend payments to DNO
\u00a0
ASA. The borrowing base amount of the facility
\u00a0
from 1 January 2023 is USD 74.2
million. Amount utilized as of the reporting date is
\u00a0
disclosed in the table above. In addition, USD
\u00a0
31.8 million is utilized in respect of
letters of credit.
There have been no breaches of the financial
\u00a0
covenants of any interest-bearing liability in the
\u00a0
current period.
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
2022
flows
Amortization
Currency
Acquisition
2022
Bond loans
794.9
-263.7
-
-
-
531.2
Borrowing issue costs
-16.5
-
5.2
-
-
-11.3
Reserve based lending facility
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
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2021
flows
Amortization
Currency
Acquisition
2021
Bond loans
800.0
-5.1
-
-
-
794.9
Borrowing issue costs
-15.4
-10.5
9.4
-
-
-16.5
Reserve based lending facility
149.6
-53.9
-
-0.7
-
95.0
Total
934.2
-69.5
9.4
-0.7
-
873.4
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2022
2021
2022
2021
Non-current
Bond loan (ISIN NO0010852643)
DNO03
USD
150.7
8.375
29.05.24
9.0
131.5
410.2
131.2
394.9
Bond loan (ISIN NO0011088593)
DNO04
USD
400.0
7.875
09.09.26
8.8
375.8
414.0
400.0
400.0
Capitalized borrowing issue costs
-11.3
-16.5
Reserve based lending facility
-
USD
350.0
see below
see below
-
26.6
95.0
26.6
95.0
Total non-current interest-bearing liabilities
533.9
919.2
546.4
873.4
Current
Reserve based lending facility (current)
-
NOK
350.0
see below
see below
-
8.4
-
8.4
-
Total current interest-bearing liabilities
8.4
-
8.4
-
Total interest-bearing liabilities
542.3
919.2
554.8
873.4
During 2022, DNO ASA acquired USD 263.7 million
\u00a0
of DNO03 bonds at a price range of
\u00a0
99 to 103.35 percent of par plus accrued
interest. Facility and carrying amount for the bonds
\u00a0
is shown net of bonds held by the Company.
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.
The Group has a reserve-based lending (RBL)
\u00a0
facility for its Norway and UK production licenses
\u00a0
with a total facility limit of USD 350
million which is available for both debt and issuance
\u00a0
of letters of credit. In addition, there is an
\u00a0
uncommitted accordion option of USD
350 million. Interest charged on utilizations is based
\u00a0
on LIBOR plus a margin ranging from 2.75
\u00a0
to 3.25 percent. The facility will amortize
over the loan life with a final maturity date
\u00a0
of 7 November 2026. The entities that participate
\u00a0
in the facility are required to submit
quarterly a liquidity test and maintain a consolidated
\u00a0
net debt divided by EBITDAX ratio of maximum
\u00a0
3.50. The security under the RBL
includes, without limitation, a pledge over the
\u00a0
shares in DNO North Sea plc and its subsidiaries,
\u00a0
assignment of claims under shareholder
loans, intra-group loans and insurances, a pledge
\u00a0
of certain bank accounts and mortgages over
\u00a0
the license interests. There are also
restrictions on loans and dividend payments to DNO
\u00a0
ASA. The borrowing base amount of the facility
\u00a0
from 1 January 2023 is USD 74.2
million. Amount utilized as of the reporting date is
\u00a0
disclosed in the table above. In addition, USD
\u00a0
31.8 million is utilized in respect of
letters of credit.
There have been no breaches of the financial
\u00a0
covenants of any interest-bearing liability in the
\u00a0
current period.
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
2022
flows
Amortization
Currency
Acquisition
2022
Bond loans
794.9
-263.7
-
-
-
531.2
Borrowing issue costs
-16.5
-
5.2
-
-
-11.3
Reserve based lending facility
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
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2021
flows
Amortization
Currency
Acquisition
2021
Bond loans
800.0
-5.1
-
-
-
794.9
Borrowing issue costs
-15.4
-10.5
9.4
-
-
-16.5
Reserve based lending facility
149.6
-53.9
-
-0.7
-
95.0
Total
934.2
-69.5
9.4
-0.7
-
873.4
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2022
2021
2022
2021
Non-current
Bond loan (ISIN NO0010852643)
DNO03
USD
150.7
8.375
29.05.24
9.0
131.5
410.2
131.2
394.9
Bond loan (ISIN NO0011088593)
DNO04
USD
400.0
7.875
09.09.26
8.8
375.8
414.0
400.0
400.0
Capitalized borrowing issue costs
-11.3
-16.5
Reserve based lending facility
-
USD
350.0
see below
see below
-
26.6
95.0
26.6
95.0
Total non-current interest-bearing liabilities
533.9
919.2
546.4
873.4
Current
Reserve based lending facility (current)
-
NOK
350.0
see below
see below
-
8.4
-
8.4
-
Total current interest-bearing liabilities
8.4
-
8.4
-
Total interest-bearing liabilities
542.3
919.2
554.8
873.4
During 2022, DNO ASA acquired USD 263.7 million
\u00a0
of DNO03 bonds at a price range of
\u00a0
99 to 103.35 percent of par plus accrued
interest. Facility and carrying amount for the bonds
\u00a0
is shown net of bonds held by the Company.
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.
The Group has a reserve-based lending (RBL)
\u00a0
facility for its Norway and UK production licenses
\u00a0
with a total facility limit of USD 350
million which is available for both debt and issuance
\u00a0
of letters of credit. In addition, there is an
\u00a0
uncommitted accordion option of USD
350 million. Interest charged on utilizations is based
\u00a0
on LIBOR plus a margin ranging from 2.75
\u00a0
to 3.25 percent. The facility will amortize
over the loan life with a final maturity date
\u00a0
of 7 November 2026. The entities that participate
\u00a0
in the facility are required to submit
quarterly a liquidity test and maintain a consolidated
\u00a0
net debt divided by EBITDAX ratio of maximum
\u00a0
3.50. The security under the RBL
includes, without limitation, a pledge over the
\u00a0
shares in DNO North Sea plc and its subsidiaries,
\u00a0
assignment of claims under shareholder
loans, intra-group loans and insurances, a pledge
\u00a0
of certain bank accounts and mortgages over
\u00a0
the license interests. There are also
restrictions on loans and dividend payments to DNO
\u00a0
ASA. The borrowing base amount of the facility
\u00a0
from 1 January 2023 is USD 74.2
million. Amount utilized as of the reporting date is
\u00a0
disclosed in the table above. In addition, USD
\u00a0
31.8 million is utilized in respect of
letters of credit.
There have been no breaches of the financial
\u00a0
covenants of any interest-bearing liability in the
\u00a0
current period.
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
2022
flows
Amortization
Currency
Acquisition
2022
Bond loans
794.9
-263.7
-
-
-
531.2
Borrowing issue costs
-16.5
-
5.2
-
-
-11.3
Reserve based lending facility
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
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2021
flows
Amortization
Currency
Acquisition
2021
Bond loans
800.0
-5.1
-
-
-
794.9
Borrowing issue costs
-15.4
-10.5
9.4
-
-
-16.5
Reserve based lending facility
149.6
-53.9
-
-0.7
-
95.0
Total
934.2
-69.5
9.4
-0.7
-
873.4
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2022
2021
2022
2021
Non-current
Bond loan (ISIN NO0010852643)
DNO03
USD
150.7
8.375
29.05.24
9.0
131.5
410.2
131.2
394.9
Bond loan (ISIN NO0011088593)
DNO04
USD
400.0
7.875
09.09.26
8.8
375.8
414.0
400.0
400.0
Capitalized borrowing issue costs
-11.3
-16.5
Reserve based lending facility
-
USD
350.0
see below
see below
-
26.6
95.0
26.6
95.0
Total non-current interest-bearing liabilities
533.9
919.2
546.4
873.4
Current
Reserve based lending facility (current)
-
NOK
350.0
see below
see below
-
8.4
-
8.4
-
Total current interest-bearing liabilities
8.4
-
8.4
-
Total interest-bearing liabilities
542.3
919.2
554.8
873.4
During 2022, DNO ASA acquired USD 263.7 million
\u00a0
of DNO03 bonds at a price range of
\u00a0
99 to 103.35 percent of par plus accrued
interest. Facility and carrying amount for the bonds
\u00a0
is shown net of bonds held by the Company.
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.
The Group has a reserve-based lending (RBL)
\u00a0
facility for its Norway and UK production licenses
\u00a0
with a total facility limit of USD 350
million which is available for both debt and issuance
\u00a0
of letters of credit. In addition, there is an
\u00a0
uncommitted accordion option of USD
350 million. Interest charged on utilizations is based
\u00a0
on LIBOR plus a margin ranging from 2.75
\u00a0
to 3.25 percent. The facility will amortize
over the loan life with a final maturity date
\u00a0
of 7 November 2026. The entities that participate
\u00a0
in the facility are required to submit
quarterly a liquidity test and maintain a consolidated
\u00a0
net debt divided by EBITDAX ratio of maximum
\u00a0
3.50. The security under the RBL
includes, without limitation, a pledge over the
\u00a0
shares in DNO North Sea plc and its subsidiaries,
\u00a0
assignment of claims under shareholder
loans, intra-group loans and insurances, a pledge
\u00a0
of certain bank accounts and mortgages over
\u00a0
the license interests. There are also
restrictions on loans and dividend payments to DNO
\u00a0
ASA. The borrowing base amount of the facility
\u00a0
from 1 January 2023 is USD 74.2
million. Amount utilized as of the reporting date is
\u00a0
disclosed in the table above. In addition, USD
\u00a0
31.8 million is utilized in respect of
letters of credit.
There have been no breaches of the financial
\u00a0
covenants of any interest-bearing liability in the
\u00a0
current period.
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
2022
flows
Amortization
Currency
Acquisition
2022
Bond loans
794.9
-263.7
-
-
-
531.2
Borrowing issue costs
-16.5
-
5.2
-
-
-11.3
Reserve based lending facility
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
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2021
flows
Amortization
Currency
Acquisition
2021
Bond loans
800.0
-5.1
-
-
-
794.9
Borrowing issue costs
-15.4
-10.5
9.4
-
-
-16.5
Reserve based lending facility
149.6
-53.9
-
-0.7
-
95.0
Total
934.2
-69.5
9.4
-0.7
-
873.4
Years ended 31 December
USD million
2022
2021
Non-current
Asset retirement obligations (ARO)
368.2
386.3
Other long-term obligations
4.9
3.6
Total non-current provisions for other liabilities and charges
373.1
389.9
Lease liabilities
6.5
12.5
Total non-current lease liabilities
6.5
12.5
Current
Asset retirement obligations (ARO)
20.5
69.7
Other provisions and charges
39.8
34.8
Total current provisions for other liabilities and charges
60.2
104.4
Current lease liabilities
6.8
15.7
Total current lease liabilities
6.8
15.7
Total provisions for other liabilities and charges and lease liabilities
446.6
522.6
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 2022 were between 4.5 percent
\u00a0
and 4.8 percent (yearend 2021:
between 3.2 percent and 3.7 percent). The credit
\u00a0
margin included in the discount rates at yearend
\u00a0
2022 was 0.8 percent (yearend 2021:
2.3 percent).
Asset
Other
retirement
non-
USD million
obligations
current
Provisions as of 1 January 2021
523.3
3.4
Decommissioning spend
-86.8
-
Increase/-decrease in existing provisions
0.9
0.2
Amounts charged against provisions
-
-
Effects of change in the discount rate
0.9
-
Accretion expenses (unwinding of discount)
17.7
-
Reclassification and transfer
-
-
Provisions as of 31 December 2021
456.0
3.6
Decommissioning spend
-70.5
-
Increase/-decrease in existing provisions
25.0
1.3
Amounts charged against provisions
-
-
Effects of change in the discount rate
-37.0
-
Accretion expenses (unwinding of discount)
15.2
-
Reclassification and transfer
-
-
Provisions as of 31 December 2022
388.7
4.9
Lease liabilities
The recognized lease liabilities in the balance sheet
\u00a0
are mainly related to rig lease and office rent.
In 2021, DNO entered into a rig lease
agreement to perform decommissioning, plugging and abandonment
\u00a0
at the Schooner and Ketch fields in the UK part of
\u00a0
the North Sea.
The rig lease was entered into with DNO as
\u00a0
the operator of the licenses at the initial signing
\u00a0
and subsequently partly allocated to the
license partners (presented under non-current and
\u00a0
current receivables). The rig lease was recognized
\u00a0
on a gross basis, rather than
based on DNO\u2019s working interest share (60 percent).
\u00a0
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. Extension
\u00a0
options are included in the lease liability when,
\u00a0
based on the management\u2019s
judgement, it is reasonably certain that an extension
\u00a0
will be exercised. Lease payments related
\u00a0
to short-term leases and leases of low-
value assets are recognized under lifting costs and
\u00a0
exploration costs, or tangible assets and
\u00a0
capitalized exploration. Total lease
payments related to short-term leases and low-value
\u00a0
assets were USD 56 million (2021: USD 56.6
\u00a0
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
2022
2021
Within one year
7.0
16.6
6.5
13.1
-
-
Total undiscounted lease liabilities end of the period
\u00a0
13.5
29.7
.
Years ended 31 December
USD million
2022
2021
Non-current
Asset retirement obligations (ARO)
368.2
386.3
Other long-term obligations
4.9
3.6
Total non-current provisions for other liabilities and charges
373.1
389.9
Lease liabilities
6.5
12.5
Total non-current lease liabilities
6.5
12.5
Current
Asset retirement obligations (ARO)
20.5
69.7
Other provisions and charges
39.8
34.8
Total current provisions for other liabilities and charges
60.2
104.4
Current lease liabilities
6.8
15.7
Total current lease liabilities
6.8
15.7
Total provisions for other liabilities and charges and lease liabilities
446.6
522.6
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 2022 were between 4.5 percent
\u00a0
and 4.8 percent (yearend 2021:
between 3.2 percent and 3.7 percent). The credit
\u00a0
margin included in the discount rates at yearend
\u00a0
2022 was 0.8 percent (yearend 2021:
2.3 percent).
Asset
Other
retirement
non-
USD million
obligations
current
Provisions as of 1 January 2021
523.3
3.4
Decommissioning spend
-86.8
-
Increase/-decrease in existing provisions
0.9
0.2
Amounts charged against provisions
-
-
Effects of change in the discount rate
0.9
-
Accretion expenses (unwinding of discount)
17.7
-
Reclassification and transfer
-
-
Provisions as of 31 December 2021
456.0
3.6
Decommissioning spend
-70.5
-
Increase/-decrease in existing provisions
25.0
1.3
Amounts charged against provisions
-
-
Effects of change in the discount rate
-37.0
-
Accretion expenses (unwinding of discount)
15.2
-
Reclassification and transfer
-
-
Provisions as of 31 December 2022
388.7
4.9
Lease liabilities
The recognized lease liabilities in the balance sheet
\u00a0
are mainly related to rig lease and office rent.
In 2021, DNO entered into a rig lease
agreement to perform decommissioning, plugging and abandonment
\u00a0
at the Schooner and Ketch fields in the UK part of
\u00a0
the North Sea.
The rig lease was entered into with DNO as
\u00a0
the operator of the licenses at the initial signing
\u00a0
and subsequently partly allocated to the
license partners (presented under non-current and
\u00a0
current receivables). The rig lease was recognized
\u00a0
on a gross basis, rather than
based on DNO\u2019s working interest share (60 percent).
\u00a0
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. Extension
\u00a0
options are included in the lease liability when,
\u00a0
based on the management\u2019s
judgement, it is reasonably certain that an extension
\u00a0
will be exercised. Lease payments related
\u00a0
to short-term leases and leases of low-
value assets are recognized under lifting costs and
\u00a0
exploration costs, or tangible assets and
\u00a0
capitalized exploration. Total lease
payments related to short-term leases and low-value
\u00a0
assets were USD 56 million (2021: USD 56.6
\u00a0
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
2022
2021
Within one year
7.0
16.6
6.5
13.1
-
-
Total undiscounted lease liabilities end of the period
\u00a0
13.5
29.7
.
Years ended 31 December
USD million
2022
2021
Non-current
Asset retirement obligations (ARO)
368.2
386.3
Other long-term obligations
4.9
3.6
Total non-current provisions for other liabilities and charges
373.1
389.9
Lease liabilities
6.5
12.5
Total non-current lease liabilities
6.5
12.5
Current
Asset retirement obligations (ARO)
20.5
69.7
Other provisions and charges
39.8
34.8
Total current provisions for other liabilities and charges
60.2
104.4
Current lease liabilities
6.8
15.7
Total current lease liabilities
6.8
15.7
Total provisions for other liabilities and charges and lease liabilities
446.6
522.6
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 2022 were between 4.5 percent
\u00a0
and 4.8 percent (yearend 2021:
between 3.2 percent and 3.7 percent). The credit
\u00a0
margin included in the discount rates at yearend
\u00a0
2022 was 0.8 percent (yearend 2021:
2.3 percent).
Asset
Other
retirement
non-
USD million
obligations
current
Provisions as of 1 January 2021
523.3
3.4
Decommissioning spend
-86.8
-
Increase/-decrease in existing provisions
0.9
0.2
Amounts charged against provisions
-
-
Effects of change in the discount rate
0.9
-
Accretion expenses (unwinding of discount)
17.7
-
Reclassification and transfer
-
-
Provisions as of 31 December 2021
456.0
3.6
Decommissioning spend
-70.5
-
Increase/-decrease in existing provisions
25.0
1.3
Amounts charged against provisions
-
-
Effects of change in the discount rate
-37.0
-
Accretion expenses (unwinding of discount)
15.2
-
Reclassification and transfer
-
-
Provisions as of 31 December 2022
388.7
4.9
Lease liabilities
The recognized lease liabilities in the balance sheet
\u00a0
are mainly related to rig lease and office rent.
In 2021, DNO entered into a rig lease
agreement to perform decommissioning, plugging and abandonment
\u00a0
at the Schooner and Ketch fields in the UK part of
\u00a0
the North Sea.
The rig lease was entered into with DNO as
\u00a0
the operator of the licenses at the initial signing
\u00a0
and subsequently partly allocated to the
license partners (presented under non-current and
\u00a0
current receivables). The rig lease was recognized
\u00a0
on a gross basis, rather than
based on DNO\u2019s working interest share (60 percent).
\u00a0
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. Extension
\u00a0
options are included in the lease liability when,
\u00a0
based on the management\u2019s
judgement, it is reasonably certain that an extension
\u00a0
will be exercised. Lease payments related
\u00a0
to short-term leases and leases of low-
value assets are recognized under lifting costs and
\u00a0
exploration costs, or tangible assets and
\u00a0
capitalized exploration. Total lease
payments related to short-term leases and low-value
\u00a0
assets were USD 56 million (2021: USD 56.6
\u00a0
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
2022
2021
Within one year
7.0
16.6
6.5
13.1
-
-
Total undiscounted lease liabilities end of the period
\u00a0
13.5
29.7
.
Note 17
Trade and other payables
Years ended 31 December
USD million
2022
2021
Trade payables
62.7
85.7
Public duties payable
4.1
6.1
Prepayments from customers
12.7
-
Overlift
9.0
17.3
Other accrued expenses
155.7
123.4
Total trade and other payables
244.1
232.6
Trade payables are non-interest bearing and are normally settled
\u00a0
within 30 days.
Trade payables and other accrued expenses include items of working
\u00a0
capital related to participation in licenses in Kurdistan
\u00a0
and the
North Sea, and prepayment from customers related
\u00a0
to oil sales in the North Sea.
The overlift payable relates to North Sea overlifted
\u00a0
volumes, valued at production cost including depreciation.
Note 17
Trade and other payables
Years ended 31 December
USD million
2022
2021
Trade payables
62.7
85.7
Public duties payable
4.1
6.1
Prepayments from customers
12.7
-
Overlift
9.0
17.3
Other accrued expenses
155.7
123.4
Total trade and other payables
244.1
232.6
Trade payables are non-interest bearing and are normally settled
\u00a0
within 30 days.
Trade payables and other accrued expenses include items of working
\u00a0
capital related to participation in licenses in Kurdistan
\u00a0
and the
North Sea, and prepayment from customers related
\u00a0
to oil sales in the North Sea.
The overlift payable relates to North Sea overlifted
\u00a0
volumes, valued at production cost including depreciation.
Note 17
Trade and other payables
Years ended 31 December
USD million
2022
2021
Trade payables
62.7
85.7
Public duties payable
4.1
6.1
Prepayments from customers
12.7
-
Overlift
9.0
17.3
Other accrued expenses
155.7
123.4
Total trade and other payables
244.1
232.6
Trade payables are non-interest bearing and are normally settled
\u00a0
within 30 days.
Trade payables and other accrued expenses include items of working
\u00a0
capital related to participation in licenses in Kurdistan
\u00a0
and the
North Sea, and prepayment from customers related
\u00a0
to oil sales in the North Sea.
The overlift payable relates to North Sea overlifted
\u00a0
volumes, valued at production cost including depreciation.
Financial risk management, objectives and policies
Overview
The Group\u2019s principal financial liabilities are comprised of interest-bearing
\u00a0
liabilities and trade and other payables. The
\u00a0
main purpose of
these financial liabilities is to finance DNO\u2019s operations. The
\u00a0
Group\u2019s principal financial assets include trade
\u00a0
and other receivables, tax
receivables and cash and cash equivalents.
\u00a0
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. In 2022, the Group had gas price
\u00a0
put options in place with strike prices of
GBP 79 -110 pence per therm, securing approximately 75 percent of after-tax
\u00a0
profit from estimated 2022 gas production.
\u00a0
The Group
had no oil and gas price hedging arrangements
\u00a0
at yearend 2022.
\u00a0
The following table illustrates the impact on reported 2021
\u00a0
and 2022 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 9 for a
sensitivity analysis related to the impairment
\u00a0
assessment of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
2022
+/- 15.0
2021
+/- 15.0
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 2022 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2021 and
\u00a0
2022 from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP exchange rates,
\u00a0
with all other variables held
constant. The other currencies (e.g., AED, IQD) are not
\u00a0
included as the exposure is deemed immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2022
+ 10.0
-3.5
2022
- 10.0
3.5
2021
+ 10.0
-5.9
2021
- 10.0
5.9
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2022
+ 10.0
-19.0
2022
- 10.0
19.0
2021
+ 10.0
1.4
2021
- 10.0
-1.4
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2022
+ 10.0
-4.8
2022
- 10.0
4.8
2021
+ 10.0
-3.6
2021
- 10.0
3.6
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 2022. 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 2021 and
\u00a0
2022 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)
2022
+/- 200
+/-7.7
2021
+/- 200
+/-14.8
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 and
\u00a0
other financial resources to maintain financial
\u00a0
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 15. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 10) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made on
\u00a0
a regular basis pursuant to an approved budget
\u00a0
and work program.
\u00a0
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 in 2022
\u00a0
derived primarily from production in the Tawke license in Kurdistan and
from several licenses in the North Sea. The Group
\u00a0
actively seeks to reduce such risk through
\u00a0
organic growth and asset acquisitions
aimed at further diversifying its revenue sources.
\u00a0
See also Note 10 regarding the Company\u2019s entry in
\u00a0
West Africa.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
USD million
On
At 31 December 2022
demand
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
USD million
On
At 31 December 2021
demand
Interest-bearing liabilities*
16.9
60.8
510.4
545.3
Other provisions and charges
18.6
16.2
Taxes payable
-
12.6
20.5
-
-
Trade and other payables
1.9
210.4
3.0
Total liabilities
1.9
258.5
100.5
510.4
545.3
* Face value of the bonds was USD 531.2 million at yearend 2022 (USD 794.9 million at yearend 2021).
For changes in liabilities arising from financing activities,
\u00a0
see Note 15.
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
2022
2021
Trade debtors (non-current portion) (Note 12)
-
18.2
Trade debtors (Note 12)
311.8
344.4
Other receivables (Note 12)
126.0
139.4
25.8
21.1
Cash and cash equivalents
954.3
736.6
1,417.9
1,259.7
Trade debtors
The impairment model in IFRS 9 is based on
\u00a0
the premise of providing for expected credit
\u00a0
losses. Expected credit losses (ECL) under
IFRS 9 are based on the difference between the contractual
\u00a0
cash flows due in accordance with the contract and
\u00a0
all the cash flows that
are expected to be received, discounted at an
\u00a0
approximation of the original effective interest rate.
\u00a0
Measurement of ECLs under IFRS 9
shall reflect an unbiased and probability-weighted
\u00a0
amount that is determined by evaluating the range
\u00a0
of possible outcomes as well as
incorporating the time value of money. The entity should consider reasonable and
\u00a0
supportable information about past events, current
conditions and reasonable and supportable forecasts
\u00a0
of future economic conditions when measuring expected
\u00a0
credit losses.
Trade debtors from oil sales invoices in Kurdistan
Normal payment terms apply to amounts owed to
\u00a0
DNO by the KRG for oil sales and override invoices
\u00a0
from the Tawke and the Baeshiqa
license in Kurdistan. Since late 2015, DNO received
\u00a0
the payment due to it from oil sales and overrides
\u00a0
on a monthly basis from the KRG
At yearend 2020, the Group had accumulated
\u00a0
a receivable against the KRG of USD 259
\u00a0
million after certain 2019 and 2020 entitlement
and override payments to the Group and other
\u00a0
Kurdistan oil exporters were withheld early in
\u00a0
2020 by the KRG in connection with the
hardships and uncertainties brought about by
\u00a0
the Covid-19 pandemic. Entitlement payments resumed
\u00a0
in March 2020 and override
payments in early 2021. A payment plan was
\u00a0
put in place by the KRG in December
\u00a0
2020 and subsequently revised in May 2021
\u00a0
to pay
the outstanding arrears. As a part of the May 2021
\u00a0
revision, the KRG also informed the international
\u00a0
oil companies that all invoices,
including towards the arrears, will be settled within 60
\u00a0
days of the end of the respective production
\u00a0
month. During 2022, the outstanding
arrears were reduced from USD 169 million
\u00a0
at the start of the year to USD 2 million
\u00a0
at yearend, not including any interest. The Company
continues to work to collect the remaining balances
\u00a0
and expects to be paid accordingly.
\u00a0
Over the course of 2022, KRG payments to
\u00a0
international oil companies were increasingly delayed.
\u00a0
At the time of issuing this report, the
invoices related to August and September 2022 oil
\u00a0
deliveries were paid in January and March
\u00a0
2023, respectively. The Company is in
dialogue with the KRG, seeking timely payments to
\u00a0
support timely investments. Moreover, in September 2022, the KRG proposed
\u00a0
a
change in the previously agreed pricing formula for
\u00a0
oil such that prices should, with effect from 1 September
\u00a0
2022, be based on the
purported price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been accepted
\u00a0
by DNO and the Company
continues to invoice the KRG for oil sales based
\u00a0
on the previously agreed pricing formula (including
\u00a0
the September 2022 invoice) until
such time that protocols are put in place to ensure
\u00a0
that realized prices are transparent, based on arms-length
\u00a0
transactions and subject
to third-party audit. The payment for the September oil
\u00a0
delivery received after yearend reflects the formula
\u00a0
proposed and unilaterally
applied by the KRG in September 2022 resulting in an
\u00a0
approximately USD 11/bbl reduction in realized price compared to current pricing
formula based on Dated Brent. The payment received
\u00a0
was USD 5.2 million (net to DNO) lower than
\u00a0
invoiced. The Company is in
continuing dialogue with the KRG to resolve this
\u00a0
matter and collect outstanding balances. The Company
\u00a0
estimates that using the KRG
proposed prices, the impact of the change in pricing
\u00a0
would have resulted in approximately USD
\u00a0
23 million lower revenues compared to
the reported September through December 2022 Kurdistan
\u00a0
revenues.
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 2022
Trade debtors (nominal value) (Note 12)
-
132.7
58.1
55.9
63.1
2.0
311.8
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2021
Trade debtors (nominal value) (Note 12)
-
131.6
61.9
-
-
169.1
362.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Total trade debtors of USD 311.8 million at yearend 2022 relate mainly to the Tawke license, see Note 12 for details.
\u00a0
Cash deposits
Credit risk from balances with banks and financial
\u00a0
institutions is managed by the Group\u2019s treasury function.
\u00a0
The Group limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the 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
15. The equity ratio has improved primarily
\u00a0
due to a net profit in 2022. 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 2022 and
\u00a0
2021.
Years ended 31 December
USD million
2022
2021
Total equity
1,369.4
1,018.8
Total assets
2,803.0
2,947.8
Equity ratio
48.9%
34.6%
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 assets and financial liabilities,
\u00a0
including their levels in the fair
value hierarchy. It does not include the carrying amounts and fair value
\u00a0
information for financial assets and financial liabilities
\u00a0
not
measured or disclosed at fair value if the carrying
\u00a0
amount is a reasonable approximation of
\u00a0
fair value.
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2022 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
-
-
-
31 December 2022
-
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
15
-
8.4
8.4
-
8.4
* Financial assets designated at FVTOCI with no recycling of cumulative gains and losses upon derecognition
\u00a0
(equity instruments).
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2021 - USD million
Note
at FVTOCI
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
16.2
-
16.2
31 December 2021
16.2
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
873.4
873.4
31 December 2021
824.2
-
95.0
Interest-bearing liabilities (current)
15
-
-
-
-
-
-
Financial risk management, objectives and policies
Overview
The Group\u2019s principal financial liabilities are comprised of interest-bearing
\u00a0
liabilities and trade and other payables. The
\u00a0
main purpose of
these financial liabilities is to finance DNO\u2019s operations. The
\u00a0
Group\u2019s principal financial assets include trade
\u00a0
and other receivables, tax
receivables and cash and cash equivalents.
\u00a0
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. In 2022, the Group had gas price
\u00a0
put options in place with strike prices of
GBP 79 -110 pence per therm, securing approximately 75 percent of after-tax
\u00a0
profit from estimated 2022 gas production.
\u00a0
The Group
had no oil and gas price hedging arrangements
\u00a0
at yearend 2022.
\u00a0
The following table illustrates the impact on reported 2021
\u00a0
and 2022 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 9 for a
sensitivity analysis related to the impairment
\u00a0
assessment of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
2022
+/- 15.0
2021
+/- 15.0
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 2022 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2021 and
\u00a0
2022 from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP exchange rates,
\u00a0
with all other variables held
constant. The other currencies (e.g., AED, IQD) are not
\u00a0
included as the exposure is deemed immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2022
+ 10.0
-3.5
2022
- 10.0
3.5
2021
+ 10.0
-5.9
2021
- 10.0
5.9
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2022
+ 10.0
-19.0
2022
- 10.0
19.0
2021
+ 10.0
1.4
2021
- 10.0
-1.4
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2022
+ 10.0
-4.8
2022
- 10.0
4.8
2021
+ 10.0
-3.6
2021
- 10.0
3.6
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 2022. 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 2021 and
\u00a0
2022 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)
2022
+/- 200
+/-7.7
2021
+/- 200
+/-14.8
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 and
\u00a0
other financial resources to maintain financial
\u00a0
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 15. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 10) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made on
\u00a0
a regular basis pursuant to an approved budget
\u00a0
and work program.
\u00a0
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 in 2022
\u00a0
derived primarily from production in the Tawke license in Kurdistan and
from several licenses in the North Sea. The Group
\u00a0
actively seeks to reduce such risk through
\u00a0
organic growth and asset acquisitions
aimed at further diversifying its revenue sources.
\u00a0
See also Note 10 regarding the Company\u2019s entry in
\u00a0
West Africa.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
USD million
On
At 31 December 2022
demand
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
USD million
On
At 31 December 2021
demand
Interest-bearing liabilities*
16.9
60.8
510.4
545.3
Other provisions and charges
18.6
16.2
Taxes payable
-
12.6
20.5
-
-
Trade and other payables
1.9
210.4
3.0
Total liabilities
1.9
258.5
100.5
510.4
545.3
* Face value of the bonds was USD 531.2 million at yearend 2022 (USD 794.9 million at yearend 2021).
For changes in liabilities arising from financing activities,
\u00a0
see Note 15.
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
2022
2021
Trade debtors (non-current portion) (Note 12)
-
18.2
Trade debtors (Note 12)
311.8
344.4
Other receivables (Note 12)
126.0
139.4
25.8
21.1
Cash and cash equivalents
954.3
736.6
1,417.9
1,259.7
Trade debtors
The impairment model in IFRS 9 is based on
\u00a0
the premise of providing for expected credit
\u00a0
losses. Expected credit losses (ECL) under
IFRS 9 are based on the difference between the contractual
\u00a0
cash flows due in accordance with the contract and
\u00a0
all the cash flows that
are expected to be received, discounted at an
\u00a0
approximation of the original effective interest rate.
\u00a0
Measurement of ECLs under IFRS 9
shall reflect an unbiased and probability-weighted
\u00a0
amount that is determined by evaluating the range
\u00a0
of possible outcomes as well as
incorporating the time value of money. The entity should consider reasonable and
\u00a0
supportable information about past events, current
conditions and reasonable and supportable forecasts
\u00a0
of future economic conditions when measuring expected
\u00a0
credit losses.
Trade debtors from oil sales invoices in Kurdistan
Normal payment terms apply to amounts owed to
\u00a0
DNO by the KRG for oil sales and override invoices
\u00a0
from the Tawke and the Baeshiqa
license in Kurdistan. Since late 2015, DNO received
\u00a0
the payment due to it from oil sales and overrides
\u00a0
on a monthly basis from the KRG
At yearend 2020, the Group had accumulated
\u00a0
a receivable against the KRG of USD 259
\u00a0
million after certain 2019 and 2020 entitlement
and override payments to the Group and other
\u00a0
Kurdistan oil exporters were withheld early in
\u00a0
2020 by the KRG in connection with the
hardships and uncertainties brought about by
\u00a0
the Covid-19 pandemic. Entitlement payments resumed
\u00a0
in March 2020 and override
payments in early 2021. A payment plan was
\u00a0
put in place by the KRG in December
\u00a0
2020 and subsequently revised in May 2021
\u00a0
to pay
the outstanding arrears. As a part of the May 2021
\u00a0
revision, the KRG also informed the international
\u00a0
oil companies that all invoices,
including towards the arrears, will be settled within 60
\u00a0
days of the end of the respective production
\u00a0
month. During 2022, the outstanding
arrears were reduced from USD 169 million
\u00a0
at the start of the year to USD 2 million
\u00a0
at yearend, not including any interest. The Company
continues to work to collect the remaining balances
\u00a0
and expects to be paid accordingly.
\u00a0
Over the course of 2022, KRG payments to
\u00a0
international oil companies were increasingly delayed.
\u00a0
At the time of issuing this report, the
invoices related to August and September 2022 oil
\u00a0
deliveries were paid in January and March
\u00a0
2023, respectively. The Company is in
dialogue with the KRG, seeking timely payments to
\u00a0
support timely investments. Moreover, in September 2022, the KRG proposed
\u00a0
a
change in the previously agreed pricing formula for
\u00a0
oil such that prices should, with effect from 1 September
\u00a0
2022, be based on the
purported price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been accepted
\u00a0
by DNO and the Company
continues to invoice the KRG for oil sales based
\u00a0
on the previously agreed pricing formula (including
\u00a0
the September 2022 invoice) until
such time that protocols are put in place to ensure
\u00a0
that realized prices are transparent, based on arms-length
\u00a0
transactions and subject
to third-party audit. The payment for the September oil
\u00a0
delivery received after yearend reflects the formula
\u00a0
proposed and unilaterally
applied by the KRG in September 2022 resulting in an
\u00a0
approximately USD 11/bbl reduction in realized price compared to current pricing
formula based on Dated Brent. The payment received
\u00a0
was USD 5.2 million (net to DNO) lower than
\u00a0
invoiced. The Company is in
continuing dialogue with the KRG to resolve this
\u00a0
matter and collect outstanding balances. The Company
\u00a0
estimates that using the KRG
proposed prices, the impact of the change in pricing
\u00a0
would have resulted in approximately USD
\u00a0
23 million lower revenues compared to
the reported September through December 2022 Kurdistan
\u00a0
revenues.
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 2022
Trade debtors (nominal value) (Note 12)
-
132.7
58.1
55.9
63.1
2.0
311.8
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2021
Trade debtors (nominal value) (Note 12)
-
131.6
61.9
-
-
169.1
362.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Total trade debtors of USD 311.8 million at yearend 2022 relate mainly to the Tawke license, see Note 12 for details.
\u00a0
Cash deposits
Credit risk from balances with banks and financial
\u00a0
institutions is managed by the Group\u2019s treasury function.
\u00a0
The Group limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the 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
15. The equity ratio has improved primarily
\u00a0
due to a net profit in 2022. 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 2022 and
\u00a0
2021.
Years ended 31 December
USD million
2022
2021
Total equity
1,369.4
1,018.8
Total assets
2,803.0
2,947.8
Equity ratio
48.9%
34.6%
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 assets and financial liabilities,
\u00a0
including their levels in the fair
value hierarchy. It does not include the carrying amounts and fair value
\u00a0
information for financial assets and financial liabilities
\u00a0
not
measured or disclosed at fair value if the carrying
\u00a0
amount is a reasonable approximation of
\u00a0
fair value.
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2022 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
-
-
-
31 December 2022
-
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
15
-
8.4
8.4
-
8.4
* Financial assets designated at FVTOCI with no recycling of cumulative gains and losses upon derecognition
\u00a0
(equity instruments).
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2021 - USD million
Note
at FVTOCI
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
16.2
-
16.2
31 December 2021
16.2
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
873.4
873.4
31 December 2021
824.2
-
95.0
Interest-bearing liabilities (current)
15
-
-
-
-
-
-
Financial risk management, objectives and policies
Overview
The Group\u2019s principal financial liabilities are comprised of interest-bearing
\u00a0
liabilities and trade and other payables. The
\u00a0
main purpose of
these financial liabilities is to finance DNO\u2019s operations. The
\u00a0
Group\u2019s principal financial assets include trade
\u00a0
and other receivables, tax
receivables and cash and cash equivalents.
\u00a0
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. In 2022, the Group had gas price
\u00a0
put options in place with strike prices of
GBP 79 -110 pence per therm, securing approximately 75 percent of after-tax
\u00a0
profit from estimated 2022 gas production.
\u00a0
The Group
had no oil and gas price hedging arrangements
\u00a0
at yearend 2022.
\u00a0
The following table illustrates the impact on reported 2021
\u00a0
and 2022 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 9 for a
sensitivity analysis related to the impairment
\u00a0
assessment of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
2022
+/- 15.0
2021
+/- 15.0
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 2022 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2021 and
\u00a0
2022 from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP exchange rates,
\u00a0
with all other variables held
constant. The other currencies (e.g., AED, IQD) are not
\u00a0
included as the exposure is deemed immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2022
+ 10.0
-3.5
2022
- 10.0
3.5
2021
+ 10.0
-5.9
2021
- 10.0
5.9
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2022
+ 10.0
-19.0
2022
- 10.0
19.0
2021
+ 10.0
1.4
2021
- 10.0
-1.4
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2022
+ 10.0
-4.8
2022
- 10.0
4.8
2021
+ 10.0
-3.6
2021
- 10.0
3.6
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 2022. 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 2021 and
\u00a0
2022 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)
2022
+/- 200
+/-7.7
2021
+/- 200
+/-14.8
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 and
\u00a0
other financial resources to maintain financial
\u00a0
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 15. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 10) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made on
\u00a0
a regular basis pursuant to an approved budget
\u00a0
and work program.
\u00a0
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 in 2022
\u00a0
derived primarily from production in the Tawke license in Kurdistan and
from several licenses in the North Sea. The Group
\u00a0
actively seeks to reduce such risk through
\u00a0
organic growth and asset acquisitions
aimed at further diversifying its revenue sources.
\u00a0
See also Note 10 regarding the Company\u2019s entry in
\u00a0
West Africa.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
USD million
On
At 31 December 2022
demand
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
USD million
On
At 31 December 2021
demand
Interest-bearing liabilities*
16.9
60.8
510.4
545.3
Other provisions and charges
18.6
16.2
Taxes payable
-
12.6
20.5
-
-
Trade and other payables
1.9
210.4
3.0
Total liabilities
1.9
258.5
100.5
510.4
545.3
* Face value of the bonds was USD 531.2 million at yearend 2022 (USD 794.9 million at yearend 2021).
For changes in liabilities arising from financing activities,
\u00a0
see Note 15.
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
2022
2021
Trade debtors (non-current portion) (Note 12)
-
18.2
Trade debtors (Note 12)
311.8
344.4
Other receivables (Note 12)
126.0
139.4
25.8
21.1
Cash and cash equivalents
954.3
736.6
1,417.9
1,259.7
Trade debtors
The impairment model in IFRS 9 is based on
\u00a0
the premise of providing for expected credit
\u00a0
losses. Expected credit losses (ECL) under
IFRS 9 are based on the difference between the contractual
\u00a0
cash flows due in accordance with the contract and
\u00a0
all the cash flows that
are expected to be received, discounted at an
\u00a0
approximation of the original effective interest rate.
\u00a0
Measurement of ECLs under IFRS 9
shall reflect an unbiased and probability-weighted
\u00a0
amount that is determined by evaluating the range
\u00a0
of possible outcomes as well as
incorporating the time value of money. The entity should consider reasonable and
\u00a0
supportable information about past events, current
conditions and reasonable and supportable forecasts
\u00a0
of future economic conditions when measuring expected
\u00a0
credit losses.
Trade debtors from oil sales invoices in Kurdistan
Normal payment terms apply to amounts owed to
\u00a0
DNO by the KRG for oil sales and override invoices
\u00a0
from the Tawke and the Baeshiqa
license in Kurdistan. Since late 2015, DNO received
\u00a0
the payment due to it from oil sales and overrides
\u00a0
on a monthly basis from the KRG
At yearend 2020, the Group had accumulated
\u00a0
a receivable against the KRG of USD 259
\u00a0
million after certain 2019 and 2020 entitlement
and override payments to the Group and other
\u00a0
Kurdistan oil exporters were withheld early in
\u00a0
2020 by the KRG in connection with the
hardships and uncertainties brought about by
\u00a0
the Covid-19 pandemic. Entitlement payments resumed
\u00a0
in March 2020 and override
payments in early 2021. A payment plan was
\u00a0
put in place by the KRG in December
\u00a0
2020 and subsequently revised in May 2021
\u00a0
to pay
the outstanding arrears. As a part of the May 2021
\u00a0
revision, the KRG also informed the international
\u00a0
oil companies that all invoices,
including towards the arrears, will be settled within 60
\u00a0
days of the end of the respective production
\u00a0
month. During 2022, the outstanding
arrears were reduced from USD 169 million
\u00a0
at the start of the year to USD 2 million
\u00a0
at yearend, not including any interest. The Company
continues to work to collect the remaining balances
\u00a0
and expects to be paid accordingly.
\u00a0
Over the course of 2022, KRG payments to
\u00a0
international oil companies were increasingly delayed.
\u00a0
At the time of issuing this report, the
invoices related to August and September 2022 oil
\u00a0
deliveries were paid in January and March
\u00a0
2023, respectively. The Company is in
dialogue with the KRG, seeking timely payments to
\u00a0
support timely investments. Moreover, in September 2022, the KRG proposed
\u00a0
a
change in the previously agreed pricing formula for
\u00a0
oil such that prices should, with effect from 1 September
\u00a0
2022, be based on the
purported price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been accepted
\u00a0
by DNO and the Company
continues to invoice the KRG for oil sales based
\u00a0
on the previously agreed pricing formula (including
\u00a0
the September 2022 invoice) until
such time that protocols are put in place to ensure
\u00a0
that realized prices are transparent, based on arms-length
\u00a0
transactions and subject
to third-party audit. The payment for the September oil
\u00a0
delivery received after yearend reflects the formula
\u00a0
proposed and unilaterally
applied by the KRG in September 2022 resulting in an
\u00a0
approximately USD 11/bbl reduction in realized price compared to current pricing
formula based on Dated Brent. The payment received
\u00a0
was USD 5.2 million (net to DNO) lower than
\u00a0
invoiced. The Company is in
continuing dialogue with the KRG to resolve this
\u00a0
matter and collect outstanding balances. The Company
\u00a0
estimates that using the KRG
proposed prices, the impact of the change in pricing
\u00a0
would have resulted in approximately USD
\u00a0
23 million lower revenues compared to
the reported September through December 2022 Kurdistan
\u00a0
revenues.
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 2022
Trade debtors (nominal value) (Note 12)
-
132.7
58.1
55.9
63.1
2.0
311.8
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2021
Trade debtors (nominal value) (Note 12)
-
131.6
61.9
-
-
169.1
362.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Total trade debtors of USD 311.8 million at yearend 2022 relate mainly to the Tawke license, see Note 12 for details.
\u00a0
Cash deposits
Credit risk from balances with banks and financial
\u00a0
institutions is managed by the Group\u2019s treasury function.
\u00a0
The Group limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the 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
15. The equity ratio has improved primarily
\u00a0
due to a net profit in 2022. 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 2022 and
\u00a0
2021.
Years ended 31 December
USD million
2022
2021
Total equity
1,369.4
1,018.8
Total assets
2,803.0
2,947.8
Equity ratio
48.9%
34.6%
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 assets and financial liabilities,
\u00a0
including their levels in the fair
value hierarchy. It does not include the carrying amounts and fair value
\u00a0
information for financial assets and financial liabilities
\u00a0
not
measured or disclosed at fair value if the carrying
\u00a0
amount is a reasonable approximation of
\u00a0
fair value.
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2022 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
-
-
-
31 December 2022
-
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
15
-
8.4
8.4
-
8.4
* Financial assets designated at FVTOCI with no recycling of cumulative gains and losses upon derecognition
\u00a0
(equity instruments).
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2021 - USD million
Note
at FVTOCI
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
16.2
-
16.2
31 December 2021
16.2
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
873.4
873.4
31 December 2021
824.2
-
95.0
Interest-bearing liabilities (current)
15
-
-
-
-
-
-
Financial risk management, objectives and policies
Overview
The Group\u2019s principal financial liabilities are comprised of interest-bearing
\u00a0
liabilities and trade and other payables. The
\u00a0
main purpose of
these financial liabilities is to finance DNO\u2019s operations. The
\u00a0
Group\u2019s principal financial assets include trade
\u00a0
and other receivables, tax
receivables and cash and cash equivalents.
\u00a0
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. In 2022, the Group had gas price
\u00a0
put options in place with strike prices of
GBP 79 -110 pence per therm, securing approximately 75 percent of after-tax
\u00a0
profit from estimated 2022 gas production.
\u00a0
The Group
had no oil and gas price hedging arrangements
\u00a0
at yearend 2022.
\u00a0
The following table illustrates the impact on reported 2021
\u00a0
and 2022 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 9 for a
sensitivity analysis related to the impairment
\u00a0
assessment of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
2022
+/- 15.0
2021
+/- 15.0
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 2022 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2021 and
\u00a0
2022 from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP exchange rates,
\u00a0
with all other variables held
constant. The other currencies (e.g., AED, IQD) are not
\u00a0
included as the exposure is deemed immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2022
+ 10.0
-3.5
2022
- 10.0
3.5
2021
+ 10.0
-5.9
2021
- 10.0
5.9
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2022
+ 10.0
-19.0
2022
- 10.0
19.0
2021
+ 10.0
1.4
2021
- 10.0
-1.4
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2022
+ 10.0
-4.8
2022
- 10.0
4.8
2021
+ 10.0
-3.6
2021
- 10.0
3.6
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 2022. 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 2021 and
\u00a0
2022 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)
2022
+/- 200
+/-7.7
2021
+/- 200
+/-14.8
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 and
\u00a0
other financial resources to maintain financial
\u00a0
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 15. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 10) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made on
\u00a0
a regular basis pursuant to an approved budget
\u00a0
and work program.
\u00a0
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 in 2022
\u00a0
derived primarily from production in the Tawke license in Kurdistan and
from several licenses in the North Sea. The Group
\u00a0
actively seeks to reduce such risk through
\u00a0
organic growth and asset acquisitions
aimed at further diversifying its revenue sources.
\u00a0
See also Note 10 regarding the Company\u2019s entry in
\u00a0
West Africa.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
USD million
On
At 31 December 2022
demand
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
USD million
On
At 31 December 2021
demand
Interest-bearing liabilities*
16.9
60.8
510.4
545.3
Other provisions and charges
18.6
16.2
Taxes payable
-
12.6
20.5
-
-
Trade and other payables
1.9
210.4
3.0
Total liabilities
1.9
258.5
100.5
510.4
545.3
* Face value of the bonds was USD 531.2 million at yearend 2022 (USD 794.9 million at yearend 2021).
For changes in liabilities arising from financing activities,
\u00a0
see Note 15.
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
2022
2021
Trade debtors (non-current portion) (Note 12)
-
18.2
Trade debtors (Note 12)
311.8
344.4
Other receivables (Note 12)
126.0
139.4
25.8
21.1
Cash and cash equivalents
954.3
736.6
1,417.9
1,259.7
Trade debtors
The impairment model in IFRS 9 is based on
\u00a0
the premise of providing for expected credit
\u00a0
losses. Expected credit losses (ECL) under
IFRS 9 are based on the difference between the contractual
\u00a0
cash flows due in accordance with the contract and
\u00a0
all the cash flows that
are expected to be received, discounted at an
\u00a0
approximation of the original effective interest rate.
\u00a0
Measurement of ECLs under IFRS 9
shall reflect an unbiased and probability-weighted
\u00a0
amount that is determined by evaluating the range
\u00a0
of possible outcomes as well as
incorporating the time value of money. The entity should consider reasonable and
\u00a0
supportable information about past events, current
conditions and reasonable and supportable forecasts
\u00a0
of future economic conditions when measuring expected
\u00a0
credit losses.
Trade debtors from oil sales invoices in Kurdistan
Normal payment terms apply to amounts owed to
\u00a0
DNO by the KRG for oil sales and override invoices
\u00a0
from the Tawke and the Baeshiqa
license in Kurdistan. Since late 2015, DNO received
\u00a0
the payment due to it from oil sales and overrides
\u00a0
on a monthly basis from the KRG
At yearend 2020, the Group had accumulated
\u00a0
a receivable against the KRG of USD 259
\u00a0
million after certain 2019 and 2020 entitlement
and override payments to the Group and other
\u00a0
Kurdistan oil exporters were withheld early in
\u00a0
2020 by the KRG in connection with the
hardships and uncertainties brought about by
\u00a0
the Covid-19 pandemic. Entitlement payments resumed
\u00a0
in March 2020 and override
payments in early 2021. A payment plan was
\u00a0
put in place by the KRG in December
\u00a0
2020 and subsequently revised in May 2021
\u00a0
to pay
the outstanding arrears. As a part of the May 2021
\u00a0
revision, the KRG also informed the international
\u00a0
oil companies that all invoices,
including towards the arrears, will be settled within 60
\u00a0
days of the end of the respective production
\u00a0
month. During 2022, the outstanding
arrears were reduced from USD 169 million
\u00a0
at the start of the year to USD 2 million
\u00a0
at yearend, not including any interest. The Company
continues to work to collect the remaining balances
\u00a0
and expects to be paid accordingly.
\u00a0
Over the course of 2022, KRG payments to
\u00a0
international oil companies were increasingly delayed.
\u00a0
At the time of issuing this report, the
invoices related to August and September 2022 oil
\u00a0
deliveries were paid in January and March
\u00a0
2023, respectively. The Company is in
dialogue with the KRG, seeking timely payments to
\u00a0
support timely investments. Moreover, in September 2022, the KRG proposed
\u00a0
a
change in the previously agreed pricing formula for
\u00a0
oil such that prices should, with effect from 1 September
\u00a0
2022, be based on the
purported price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been accepted
\u00a0
by DNO and the Company
continues to invoice the KRG for oil sales based
\u00a0
on the previously agreed pricing formula (including
\u00a0
the September 2022 invoice) until
such time that protocols are put in place to ensure
\u00a0
that realized prices are transparent, based on arms-length
\u00a0
transactions and subject
to third-party audit. The payment for the September oil
\u00a0
delivery received after yearend reflects the formula
\u00a0
proposed and unilaterally
applied by the KRG in September 2022 resulting in an
\u00a0
approximately USD 11/bbl reduction in realized price compared to current pricing
formula based on Dated Brent. The payment received
\u00a0
was USD 5.2 million (net to DNO) lower than
\u00a0
invoiced. The Company is in
continuing dialogue with the KRG to resolve this
\u00a0
matter and collect outstanding balances. The Company
\u00a0
estimates that using the KRG
proposed prices, the impact of the change in pricing
\u00a0
would have resulted in approximately USD
\u00a0
23 million lower revenues compared to
the reported September through December 2022 Kurdistan
\u00a0
revenues.
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 2022
Trade debtors (nominal value) (Note 12)
-
132.7
58.1
55.9
63.1
2.0
311.8
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2021
Trade debtors (nominal value) (Note 12)
-
131.6
61.9
-
-
169.1
362.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Total trade debtors of USD 311.8 million at yearend 2022 relate mainly to the Tawke license, see Note 12 for details.
\u00a0
Cash deposits
Credit risk from balances with banks and financial
\u00a0
institutions is managed by the Group\u2019s treasury function.
\u00a0
The Group limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the 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
15. The equity ratio has improved primarily
\u00a0
due to a net profit in 2022. 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 2022 and
\u00a0
2021.
Years ended 31 December
USD million
2022
2021
Total equity
1,369.4
1,018.8
Total assets
2,803.0
2,947.8
Equity ratio
48.9%
34.6%
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 assets and financial liabilities,
\u00a0
including their levels in the fair
value hierarchy. It does not include the carrying amounts and fair value
\u00a0
information for financial assets and financial liabilities
\u00a0
not
measured or disclosed at fair value if the carrying
\u00a0
amount is a reasonable approximation of
\u00a0
fair value.
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2022 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
-
-
-
31 December 2022
-
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
15
-
8.4
8.4
-
8.4
* Financial assets designated at FVTOCI with no recycling of cumulative gains and losses upon derecognition
\u00a0
(equity instruments).
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2021 - USD million
Note
at FVTOCI
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
16.2
-
16.2
31 December 2021
16.2
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
873.4
873.4
31 December 2021
824.2
-
95.0
Interest-bearing liabilities (current)
15
-
-
-
-
-
-
Financial risk management, objectives and policies
Overview
The Group\u2019s principal financial liabilities are comprised of interest-bearing
\u00a0
liabilities and trade and other payables. The
\u00a0
main purpose of
these financial liabilities is to finance DNO\u2019s operations. The
\u00a0
Group\u2019s principal financial assets include trade
\u00a0
and other receivables, tax
receivables and cash and cash equivalents.
\u00a0
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. In 2022, the Group had gas price
\u00a0
put options in place with strike prices of
GBP 79 -110 pence per therm, securing approximately 75 percent of after-tax
\u00a0
profit from estimated 2022 gas production.
\u00a0
The Group
had no oil and gas price hedging arrangements
\u00a0
at yearend 2022.
\u00a0
The following table illustrates the impact on reported 2021
\u00a0
and 2022 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 9 for a
sensitivity analysis related to the impairment
\u00a0
assessment of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
2022
+/- 15.0
2021
+/- 15.0
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 2022 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2021 and
\u00a0
2022 from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP exchange rates,
\u00a0
with all other variables held
constant. The other currencies (e.g., AED, IQD) are not
\u00a0
included as the exposure is deemed immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2022
+ 10.0
-3.5
2022
- 10.0
3.5
2021
+ 10.0
-5.9
2021
- 10.0
5.9
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2022
+ 10.0
-19.0
2022
- 10.0
19.0
2021
+ 10.0
1.4
2021
- 10.0
-1.4
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2022
+ 10.0
-4.8
2022
- 10.0
4.8
2021
+ 10.0
-3.6
2021
- 10.0
3.6
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 2022. 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 2021 and
\u00a0
2022 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)
2022
+/- 200
+/-7.7
2021
+/- 200
+/-14.8
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 and
\u00a0
other financial resources to maintain financial
\u00a0
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 15. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 10) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made on
\u00a0
a regular basis pursuant to an approved budget
\u00a0
and work program.
\u00a0
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 in 2022
\u00a0
derived primarily from production in the Tawke license in Kurdistan and
from several licenses in the North Sea. The Group
\u00a0
actively seeks to reduce such risk through
\u00a0
organic growth and asset acquisitions
aimed at further diversifying its revenue sources.
\u00a0
See also Note 10 regarding the Company\u2019s entry in
\u00a0
West Africa.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
USD million
On
At 31 December 2022
demand
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
USD million
On
At 31 December 2021
demand
Interest-bearing liabilities*
16.9
60.8
510.4
545.3
Other provisions and charges
18.6
16.2
Taxes payable
-
12.6
20.5
-
-
Trade and other payables
1.9
210.4
3.0
Total liabilities
1.9
258.5
100.5
510.4
545.3
* Face value of the bonds was USD 531.2 million at yearend 2022 (USD 794.9 million at yearend 2021).
For changes in liabilities arising from financing activities,
\u00a0
see Note 15.
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
2022
2021
Trade debtors (non-current portion) (Note 12)
-
18.2
Trade debtors (Note 12)
311.8
344.4
Other receivables (Note 12)
126.0
139.4
25.8
21.1
Cash and cash equivalents
954.3
736.6
1,417.9
1,259.7
Trade debtors
The impairment model in IFRS 9 is based on
\u00a0
the premise of providing for expected credit
\u00a0
losses. Expected credit losses (ECL) under
IFRS 9 are based on the difference between the contractual
\u00a0
cash flows due in accordance with the contract and
\u00a0
all the cash flows that
are expected to be received, discounted at an
\u00a0
approximation of the original effective interest rate.
\u00a0
Measurement of ECLs under IFRS 9
shall reflect an unbiased and probability-weighted
\u00a0
amount that is determined by evaluating the range
\u00a0
of possible outcomes as well as
incorporating the time value of money. The entity should consider reasonable and
\u00a0
supportable information about past events, current
conditions and reasonable and supportable forecasts
\u00a0
of future economic conditions when measuring expected
\u00a0
credit losses.
Trade debtors from oil sales invoices in Kurdistan
Normal payment terms apply to amounts owed to
\u00a0
DNO by the KRG for oil sales and override invoices
\u00a0
from the Tawke and the Baeshiqa
license in Kurdistan. Since late 2015, DNO received
\u00a0
the payment due to it from oil sales and overrides
\u00a0
on a monthly basis from the KRG
At yearend 2020, the Group had accumulated
\u00a0
a receivable against the KRG of USD 259
\u00a0
million after certain 2019 and 2020 entitlement
and override payments to the Group and other
\u00a0
Kurdistan oil exporters were withheld early in
\u00a0
2020 by the KRG in connection with the
hardships and uncertainties brought about by
\u00a0
the Covid-19 pandemic. Entitlement payments resumed
\u00a0
in March 2020 and override
payments in early 2021. A payment plan was
\u00a0
put in place by the KRG in December
\u00a0
2020 and subsequently revised in May 2021
\u00a0
to pay
the outstanding arrears. As a part of the May 2021
\u00a0
revision, the KRG also informed the international
\u00a0
oil companies that all invoices,
including towards the arrears, will be settled within 60
\u00a0
days of the end of the respective production
\u00a0
month. During 2022, the outstanding
arrears were reduced from USD 169 million
\u00a0
at the start of the year to USD 2 million
\u00a0
at yearend, not including any interest. The Company
continues to work to collect the remaining balances
\u00a0
and expects to be paid accordingly.
\u00a0
Over the course of 2022, KRG payments to
\u00a0
international oil companies were increasingly delayed.
\u00a0
At the time of issuing this report, the
invoices related to August and September 2022 oil
\u00a0
deliveries were paid in January and March
\u00a0
2023, respectively. The Company is in
dialogue with the KRG, seeking timely payments to
\u00a0
support timely investments. Moreover, in September 2022, the KRG proposed
\u00a0
a
change in the previously agreed pricing formula for
\u00a0
oil such that prices should, with effect from 1 September
\u00a0
2022, be based on the
purported price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been accepted
\u00a0
by DNO and the Company
continues to invoice the KRG for oil sales based
\u00a0
on the previously agreed pricing formula (including
\u00a0
the September 2022 invoice) until
such time that protocols are put in place to ensure
\u00a0
that realized prices are transparent, based on arms-length
\u00a0
transactions and subject
to third-party audit. The payment for the September oil
\u00a0
delivery received after yearend reflects the formula
\u00a0
proposed and unilaterally
applied by the KRG in September 2022 resulting in an
\u00a0
approximately USD 11/bbl reduction in realized price compared to current pricing
formula based on Dated Brent. The payment received
\u00a0
was USD 5.2 million (net to DNO) lower than
\u00a0
invoiced. The Company is in
continuing dialogue with the KRG to resolve this
\u00a0
matter and collect outstanding balances. The Company
\u00a0
estimates that using the KRG
proposed prices, the impact of the change in pricing
\u00a0
would have resulted in approximately USD
\u00a0
23 million lower revenues compared to
the reported September through December 2022 Kurdistan
\u00a0
revenues.
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 2022
Trade debtors (nominal value) (Note 12)
-
132.7
58.1
55.9
63.1
2.0
311.8
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2021
Trade debtors (nominal value) (Note 12)
-
131.6
61.9
-
-
169.1
362.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Total trade debtors of USD 311.8 million at yearend 2022 relate mainly to the Tawke license, see Note 12 for details.
\u00a0
Cash deposits
Credit risk from balances with banks and financial
\u00a0
institutions is managed by the Group\u2019s treasury function.
\u00a0
The Group limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the 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
15. The equity ratio has improved primarily
\u00a0
due to a net profit in 2022. 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 2022 and
\u00a0
2021.
Years ended 31 December
USD million
2022
2021
Total equity
1,369.4
1,018.8
Total assets
2,803.0
2,947.8
Equity ratio
48.9%
34.6%
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 assets and financial liabilities,
\u00a0
including their levels in the fair
value hierarchy. It does not include the carrying amounts and fair value
\u00a0
information for financial assets and financial liabilities
\u00a0
not
measured or disclosed at fair value if the carrying
\u00a0
amount is a reasonable approximation of
\u00a0
fair value.
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2022 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
-
-
-
31 December 2022
-
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
15
-
8.4
8.4
-
8.4
* Financial assets designated at FVTOCI with no recycling of cumulative gains and losses upon derecognition
\u00a0
(equity instruments).
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2021 - USD million
Note
at FVTOCI
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
16.2
-
16.2
31 December 2021
16.2
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
873.4
873.4
31 December 2021
824.2
-
95.0
Interest-bearing liabilities (current)
15
-
-
-
-
-
-
Financial risk management, objectives and policies
Overview
The Group\u2019s principal financial liabilities are comprised of interest-bearing
\u00a0
liabilities and trade and other payables. The
\u00a0
main purpose of
these financial liabilities is to finance DNO\u2019s operations. The
\u00a0
Group\u2019s principal financial assets include trade
\u00a0
and other receivables, tax
receivables and cash and cash equivalents.
\u00a0
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. In 2022, the Group had gas price
\u00a0
put options in place with strike prices of
GBP 79 -110 pence per therm, securing approximately 75 percent of after-tax
\u00a0
profit from estimated 2022 gas production.
\u00a0
The Group
had no oil and gas price hedging arrangements
\u00a0
at yearend 2022.
\u00a0
The following table illustrates the impact on reported 2021
\u00a0
and 2022 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 9 for a
sensitivity analysis related to the impairment
\u00a0
assessment of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
2022
+/- 15.0
2021
+/- 15.0
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 2022 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2021 and
\u00a0
2022 from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP exchange rates,
\u00a0
with all other variables held
constant. The other currencies (e.g., AED, IQD) are not
\u00a0
included as the exposure is deemed immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2022
+ 10.0
-3.5
2022
- 10.0
3.5
2021
+ 10.0
-5.9
2021
- 10.0
5.9
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2022
+ 10.0
-19.0
2022
- 10.0
19.0
2021
+ 10.0
1.4
2021
- 10.0
-1.4
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2022
+ 10.0
-4.8
2022
- 10.0
4.8
2021
+ 10.0
-3.6
2021
- 10.0
3.6
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 2022. 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 2021 and
\u00a0
2022 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)
2022
+/- 200
+/-7.7
2021
+/- 200
+/-14.8
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 and
\u00a0
other financial resources to maintain financial
\u00a0
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 15. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 10) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made on
\u00a0
a regular basis pursuant to an approved budget
\u00a0
and work program.
\u00a0
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 in 2022
\u00a0
derived primarily from production in the Tawke license in Kurdistan and
from several licenses in the North Sea. The Group
\u00a0
actively seeks to reduce such risk through
\u00a0
organic growth and asset acquisitions
aimed at further diversifying its revenue sources.
\u00a0
See also Note 10 regarding the Company\u2019s entry in
\u00a0
West Africa.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
USD million
On
At 31 December 2022
demand
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
USD million
On
At 31 December 2021
demand
Interest-bearing liabilities*
16.9
60.8
510.4
545.3
Other provisions and charges
18.6
16.2
Taxes payable
-
12.6
20.5
-
-
Trade and other payables
1.9
210.4
3.0
Total liabilities
1.9
258.5
100.5
510.4
545.3
* Face value of the bonds was USD 531.2 million at yearend 2022 (USD 794.9 million at yearend 2021).
For changes in liabilities arising from financing activities,
\u00a0
see Note 15.
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
2022
2021
Trade debtors (non-current portion) (Note 12)
-
18.2
Trade debtors (Note 12)
311.8
344.4
Other receivables (Note 12)
126.0
139.4
25.8
21.1
Cash and cash equivalents
954.3
736.6
1,417.9
1,259.7
Trade debtors
The impairment model in IFRS 9 is based on
\u00a0
the premise of providing for expected credit
\u00a0
losses. Expected credit losses (ECL) under
IFRS 9 are based on the difference between the contractual
\u00a0
cash flows due in accordance with the contract and
\u00a0
all the cash flows that
are expected to be received, discounted at an
\u00a0
approximation of the original effective interest rate.
\u00a0
Measurement of ECLs under IFRS 9
shall reflect an unbiased and probability-weighted
\u00a0
amount that is determined by evaluating the range
\u00a0
of possible outcomes as well as
incorporating the time value of money. The entity should consider reasonable and
\u00a0
supportable information about past events, current
conditions and reasonable and supportable forecasts
\u00a0
of future economic conditions when measuring expected
\u00a0
credit losses.
Trade debtors from oil sales invoices in Kurdistan
Normal payment terms apply to amounts owed to
\u00a0
DNO by the KRG for oil sales and override invoices
\u00a0
from the Tawke and the Baeshiqa
license in Kurdistan. Since late 2015, DNO received
\u00a0
the payment due to it from oil sales and overrides
\u00a0
on a monthly basis from the KRG
At yearend 2020, the Group had accumulated
\u00a0
a receivable against the KRG of USD 259
\u00a0
million after certain 2019 and 2020 entitlement
and override payments to the Group and other
\u00a0
Kurdistan oil exporters were withheld early in
\u00a0
2020 by the KRG in connection with the
hardships and uncertainties brought about by
\u00a0
the Covid-19 pandemic. Entitlement payments resumed
\u00a0
in March 2020 and override
payments in early 2021. A payment plan was
\u00a0
put in place by the KRG in December
\u00a0
2020 and subsequently revised in May 2021
\u00a0
to pay
the outstanding arrears. As a part of the May 2021
\u00a0
revision, the KRG also informed the international
\u00a0
oil companies that all invoices,
including towards the arrears, will be settled within 60
\u00a0
days of the end of the respective production
\u00a0
month. During 2022, the outstanding
arrears were reduced from USD 169 million
\u00a0
at the start of the year to USD 2 million
\u00a0
at yearend, not including any interest. The Company
continues to work to collect the remaining balances
\u00a0
and expects to be paid accordingly.
\u00a0
Over the course of 2022, KRG payments to
\u00a0
international oil companies were increasingly delayed.
\u00a0
At the time of issuing this report, the
invoices related to August and September 2022 oil
\u00a0
deliveries were paid in January and March
\u00a0
2023, respectively. The Company is in
dialogue with the KRG, seeking timely payments to
\u00a0
support timely investments. Moreover, in September 2022, the KRG proposed
\u00a0
a
change in the previously agreed pricing formula for
\u00a0
oil such that prices should, with effect from 1 September
\u00a0
2022, be based on the
purported price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been accepted
\u00a0
by DNO and the Company
continues to invoice the KRG for oil sales based
\u00a0
on the previously agreed pricing formula (including
\u00a0
the September 2022 invoice) until
such time that protocols are put in place to ensure
\u00a0
that realized prices are transparent, based on arms-length
\u00a0
transactions and subject
to third-party audit. The payment for the September oil
\u00a0
delivery received after yearend reflects the formula
\u00a0
proposed and unilaterally
applied by the KRG in September 2022 resulting in an
\u00a0
approximately USD 11/bbl reduction in realized price compared to current pricing
formula based on Dated Brent. The payment received
\u00a0
was USD 5.2 million (net to DNO) lower than
\u00a0
invoiced. The Company is in
continuing dialogue with the KRG to resolve this
\u00a0
matter and collect outstanding balances. The Company
\u00a0
estimates that using the KRG
proposed prices, the impact of the change in pricing
\u00a0
would have resulted in approximately USD
\u00a0
23 million lower revenues compared to
the reported September through December 2022 Kurdistan
\u00a0
revenues.
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 2022
Trade debtors (nominal value) (Note 12)
-
132.7
58.1
55.9
63.1
2.0
311.8
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2021
Trade debtors (nominal value) (Note 12)
-
131.6
61.9
-
-
169.1
362.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Total trade debtors of USD 311.8 million at yearend 2022 relate mainly to the Tawke license, see Note 12 for details.
\u00a0
Cash deposits
Credit risk from balances with banks and financial
\u00a0
institutions is managed by the Group\u2019s treasury function.
\u00a0
The Group limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the 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
15. The equity ratio has improved primarily
\u00a0
due to a net profit in 2022. 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 2022 and
\u00a0
2021.
Years ended 31 December
USD million
2022
2021
Total equity
1,369.4
1,018.8
Total assets
2,803.0
2,947.8
Equity ratio
48.9%
34.6%
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 assets and financial liabilities,
\u00a0
including their levels in the fair
value hierarchy. It does not include the carrying amounts and fair value
\u00a0
information for financial assets and financial liabilities
\u00a0
not
measured or disclosed at fair value if the carrying
\u00a0
amount is a reasonable approximation of
\u00a0
fair value.
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2022 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
-
-
-
31 December 2022
-
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
15
-
8.4
8.4
-
8.4
* Financial assets designated at FVTOCI with no recycling of cumulative gains and losses upon derecognition
\u00a0
(equity instruments).
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2021 - USD million
Note
at FVTOCI
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
16.2
-
16.2
31 December 2021
16.2
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
873.4
873.4
31 December 2021
824.2
-
95.0
Interest-bearing liabilities (current)
15
-
-
-
-
-
-
Financial risk management, objectives and policies
Overview
The Group\u2019s principal financial liabilities are comprised of interest-bearing
\u00a0
liabilities and trade and other payables. The
\u00a0
main purpose of
these financial liabilities is to finance DNO\u2019s operations. The
\u00a0
Group\u2019s principal financial assets include trade
\u00a0
and other receivables, tax
receivables and cash and cash equivalents.
\u00a0
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. In 2022, the Group had gas price
\u00a0
put options in place with strike prices of
GBP 79 -110 pence per therm, securing approximately 75 percent of after-tax
\u00a0
profit from estimated 2022 gas production.
\u00a0
The Group
had no oil and gas price hedging arrangements
\u00a0
at yearend 2022.
\u00a0
The following table illustrates the impact on reported 2021
\u00a0
and 2022 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 9 for a
sensitivity analysis related to the impairment
\u00a0
assessment of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
2022
+/- 15.0
2021
+/- 15.0
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 2022 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2021 and
\u00a0
2022 from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP exchange rates,
\u00a0
with all other variables held
constant. The other currencies (e.g., AED, IQD) are not
\u00a0
included as the exposure is deemed immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2022
+ 10.0
-3.5
2022
- 10.0
3.5
2021
+ 10.0
-5.9
2021
- 10.0
5.9
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2022
+ 10.0
-19.0
2022
- 10.0
19.0
2021
+ 10.0
1.4
2021
- 10.0
-1.4
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2022
+ 10.0
-4.8
2022
- 10.0
4.8
2021
+ 10.0
-3.6
2021
- 10.0
3.6
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 2022. 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 2021 and
\u00a0
2022 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)
2022
+/- 200
+/-7.7
2021
+/- 200
+/-14.8
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 and
\u00a0
other financial resources to maintain financial
\u00a0
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 15. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 10) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made on
\u00a0
a regular basis pursuant to an approved budget
\u00a0
and work program.
\u00a0
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 in 2022
\u00a0
derived primarily from production in the Tawke license in Kurdistan and
from several licenses in the North Sea. The Group
\u00a0
actively seeks to reduce such risk through
\u00a0
organic growth and asset acquisitions
aimed at further diversifying its revenue sources.
\u00a0
See also Note 10 regarding the Company\u2019s entry in
\u00a0
West Africa.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
USD million
On
At 31 December 2022
demand
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
USD million
On
At 31 December 2021
demand
Interest-bearing liabilities*
16.9
60.8
510.4
545.3
Other provisions and charges
18.6
16.2
Taxes payable
-
12.6
20.5
-
-
Trade and other payables
1.9
210.4
3.0
Total liabilities
1.9
258.5
100.5
510.4
545.3
* Face value of the bonds was USD 531.2 million at yearend 2022 (USD 794.9 million at yearend 2021).
For changes in liabilities arising from financing activities,
\u00a0
see Note 15.
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
2022
2021
Trade debtors (non-current portion) (Note 12)
-
18.2
Trade debtors (Note 12)
311.8
344.4
Other receivables (Note 12)
126.0
139.4
25.8
21.1
Cash and cash equivalents
954.3
736.6
1,417.9
1,259.7
Trade debtors
The impairment model in IFRS 9 is based on
\u00a0
the premise of providing for expected credit
\u00a0
losses. Expected credit losses (ECL) under
IFRS 9 are based on the difference between the contractual
\u00a0
cash flows due in accordance with the contract and
\u00a0
all the cash flows that
are expected to be received, discounted at an
\u00a0
approximation of the original effective interest rate.
\u00a0
Measurement of ECLs under IFRS 9
shall reflect an unbiased and probability-weighted
\u00a0
amount that is determined by evaluating the range
\u00a0
of possible outcomes as well as
incorporating the time value of money. The entity should consider reasonable and
\u00a0
supportable information about past events, current
conditions and reasonable and supportable forecasts
\u00a0
of future economic conditions when measuring expected
\u00a0
credit losses.
Trade debtors from oil sales invoices in Kurdistan
Normal payment terms apply to amounts owed to
\u00a0
DNO by the KRG for oil sales and override invoices
\u00a0
from the Tawke and the Baeshiqa
license in Kurdistan. Since late 2015, DNO received
\u00a0
the payment due to it from oil sales and overrides
\u00a0
on a monthly basis from the KRG
At yearend 2020, the Group had accumulated
\u00a0
a receivable against the KRG of USD 259
\u00a0
million after certain 2019 and 2020 entitlement
and override payments to the Group and other
\u00a0
Kurdistan oil exporters were withheld early in
\u00a0
2020 by the KRG in connection with the
hardships and uncertainties brought about by
\u00a0
the Covid-19 pandemic. Entitlement payments resumed
\u00a0
in March 2020 and override
payments in early 2021. A payment plan was
\u00a0
put in place by the KRG in December
\u00a0
2020 and subsequently revised in May 2021
\u00a0
to pay
the outstanding arrears. As a part of the May 2021
\u00a0
revision, the KRG also informed the international
\u00a0
oil companies that all invoices,
including towards the arrears, will be settled within 60
\u00a0
days of the end of the respective production
\u00a0
month. During 2022, the outstanding
arrears were reduced from USD 169 million
\u00a0
at the start of the year to USD 2 million
\u00a0
at yearend, not including any interest. The Company
continues to work to collect the remaining balances
\u00a0
and expects to be paid accordingly.
\u00a0
Over the course of 2022, KRG payments to
\u00a0
international oil companies were increasingly delayed.
\u00a0
At the time of issuing this report, the
invoices related to August and September 2022 oil
\u00a0
deliveries were paid in January and March
\u00a0
2023, respectively. The Company is in
dialogue with the KRG, seeking timely payments to
\u00a0
support timely investments. Moreover, in September 2022, the KRG proposed
\u00a0
a
change in the previously agreed pricing formula for
\u00a0
oil such that prices should, with effect from 1 September
\u00a0
2022, be based on the
purported price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been accepted
\u00a0
by DNO and the Company
continues to invoice the KRG for oil sales based
\u00a0
on the previously agreed pricing formula (including
\u00a0
the September 2022 invoice) until
such time that protocols are put in place to ensure
\u00a0
that realized prices are transparent, based on arms-length
\u00a0
transactions and subject
to third-party audit. The payment for the September oil
\u00a0
delivery received after yearend reflects the formula
\u00a0
proposed and unilaterally
applied by the KRG in September 2022 resulting in an
\u00a0
approximately USD 11/bbl reduction in realized price compared to current pricing
formula based on Dated Brent. The payment received
\u00a0
was USD 5.2 million (net to DNO) lower than
\u00a0
invoiced. The Company is in
continuing dialogue with the KRG to resolve this
\u00a0
matter and collect outstanding balances. The Company
\u00a0
estimates that using the KRG
proposed prices, the impact of the change in pricing
\u00a0
would have resulted in approximately USD
\u00a0
23 million lower revenues compared to
the reported September through December 2022 Kurdistan
\u00a0
revenues.
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 2022
Trade debtors (nominal value) (Note 12)
-
132.7
58.1
55.9
63.1
2.0
311.8
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2021
Trade debtors (nominal value) (Note 12)
-
131.6
61.9
-
-
169.1
362.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Total trade debtors of USD 311.8 million at yearend 2022 relate mainly to the Tawke license, see Note 12 for details.
\u00a0
Cash deposits
Credit risk from balances with banks and financial
\u00a0
institutions is managed by the Group\u2019s treasury function.
\u00a0
The Group limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the 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
15. The equity ratio has improved primarily
\u00a0
due to a net profit in 2022. 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 2022 and
\u00a0
2021.
Years ended 31 December
USD million
2022
2021
Total equity
1,369.4
1,018.8
Total assets
2,803.0
2,947.8
Equity ratio
48.9%
34.6%
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 assets and financial liabilities,
\u00a0
including their levels in the fair
value hierarchy. It does not include the carrying amounts and fair value
\u00a0
information for financial assets and financial liabilities
\u00a0
not
measured or disclosed at fair value if the carrying
\u00a0
amount is a reasonable approximation of
\u00a0
fair value.
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2022 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
-
-
-
31 December 2022
-
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
15
-
8.4
8.4
-
8.4
* Financial assets designated at FVTOCI with no recycling of cumulative gains and losses upon derecognition
\u00a0
(equity instruments).
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2021 - USD million
Note
at FVTOCI
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
16.2
-
16.2
31 December 2021
16.2
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
873.4
873.4
31 December 2021
824.2
-
95.0
Interest-bearing liabilities (current)
15
-
-
-
-
-
-
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen (MOM) \u2013 Block
\u00a0
53, Block 43 and Block 32
The Ministry of Oil and Minerals (MOM) of
\u00a0
Yemen filed an arbitration claim against operator Dove Energy Limited and
\u00a0
the other partners
(including DNO Yemen AS) for allegedly wrongful withdrawal from Block 53. An
\u00a0
arbitral award was rendered in July 2019
\u00a0
partially in the
Ministry\u2019s favor in the amount of USD 29 million (out
\u00a0
of a USD 171 million claim). The Contractor
\u00a0
(including DNO Yemen AS), filed for
annulment proceedings in the Paris Court d\u2019Appel
\u00a0
which was dismissed in 2022 but is currently
\u00a0
on appeal at the Supreme Court. A
provision of USD 22.2 million was recognized at
\u00a0
yearend 2022 related to this arbitration award (USD
\u00a0
14 million at yearend 2021).
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). A provision for liability of
USD 1.4 million (net to DNO Yemen AS) was recognized in 2021 related
\u00a0
to this arbitration award (unchanged
\u00a0
at yearend 2022).
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\u2019 favor in the amount of USD 6.8 million (almost entirely dismissing
\u00a0
the USD 131
million counterclaim of the MOM). In accordance
\u00a0
with IAS 37, the asset related to this arbitration
\u00a0
award was not recognized in the
balance sheet as of 31 December 2022.
As part of the Block 43 arbitral award in 2020
\u00a0
(above), a cost recovery audit was mandated
\u00a0
for the years 2014 and 2015. In 2021, MOM
filed an arbitration claim against DNO Yemen AS for allegedly over-recovered costs of
\u00a0
USD 17.2 million from the Ministry in 2014 and
2015. In accordance with IAS 37.92, the Group does
\u00a0
not provide further information with respect
\u00a0
to this arbitration dispute and the
associated risk for the Group, especially with regards
\u00a0
to the measures taken in this context, in order not
\u00a0
to impair the outcome of the
proceedings. In accordance with IAS 37, no provision
\u00a0
for a liability was made at yearend 2022 related
\u00a0
to this dispute.
On 8 December 2022, the Oslo District Court
\u00a0
ruled that previously rendered arbitration awards
\u00a0
regarding Blocks 53 and 32 are
enforceable against DNO Yemen in Norway. DNO Yemen has appealed this decision. The Oslo District Court also ruled that the
previously rendered arbitration award regarding
\u00a0
Block 43 in favor of DNO Yemen is enforceable against the MOM in Norway. The MOM
has not contested this decision. A parallel enforcement
\u00a0
case regarding the same subject matter but
\u00a0
filed against DNO ASA remains
suspended pending a final ruling in the DNO
\u00a0
Yemen case.
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 2022 and
\u00a0
contingent on future market conditions including
\u00a0
development in the oil price, the Group\u2019s
projected operational spend comprising of capital and
\u00a0
exploration expenditures,
\u00a0
abandonment expenditures and operational
expenditures at yearend 2022 amounted to USD 640
\u00a0
million. The projected operational spend reflects the Group\u2019s
\u00a0
share of planned
drilling and facility investments and decommissioning
\u00a0
plan in its licenses for 2022. Execution
\u00a0
of these work plans is subject to revisions.
Guarantees related to assets in operation at yearend
\u00a0
2022
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.
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen (MOM) \u2013 Block
\u00a0
53, Block 43 and Block 32
The Ministry of Oil and Minerals (MOM) of
\u00a0
Yemen filed an arbitration claim against operator Dove Energy Limited and
\u00a0
the other partners
(including DNO Yemen AS) for allegedly wrongful withdrawal from Block 53. An
\u00a0
arbitral award was rendered in July 2019
\u00a0
partially in the
Ministry\u2019s favor in the amount of USD 29 million (out
\u00a0
of a USD 171 million claim). The Contractor
\u00a0
(including DNO Yemen AS), filed for
annulment proceedings in the Paris Court d\u2019Appel
\u00a0
which was dismissed in 2022 but is currently
\u00a0
on appeal at the Supreme Court. A
provision of USD 22.2 million was recognized at
\u00a0
yearend 2022 related to this arbitration award (USD
\u00a0
14 million at yearend 2021).
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). A provision for liability of
USD 1.4 million (net to DNO Yemen AS) was recognized in 2021 related
\u00a0
to this arbitration award (unchanged
\u00a0
at yearend 2022).
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\u2019 favor in the amount of USD 6.8 million (almost entirely dismissing
\u00a0
the USD 131
million counterclaim of the MOM). In accordance
\u00a0
with IAS 37, the asset related to this arbitration
\u00a0
award was not recognized in the
balance sheet as of 31 December 2022.
As part of the Block 43 arbitral award in 2020
\u00a0
(above), a cost recovery audit was mandated
\u00a0
for the years 2014 and 2015. In 2021, MOM
filed an arbitration claim against DNO Yemen AS for allegedly over-recovered costs of
\u00a0
USD 17.2 million from the Ministry in 2014 and
2015. In accordance with IAS 37.92, the Group does
\u00a0
not provide further information with respect
\u00a0
to this arbitration dispute and the
associated risk for the Group, especially with regards
\u00a0
to the measures taken in this context, in order not
\u00a0
to impair the outcome of the
proceedings. In accordance with IAS 37, no provision
\u00a0
for a liability was made at yearend 2022 related
\u00a0
to this dispute.
On 8 December 2022, the Oslo District Court
\u00a0
ruled that previously rendered arbitration awards
\u00a0
regarding Blocks 53 and 32 are
enforceable against DNO Yemen in Norway. DNO Yemen has appealed this decision. The Oslo District Court also ruled that the
previously rendered arbitration award regarding
\u00a0
Block 43 in favor of DNO Yemen is enforceable against the MOM in Norway. The MOM
has not contested this decision. A parallel enforcement
\u00a0
case regarding the same subject matter but
\u00a0
filed against DNO ASA remains
suspended pending a final ruling in the DNO
\u00a0
Yemen case.
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 2022 and
\u00a0
contingent on future market conditions including
\u00a0
development in the oil price, the Group\u2019s
projected operational spend comprising of capital and
\u00a0
exploration expenditures,
\u00a0
abandonment expenditures and operational
expenditures at yearend 2022 amounted to USD 640
\u00a0
million. The projected operational spend reflects the Group\u2019s
\u00a0
share of planned
drilling and facility investments and decommissioning
\u00a0
plan in its licenses for 2022. Execution
\u00a0
of these work plans is subject to revisions.
Guarantees related to assets in operation at yearend
\u00a0
2022
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.
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen (MOM) \u2013 Block
\u00a0
53, Block 43 and Block 32
The Ministry of Oil and Minerals (MOM) of
\u00a0
Yemen filed an arbitration claim against operator Dove Energy Limited and
\u00a0
the other partners
(including DNO Yemen AS) for allegedly wrongful withdrawal from Block 53. An
\u00a0
arbitral award was rendered in July 2019
\u00a0
partially in the
Ministry\u2019s favor in the amount of USD 29 million (out
\u00a0
of a USD 171 million claim). The Contractor
\u00a0
(including DNO Yemen AS), filed for
annulment proceedings in the Paris Court d\u2019Appel
\u00a0
which was dismissed in 2022 but is currently
\u00a0
on appeal at the Supreme Court. A
provision of USD 22.2 million was recognized at
\u00a0
yearend 2022 related to this arbitration award (USD
\u00a0
14 million at yearend 2021).
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). A provision for liability of
USD 1.4 million (net to DNO Yemen AS) was recognized in 2021 related
\u00a0
to this arbitration award (unchanged
\u00a0
at yearend 2022).
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\u2019 favor in the amount of USD 6.8 million (almost entirely dismissing
\u00a0
the USD 131
million counterclaim of the MOM). In accordance
\u00a0
with IAS 37, the asset related to this arbitration
\u00a0
award was not recognized in the
balance sheet as of 31 December 2022.
As part of the Block 43 arbitral award in 2020
\u00a0
(above), a cost recovery audit was mandated
\u00a0
for the years 2014 and 2015. In 2021, MOM
filed an arbitration claim against DNO Yemen AS for allegedly over-recovered costs of
\u00a0
USD 17.2 million from the Ministry in 2014 and
2015. In accordance with IAS 37.92, the Group does
\u00a0
not provide further information with respect
\u00a0
to this arbitration dispute and the
associated risk for the Group, especially with regards
\u00a0
to the measures taken in this context, in order not
\u00a0
to impair the outcome of the
proceedings. In accordance with IAS 37, no provision
\u00a0
for a liability was made at yearend 2022 related
\u00a0
to this dispute.
On 8 December 2022, the Oslo District Court
\u00a0
ruled that previously rendered arbitration awards
\u00a0
regarding Blocks 53 and 32 are
enforceable against DNO Yemen in Norway. DNO Yemen has appealed this decision. The Oslo District Court also ruled that the
previously rendered arbitration award regarding
\u00a0
Block 43 in favor of DNO Yemen is enforceable against the MOM in Norway. The MOM
has not contested this decision. A parallel enforcement
\u00a0
case regarding the same subject matter but
\u00a0
filed against DNO ASA remains
suspended pending a final ruling in the DNO
\u00a0
Yemen case.
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 2022 and
\u00a0
contingent on future market conditions including
\u00a0
development in the oil price, the Group\u2019s
projected operational spend comprising of capital and
\u00a0
exploration expenditures,
\u00a0
abandonment expenditures and operational
expenditures at yearend 2022 amounted to USD 640
\u00a0
million. The projected operational spend reflects the Group\u2019s
\u00a0
share of planned
drilling and facility investments and decommissioning
\u00a0
plan in its licenses for 2022. Execution
\u00a0
of these work plans is subject to revisions.
Guarantees related to assets in operation at yearend
\u00a0
2022
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.
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen (MOM) \u2013 Block
\u00a0
53, Block 43 and Block 32
The Ministry of Oil and Minerals (MOM) of
\u00a0
Yemen filed an arbitration claim against operator Dove Energy Limited and
\u00a0
the other partners
(including DNO Yemen AS) for allegedly wrongful withdrawal from Block 53. An
\u00a0
arbitral award was rendered in July 2019
\u00a0
partially in the
Ministry\u2019s favor in the amount of USD 29 million (out
\u00a0
of a USD 171 million claim). The Contractor
\u00a0
(including DNO Yemen AS), filed for
annulment proceedings in the Paris Court d\u2019Appel
\u00a0
which was dismissed in 2022 but is currently
\u00a0
on appeal at the Supreme Court. A
provision of USD 22.2 million was recognized at
\u00a0
yearend 2022 related to this arbitration award (USD
\u00a0
14 million at yearend 2021).
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). A provision for liability of
USD 1.4 million (net to DNO Yemen AS) was recognized in 2021 related
\u00a0
to this arbitration award (unchanged
\u00a0
at yearend 2022).
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\u2019 favor in the amount of USD 6.8 million (almost entirely dismissing
\u00a0
the USD 131
million counterclaim of the MOM). In accordance
\u00a0
with IAS 37, the asset related to this arbitration
\u00a0
award was not recognized in the
balance sheet as of 31 December 2022.
As part of the Block 43 arbitral award in 2020
\u00a0
(above), a cost recovery audit was mandated
\u00a0
for the years 2014 and 2015. In 2021, MOM
filed an arbitration claim against DNO Yemen AS for allegedly over-recovered costs of
\u00a0
USD 17.2 million from the Ministry in 2014 and
2015. In accordance with IAS 37.92, the Group does
\u00a0
not provide further information with respect
\u00a0
to this arbitration dispute and the
associated risk for the Group, especially with regards
\u00a0
to the measures taken in this context, in order not
\u00a0
to impair the outcome of the
proceedings. In accordance with IAS 37, no provision
\u00a0
for a liability was made at yearend 2022 related
\u00a0
to this dispute.
On 8 December 2022, the Oslo District Court
\u00a0
ruled that previously rendered arbitration awards
\u00a0
regarding Blocks 53 and 32 are
enforceable against DNO Yemen in Norway. DNO Yemen has appealed this decision. The Oslo District Court also ruled that the
previously rendered arbitration award regarding
\u00a0
Block 43 in favor of DNO Yemen is enforceable against the MOM in Norway. The MOM
has not contested this decision. A parallel enforcement
\u00a0
case regarding the same subject matter but
\u00a0
filed against DNO ASA remains
suspended pending a final ruling in the DNO
\u00a0
Yemen case.
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 2022 and
\u00a0
contingent on future market conditions including
\u00a0
development in the oil price, the Group\u2019s
projected operational spend comprising of capital and
\u00a0
exploration expenditures,
\u00a0
abandonment expenditures and operational
expenditures at yearend 2022 amounted to USD 640
\u00a0
million. The projected operational spend reflects the Group\u2019s
\u00a0
share of planned
drilling and facility investments and decommissioning
\u00a0
plan in its licenses for 2022. Execution
\u00a0
of these work plans is subject to revisions.
Guarantees related to assets in operation at yearend
\u00a0
2022
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.
Years ended 31 December
USD million
2022
2021
Non-current
Asset retirement obligations (ARO)
368.2
386.3
Other long-term obligations
4.9
3.6
Total non-current provisions for other liabilities and charges
373.1
389.9
Lease liabilities
6.5
12.5
Total non-current lease liabilities
6.5
12.5
Current
Asset retirement obligations (ARO)
20.5
69.7
Other provisions and charges
39.8
34.8
Total current provisions for other liabilities and charges
60.2
104.4
Current lease liabilities
6.8
15.7
Total current lease liabilities
6.8
15.7
Total provisions for other liabilities and charges and lease liabilities
446.6
522.6
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 2022 were between 4.5 percent
\u00a0
and 4.8 percent (yearend 2021:
between 3.2 percent and 3.7 percent). The credit
\u00a0
margin included in the discount rates at yearend
\u00a0
2022 was 0.8 percent (yearend 2021:
2.3 percent).
Asset
Other
retirement
non-
USD million
obligations
current
Provisions as of 1 January 2021
523.3
3.4
Decommissioning spend
-86.8
-
Increase/-decrease in existing provisions
0.9
0.2
Amounts charged against provisions
-
-
Effects of change in the discount rate
0.9
-
Accretion expenses (unwinding of discount)
17.7
-
Reclassification and transfer
-
-
Provisions as of 31 December 2021
456.0
3.6
Decommissioning spend
-70.5
-
Increase/-decrease in existing provisions
25.0
1.3
Amounts charged against provisions
-
-
Effects of change in the discount rate
-37.0
-
Accretion expenses (unwinding of discount)
15.2
-
Reclassification and transfer
-
-
Provisions as of 31 December 2022
388.7
4.9
Lease liabilities
The recognized lease liabilities in the balance sheet
\u00a0
are mainly related to rig lease and office rent.
In 2021, DNO entered into a rig lease
agreement to perform decommissioning, plugging and abandonment
\u00a0
at the Schooner and Ketch fields in the UK part of
\u00a0
the North Sea.
The rig lease was entered into with DNO as
\u00a0
the operator of the licenses at the initial signing
\u00a0
and subsequently partly allocated to the
license partners (presented under non-current and
\u00a0
current receivables). The rig lease was recognized
\u00a0
on a gross basis, rather than
based on DNO\u2019s working interest share (60 percent).
\u00a0
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. Extension
\u00a0
options are included in the lease liability when,
\u00a0
based on the management\u2019s
judgement, it is reasonably certain that an extension
\u00a0
will be exercised. Lease payments related
\u00a0
to short-term leases and leases of low-
value assets are recognized under lifting costs and
\u00a0
exploration costs, or tangible assets and
\u00a0
capitalized exploration. Total lease
payments related to short-term leases and low-value
\u00a0
assets were USD 56 million (2021: USD 56.6
\u00a0
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
2022
2021
Within one year
7.0
16.6
6.5
13.1
-
-
Total undiscounted lease liabilities end of the period
\u00a0
13.5
29.7
.
1 January - 31 December
2022
2021
Net profit/-loss attributable to ordinary equity holders of the parent (USD million)
384.9
203.9
Weighted average number of ordinary shares excluding treasury shares (millions)
986.97
975.43
Earnings per share, basic (USD per share)
0.39
0.21
Earnings per share, diluted (USD per share)
0.39
0.21
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 2022.
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
DNO Oman Block 30 Limited
Guernsey
100
North Limited
Guernsey
100
DNO Tunisia Limited
Guernsey
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 of 33.33
\u00a0
percent is accounted for
using the equity method. DNO ASA, DNO Technical Services AS and DNO North Sea plc provide
\u00a0
technical support and services to the
various companies in the Group. The other subsidiaries
\u00a0
from the table above had minimal activity during
\u00a0
the year. Northstar Norge AS
(DNO North Sea (Norge) AS) was liquidated during
\u00a0
2022 and DNO Technical Services Limited was renamed to Northstar Limited.
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
DNO Oman Block 30 Limited
Guernsey
100
North Limited
Guernsey
100
DNO Tunisia Limited
Guernsey
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 of 33.33
\u00a0
percent is accounted for
using the equity method. DNO ASA, DNO Technical Services AS and DNO North Sea plc provide
\u00a0
technical support and services to the
various companies in the Group. The other subsidiaries
\u00a0
from the table above had minimal activity during
\u00a0
the year. Northstar Norge AS
(DNO North Sea (Norge) AS) was liquidated during
\u00a0
2022 and DNO Technical Services Limited was renamed to Northstar Limited.
The following table provides details of the
\u00a0
Group\u2019s related party transactions in 2022. See also
\u00a0
Note 5 on remuneration.
1 January - 31 December
Related party (USD million)
Transaction
2022
2021
RAK Petroleum plc
Service agreement
-1.1
-0.1
Total related party transactions
-1.1
-0.1
Prior to the completion of the agreement entered
\u00a0
between DNO and RAK Petroleum in October 2022
\u00a0
(see Note 10), RAK Petroleum,
through its subsidiary RAK Petroleum Holdings B.V., was the Company\u2019s largest shareholder
\u00a0
and the Company\u2019s Executive Chairman
Bijan Mossavar-Rahmani also served as Executive Chairman
\u00a0
of RAK Petroleum. The Company had an
\u00a0
agreement with RAK Petroleum
for services including administrative and commercial
\u00a0
support, travel and other expenses. See also Note
\u00a0
3 in the parent company
accounts relating to reimbursement of expenses to
\u00a0
the members of the Board of Directors.
There are additional transactions between Group companies,
\u00a0
see Note 20 in the parent company accounts.
A portion of the overhead expenses in the
\u00a0
Company are charged to the subsidiaries through
\u00a0
the hourly rate for services provided by the
Company.
Kurdistan licenses
At yearend 2022, DNO held interests in two
\u00a0
licenses in Kurdistan, both of which are PSCs.
\u00a0
The Tawke license contains the producing
Tawke and Peshkabir fields. The Baeshiqa license contains two large structures with multiple independent
\u00a0
stacked target reservoirs,
including in the Cretaceous, Jurassic and Triassic formations.
\u00a0
The structures at Baeshiqa and Zartik have
\u00a0
the potential to be part of a
single accumulation of hydrocarbons at one or
\u00a0
more of the geological formation intervals.
North Sea (Norway and the UK, and other)
At yearend 2022, DNO held 68 offshore licenses in
\u00a0
Norway, seven offshore licenses in the UK and two offshore licenses in Netherlands.
West Africa (C\u00f4te d\u2019Ivoire)
At yearend 2022, 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 in
\u00a0
Foxtrot Mondoil C\u00f4te
d\u2019Ivoire/Foxtrot International is accounted for using
\u00a0
the equity method (see Note 10).
Other
At yearend 2022, 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.
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
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 AS, Neptune Energy Norway AS
\u00a0
PL055 (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi AS, Neptune Energy Norway AS
\u00a0
PL055 B (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi AS, Neptune Energy Norway AS
\u00a0
PL055 D (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi AS, Neptune Energy Norway AS
\u00a0
PL055 E (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi AS, 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 AS, 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 AS
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 B (Marulk)
17.0
V\u00e5r Energi AS
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 C (Marulk)
17.0
V\u00e5r Energi AS
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 D (Marulk)
17.0
V\u00e5r Energi AS
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 AS
PL185 (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi AS, 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 AS, Suncor Energy Norge AS
PL586B (Fenja)
7.5
Neptune Energy Norge AS
DNO Norge AS, V\u00e5r Energi AS, 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 AS
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
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 AS, Source Energy AS
PL984 BS
30.0
DNO Norge AS
V\u00e5r Energi AS, 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 10):
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
Nationale d\u2019Op
e\u0301
rations P
e\u0301
troli
e\u0300
res de la C
o\u0302
te d\u2019Ivoire
As of 31 December 2021
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
PL006 E
85.0
DNO Norge AS
Aker BP ASA
PL006 F
85.0
DNO Norge AS
Aker BP ASA
PL018 ES
45.0
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 AS, Neptune Energy Norway AS
\u00a0
PL055 (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi AS, Neptune Energy Norway AS
\u00a0
PL055 B (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi AS, Neptune Energy Norway AS
\u00a0
PL055 D (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi AS, Neptune Energy Norway AS
\u00a0
PL055 E (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi AS, 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
PL1006
30.0
Equinor Energy AS
DNO Norge AS
PL1007
40.0
DNO Norge AS
OMV (Norge) AS, Spirit Energy Norway AS, Equinor Energy AS
PL1027
20.0
Lundin Norway AS
DNO Norge AS, Wintershall Dea Norge AS, INPEX Norge AS
PL1029
40.0
Lundin Norway AS
DNO Norge AS, Spirit Energy Norway AS
PL1036
60.0
DNO Norge AS
Source Energy AS
PL1048
50.0
Lundin Energy Norway AS
DNO Norge AS
PL1070
30.0
Total E&P Norge AS
DNO Norge AS, V\u00e5r Energi As
PL1076
50.0
Equinor Energy AS
DNO Norge AS
PL1077
40.0
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
40.0
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 AS, Wintershall Dea Norge AS
PL1127
20.0
Equinor Energy AS
DNO Norge AS, TotalEnergies EP Norge
\u00a0
AS
PL122 (Marulk)
17.0
V\u00e5r Energi AS
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 B (Marulk)
17.0
V\u00e5r Energi AS
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 C (Marulk)
17.0
V\u00e5r Energi AS
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 D (Marulk)
17.0
V\u00e5r Energi AS
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 AS
PL185 (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, V\u00e5r Energi AS, 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
PL248 HS
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 AS, 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 AS
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
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
PL924
15.0
Wellesley Petroleum AS
DNO Norge AS, Equinor Energy AS, Lundin Energy Norway 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
PL967
60.0
DNO Norge AS
Equinor Energy AS
PL968
40.0
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
PL983
20.0
Equinor Energy AS
DNO Norge AS, TotalEnergies EP Norge
\u00a0
AS, Petoro AS
PL984
40.0
DNO Norge AS
V\u00e5r Energi AS, Source Energy AS
PL984 BS
40.0
DNO Norge AS
V\u00e5r Energi AS, Source Energy AS
PL986
20.0
Aker BP ASA
DNO Norge AS, Petoro 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
P2472
70.0
DNO North Sea (U.K.) Ltd
One-Dyas E&P 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
P2551
100.0
DNO North Sea (U.K.) Ltd
P2537
30.0
Chrysaor Production (U.K.) Limited
DNO North Sea (U.K.) Ltd, Neo Energy (ZEX) Limited
P2548
100.0
DNO North Sea (U.K.) Ltd
P2533
50.0
NEO Energy (ZEX) Limited
DNO North Sea (U.K.) Ltd
Ireland
FEL3/19
20.0
CNOOC Petroleum Europe Ltd
DNO North Sea (U.K.) Ltd
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
Acquisition of Mondoil Enterprises
\u00a0
LLC
On 11 October 2022, the Company completed the transaction with RAK
\u00a0
Petroleum plc (RAK Petroleum) for transferring
\u00a0
shares in
Mondoil Enterprises LLC (Mondoil Enterprises) to DNO
\u00a0
ASA (see also Note 11). The transaction was entered on 22 August 2022
\u00a0
with
effective date 1 January 2022 and the Company issued
\u00a0
78.94 million new shares to RAK Petroleum as
\u00a0
consideration (consideration
shares). Following transaction completion, the Company
\u00a0
holds 100 percent of the shares in Mondoil
\u00a0
Enterprises. Mondoil Enterprises
owns 50 percent of Mondoil C\u00f4te d\u2019Ivoire LLC
\u00a0
(Mondoil C\u00f4te d\u2019Ivoire), which, in turn, owns
\u00a0
66.66 percent in the privately-held Foxtrot
International LDC (Foxtrot International), resulting in the
\u00a0
Company\u2019s indirect 33.33 percent interest in Foxtrot
\u00a0
International. Foxtrot
International holds a 27.27 percent interest in and
\u00a0
operatorship of Block CI-27 offshore C\u00f4te d\u2019Ivoire, which
\u00a0
contains the Foxtrot gas
field, the Mahi gas field, the Marlin oil and gas field
\u00a0
and the Manta gas field. Foxtrot International
\u00a0
also operates an exploration license
offshore C\u00f4te d\u2019Ivoire, Block CI-12, in which it holds
\u00a0
a 24 percent interest.
\u00a0
The acquisition date for accounting purposes corresponds
\u00a0
to the completion of the transaction on 11 October 2022. A purchase price
allocation (PPA) has been performed to allocate the value of consideration
\u00a0
shares to fair value of assets acquired and liabilities
assumed. The PPA was performed as of the completion date, 11 October 2022. The 11 October closing share price at Oslo Stock
Exchange (NOK 13.27/USD 1.24) and the closing
\u00a0
currency exchange rate (USD/NOK 10.7205) were
\u00a0
used as a basis for measuring the
value of the consideration shares, as set forth below.
\u00a0
The following table summarizes the PPA and acquisition cost as recorded
\u00a0
as at transaction completion date:
\u00a0
Purchase price allocation (PPA)
As at transaction
USD million
completion date
Consideration shares
78,943,763
Share price at closing date (USD/share)
1.24
Consideraton in the form of equity instruments issued at fair value
97.7
Transaction fees
1.3
Total consideration
99.0
Carrying amount of proportional net assets acquired (of Foxtrot International)
63.8
Fair value uplift of proportional net assets acquired (of Foxtrot International)
12.9
Cash and cash equivalents (of Mondoil Enterprises)
21.5
Total proportional identifiable net assets at fair value
98.2
Goodwill
0.8
The provisional fair values from the table above are based
\u00a0
on currently available information about fair values
\u00a0
as of the completion date.
If new information becomes available within 12
\u00a0
months from this date (measurement period), the
\u00a0
Group may change the fair value
assessment in the PPA. Eventual changes in fair values will be recorded
\u00a0
retrospectively from the completion date.
\u00a0
Financial information of Foxtrot International as of
\u00a0
yearend 2022
The Company\u2019s indirect 33.33 percent interest in Foxtrot
\u00a0
International is treated in accordance with
\u00a0
IFRS 11 and IAS 28
Investments in
Associates and Joint Ventures
\u00a0
(i.e., the Group\u2019s interest in Mondoil C\u00f4te d\u2019Ivoire/Foxtrot
\u00a0
International is accounted for using the equity
method) and disclose in the table below the summarised
\u00a0
financial information of Foxtrot International as an associate/joint
\u00a0
venture (IAS
28) in terms of summarised financial information.
\u00a0
Foxtrot International's summarized statement of financial position
Year ended 31 December
USD million
2022
Non-current assets
216.5
Current assets
67.3
Total assets
283.7
Non-current liabilities
67.1
Current liabilities
30.0
Total liabilities
97.2
Equity
186.6
Group's share of net assets (33.33 percent)
62.2
Goodwill
0.8
Fair value uplift on PP&E and ARO (net of related deferred tax)
13.0
Carrying amount Investment in Joint Venture
76.1
Foxtrot International's summarized statement of comprehensive income
1 January -
\u00a0
31 December
USD million
2022
Revenues
28.8
Expenses
-4.2
Depreciation
-8.0
Other income/finance income
3.5
Tax income/-expense
-
Net profit/-loss
20.1
Group's share of net profit (33.33 percent)
6.7
Depletion of fair value uplift of PP&E and ARO (net of related deferred tax)
-0.7
Share of profit/-loss from Joint Venture
6.0
As at transaction
Year ended 31
Movement in the carrying amount of Investment in Joint Venture
completion date
USD million
2022
2022
Opening balance
-
77.5
Acquired share of Joint Venture's carrying amount
63.8
-
Acquired fair value uplift of PP&E and ARO (net of related deferred tax)
12.9
-
Goodwill
0.8
-
Share of profit/-loss from Joint Venture
-
6.0
Equity contribution into Joint Venture
-
4.2
Dividends from Joint Venture
-
-11.5
Carrying amount Investment in Joint Venture
77.5
76.1
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen (MOM) \u2013 Block
\u00a0
53, Block 43 and Block 32
The Ministry of Oil and Minerals (MOM) of
\u00a0
Yemen filed an arbitration claim against operator Dove Energy Limited and
\u00a0
the other partners
(including DNO Yemen AS) for allegedly wrongful withdrawal from Block 53. An
\u00a0
arbitral award was rendered in July 2019
\u00a0
partially in the
Ministry\u2019s favor in the amount of USD 29 million (out
\u00a0
of a USD 171 million claim). The Contractor
\u00a0
(including DNO Yemen AS), filed for
annulment proceedings in the Paris Court d\u2019Appel
\u00a0
which was dismissed in 2022 but is currently
\u00a0
on appeal at the Supreme Court. A
provision of USD 22.2 million was recognized at
\u00a0
yearend 2022 related to this arbitration award (USD
\u00a0
14 million at yearend 2021).
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). A provision for liability of
USD 1.4 million (net to DNO Yemen AS) was recognized in 2021 related
\u00a0
to this arbitration award (unchanged
\u00a0
at yearend 2022).
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\u2019 favor in the amount of USD 6.8 million (almost entirely dismissing
\u00a0
the USD 131
million counterclaim of the MOM). In accordance
\u00a0
with IAS 37, the asset related to this arbitration
\u00a0
award was not recognized in the
balance sheet as of 31 December 2022.
As part of the Block 43 arbitral award in 2020
\u00a0
(above), a cost recovery audit was mandated
\u00a0
for the years 2014 and 2015. In 2021, MOM
filed an arbitration claim against DNO Yemen AS for allegedly over-recovered costs of
\u00a0
USD 17.2 million from the Ministry in 2014 and
2015. In accordance with IAS 37.92, the Group does
\u00a0
not provide further information with respect
\u00a0
to this arbitration dispute and the
associated risk for the Group, especially with regards
\u00a0
to the measures taken in this context, in order not
\u00a0
to impair the outcome of the
proceedings. In accordance with IAS 37, no provision
\u00a0
for a liability was made at yearend 2022 related
\u00a0
to this dispute.
On 8 December 2022, the Oslo District Court
\u00a0
ruled that previously rendered arbitration awards
\u00a0
regarding Blocks 53 and 32 are
enforceable against DNO Yemen in Norway. DNO Yemen has appealed this decision. The Oslo District Court also ruled that the
previously rendered arbitration award regarding
\u00a0
Block 43 in favor of DNO Yemen is enforceable against the MOM in Norway. The MOM
has not contested this decision. A parallel enforcement
\u00a0
case regarding the same subject matter but
\u00a0
filed against DNO ASA remains
suspended pending a final ruling in the DNO
\u00a0
Yemen case.
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 2022 and
\u00a0
contingent on future market conditions including
\u00a0
development in the oil price, the Group\u2019s
projected operational spend comprising of capital and
\u00a0
exploration expenditures,
\u00a0
abandonment expenditures and operational
expenditures at yearend 2022 amounted to USD 640
\u00a0
million. The projected operational spend reflects the Group\u2019s
\u00a0
share of planned
drilling and facility investments and decommissioning
\u00a0
plan in its licenses for 2022. Execution
\u00a0
of these work plans is subject to revisions.
Guarantees related to assets in operation at yearend
\u00a0
2022
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.
Principal activities and corporate information
The principal activities of the Group are international
oil and gas
exploration, development and production
DNO ASA
\u00a0
is a Norwegian public limited liability company
organized and existing under the laws of
Norway
Norwegian
Public Limited Liability
(\u201callmennaksjeloven\u201d). The Company was incorporated
\u00a0
on 6
August 1971 and its registration number in
\u00a0
the Norwegian
Register of Business Enterprises is 921 526 121. The
\u00a0
shares in
the Company have been listed on the
Oslo
\u00a0
Stock Exchange since
1981, currently under the ticker \"DNO\". The Company's
\u00a0
registered
office is located at
Dokkveien 1, 0250 Oslo, Norway
. DNO\u2019s
activities are mainly undertaken in the Middle East,
\u00a0
the North Sea
\u25a0
Statement of compliance
The consolidated financial statements of
DNO ASA
prepared in accordance with International Financial
\u00a0
Reporting
Standards (IFRS) as adopted by the European
\u00a0
Union (EU) and
additional disclosure requirements in the Norwegian
\u00a0
Accounting
Act, effective as of 31 December 2022. The consolidated
\u00a0
financial
statements were approved by the Board of Directors
\u00a0
on 15 March
2023.
\u25a0
Basis for preparation
The consolidated financial statements have been
\u00a0
prepared on a
historical cost basis, with the following exemptions:
\u00a0
liabilities
related to share-based payments and investments in
\u00a0
equity
instruments classified as financial investments at fair value
through other comprehensive income are recognized
\u00a0
at fair value.
As permitted by International Accounting Standard
\u00a0
(IAS) 1
Presentation of Financial Statements
\u00a0
and in conformity with
industry practice, the expenses in the consolidated statements
\u00a0
of
comprehensive income are presented as a combination of
\u00a0
nature
and function as this gives the most relevant and
\u00a0
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.
Going concern
As required under the Norwegian Accounting Act,
\u00a0
the Company\u2019s
Board of Directors conducted a review of the
\u00a0
going concern
assumption considering all relevant information available
\u00a0
up to the
date the
DNO ASA
\u00a0
consolidated and Company accounts are
issued and taking into account all available information
\u00a0
about the
future covering at least 12 months from the end of
\u00a0
the reporting
period. The Board of Directors\u2019 review included
\u00a0
in particular
assessment of the Group\u2019s projected cash reserves and
\u00a0
access to
financing arrangements considering its operational
\u00a0
outlook and
work programs, while maintaining appropriate headroom
\u00a0
in
respect of liquidity and financial covenant compliance
\u00a0
throughout
the assessment period.
\u00a0
Following its review, the Board of Directors confirmed, pursuant to
the Norwegian Accounting Act section 3-3a, that the
\u00a0
requirements
of the going concern assumption are met and
\u00a0
that these financial
statements have been prepared on that basis.
\u25a0
Significant accounting estimates and assumptions
The preparation of the Group\u2019s financial statements requires
management to make judgments, estimates and assumptions
\u00a0
that
affect the reported amounts of revenues and expenses, assets
and liabilities, and the accompanying disclosures, and
\u00a0
the
disclosure of contingent liabilities at the reporting
\u00a0
date. Estimates
and assumptions are based on management\u2019s best knowledge
and historical experience and various other factors
\u00a0
that are
believed to be reasonable under the circumstances. Uncertainty
about these estimates and assumptions could
\u00a0
result in outcomes
that require a material adjustment to the carrying
\u00a0
amount of
assets or liabilities affected in future periods.
\u00a0
The key assumptions concerning the future and other
\u00a0
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 below. The Group based its assumptions and estimates
on parameters available when the Group financial
\u00a0
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
for the Group are:
\u00a0
Risks associated with operating in Kurdistan;
\u2022
Reserves and resources estimates;
\u2022
Contingencies, provisions and litigations;
\u2022
Impairment/reversal of impairment of oil and gas assets;
\u2022
Impairment of technical goodwill;
\u2022
Measurement of fair values;
\u2022
Acquisition accounting;
\u2022
Accounting for exploration costs;
\u00a0
and
\u2022
Notional corporate income tax/deferred taxation in Kurdistan.
\u00a0
Risks associated with operating in Kurdistan
DNO has interests in two licenses in Kurdistan
\u00a0
through Production
Sharing Contracts (PSCs) and has based its entitlement
calculations on the terms of these PSCs. In 2012,
\u00a0
the Federal
Government of Iraq (FGI) challenged the constitutional
\u00a0
validity of
the Kurdistan Oil and Gas Law No. 27/2007 (KOGL)
\u00a0
and the right
of the KRG to export oil independently of the
\u00a0
FGI.
\u00a0
The Company notes from public reports that on 15
\u00a0
February
2022, the Federal Supreme Court of Iraq (FSCI)
\u00a0
ruled on this
matter along with another related matter dating back
\u00a0
to 2019.
Reportedly, the FSCI found amongst other things that the KOGL
is unconstitutional, that the KRG is to hand over
\u00a0
all oil production
from areas located in the KRI to the FGI and that
\u00a0
the FGI has the
right to pursue the nullity of the oil contracts
\u00a0
concluded by the
KRG. DNO was not a party to the legal proceedings.
\u00a0
DNO has
learned via media reports that on 4 July 2022, a
\u00a0
commercial court
in Baghdad ruled that PSCs signed between the
\u00a0
KRG and four
international oil companies including DNO should
\u00a0
be voided.
Likewise, DNO notes from media reports that on
\u00a0
21 August 2022,
the KRG filed third party objections to the reported
\u00a0
4 July 2022
Baghdad rulings including those understood to concern
\u00a0
DNO.
These cases, along with other similar cases against
\u00a0
international
oil companies, are reported to be still pending.
\u00a0
Furthermore and
importantly, the KRG has issued repeated reassurances that the
PSCs remain valid. The KRG has also initiated legal
\u00a0
proceedings
against FGI in Erbil courts and there have been
\u00a0
several rulings in
Erbil courts affirming the validity of the PSCs. DNO notes
\u00a0
from
public reports that there is increased dialogue between
\u00a0
KRG and
FGI on oil related matters, in particular following
\u00a0
the 27 October
2022 federal parliamentary approval of a new federal
\u00a0
government
led by Prime Minister Mohammed Shia' Sabbar al-Sudani.
\u00a0
Since
then, DNO notes frequent media reports on regular
\u00a0
KRG and FGI
engagement to find a way forward, including by
\u00a0
way of adopting a
new federal oil and gas law. On 13 March 2023, it was announced
that the KRG had received a USD 275.5 million payment
\u00a0
from the
FGI pursuant to an agreement between the parties,
notwithstanding an FSCI ruling that deemed such payments
\u00a0
by a
previous government as \u201cwrong\u201d.
It is unclear how and when the KRG and the
\u00a0
FGI will permanently
address these matters. At present, normal operations
\u00a0
are
maintained at the Tawke and Baeshiqa licenses.
Due to disagreements between the FGI and the
\u00a0
KRG, economic
conditions in Kurdistan and limited oil export channels,
\u00a0
DNO has
historically faced constraints in fully monetizing the oil
\u00a0
it produces
in Kurdistan. There is no guarantee that oil and
\u00a0
gas can be
exported in sufficient quantities or at prices required
\u00a0
to sustain
DNO\u2019s operations and investment plans or that the Group
\u00a0
will
promptly receive its full entitlement payments for the oil
\u00a0
and gas it
delivers for export. Export sales have not always
\u00a0
followed the
PSC terms and there has been uncertainty related
\u00a0
to receipt of
payments but notwithstanding sometimes lengthy delays,
payments have ultimately been received by DNO.
\u00a0
See Note 18 for
more information.
DNO also notes the ongoing arbitration case,
\u00a0
commenced in
2014, by the FGI against the Turkish Government and its state-
owned pipeline operator BOTAS relating to the Iraq-Turkey
Pipeline. It is unclear if a ruling, when
\u00a0
it comes, may have an
impact on future transportation of Kurdish oil in said
\u00a0
pipeline.
Reserves and resources estimate
DNO\u2019s reserves and contingent resources are estimated
\u00a0
and
classified by the Company in accordance with the rules
\u00a0
and
guidelines of the Society of Petroleum Engineers (SPE)
\u00a0
and are in
conformity with requirements from the Oslo Stock Exchange
\u00a0
for
the reporting of reserves and resources.
\u00a0
All estimates of reserves and resources involve uncertainty.
Figures reported in Note 23 are the estimated proven
\u00a0
(1P),
proven and probable (2P) and proven, probable and
\u00a0
possible (3P)
quantities of oil and gas that can be recovered
\u00a0
from a field or
reservoir given the information available at yearend.
Important factors that could cause actual results to
\u00a0
differ from the
estimates include, but are not limited to: technical,
\u00a0
geological and
geotechnical conditions; economic and market conditions;
\u00a0
oil and
gas prices; changes in government regulations; political
development; interest rates; and currency exchange rates.
Specific parameters of uncertainty related to the
\u00a0
field/reservoir
include but are not limited to: reservoir pressure
\u00a0
and porosity;
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
cut-off and remaining reserves, which may change the
\u00a0
timing of
assumed decommissioning activities. Future changes to
estimated reserves can also have a material effect on
depreciation, impairment of oil and gas fields and
\u00a0
operating
results. The Group may also not be able to
\u00a0
commercially develop
its contingent resources that are used in impairment
\u00a0
assessments
or acquisition accounting where the fair value approach
\u00a0
is applied.
Contingencies, provisions and litigations
By their nature, contingencies will only be resolved
\u00a0
when one or
more uncertain future event occurs or fails to occur. The
assessment of the existence and potential quantum of
contingencies inherently involves the exercise of
\u00a0
significant
judgment and the use of estimates regarding
\u00a0
the outcome of
future events. Management uses its judgment to evaluate
\u00a0
certain
provisions and legal disputes in order to ensure
\u00a0
the correct
accounting treatment. This includes the assessment
\u00a0
of future
asset retirement obligations (ARO), any provisions or
\u00a0
contingent
payments.
Asset retirement obligations
The Group has recognized significant provisions relating
\u00a0
to the
decommissioning of oil and gas assets at the end
\u00a0
of the
production period. Obligations associated with decommissioning
assets are recognized at present value of future expenditures
\u00a0
on
the date they incur.
\u00a0
At the initial recognition of an obligation, the
estimated cost is capitalized as property, plant and equipment
(PP&E) and depreciated over the useful life of the asset
\u00a0
(typically
by unit-of-production).
\u00a0
It is difficult to estimate the costs for decommissioning at
\u00a0
initial
recognition as these estimates are based on
\u00a0
currently applicable
laws and regulations,
\u00a0
and technology. Decommissioning activities
will normally take place in the distant future, and
\u00a0
the technology,
regulatory requirements and related costs may change.
\u00a0
The
energy transition may bring forward the decommissioning
activities and thereby increasing the present value
\u00a0
of associated
decommissioning provisions.
\u00a0
Based on various scenario analysis
performed by the Company, management does not expect any
reasonable change in the expected timeframe to have
\u00a0
a material
effect on the Group\u2019s decommissioning provisions, assuming
\u00a0
cost
estimates (i.e., cash flows) remain unchanged. The estimates
cover expected removal concepts based on known technology
and, in the case of offshore decommissioning, estimated costs
\u00a0
of
maritime operations, hiring of heavy-lift barges
\u00a0
and drilling rigs. As
a result, the initial recognition of the liability and
\u00a0
the capitalized
cost associated with decommissioning obligations,
\u00a0
and the
subsequent adjustment of these balance sheet items, involve
\u00a0
the
application of significant judgement. Based on the
\u00a0
described
uncertainty, there may be significant adjustments in estimates of
liabilities that can affect future financial results.
Impairment/reversal of impairment of oil and gas
\u00a0
assets
DNO has recognized significant investments in development
\u00a0
and
production assets (classified under PP&E) and exploration
\u00a0
and
evaluation assets (classified under intangible assets)
\u00a0
in the
consolidated statements of financial position. Changes
\u00a0
in the
circumstances or expectations of future performance
\u00a0
of an
individual asset or a group of assets may be an
\u00a0
indicator that the
asset is impaired, requiring the carrying amount
\u00a0
to be written
down to its recoverable amount. Management must
\u00a0
determine
whether there are circumstances indicating a possible
\u00a0
impairment
of the Group\u2019s oil and gas assets. The estimation of
\u00a0
the
recoverable amount for the oil and gas assets includes
assessments of expected future cash flows and future
\u00a0
market
conditions, including entitlement production, future
\u00a0
oil and gas
prices, cost profiles, country risk factors (i.e., discount
\u00a0
rate) and
the date of expiration of the licenses.
\u00a0
Impairments,
\u00a0
other than those relating to goodwill, are
\u00a0
reversed if
the conditions for impairment are no longer present.
\u00a0
Evaluating
whether an asset is impaired or if an impairment
\u00a0
should be
reversed requires a high degree of judgment.
Impairment of technical goodwill
\u00a0
Although not an IFRS term, \u201ctechnical goodwill\u201d is
\u00a0
commonly
\u00a0
used
in the oil and gas industry to describe a category
\u00a0
of goodwill
arising as an offsetting amount to deferred tax recognized in
business combinations. DNO has recognized a significant
technical goodwill arising from business combinations.
\u00a0
There are
no specific IFRS guidelines about the allocation of technical
goodwill, and the Group has therefore applied the general
guidelines for allocating goodwill for the purpose
\u00a0
of impairment
testing. In general,
\u00a0
technical goodwill is allocated to a cash-
generating unit (CGU) or group of CGUs that give rise
\u00a0
to the
technical goodwill, while any residual goodwill may
\u00a0
be allocated
across all CGUs based on facts and circumstances
\u00a0
in the
business combination.
\u00a0
Goodwill is tested for impairment annually or more frequently
when there are impairment indicators. Moreover, goodwill is not
depreciated and hence, impairment of technical goodwill
\u00a0
is
expected on a recurring basis, unless there are positive
\u00a0
changes
in underlying assumptions that more than offset the production
from the CGU (or groups
\u00a0
of CGUs).
When performing the impairment test for technical
\u00a0
goodwill,
deferred tax recognized in relation to the acquired
\u00a0
assets in a
business combination reduces the net carrying value prior
\u00a0
to the
impairment charges. When deferred tax from the
\u00a0
initial recognition
decreases, more goodwill is exposed for impairment.
\u00a0
After initial
recognition, depreciation of values calculated in the purchase
price allocations from business combinations will result in
decreased deferred tax liability.
Climate considerations in impairment assessment
Climate change and transition to a lower carbon economy
\u00a0
is
considered in the impairment assessments. In
\u00a0
the context of
assessing the potential impact on the book values
\u00a0
related to the
Group\u2019s oil and gas assets, certain climate considerations
\u00a0
are
factored into the Group\u2019s estimation of cash flows that
\u00a0
are applied
in the calculation of recoverable amount. This includes
\u00a0
factoring in
current legislation in Norway and the UK (e.g.,
\u00a0
environmental
taxes/fees) and estimation of future levels of environmental
\u00a0
taxes.
An energy transition is likely to impact the future oil
\u00a0
and gas
prices which in turn may affect the recoverable amount
\u00a0
of the oil
and gas assets. Indirectly, climate considerations are also
assessed in the forecasting of oil and gas prices
\u00a0
where supply
and demand are considered. A significant reduction in the
Company\u2019s oil and gas price assumptions would result
\u00a0
in
impairments on certain production and development
\u00a0
assets
including intangible assets that are subject to impairment
assessment under IAS 36, but an opposite revision
\u00a0
in the price
assumptions would lead to limited impairment reversals
\u00a0
as most
of the impairments recognized were related to
\u00a0
impairment of
goodwill which cannot be reversed under IFRS.
In the context of testing robustness of the oil
\u00a0
and gas assets
against the scenarios from the International Energy Agency
\u00a0
(IEA),
the Company has applied the Net Zero Emissions
\u00a0
Scenario,
Announced Pledges Scenario and the Stated Policies
\u00a0
Scenario as
published by the IEA. These scenarios are commonly
\u00a0
applied by
peer companies and the Company believes are useful
\u00a0
to
investors and other stakeholders in assessing portfolio
\u00a0
resilience
across companies in the industry. For more details, see Note 9.
\u00a0
Measurement of fair values
Fair value is the price that would be received
\u00a0
to sell an asset or
paid to transfer a liability in an orderly transaction between
\u00a0
market
participants at the measurement date (IFRS 13
Fair Value
Measurement
). The fair value of an asset or a liability
\u00a0
is measured
using the assumptions that market participants would
\u00a0
use when
pricing the asset or liability, including assumptions about risk,
assuming that market participants act in their economic
\u00a0
best
interest. There are situations when the Group is required
\u00a0
to
measure fair values of non-financial assets and liabilities,
\u00a0
for
example when investing in equity instruments, in a business
combination including allocation of purchase price or when
\u00a0
the
Group measures the recoverable amount of an asset
\u00a0
at fair value
less costs to sell in an impairment testing situation.
\u00a0
Fair value measurement of a non-financial asset
\u00a0
takes into
account a market participant\u2019s ability to generate economic
benefits by using the asset in its highest and
\u00a0
best use or by
selling it to another market participant that would
\u00a0
use the asset in
its highest and best use.
\u00a0
The Group uses valuation techniques that are appropriate
\u00a0
in the
circumstances and for which sufficient data are available
\u00a0
to
measure fair value. The fair value of oil and gas assets
\u00a0
is
normally based on discounted cash flow models (income
approach), where the determination of different inputs
\u00a0
in the
model requires significant judgment from management,
\u00a0
as
described in the section above regarding impairment.
Acquisition accounting
The Group applies the acquisition method for transactions
involving business combinations and applies the principles
\u00a0
of the
acquisition method when an interest or an additional
\u00a0
interest is
acquired in a joint operation which constitutes a
\u00a0
business.
Application of the acquisition method may require significant
judgement in, among other matters, determining and measuring
the fair value of the transaction consideration including
\u00a0
contingent
consideration elements, identifying all assets acquired
\u00a0
and
liabilities assumed, establishing their fair values, determining
deferred taxes, and allocating the purchase price
\u00a0
accordingly,
including measurement and allocation of goodwill. The
judgements applied in acquisition accounting may
\u00a0
materially
affect the financial statements both in the transaction period
\u00a0
and
in future periods.
The assets acquired through business combinations are
recognized at fair values and, as such, are sensitive
\u00a0
to adverse
changes in a number of often volatile economic factors,
\u00a0
including
future oil and gas prices and the underlying
\u00a0
performance of the
assets.
Accounting for exploration costs
The Group\u2019s accounting policy is to temporarily capitalize drilling
expenditures related to exploration wells, pending an
\u00a0
evaluation
of potential oil and gas discoveries. If resources
\u00a0
are not
discovered, or if recovery of the resources is not
\u00a0
considered
technically or commercially viable, the costs of the exploration
wells are expensed in the income statement. Decisions
\u00a0
as to
whether an exploration well should remain capitalized
\u00a0
or
expensed during the period may have a material
\u00a0
effect on the
financial results
\u00a0
for the period.
Notional corporate income tax/deferred taxation
\u00a0
in Kurdistan
Under the terms of its PSCs in Kurdistan, DNO
\u00a0
is not required to
pay any corporate income taxes. The share of profit
\u00a0
oil which the
government is entitled to is deemed to include a
\u00a0
portion
representing the notional corporate income tax paid
\u00a0
by the
government on behalf of DNO. Current and deferred
\u00a0
taxation for
accounting purposes arising from such notional corporate
\u00a0
income
tax is not recognized for Kurdistan as it has
\u00a0
not been possible to
measure reliably such notional corporate income tax
\u00a0
paid on
behalf of DNO. This is an accounting presentational matter
\u00a0
and
there is no corporate income tax required
\u00a0
to be paid, see also
section Income taxes and Note 8.
\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 of
\u00a0
its subsidiaries.
The financial results of subsidiaries acquired or
\u00a0
sold during the
year are included in the consolidated financial statements
\u00a0
from
the date when the Company obtains control of the
\u00a0
subsidiary and
up to the date when the Company loses control
\u00a0
of the subsidiary.
The financial statements of the subsidiaries are prepared
\u00a0
for the
same reporting period as the parent company using
\u00a0
consistent
accounting policies. Where necessary, the accounting policies of
the subsidiaries have been adjusted to ensure consistency
\u00a0
with
the policies adopted by DNO. All intercompany balances
\u00a0
and
transactions have been eliminated upon consolidation.
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO
\u00a0
holds a long-term
interest which is jointly controlled by DNO and one
\u00a0
or more other
parties under a contractual arrangement in which
\u00a0
decisions about
the relevant activities require the unanimous
\u00a0
consent of the
parties sharing control. Such joint arrangements are classified
\u00a0
as
either joint operations or joint ventures.
Under IFRS 11
Joint Arrangements
, a joint operation is a joint
arrangement whereby the parties that have joint
\u00a0
control of the
arrangement have rights to the assets and obligations
\u00a0
for the
liabilities. Oil and gas licenses held by the Group
\u00a0
which are within
the scope of IFRS 11 have been classified as 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
A joint venture under IFRS 11, is a joint arrangement whereby the
parties that have joint control of the arrangement
\u00a0
have rights to
the net assets of the arrangement. Those parties are
\u00a0
called joint
venturers. Joint control is the contractually agreed sharing
\u00a0
of
control of an arrangement, which exists only when
\u00a0
decisions
about the relevant activities require unanimous
\u00a0
consent of the
parties sharing control.
\u00a0
The Group\u2019s investments in a joint venture are accounted
\u00a0
for
using the equity method. Under the equity method,
\u00a0
the investment
is initially recognized at cost. The carrying value of
\u00a0
the investment
is adjusted to recognize the Group\u2019s share of the net assets
\u00a0
of the
joint venture since the acquisition date. Goodwill relating
\u00a0
to the
joint venture is included in the carrying amount of
\u00a0
the investment
and is neither amortized nor individually tested
\u00a0
for impairment.
The income statement reflects the Group\u2019s share of the results
\u00a0
of
operations in the joint venture. On acquisition of
\u00a0
the investment,
any difference between the cost of the investment and
\u00a0
the
Group\u2019s share of the net fair value of the investee\u2019s identifiable
assets and liabilities is accounted for as: Goodwill
\u00a0
relating to a
joint venture and is included in the carrying
\u00a0
amount of the
investment; and any excess of the Group\u2019s share of
\u00a0
the net fair
value of the joint venture\u2019s profit or loss in the period
\u00a0
in which the
investment is acquired.
Appropriate adjustments to the Group\u2019s share of the joint
venture\u2019s profit or loss after acquisition are made in
\u00a0
order to
account for, for example, for depreciation of the depreciable
assets (and related deferred tax, if any) based
\u00a0
on their fair values
at the acquisition date.
Any change in OCI of those investees is presented
\u00a0
as part of the
Group\u2019s OCI. In addition, when there has been a change
recognized directly in the equity of the joint venture,
\u00a0
the Group
recognizes its share of any changes, when applicable,
\u00a0
in the
statement of changes in equity.
The aggregate of the Group\u2019s share of profit or loss
\u00a0
of a joint
venture represents profit or loss after tax and non-controlling
interests in the subsidiaries of the joint venture. The
\u00a0
financial
statements of the joint venture are prepared for
\u00a0
the same
reporting period as the Group. When necessary, adjustments are
made to bring the accounting policies in line
\u00a0
with those of the
Group (IFRS).
The impact of reciprocal interests between the
\u00a0
Group and its
investees is eliminated before the Group accounts
\u00a0
for its share;
the Group also reduces its equity and investment
\u00a0
balance by its
effective interest in its own shares.
For those licenses that are not deemed to be joint
\u00a0
arrangements
pursuant to the definition in IFRS 11, either because unanimous
consent is not required among the parties involved,
\u00a0
or no single
group of parties has joint control over the
\u00a0
activity, DNO
recognizes its share of related expenses, assets,
\u00a0
liabilities and
cash flows under the respective items in the Group\u2019s financial
statements in accordance with applicable IFRS
\u00a0
standards. In
determining whether each separate arrangement related
\u00a0
to
DNO\u2019s joint operations is within or outside the scope of
\u00a0
IFRS 11,
DNO considers the terms of relevant license agreements,
governmental concessions and other legal arrangements
impacting how and by whom each arrangement
\u00a0
is controlled.
\u25a0
Foreign currency translation and transactions
Functional currency
The consolidated financial statements are presented
\u00a0
in USD,
which is also DNO ASA\u2019s functional currency and presentation
Items included in the financial statements of each
\u00a0
subsidiary are
initially recorded in the subsidiary\u2019s functional currency, i.e., the
currency that best reflects the economic substance of
\u00a0
the
underlying events and circumstances relevant to
\u00a0
that subsidiary.
Transactions and balances
Foreign currency transactions are translated into functional
currency of the Company or subsidiaries using
\u00a0
the exchange
rates prevailing at the dates of the transactions. Financial
\u00a0
assets
and financial liabilities in foreign currencies are translated
\u00a0
into
functional currency at the balance sheet date exchange
\u00a0
rates.
Foreign exchange gains and losses resulting from
\u00a0
the settlement
of such transactions and from the translation of
\u00a0
monetary assets
and liabilities denominated in foreign currencies are
\u00a0
recognized in
profit or loss. Those arising in respect of financial
\u00a0
assets and
liabilities are recorded
\u00a0
on a net basis as a financial item.
Foreign exchange gains or losses relating to
\u00a0
changes in the fair
value of non-monetary financial assets classified as
\u00a0
equity
instruments are recognized directly in other comprehensive
income.
Subsidiaries
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 translation
differences taken directly to other comprehensive income. When
a foreign entity is sold, such translation differences are
recognized in profit or loss as part of the gain
\u00a0
or loss on the sale.
\u25a0
Classification in the statements of financial
position
Current assets and current liabilities include items
\u00a0
due less than
one year from the balance sheet date, and if
\u00a0
longer, items related
to the operating cycle. The current portion of non-current
\u00a0
liabilities
is included under current liabilities. Investments in shares held
\u00a0
for
trading are classified as current assets, while
\u00a0
strategic
investments are classified as non-current assets. Other
\u00a0
assets
and liabilities are classified as non-current assets
\u00a0
and non-current
liabilities.
\u25a0
Fair value
Fair value is the price that would be received to
\u00a0
sell an asset or
be paid to transfer a liability in an orderly transaction
\u00a0
between
market participants at the measurement date. The
\u00a0
fair value of an
asset or a liability is measured using the assumptions
\u00a0
that market
participants would use when pricing the asset
\u00a0
or liability,
assuming that market participants act in their economic
\u00a0
best
interest. All assets and liabilities for which fair
\u00a0
value is measured
or disclosed in the financial statements are categorized
\u00a0
within the
fair value hierarchy as follows:
\u00a0
\u2022
Level 1 - Quoted market prices in active markets
\u00a0
for identical
assets or liabilities
\u00a0
\u2022
Level 2 - Valuation techniques for which the lowest level input
that is significant to the fair value measurement is directly
\u00a0
or
indirectly observable
\u00a0
\u2022
Level 3 - Valuation techniques for which the lowest level input
that is significant to the fair value measurement is
unobservable.
Investments in equity instruments, where available,
\u00a0
are measured
at quoted market prices at the measurement date.
\u25a0
Property, plant and equipment
General
PP&E are recognized at historical cost and adjusted
\u00a0
for
depreciation, depletion and amortization (DD&A) and
\u00a0
impairment
Depreciation of PP&E other than oil and gas assets
\u00a0
are generally
depreciated on a straight-line basis over expected
\u00a0
useful lives,
normally varying from three to seven years. Expected
\u00a0
useful lives
are reviewed at each balance sheet date and, where
\u00a0
there are
changes in estimates, depreciation periods are changed
accordingly.
The carrying amount of the PP&E in the statements
\u00a0
of financial
position represents the cost less accumulated DD&A
\u00a0
and
accumulated impairment charges.
Ordinary repairs and maintenance costs, defined
\u00a0
as day-to-day
servicing costs, are charged to profit or loss during
\u00a0
the financial
period in which they are incurred. The cost of major
\u00a0
repairs and
maintenance is included in the asset\u2019s carrying amount
\u00a0
when it is
likely that the Group will derive future financial benefits
\u00a0
exceeding
the originally assessed standard of performance of
\u00a0
the existing
asset.
Gains and losses on disposals are determined
\u00a0
by comparing the
disposal proceeds with the carrying amount and
\u00a0
are included in
Assets held for sale are reported at the lower
\u00a0
of the carrying
amount and the fair value, less selling costs.
Exploration and development costs
\u00a0
Capitalized exploration expenditures are classified as
\u00a0
intangible
assets and reclassified to tangible assets (i.e.,
\u00a0
PP&E) at the start
of the development. For accounting purposes, an oil
\u00a0
and gas field
is considered to enter the development phase when
\u00a0
the technical
feasibility and commercial viability of extracting oil and gas
\u00a0
from
the field are demonstrable, normally at the time
\u00a0
of concept
selection. All costs of developing commercial oil
\u00a0
and gas fields
are capitalized, including indirect costs. Capitalized development
costs are classified as tangible assets. Pre-development
expenditures up until development project sanction in
\u00a0
general do
not meet the criteria for capitalization and are expensed
\u00a0
as
incurred.
Acquired license rights are recognized as intangible assets
\u00a0
at the
time of acquisition. Acquired license rights related
\u00a0
to fields in the
exploration phase remain as intangible assets when
\u00a0
the related
fields enter the development or production phase.
Oil and gas assets in production
Capitalized costs for oil and gas assets are depreciated
\u00a0
using the
unit-of-production (UoP) method. The rate of depreciation
\u00a0
is equal
to the ratio of oil and gas production for
\u00a0
the period over the
estimated remaining 2P reserves at the beginning of
\u00a0
the period.
The future development expenditures necessary to bring
\u00a0
those
reserves into production are included in the
\u00a0
basis for depreciation
and are estimated by the management based
\u00a0
on current period-
end un-escalated price levels. The reserve basis used
\u00a0
for
depreciation purposes is updated at least once a year. Any
changes in the reserves affecting UoP calculations are reflected
prospectively.
Component cost accounting/decomposition
The Group allocates the amount initially recognized
\u00a0
in respect of
an item of PP&E to its significant parts and depreciates
\u00a0
separately
each such part over its useful life.
\u00a0
Borrowing costs
Interest costs directly attributable to the construction phase
\u00a0
of
PP&E assets are capitalized during the period required
\u00a0
to
complete and prepare the asset for its intended
\u00a0
use. Borrowing
costs consist of interest and other costs that the Group
\u00a0
incurs in
connection with the borrowing of funds.
\u00a0
Other borrowing costs are expensed when incurred.
\u00a0
The
capitalization of borrowing costs is recorded based
\u00a0
on the
average interest rate for the Group in the period.
\u00a0
The capitalized
borrowing costs cannot exceed the actual borrowing
\u00a0
costs in each
period.
Leases
The Group assesses at contract inception whether
\u00a0
a contract is,
or contains, a lease. That is, if the contract
\u00a0
conveys the right to
control the use of an identified asset for a period
\u00a0
of time in
exchange for consideration.
\u00a0
The Group applies a single recognition and measurement
approach for all leases, except for short-term leases (12
\u00a0
months
or less) and leases of low-value assets. Short
\u00a0
term leases and
leases of low value assets have not been reflected
\u00a0
in the balance
sheet but expensed or capitalized as incurred, depending
\u00a0
on the
activity in which the leased asset is used.
At the commencement date of a lease, the Group recognizes
\u00a0
a
liability to make lease payments and an asset representing
\u00a0
the
right to use the underlying asset (right-of-use (RoU)
\u00a0
asset) during
The RoU assets are measured to cost, less any
\u00a0
accumulated
depreciation and impairment losses, and adjusted
\u00a0
for any
remeasurement of lease liabilities. The RoU assets
\u00a0
are
depreciated linearly over the lifetime of the related lease
\u00a0
contract.
Lease liabilities are measured at the present value
\u00a0
of lease
payments to be made over the lease term. In
\u00a0
calculating the
present value of lease payments, the Group
\u00a0
uses the implicit
interest rate and if not readily determinable, its
\u00a0
incremental
borrowing rate at the lease commencement date.
Extension options are included in the lease liability
\u00a0
when, based
on the management\u2019s judgement, it is reasonably certain
\u00a0
that an
extension will be exercised.
When DNO, as the operator of a license, is considered
\u00a0
to have
the primary responsibility for the full lease payments
\u00a0
(e.g., a rig
lease where the lease agreement is entered into DNO\u2019s
\u00a0
name as
the operator of a license at the initial signing),
\u00a0
the lease liability
may be recognized on gross basis, rather than based
\u00a0
on DNO\u2019s
working interest share. DNO then derecognizes a portion
\u00a0
of the
RoU asset corresponding to the non-operator\u2019s
\u00a0
interests in the
license (presented under receivables).
In the consolidated statements of comprehensive
\u00a0
income,
operating lease costs, relating to contracts that contain
\u00a0
a lease,
are replaced by depreciation and interest expense.
In the consolidated cash flow, lease payments related to lease
liabilities recognized in accordance with IFRS 16,
\u00a0
are presented
as cash flow used in financing activities.
The Group\u2019s RoU assets mainly relate to office rent,
\u00a0
rig and
equipment. The Group also leases equipment
\u00a0
with contract terms
of one to three years but has elected to apply
\u00a0
the practical
expedient on low value assets and does not recognize
\u00a0
lease
liabilities or RoU assets and the leases are
\u00a0
instead expensed
when the costs are incurred.
\u25a0
Intangible assets
General
Intangible assets are stated at cost, less accumulated
amortization and accumulated impairment charges.
\u00a0
Intangible
assets include acquisition costs for oil and gas licenses,
expenditures on the exploration for oil and gas
\u00a0
resources,
technical goodwill and other intangible assets. Goodwill
\u00a0
is not
depreciated.
The useful lives of intangible assets are assessed
\u00a0
as either finite
or infinite. Amortization of intangible assets is
\u00a0
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 more often
\u00a0
if indicators
exist.
Exploration and evaluation assets
The Group uses the successful efforts method to account for
\u00a0
its
exploration and evaluation assets. All exploration
\u00a0
costs (including
purchase of seismic, geological and geophysical
\u00a0
costs and
general and administrative costs), except for acquisition
\u00a0
costs of
licenses and drilling costs of exploration wells, are
\u00a0
expensed as
incurred. Acquisition costs of licenses and drilling
\u00a0
costs of
exploration wells are temporarily capitalized pending
\u00a0
the
determination of oil and gas resources. These
\u00a0
costs include
directly attributable employee remuneration, materials and
\u00a0
fuel
used, rig costs and payments to contractors. Continued
capitalization of such costs is assessed for impairment
\u00a0
at each
reporting date. The main criterion is that there must
\u00a0
be plans for
future activity in the license or that a development
\u00a0
decision is
expected in the near future. If reserves or resources are
\u00a0
not
found, or if discoveries are assessed not technically
\u00a0
or
commercially recoverable, the costs of exploration wells and
licenses are expensed.
\u25a0
Impairment/reversal of impairment
At the end of each reporting period, the Group
\u00a0
assesses whether
there is any indication that an asset may be
\u00a0
impaired. If an
impairment indicator is concluded to exist, an impairment
\u00a0
test is
Indications of impairment may include a decline
\u00a0
in the long-term
oil and gas price (or short-term oil and gas price
\u00a0
for late-life oil
and gas fields), changes in future investments or significant
downward revision of reserve and resource estimates.
\u00a0
For the
purposes of impairment assessment, assets are grouped
\u00a0
at the
lowest levels for which there are separable identifiable
\u00a0
cash
inflows. For oil and gas assets, a CGU may be individual
\u00a0
oil and
gas fields, or a group of oil and gas
\u00a0
fields 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 asset. The
\u00a0
recoverable
amount is the higher of the asset\u2019s fair value less costs to
\u00a0
sell and
its value in use. Fair value less costs to sell
\u00a0
determined through
either the discounted cash flow method (income approach)
\u00a0
or the
market transactions method (market approach). The value
\u00a0
in use
can only be determined through the discounted cash
\u00a0
flow method.
A previously recognized impairment loss is reversed
\u00a0
through the
income statement if the circumstances that gave rise
\u00a0
to the
impairment no longer exist. It is not reversed
\u00a0
to an amount that
would be higher than if no impairment loss
\u00a0
had been recognized.
After such a reversal, the depreciation charge
\u00a0
is adjusted in future
periods to allocate the asset\u2019s revised carrying amount,
\u00a0
less any
residual value, on a systematic basis over its remaining
\u00a0
useful life.
Technical goodwill
Technical goodwill is tested for impairment annually or more
frequently when there are impairment indicators. Those
\u00a0
indicators
may be specific to an individual CGU or groups
\u00a0
of CGUs to which
the technical goodwill is related. When performing
\u00a0
the impairment
test for technical goodwill, deferred tax recognized
\u00a0
in relation to
the acquired licenses reduces the net carrying value prior
\u00a0
to the
impairment charges.
Impairment is recognized if the recoverable amount
\u00a0
of the CGU
(or groups
\u00a0
of CGUs) to which the technical goodwill is related
\u00a0
is
less than the carrying amount.
\u00a0
Impairment of goodwill cannot be reversed in future
\u00a0
periods.
\u25a0
Financial instruments
A financial instrument is any contract that gives
\u00a0
rise to a financial
asset of one entity and a financial liability or
\u00a0
equity instrument of
another entity. Financial instruments are initially recognized at fair
value. After initial recognition the measurement and accounting
treatment depend on the type of instrument and
\u00a0
classification.
Financial assets
Financial assets are classified at initial recognition
\u00a0
and
subsequently measured at:
\u2022
Amortized cost;
\u2022
Fair value through other comprehensive income (FVTOCI); and
\u00a0
\u2022
Fair value through profit or loss (FVTPL).
Financial assets at amortized cost
Financial assets are measured at amortized cost if
\u00a0
both of the
following conditions are met:
\u00a0
\u2022
The financial asset is held within a business
\u00a0
model with the
objective to hold financial assets in order to collect
\u00a0
contractual
\u2022
The contractual terms of the financial asset give
\u00a0
rise on
specified dates to cash flows that are solely payments
\u00a0
of
principal and interest on the principal amount outstanding.
Financial assets at amortized cost are subsequently
\u00a0
measured
using the effective interest rate (EIR) method and are
\u00a0
subject to
impairment. Gains and losses are recognized in profit
\u00a0
or loss
when the asset is derecognized, modified or impaired.
\u00a0
The
Group\u2019s financial assets at amortized cost include trade
\u00a0
and other
receivables.
Financial assets designated at FVTOCI
Upon initial recognition, equity investments can be
\u00a0
irrevocably
classified as equity instruments designated at
\u00a0
FVTOCI. Gains and
losses on these financial assets are not recycled
\u00a0
to profit or loss
at later periods. Equity instruments designated at
\u00a0
FVTOCI are not
subject to an impairment assessment.
Financial assets at FVTPL
Financial assets at FVTPL include financial assets held
\u00a0
for
trading, financial assets designated upon initial recognition
\u00a0
at
FVTPL or financial assets mandatorily required to be
\u00a0
measured at
fair value. Financial assets at FVTPL are carried
\u00a0
in the statements
of financial position at fair value with net changes
\u00a0
in fair value
recognized in profit or loss. Dividends on listed equity
\u00a0
investments
are also recognized as other income in profit
\u00a0
or loss when the
right of payment has been established. The Group
\u00a0
does not have
significant assets designated at FVTPL.
Derecognition of financial assets
A financial asset is derecognized when the Group:
\u2022
No longer has the right to receive cash flows from
\u00a0
the asset;
\u2022
Retains the right to receive cash flows from the asset
\u00a0
but has
assumed an obligation to pay them in full without
\u00a0
material
delay to a third party under a pass-through arrangement;
\u00a0
or
\u2022
Has transferred its rights to receive cash flows from
\u00a0
the asset
and either has transferred substantially all the risks
\u00a0
and
rewards of the asset or has neither transferred
\u00a0
nor retained
substantially all the risks and rewards of the asset
\u00a0
but has
transferred the control of the asset.
Impairment of financial assets
An allowance is recognized for expected credit
\u00a0
losses (ECLs) for
all debt instruments not held at FVTPL. ECLs are
\u00a0
based on the
difference between the contractual cash flows due in accordance
with the contract and all the cash flows that are
\u00a0
expected to be
received, discounted at an approximation of the original
\u00a0
effective
ECLs are recognized in two stages. For credit exposures
\u00a0
with no
significant increase in credit risk since initial recognition,
\u00a0
ECLs are
provided for credit losses that result from default events
\u00a0
that are
possible within the next 12 months. For credit exposures
\u00a0
with
significant increase in credit risk since initial recognition,
\u00a0
a loss
allowance is provided for credit losses expected
\u00a0
over the
remaining life of the exposure, irrespective of
\u00a0
the timing of the
For trade receivables, a simplified approach is applied
\u00a0
in
calculating ECLs. Changes in credit risk are not
\u00a0
tracked but
instead a loss allowance based on lifetime ECLs
\u00a0
at each reporting
date is recognized. Expected credit losses are based
\u00a0
on a
multifactor and holistic analysis and depend on
\u00a0
historical
experience with the customers adjusted for forward-looking
factors specific to the customers and the economic environment.
\u00a0
Financial assets are assessed with regards
\u00a0
to default when
contractual payments are past the established payment
\u00a0
due date
and there is internal or external information indicating
\u00a0
that the
Group is unlikely to receive the outstanding contractual
\u00a0
amounts
in full. A financial asset is written off when there is
\u00a0
no reasonable
expectation of recovering the contractual cash flows.
Further disclosures on impairment of financial assets
\u00a0
are provided
in Note 18.
Financial liabilities
Financial liabilities are classified at initial recognition as
\u00a0
financial
liabilities at FVTPL, loans and borrowings or payables.
\u00a0
All financial liabilities are recognized initially at
\u00a0
fair value and in
the case of loans/borrowings and payables, net
\u00a0
of directly
attributable transaction costs.
\u00a0
The Group\u2019s financial liabilities include trade and other payables
and loans.
The subsequent measurement of financial liabilities depends
\u00a0
on
the classification. No financial liabilities have been designated
\u00a0
at
FVTPL. Interest-bearing loans are after initial recognition
measured at amortized cost using the effective interest
\u00a0
rate
method. Gains and losses are recognized in
\u00a0
profit or loss when
the liabilities are derecognized as well as through
\u00a0
the amortization
process. Amortized cost is calculated by taking into account
\u00a0
any
discount or premium on acquisition and fees or
\u00a0
costs that are an
integral part of the effective interest rate. The amortization
\u00a0
cost is
included as finance expense in the statements of
\u00a0
comprehensive
income. This applies mainly to bond loans,
\u00a0
see Note 15.
\u00a0
A financial liability is derecognized when the obligation
\u00a0
under the
liability is discharged, cancelled or expires. When
\u00a0
an existing
financial liability is replaced by another from the
\u00a0
same lender on
substantially different terms, or the terms of an existing
\u00a0
liability are
substantially modified, such a modification is treated
\u00a0
as a
derecognition of the original liability and a recognition
\u00a0
of a new
liability. The difference in the respective carrying amounts is
recognized in the statements of comprehensive income.
Cash and cash equivalents
Cash and short-term deposits in the statements
\u00a0
of financial
position comprise cash held in banks, cash in
\u00a0
hand and short-
term deposits with an original maturity of three
\u00a0
months or less.
\u25a0
Equity
Ordinary shares
Ordinary shares are classified as equity. Costs directly
attributable to the issue of ordinary shares and
\u00a0
share options are
recognized as a reduction of equity, net of any tax effects.
Repurchase of share capital (treasury shares)
When share capital recognized as equity is repurchased,
\u00a0
the
amount of the consideration paid, which includes
\u00a0
directly
attributable costs, is net of any tax effects and is
\u00a0
recognized as a
deduction in equity. Repurchased shares are classified as
treasury shares and are presented as a deduction
\u00a0
from total
equity. When treasury shares are subsequently sold or reissued,
the amount received is recognized as an increase
\u00a0
in equity and
the resulting surplus or deficit of the transaction
\u00a0
is transferred
to/from retained earnings.
Dividend
Liability to pay a dividend is recognized when
\u00a0
the distribution is
authorized by the shareholders. A corresponding amount is
recognized directly in equity.
\u25a0
Financial income and expenses
Financial income comprises interest income; dividend
\u00a0
income;
gains on the disposal of financial investments; foreign
\u00a0
exchange
gains; changes in the fair value of financial assets through
\u00a0
profit
or loss; and other financial income. Interest income
\u00a0
is recognized
as it accrues in profit or loss using the effective interest
\u00a0
method.
Dividend income is recognized in the profit or
\u00a0
loss on the date that
the Group\u2019s right to receive payment is established,
\u00a0
which in the
case of quoted securities is the ex-dividend date.
Financial expenses comprise interest expenses on
\u00a0
loans;
unwinding of the discount on provisions; changes
\u00a0
in the fair value
of financial assets measured at FVTPL; impairment
\u00a0
losses
recognized on financial assets; foreign exchange
\u00a0
losses;
\u00a0
losses
on financial assets recognized in the profit or
\u00a0
loss; and other
financial expenses.
Foreign exchange gains or losses from financial
\u00a0
instruments are
reported as financial income or financial expenses.
\u25a0
Inventories
Inventories are valued at the lower of cost and
\u00a0
net realizable
value. Cost is determined by the first-in, first-out (FIFO)
\u00a0
method.
Net realizable value is the estimated selling price
\u00a0
in the ordinary
course of business, less the estimated costs of
\u00a0
completion and
estimated selling expenses.
\u25a0
Revenue recognition
Revenues presented in the consolidated statements 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 and gas,
\u00a0
which normally will be
when title passes at the point of delivery.
A liability (overlift) arises when the Group sells
\u00a0
more than its
share of the oil and gas production. Similarly, an asset (underlift)
arises when the sale is less than the Group\u2019s share
\u00a0
of the oil and
gas production.
In general, the overlift/underlift balances are valued
\u00a0
at production
cost including depreciation (the sales method). The movements
\u00a0
in
overlift/underlift are presented as an adjustment to
Cost of goods
sold
Tariff income from processing of oil and gas in the North Sea is
recognized as earned.
\u00a0
Other revenues are recognized when the goods
\u00a0
or services are
delivered and risk and control are transferred.
Revenue recognition in Kurdistan
DNO generates revenues in Kurdistan through the sale
\u00a0
of oil
produced from the Tawke license which is exported by pipeline
through Turkey. The title is considered to have passed on delivery
of oil to the export pipeline at Fish Khabur. In addition, pursuant
\u00a0
to
a receivables settlement agreement with the KRG
\u00a0
in August 2017,
DNO was entitled to production overrides (override)
\u00a0
representing
three percent of gross Tawke license revenues until 31 July 2022.
The Group recognizes revenues in Kurdistan in line
\u00a0
with the
invoiced oil sales and overrides following monthly
\u00a0
deliveries to the
KRG. The PSCs held by the Group are considered
\u00a0
to be within
the scope of the standard and sale of oil and gas
\u00a0
to customers is
recognized as
Revenue from contracts with customers
. Based on
business practice, the KRG is responsible for exporting
\u00a0
the oil
produced in Kurdistan and it is assessed that
\u00a0
DNO has a
customer relationship with the KRG. It is considered
\u00a0
that the
contracts with customers contain a single performance
\u00a0
obligation
which is considered to be delivery of produced oil
\u00a0
and gas to the
customer.
The price for oil deliveries to the KRG is
\u00a0
based on Brent prices
with adjustments for oil quality and transportation
\u00a0
fees.
\u25a0
Production Sharing Contracts (PSC)
A PSC is an agreement between a contractor
\u00a0
and a host
government, whereby the contractor bears all of
\u00a0
the risks and
costs of exploration, and if successful, costs of development
\u00a0
and
production in return for a stipulated share of production
\u00a0
from the
discovery.
The contractor recovers the sum of its investment
\u00a0
and operating
costs from a percentage of production (cost oil).
\u00a0
In addition, the
contractor is entitled to receive a share of production
\u00a0
in excess of
cost oil (profit oil). The sum of cost oil attributable
\u00a0
to the
contractor\u2019s share of costs and the share of
\u00a0
profit oil represents
the contractor\u2019s entitlement under a PSC.
\u00a0
The sum of royalties
and the government\u2019s share of profit oil, including that of a
government-controlled enterprise, represents the government
take under a PSC.
DNO presents its operations governed by PSCs according
\u00a0
to the
sales method and only recognizes its sales as
\u00a0
revenue after
deduction of government take.
\u25a0
Income taxes
Tax income/expense consists of taxes receivable/payable and
changes in deferred taxes.
\u00a0
Taxes receivable/payable are based
on the amounts receivable from or payable to the tax
\u00a0
authorities.
Deferred tax liability is calculated on all taxable temporary
differences unless there is a recognition exception. A deferred
\u00a0
tax
asset is recognized only to the extent that it
\u00a0
is probable that the
future taxable income will be available against which
\u00a0
the asset
can be utilized. Unrecognized deferred tax assets
\u00a0
are re-
assessed at each reporting date and are
\u00a0
recognized to the extent
that it has become probable that future taxable profits
\u00a0
will allow
the deferred tax asset to be recovered.
Deferred tax assets and deferred tax liabilities
\u00a0
are recognized
irrespective of when the differences are reversed.
\u00a0
They are
recognized at their nominal value and classified as non-current
assets/liabilities in the statements of financial position.
\u00a0
Deferred
tax assets and deferred tax liabilities are offset
\u00a0
in the statements
of financial position if there is a legal right
\u00a0
to settle current tax
amounts on a net basis and the deferred tax
\u00a0
amounts are levied
by the same taxing authority on the same entity or
\u00a0
different
entities that intend to realize the asset and settle the
\u00a0
liability at the
same time.
Tax payable and deferred tax are recognized directly in the equity
to the extent that they relate to items charged
\u00a0
directly to equity.
\u00a0
For treatment of tax in relation to business combinations,
\u00a0
see the
Business combinations section.
\u00a0
DNO\u2019s PSCs provide that the corporate income tax to which the
contractor is subject is deemed to have been paid to
\u00a0
the
government as part of the payment of profit
\u00a0
oil to the government
or its representatives. For accounting purposes, if
\u00a0
such notional
income tax is to be classified as income tax in
\u00a0
accordance with
IAS 12
Income Taxes
, the Group would present this as an income
tax expense with a corresponding increase in revenues.
Furthermore, it would be assessed whether any
\u00a0
deferred tax
asset or liability is required to be recognized
\u00a0
equal to the
difference between book values and the tax values of
\u00a0
the
qualifying assets and liabilities, multiplied by the applicable
\u00a0
tax
rate.
\u25a0
Business combinations
In accordance with IFRS 3
Business Combinations
, an acquisition
is considered a business combination, when the acquired
\u00a0
asset or
groups of assets constitute a business (i.e., an integrated
\u00a0
set of
operations and assets conducted and managed for
\u00a0
the purpose of
providing a return to the investors).
Acquired businesses are included in the financial statements
\u00a0
from
the transaction date. The transaction date is defined
\u00a0
as the date
on which the Group achieves control over the
\u00a0
financial and
operating assets. This date may differ from the actual
\u00a0
date on
which the assets are transferred.
For accounting purposes, the acquisition method is used
\u00a0
in
connection with the purchase of businesses. Acquisition
\u00a0
cost
equals the fair value of the assets used as
\u00a0
consideration,
including contingent consideration, equity instruments issued
\u00a0
and
liabilities assumed in connection with the transfer of
\u00a0
control.
Acquisition cost is measured against the fair value
\u00a0
of the acquired
assets and assumed liabilities. Identifiable intangible
\u00a0
assets are
included in connection with acquisitions if they
\u00a0
can be separated
from other assets or meet the legal contractual
\u00a0
criteria. If the
acquisition cost at the time of the acquisition exceeds
\u00a0
the fair
value of the acquired net assets (when
\u00a0
the acquiring entity
achieves control of the transferring entity), goodwill arises.
If the fair value of the acquired net assets exceeds
\u00a0
the acquisition
cost on the acquisition date, the excess amount
\u00a0
is taken to profit
or loss immediately.
Goodwill is allocated to the CGUs or groups of
\u00a0
CGUs that are
expected to benefit from synergy effects of the acquisition.
\u00a0
The
allocation of goodwill may vary depending on the
\u00a0
basis of its initial
recognition.
The goodwill that is recognized by the Group is related
\u00a0
to
technical goodwill and is recognized due to the requirement
\u00a0
to
recognize deferred tax for the difference between the assigned
fair values and the related tax base. The fair values of
\u00a0
the Group\u2019s
licenses in the North Sea are based on cash flows
\u00a0
after tax.
\u00a0
This
is because these licenses are sold only on an after-tax
\u00a0
basis. The
purchaser is therefore not entitled to a tax deduction
\u00a0
for the
consideration paid above the seller\u2019s tax values.
\u00a0
In accordance
with IAS 12, a provision is made for deferred
\u00a0
tax corresponding to
the tax rate multiplied by the difference between the fair
\u00a0
values of
the acquired assets and the transferred tax depreciation
\u00a0
basis.
\u00a0
The offsetting entry to this deferred tax is goodwill. Hence,
goodwill arises as a technical effect of deferred
\u00a0
tax. Technical
goodwill is tested for impairment separately for each
\u00a0
CGU which
gives rise to the technical goodwill. A CGU
\u00a0
may be individual oil
fields, or a group of oil fields that are
\u00a0
connected to the same
infrastructure/production facilities, or a license.
The estimation of fair value may be adjusted up
\u00a0
to 12 months
after the acquisition date if new information emerges
\u00a0
about facts
and circumstances that existed at the time of
\u00a0
the takeover and
which, had they been known, would have affected the
\u00a0
calculation
of the amounts that were included from that date.
Acquisition-related costs, except costs to issue debt or
\u00a0
equity
securities, are expensed as incurred. Taxes payable and deferred
taxes are recognized directly in the equity to
\u00a0
the extent that they
relate to items charged directly to the equity.
\u25a0
License acquisitions, farm-in/out and license
swaps
License acquisitions
\u00a0
For acquisition of oil and gas licenses, individual
\u00a0
assessment is
made whether the acquisition should be treated
\u00a0
as a business
combination or as an asset purchase. The
\u00a0
conclusion may
materially affect the financial statements both in the transaction
period and in future periods. 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.
Farm-in and farm-out
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. The farmee capitalizes or expenses
\u00a0
its costs as
incurred according to the accounting method it is
\u00a0
using. There are
no accruals for future commitments in farm-in/farm-out
agreements in the exploration and evaluation phase
\u00a0
and no profit
or loss is recognized by the farmor. In the development or
production phase, a farm-in/farm-out agreement will be
\u00a0
treated as
a transaction recorded at fair value as represented
\u00a0
by the costs
carried by the farmee. Any gain or loss arising from
\u00a0
the farm-
in/farm-out is recognized in the statements of comprehensive
License swaps
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
the fair value of
the asset divested,
\u00a0
can be reliably measured. In the exploration
phase, the Group normally recognizes license swaps based
\u00a0
on
historical cost basis. If the transaction is determined
\u00a0
to be a
business combination, the requirements of IFRS 3
\u00a0
apply.
\u25a0
Employee benefits
Pensions
The Group\u2019s pension obligations in Norway are limited
\u00a0
to certain
defined contribution plans which are paid to pension
\u00a0
insurance
plans and charged to profit or loss in the period
\u00a0
in which they are
incurred. Once the contributions are paid there are no
\u00a0
further
obligations.
Share-based payments
Cash-settled share-based payments are recognized in
\u00a0
the income
statement as expenses during the vesting period and
\u00a0
as a liability.
The liability is measured at fair value and revaluated
\u00a0
using the
Black & Scholes pricing model at each balance
\u00a0
sheet date and at
the date of settlement, with any change in the fair
\u00a0
value
recognized in the income statement for the period.
\u25a0
Provisions and contingent liabilities
A provision is recognized when the Group has
\u00a0
a present
obligation (legal or constructive) as a result of
\u00a0
a past event, there
is likely that an outflow of resources will be required
\u00a0
to settle the
obligation and a reliable estimate can be made
\u00a0
of the obligation
amount. When the Group expects some or
\u00a0
all of a provision to be
reimbursed, for example under an insurance contract,
\u00a0
the
reimbursement is recognized as a separate asset,
\u00a0
but only if the
reimbursement is certain. The expense related to any
\u00a0
provision is
presented in profit or loss, net of any reimbursement.
\u00a0
Provisions
are reviewed at each balance sheet date and
\u00a0
adjusted to reflect
the current best estimate.
The amount of the provision is the present value of
\u00a0
the risk-
adjusted expenditures expected to be required to settle
\u00a0
the
obligation, determined using the estimated risk-free interest
\u00a0
rate
and a credit margin as the discount rate. Where
\u00a0
discounting is
used, the carrying amount of the provision increases
\u00a0
in each
period to reflect the unwinding of the discount by
\u00a0
the passage of
time. This increase is recognized as other financial
\u00a0
expenses.
Contingent liabilities are not recognized but are
\u00a0
disclosed unless
the possibility of an outflow of resources is remote.
Asset retirement obligations
Provisions for ARO are initially recognized at the
\u00a0
present value of
the estimated future costs determined in accordance
\u00a0
with local
conditions and requirements.
A corresponding ARO asset (included in PP&E) of
\u00a0
an amount
equivalent to the provision is also recognized initially. This is
subsequently depreciated as part of the capital costs
\u00a0
of the
production and transportation facilities.
\u00a0
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 risk-free rate
\u00a0
used has a maturity
date that is expected to coincide with the time
\u00a0
the removal will be
affected and denominated in the same currency as the expected
future expenditures. According to IFRIC 1
Changes in Existing
Decommissioning, Restoration 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
\u00a0
a change in the
discount rate, are added to or deducted from the cost
\u00a0
of the
related asset. Changes in the estimated ARO provisions
\u00a0
impact
the ARO asset in the period in which the estimate
\u00a0
is revised.
\u25a0
Segment reporting
Management monitors the operating results of its operating
segments separately for the purpose of making decisions
\u00a0
about
resource allocation and performance assessment.
\u00a0
Segment
financial performance is evaluated based on the income
statements,
\u00a0
financial position as well as through other
\u00a0
key
performance indicators. For DNO, its operating segments
correspond to its reportable segments. The reportable
\u00a0
segments
provide products or services within a particular economic
environment that are subject to risks and returns
\u00a0
different from
those of components operating in other economic
\u00a0
environments.
The Group has identified its reportable segments
\u00a0
based on the
nature of the risk and return within its business
\u00a0
and by the
geographical location of the Group\u2019s assets and operations.
Transfer pricing between the segments and companies is set
using the arm\u2019s length principle in a manner similar to
transactions with third parties.
\u25a0
Earnings per share
Calculation of basic earnings per share is based
\u00a0
on the net profit
or loss attributable to ordinary shareholders using
\u00a0
the weighted
average number of shares outstanding during the
\u00a0
year after
deduction of the average number of treasury shares
\u00a0
held over the
period. The calculation of diluted earnings per share
\u00a0
is consistent
with the calculation of basic earnings per
\u00a0
share, while giving effect
to all dilutive potential ordinary shares that were
\u00a0
outstanding
during the period.
\u25a0
Related parties
Parties are related if one party has the ability
\u00a0
to directly, jointly or
indirectly control the other party or exercise significant
\u00a0
influence
over the party in making financial and operating
\u00a0
decisions.
Management is also considered to be a related
\u00a0
party.
\u00a0
Transactions between related parties are transfers of resources,
services or obligations, regardless of whether a
\u00a0
price is charged.
All transactions between the related parties are
\u00a0
recorded at
market value.
\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 for
\u00a0
the first time
in 2022 but are not considered to have any material
\u00a0
impact on the
Group\u2019s financial statements.
Tax income/-expense
1 January - 31 December
USD million
2022
2021
Changes in deferred taxes
162.9
-115.2
Income taxes receivable/-payable
-124.5
98.9
Total tax income/-expense
38.4
-16.3
Income tax receivable/-payable
Years ended 31 December
USD million
2022
2021
Tax receivables
25.8
21.1
Income taxes payable
-125.7
-33.1
Net tax receivable/-payable
-99.9
-11.9
The tax balances relate to the activity on the Norwegian
\u00a0
Continental Shelf (NCS) and the UK Continental
\u00a0
Shelf (UKCS). The current tax
receivable relates to tax refunds of decommissioning
\u00a0
spend on the UKCS expected to be received
\u00a0
during the third quarter of 2023. The
current income taxes payable relates to taxable
\u00a0
profits in 2022 on the NCS and will be
\u00a0
paid during first half of 2023.
\u00a0
In June 2022, the Norwegian Parliament approved
\u00a0
certain changes to the taxation of oil and gas
\u00a0
companies operating on the NCS,
effective from 1 January 2022. The companies can expense
\u00a0
investments immediately in the special tax
\u00a0
basis and receive a cash refund
of the tax value of losses in the special tax basis.
\u00a0
The uplift on investments is discontinued
\u00a0
but will apply to the investments covered by
the temporary changes, as approved by the parliament
\u00a0
in June 2020. The ordinary corporate tax is deductible
\u00a0
in the special tax basis
and to maintain a combined marginal tax rate of
\u00a0
78 percent, the special tax rate is increased
\u00a0
to 71.8 percent. Losses in the corporate tax
basis are not eligible for refund but can be
\u00a0
carried forward. The tax value of unused uplift
\u00a0
and carried forward losses as of yearend 2021
will be paid out in connection with the 2022 tax assessment
\u00a0
in November 2023 or offset tax installments on 2022
\u00a0
taxable profits.
In December 2022, the Norwegian Parliament approved
\u00a0
a change to the uplift under the temporary tax
\u00a0
rules applying to PDOs delivered
by the end of 2022, from 17.69 percent to 12.4
\u00a0
percent, effective from 1 January 2023. The change to
\u00a0
the uplift adversely impacts the
economics of development projects under the temporary
\u00a0
rules.
During 2022, DNO received tax refunds of USD 17.7
\u00a0
million in the UK in relation to decommissioning
\u00a0
spend for 2021. In Norway, DNO
paid net USD 38.9 million which consisted of repayment
\u00a0
of refunds received during the second half of
\u00a0
2021 and the first three tax
installments on 2022 taxable profits.
Reconciliation of tax income/-expense
1 January - 31 December
USD million
2022
2021
Profit/-loss before income tax
346.5
220.1
Expected income tax according to nominal tax rate in Norway, 22 percent
-108.1
-52.4
Expected income tax according to nominal petroleum tax rate in Norway,
\u00a0
78 percent
43.3
24.3
Expected income tax according to nominal tax outside Norway
33.5
7.4
Foreign exchange variations between functional and tax currency
2.5
-4.5
Adjustment of previous years
0.7
0.2
Adjustment of deferred tax assets not recognized
-62.3
-31.0
Other items including other permanent differences
116.2
35.3
Change in tax rate
12.4
4.6
Tax income/-expense
38.4
-16.3
Effective income tax rate
-11.1%
-7.4%
Taxes charged to equity
-
-
Expected income tax related to activities on the NCS and
\u00a0
outside Norway is positive as the petroleum
\u00a0
activities in Norway and the UK
generated a loss before tax. Other items above
\u00a0
consist mainly of permanent differences on impairments
\u00a0
which are not tax deductible,
and permanent differences on tax exempted profits/losses
\u00a0
from upstream activities outside of Norway carried
\u00a0
out by the Company\u2019s
Norwegian subsidiaries.
Tax effects on temporary differences
Years ended 31 December
USD million
2022
2021
Tangible assets
-195.8
-351.5
Intangible assets (including capitalized exploration expenses)
-76.9
-168.0
ARO provisions
226.2
266.6
Losses carried forward
167.6
155.5
Non-deductible interests carried forward
26.5
29.4
Other temporary differences
-0.9
-8.1
Net deferred tax assets/-liabilities
146.8
-76.0
Valuation allowance
-209.1
-162.0
Net deferred tax assets/-liabilities
-62.4
-238.0
Recognized deferred tax assets
-
29.3
Recognized deferred tax liabilities
-62.4
-267.3
A valuation allowance was recognized relating to carried
\u00a0
forward losses in Norway (ordinary tax regime)
\u00a0
and the UK due to the
uncertainty regarding future taxable profits.
Under the terms of the PSCs in Kurdistan, the
\u00a0
Company\u2019s subsidiary DNO Iraq AS is not required
\u00a0
to pay any corporate income taxes.
The share of profit oil which the government
\u00a0
is entitled to is deemed to include a portion
\u00a0
representing the notional corporate income tax
paid by the government on behalf of DNO Iraq
\u00a0
AS. Current and deferred taxation arising
\u00a0
from such notional corporate income tax is not
calculated for Kurdistan, as there is uncertainty related
\u00a0
to the tax laws of the KRG and there is
\u00a0
currently no well-established tax regime
for international oil companies. As such, it has not
\u00a0
been possible to reliably measure such notional
\u00a0
corporate income taxes deemed to
have been paid on behalf of DNO Iraq AS.
\u00a0
This is an accounting presentational issue and
\u00a0
there is no outstanding tax required to be paid
by DNO Iraq AS. See also Note 1.
\u00a0
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 (19 percent) and
\u00a0
the UKCS (40 percent). In the UK, the tax rate
\u00a0
in the
ordinary tax regime will increase to 25 percent
\u00a0
from April 2023. Additionally, in May 2022 the Energy Profits Levy (EPL) was
\u00a0
introduced
which is a new 25 percent temporary levy on oil
\u00a0
and gas ring fence profits, adjusted for decommissioning
\u00a0
spend. The rate will increase
to 35 percent from 1 January 2023. EPL did not
\u00a0
affect the 2022 results as the UK companies were loss-making.
\u00a0
The changes in tax
rates have not had any impact as deferred
\u00a0
tax asset has not been recognized on carried
\u00a0
forward losses and temporary differences in
the UK.
Reconciliation of change in deferred tax assets/-liabilities
Years ended 31 December
USD million
2022
2021
Net deferred tax assets/-liabilities at 1 January
-238.0
-131.4
Change in deferred taxes in the income statement
162.9
-115.2
Reclassification from/-to tax receivable
-15.3
-
Currency and other movements
28.0
8.6
Net deferred tax assets/-liabilities at 31 December
-62.4
-238.0
Reconciliation of change in tax receivable/-payable
Years ended 31 December
USD million
2022
2021
Net tax receivable/-payable at 1 January
-11.9
63.1
Tax receivable/-payable related to transactions
\u00a0
posted directly to balance sheet
0.9
3.7
Tax receivable/-payable in the income statement
-124.5
98.9
Tax payment/-refund
21.2
-174.7
Prior period adjustment
-0.5
-
Reclassification to/-from deferred tax asset
15.3
-
Currency and other movements
-0.4
-3.0
Net tax receivable/-payable at 31 December
-99.9
-11.9
Note 11
Financial investments
Financial investments are comprised of equity instruments
\u00a0
and are recorded at fair value (market price, where
\u00a0
available) at the end of
the reporting period. Fair value changes are included
\u00a0
in other comprehensive income (FVTOCI), see Note 1
\u00a0
for details.
\u00a0
Years ended 31 December
USD million
2022
2021
Book value as of 1 January
16.2
12.6
Fair value changes through other comprehensive income (FVTOCI)
14.2
3.6
Disposal
-30.4
-
Book value as of 31 December
-
16.2
Financial investments include the following:
USD million
2022
2021
Listed shares:
RAK Petroleum plc
-
16.2
Total financial investments
-
16.2
Prior to the completion of the agreement entered
\u00a0
between DNO and RAK Petroleum in October 2022 (see
\u00a0
Note 10), the Company held
a total of 15,849,737 (5.1 percent) shares in RAK
\u00a0
Petroleum. RAK Petroleum was listed on the Oslo
\u00a0
Stock Exchange and was the
largest shareholder in DNO ASA with 44.94 percent
\u00a0
of the total issued shares. As part of the all-share
\u00a0
transaction with RAK Petroleum,
on 19 October 2022, RAK Petroleum distributed
\u00a0
by way of a capital repayment the entirety of
\u00a0
its DNO ASA shareholding, including the
transaction consideration shares, to its shareholders, which
\u00a0
also included DNO ASA. Following the distribution,
\u00a0
the Company had
26,269,183 own shares which were retained as
\u00a0
treasury shares and the Company\u2019s investment in RAK
\u00a0
Petroleum was simultaneously
derecognized from the balance sheet.
Change in fair value prior to transaction completion
\u00a0
was recognized in other comprehensive income
\u00a0
with USD 14.2 million in 2022 (USD
3.6 million in 2021).
Note 13
Cash and cash equivalents
Years ended 31 December
USD million
2022
2021
Cash and cash equivalents, restricted
22.5
15.8
Cash and cash equivalents, non-restricted
931.8
720.8
Total cash and cash equivalents
954.3
736.6
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 2022.
Included in the non-restricted cash and cash equivalents
\u00a0
as of 31 December 2022 is USD 408.7
\u00a0
million held on fixed interest time
deposit contracts with different duration and maturity dates
\u00a0
up to 23 January 2023.
Years ended 31 December
USD million
2022
2021
Trade debtors (non-current portion)
-
18.2
Other long-term receivables
-
1.3
Total other non-current receivables
-
19.4
Trade debtors
311.8
344.4
Underlift
14.0
17.2
Other short-term receivables
111.9
122.2
Total trade and other receivables
437.8
483.8
Total book value of trade debtors of USD 311.8 million at yearend 2022 relate mainly to outstanding invoices for Kurdistan
\u00a0
oil deliveries
for the months August through December 2022 (USD
\u00a0
295.9 million).
\u00a0
In September 2022, the KRG proposed a change in
\u00a0
the previously agreed pricing formula for oil
\u00a0
such that prices should, with effect from
1 September 2022, be based on the purported
\u00a0
actual price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been
accepted by DNO and the Company continues to invoice
\u00a0
the KRG for oil sales based on the previously
\u00a0
agreed pricing formula (including
the September 2022 invoice) until such time that protocols
\u00a0
are put in place to ensure that realized
\u00a0
prices are transparent, based on
arms-length transactions and subject to third-party audit.
\u00a0
See Note 18 regarding trade debtors from
\u00a0
oil sales in Kurdistan. See also Note
25 regarding payments received from the KRG
\u00a0
after yearend.
The underlift receivable of USD 14 million as
\u00a0
of 31 December 2022 relates to North Sea
\u00a0
underlifted volumes. Other short-term
receivables mainly relate to items of working capital
\u00a0
in licenses in Kurdistan and the North Sea
\u00a0
and accrual for earned income not
invoiced in the North Sea.
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2022
2021
2022
2021
Non-current
Bond loan (ISIN NO0010852643)
DNO03
USD
150.7
8.375
29.05.24
9.0
131.5
410.2
131.2
394.9
Bond loan (ISIN NO0011088593)
DNO04
USD
400.0
7.875
09.09.26
8.8
375.8
414.0
400.0
400.0
Capitalized borrowing issue costs
-11.3
-16.5
Reserve based lending facility
-
USD
350.0
see below
see below
-
26.6
95.0
26.6
95.0
Total non-current interest-bearing liabilities
533.9
919.2
546.4
873.4
Current
Reserve based lending facility (current)
-
NOK
350.0
see below
see below
-
8.4
-
8.4
-
Total current interest-bearing liabilities
8.4
-
8.4
-
Total interest-bearing liabilities
542.3
919.2
554.8
873.4
During 2022, DNO ASA acquired USD 263.7 million
\u00a0
of DNO03 bonds at a price range of
\u00a0
99 to 103.35 percent of par plus accrued
interest. Facility and carrying amount for the bonds
\u00a0
is shown net of bonds held by the Company.
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.
The Group has a reserve-based lending (RBL)
\u00a0
facility for its Norway and UK production licenses
\u00a0
with a total facility limit of USD 350
million which is available for both debt and issuance
\u00a0
of letters of credit. In addition, there is an
\u00a0
uncommitted accordion option of USD
350 million. Interest charged on utilizations is based
\u00a0
on LIBOR plus a margin ranging from 2.75
\u00a0
to 3.25 percent. The facility will amortize
over the loan life with a final maturity date
\u00a0
of 7 November 2026. The entities that participate
\u00a0
in the facility are required to submit
quarterly a liquidity test and maintain a consolidated
\u00a0
net debt divided by EBITDAX ratio of maximum
\u00a0
3.50. The security under the RBL
includes, without limitation, a pledge over the
\u00a0
shares in DNO North Sea plc and its subsidiaries,
\u00a0
assignment of claims under shareholder
loans, intra-group loans and insurances, a pledge
\u00a0
of certain bank accounts and mortgages over
\u00a0
the license interests. There are also
restrictions on loans and dividend payments to DNO
\u00a0
ASA. The borrowing base amount of the facility
\u00a0
from 1 January 2023 is USD 74.2
million. Amount utilized as of the reporting date is
\u00a0
disclosed in the table above. In addition, USD
\u00a0
31.8 million is utilized in respect of
letters of credit.
There have been no breaches of the financial
\u00a0
covenants of any interest-bearing liability in the
\u00a0
current period.
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
2022
flows
Amortization
Currency
Acquisition
2022
Bond loans
794.9
-263.7
-
-
-
531.2
Borrowing issue costs
-16.5
-
5.2
-
-
-11.3
Reserve based lending facility
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
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2021
flows
Amortization
Currency
Acquisition
2021
Bond loans
800.0
-5.1
-
-
-
794.9
Borrowing issue costs
-15.4
-10.5
9.4
-
-
-16.5
Reserve based lending facility
149.6
-53.9
-
-0.7
-
95.0
Total
934.2
-69.5
9.4
-0.7
-
873.4
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2021
975,433
32.9
-
32.9
Treasury shares sold/-purchased
-
-
-
-
As of 31 December 2021
975,433
32.9
-
32.9
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2022
975,433
32.9
0.0
32.9
Treasury shares sold/-purchased
-36,369
-
-0.9
-0.9
Share capital increase*
78,944
1.8
-
1.8
As of 31 December 2022
1,018,008
34.8
-0.9
33.9
* See Note 10 for information and details
At the 2022 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 24,385,818 which corresponds
\u00a0
to 97,543,373 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 2023 AGM, and not beyond
\u00a0
30 June 2023.
\u00a0
The Board of Directors was also given the
\u00a0
authority to increase the Company\u2019s share capital
\u00a0
by up to NOK 24,385,818 which
corresponds to 97,543,373 new shares. The authorization
\u00a0
was time-limited until the 2023 AGM, and not
\u00a0
beyond 30 June 2023.
\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 increased
\u00a0
by up to
NOK 24,385,818. The authorization is valid until
\u00a0
the 2023 AGM, but not beyond 30 June 2023.
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 2022
AGM until the date of the 2023 AGM. Following
\u00a0
this, the Board of Directors decided to distribute
\u00a0
quarterly dividends of NOK 0.25 in
August and November 2022, as well as in
\u00a0
February 2023.
At an Extraordinary General Meeting (EGM) in
\u00a0
September 2022, a proposal to increase the Company\u2019s
\u00a0
share capital received support
of over 99 percent of the votes cast. In accordance
\u00a0
with the EGM approval and a transaction
\u00a0
agreement, DNO in October 2022 issued
78,943,763 new shares to RAK Petroleum, its then largest
\u00a0
shareholder, as consideration for the transfer of West Africa assets between
the companies. Pursuant to the transaction agreement,
\u00a0
RAK Petroleum proceeded to distribute its
\u00a0
entire DNO shareholding, including
the consideration shares, to its shareholders. As a
\u00a0
shareholder of RAK Petroleum (5.1 percent), DNO
\u00a0
received 26,269,183 own shares
to be retained as treasury shares. The total shares outstanding
\u00a0
following the completion of the transaction increased
\u00a0
to 1,054,376,509,
each with a nominal value of NOK 0.25.
In December 2022, DNO announced the initiation
\u00a0
of a share buyback program through which
\u00a0
the Company would repurchase up to
53,107,326 shares, representing approximately five percent
\u00a0
of total shares outstanding, for a maximum
\u00a0
total consideration of USD 80
million. The buyback program was based upon
\u00a0
the authorization to acquire treasury shares
\u00a0
granted to the Board of Directors at the
2022 AGM.
Interest
The Company's shareholders as of 31 December 2022
Shares
(percent)
Goldman Sachs & Co. LLC
131,926,545
12.51
Euroclear Bank S.A./N.V.
93,818,919
8.90
Folketrygdfondet
44,490,590
4.22
RAK Gas LLC
34,311,403
3.25
State Street Bank and Trust Comp
28,018,325
2.66
The Bank of New York Mellon
25,336,833
2.40
BNP Paribas
24,188,187
2.29
The Bank of New York Mellon SA/NV
15,017,836
1.42
Clearstream Banking S.A
14,083,236
1.34
CACEIS Bank
14,054,243
1.33
HSBC Bank Plc
13,888,921
1.32
JPMorgan Chase Bank
10,886,384
1.03
Citibank
10,275,813
0.97
The Bank of New York Mellon
9,285,363
0.88
State Street Bank and Trust Comp
9,059,036
0.86
Saxo Bank A/S
8,611,705
0.82
Salt Value AS
8,495,200
0.81
The Northern Trust Comp
8,193,045
0.78
Citibank
7,263,451
0.69
Morgan Stanley & Co. International
7,093,637
0.67
Other shareholders
499,708,654
47.39
Total number of shares excluding treasury shares
1,018,007,326
96.55
Treasury shares as of 31 December 2022 (DNO ASA)
36,369,183
3.45
Total number of outstanding shares
1,054,376,509
100.00
Dividends of USD 72 million were distributed in 2022
\u00a0
(USD 21.8 million in 2021). See Note 25
\u00a0
for dividend approved
on 9 February 2023. See also Note 5 for shares
\u00a0
held by Board of Directors and executive
\u00a0
management.
1 January - 31 December
Total
USD million
2022
2021
2022
2021
2022
2021
Sale of oil
820.1
594.3
241.0
233.8
1,061.1
828.1
Sale of gas
-
-
281.1
151.3
281.1
151.3
Sale of natural gas liquids (NGL)
-
-
29.1
21.3
29.1
21.3
Tariff income
-
-
5.8
3.4
5.8
3.4
Total revenues from contracts with customers
820.1
594.3
556.9
409.8
1,377.0
1,004.1
Sale of oil (bopd)
25,933
28,091
6,341
8,493
32,273
36,583
Sale of gas (boepd)
-
-
4,800
4,344
4,800
4,344
Sale of natural gas liquids (NGL) (boepd)
-
-
1,370
1,244
1,370
1,244
Total sales volume (boepd)
25,933
28,091
12,511
14,080
38,444
42,171
Note 4
Cost of goods sold/Inventory
1 January - 31 December
USD million
2022
2021
Lifting costs
-222.1
-184.2
Tariff and transportation expenses
-30.2
-34.5
Production costs based on produced volumes
-252.3
-218.8
Movement in overlift/underlift
8.1
-18.3
Production costs based on sold volumes
-244.2
-237.0
Depreciation, depletion and amortization
-216.7
-206.0
Total cost of goods sold
-460.9
-443.1
Lifting costs consist of expenses related to the production
\u00a0
of oil and gas, including operation and maintenance of
\u00a0
installations, well
intervention activities and insurances. The lifting
\u00a0
costs in 2022 included a provision for obsolete inventory
\u00a0
of USD 2.9 million related to
North Sea (2021 lifting costs included a reversal
\u00a0
of provision for obsolete inventory of USD 1
\u00a0
million related to Kurdistan). Tariff and
transportation expenses consist of charges incurred
\u00a0
by the Group in the North Sea for the use of
\u00a0
infrastructure owned by other
companies.
Years ended 31 December
USD million
2022
2021
Spare parts
47.0
35.8
Total inventory
47.0
35.8
Total inventory of USD 47 million at yearend 2022 was related to Kurdistan (USD 33.7
\u00a0
million) and the North Sea (USD 13.3 million).
1 January - 31 December
USD million
2022
2021
Salaries, bonuses, etc.
-55.2
-56.2
Employer's payroll tax expenses
-5.1
-5.4
Pensions
-4.1
-3.8
Other personnel costs
-5.8
-4.2
General and administration expenses
-32.5
-42.3
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
84.8
95.5
Total administrative expenses
-17.9
-16.2
Other expenses
-7.7
-12.0
Total other operating expenses
-7.7
-12.0
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 2022 were mainly related to provisions
\u00a0
in Yemen, see Note 19.
DNO has a defined contribution scheme for its Norway-based
\u00a0
employees, with USD 4.1 million expensed
\u00a0
in 2022 (USD 3.8 million in
2021). 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 2022, the Company\u2019s liability for synthetic
\u00a0
shares as part of other variable remuneration amounted
\u00a0
to USD 5.4 million (USD
2.2 million at yearend 2021). 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
2022
2021
Outstanding as of 1 January
3,178,536
2,837,151
Granted during the year
9,471,309
1,321,431
Forfeited/reversed during the year
37,099
71,374
Settled during the year
1,159,108
908,672
Outstanding as of 31 December
11,453,638
3,178,536
Unrestricted as of 31 December
834,872
462,214
Weighted average remaining contractual life for the synthetic shares (years)
2.43
2.78
Weighted average settlement price for synthetic shares settled during the year (NOK)
12.56
10.83
Settlement price for synthetic shares at the end of the year (NOK)
11.81
10.46
Remuneration to Board of Directors and executive
\u00a0
management
1 January - 31 December
USD million
2022
2021
Managing Director
Salary
-0.64
-0.69
Bonus
-0.26
-0.08
Pension
-0.02
-0.02
Other remuneration
-0.17
-0.07
Remuneration to Managing Director
-1.09
-0.85
Other executive management
Salary
-1.99
-3.24
Bonus
-0.15
-0.70
Pension
-0.08
-0.13
Other remuneration
-0.59
-0.55
Remuneration to other executive management
-2.81
-4.63
Total remuneration to executive management
-3.90
-5.48
Number of managers included
6
8
Total remuneration to Board of Directors
-1.17
-1.10
Total remuneration to Board of Directors and executive management
-5.07
-6.58
Total remuneration of USD 2.4 million (not included in the above table) was paid in 2022
\u00a0
to Nicholas Whiteley and Tom Allan, former
members of the executive management. For further details
\u00a0
on remuneration to the executive management,
\u00a0
see Note 3 in the parent
Shares and options held by Board of Directors
\u00a0
and executive management
Years ended 31 December
Directors and executive management
Bijan Mossavar-Rahmani, Executive Chairman*
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
-
-
-
-
Bj\u00f8rn Dale, Managing Director
-
-
-
-
Chris Spencer, Chief Operating Officer (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
35,750
-
25,750
-
Sameh Hanna, General Manager Kurdistan region of Iraq
-
-
-
-
\u00d8rjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
* At yearend 2022, Bijan Mossavar-Rahmani held interests in the Company through a nominee account held by Goldman Sachs & Co. LLC. At yearend 2021, Mr. Mossavar-
Rahmani held indirect interest in the Company through his shareholdings in RAK Petroleum plc (see also Note 11 for more details).
\u00a0
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.
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2022
2021
Auditor fees
-0.71
-0.84
Other financial auditing
-0.04
-0.04
Tax advisory services
-0.08
-0.10
Other advisory services
-
-
Total auditor fees
-0.82
-0.98
Financial risk management, objectives and policies
Overview
The Group\u2019s principal financial liabilities are comprised of interest-bearing
\u00a0
liabilities and trade and other payables. The
\u00a0
main purpose of
these financial liabilities is to finance DNO\u2019s operations. The
\u00a0
Group\u2019s principal financial assets include trade
\u00a0
and other receivables, tax
receivables and cash and cash equivalents.
\u00a0
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. In 2022, the Group had gas price
\u00a0
put options in place with strike prices of
GBP 79 -110 pence per therm, securing approximately 75 percent of after-tax
\u00a0
profit from estimated 2022 gas production.
\u00a0
The Group
had no oil and gas price hedging arrangements
\u00a0
at yearend 2022.
\u00a0
The following table illustrates the impact on reported 2021
\u00a0
and 2022 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 9 for a
sensitivity analysis related to the impairment
\u00a0
assessment of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
2022
+/- 15.0
2021
+/- 15.0
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 2022 although it monitors
\u00a0
its foreign currency risk exposure on a
\u00a0
continuous basis and evaluates
hedging alternatives.
\u00a0
The following tables illustrate the impact on DNO\u2019s reported
\u00a0
profit/-loss before income tax in 2021 and
\u00a0
2022 from foreign currency
exchange rate fluctuations deemed reasonable and possible
\u00a0
in NOK, EUR and GBP exchange rates,
\u00a0
with all other variables held
constant. The other currencies (e.g., AED, IQD) are not
\u00a0
included as the exposure is deemed immaterial.
Change in
Effect on profit
NOK (percent)
before tax (USD mill)
2022
+ 10.0
-3.5
2022
- 10.0
3.5
2021
+ 10.0
-5.9
2021
- 10.0
5.9
Change in
Effect on profit
GBP (percent)
before tax (USD mill)
2022
+ 10.0
-19.0
2022
- 10.0
19.0
2021
+ 10.0
1.4
2021
- 10.0
-1.4
Change in
Effect on profit
EUR (percent)
before tax (USD mill)
2022
+ 10.0
-4.8
2022
- 10.0
4.8
2021
+ 10.0
-3.6
2021
- 10.0
3.6
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 2022. 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 2021 and
\u00a0
2022 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)
2022
+/- 200
+/-7.7
2021
+/- 200
+/-14.8
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 and
\u00a0
other financial resources to maintain financial
\u00a0
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 15. The Group\u2019s finance function prepares
\u00a0
projections on a regular basis in order to
\u00a0
plan the Group\u2019s liquidity
requirements. These plans are updated regularly
\u00a0
for various scenarios and form part of the basis
\u00a0
for decision making by the Company\u2019s
Board of Directors and the executive management.
Investment in joint venture
Foxtrot International issues cash calls to Mondoil Enterprises
\u00a0
(see Note 10) to fund capital and operating
\u00a0
requirements for C\u00f4te d\u2019Ivoire
Block CI-27 and Block CI-12, which are made on
\u00a0
a regular basis pursuant to an approved budget
\u00a0
and work program.
\u00a0
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 in 2022
\u00a0
derived primarily from production in the Tawke license in Kurdistan and
from several licenses in the North Sea. The Group
\u00a0
actively seeks to reduce such risk through
\u00a0
organic growth and asset acquisitions
aimed at further diversifying its revenue sources.
\u00a0
See also Note 10 regarding the Company\u2019s entry in
\u00a0
West Africa.
The tables below summarize the maturity profile of
\u00a0
the Group\u2019s financial liabilities based on contractual undiscounted
\u00a0
cash flows.
USD million
On
At 31 December 2022
demand
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
USD million
On
At 31 December 2021
demand
Interest-bearing liabilities*
16.9
60.8
510.4
545.3
Other provisions and charges
18.6
16.2
Taxes payable
-
12.6
20.5
-
-
Trade and other payables
1.9
210.4
3.0
Total liabilities
1.9
258.5
100.5
510.4
545.3
* Face value of the bonds was USD 531.2 million at yearend 2022 (USD 794.9 million at yearend 2021).
For changes in liabilities arising from financing activities,
\u00a0
see Note 15.
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
2022
2021
Trade debtors (non-current portion) (Note 12)
-
18.2
Trade debtors (Note 12)
311.8
344.4
Other receivables (Note 12)
126.0
139.4
25.8
21.1
Cash and cash equivalents
954.3
736.6
1,417.9
1,259.7
Trade debtors
The impairment model in IFRS 9 is based on
\u00a0
the premise of providing for expected credit
\u00a0
losses. Expected credit losses (ECL) under
IFRS 9 are based on the difference between the contractual
\u00a0
cash flows due in accordance with the contract and
\u00a0
all the cash flows that
are expected to be received, discounted at an
\u00a0
approximation of the original effective interest rate.
\u00a0
Measurement of ECLs under IFRS 9
shall reflect an unbiased and probability-weighted
\u00a0
amount that is determined by evaluating the range
\u00a0
of possible outcomes as well as
incorporating the time value of money. The entity should consider reasonable and
\u00a0
supportable information about past events, current
conditions and reasonable and supportable forecasts
\u00a0
of future economic conditions when measuring expected
\u00a0
credit losses.
Trade debtors from oil sales invoices in Kurdistan
Normal payment terms apply to amounts owed to
\u00a0
DNO by the KRG for oil sales and override invoices
\u00a0
from the Tawke and the Baeshiqa
license in Kurdistan. Since late 2015, DNO received
\u00a0
the payment due to it from oil sales and overrides
\u00a0
on a monthly basis from the KRG
At yearend 2020, the Group had accumulated
\u00a0
a receivable against the KRG of USD 259
\u00a0
million after certain 2019 and 2020 entitlement
and override payments to the Group and other
\u00a0
Kurdistan oil exporters were withheld early in
\u00a0
2020 by the KRG in connection with the
hardships and uncertainties brought about by
\u00a0
the Covid-19 pandemic. Entitlement payments resumed
\u00a0
in March 2020 and override
payments in early 2021. A payment plan was
\u00a0
put in place by the KRG in December
\u00a0
2020 and subsequently revised in May 2021
\u00a0
to pay
the outstanding arrears. As a part of the May 2021
\u00a0
revision, the KRG also informed the international
\u00a0
oil companies that all invoices,
including towards the arrears, will be settled within 60
\u00a0
days of the end of the respective production
\u00a0
month. During 2022, the outstanding
arrears were reduced from USD 169 million
\u00a0
at the start of the year to USD 2 million
\u00a0
at yearend, not including any interest. The Company
continues to work to collect the remaining balances
\u00a0
and expects to be paid accordingly.
\u00a0
Over the course of 2022, KRG payments to
\u00a0
international oil companies were increasingly delayed.
\u00a0
At the time of issuing this report, the
invoices related to August and September 2022 oil
\u00a0
deliveries were paid in January and March
\u00a0
2023, respectively. The Company is in
dialogue with the KRG, seeking timely payments to
\u00a0
support timely investments. Moreover, in September 2022, the KRG proposed
\u00a0
a
change in the previously agreed pricing formula for
\u00a0
oil such that prices should, with effect from 1 September
\u00a0
2022, be based on the
purported price realized by KRG during the delivery
\u00a0
month. The KRG proposal has not been accepted
\u00a0
by DNO and the Company
continues to invoice the KRG for oil sales based
\u00a0
on the previously agreed pricing formula (including
\u00a0
the September 2022 invoice) until
such time that protocols are put in place to ensure
\u00a0
that realized prices are transparent, based on arms-length
\u00a0
transactions and subject
to third-party audit. The payment for the September oil
\u00a0
delivery received after yearend reflects the formula
\u00a0
proposed and unilaterally
applied by the KRG in September 2022 resulting in an
\u00a0
approximately USD 11/bbl reduction in realized price compared to current pricing
formula based on Dated Brent. The payment received
\u00a0
was USD 5.2 million (net to DNO) lower than
\u00a0
invoiced. The Company is in
continuing dialogue with the KRG to resolve this
\u00a0
matter and collect outstanding balances. The Company
\u00a0
estimates that using the KRG
proposed prices, the impact of the change in pricing
\u00a0
would have resulted in approximately USD
\u00a0
23 million lower revenues compared to
the reported September through December 2022 Kurdistan
\u00a0
revenues.
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 2022
Trade debtors (nominal value) (Note 12)
-
132.7
58.1
55.9
63.1
2.0
311.8
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
As of 31 December 2021
Trade debtors (nominal value) (Note 12)
-
131.6
61.9
-
-
169.1
362.6
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Total trade debtors of USD 311.8 million at yearend 2022 relate mainly to the Tawke license, see Note 12 for details.
\u00a0
Cash deposits
Credit risk from balances with banks and financial
\u00a0
institutions is managed by the Group\u2019s treasury function.
\u00a0
The Group limits its
counterparty credit risk by maintaining its cash deposits
\u00a0
with multiple banks and financial institutions
\u00a0
with high credit ratings.
Capital management
For the purpose of the Group\u2019s capital management, capital
\u00a0
is defined as the total equity and debt of
\u00a0
DNO. The Group manages and
adjusts its capital structure to ensure that it remains
\u00a0
sufficiently funded to support its business strategy and maximize
\u00a0
shareholder value.
If required, the capital structure may be adjusted
\u00a0
through equity or debt transactions, asset restructuring
\u00a0
or through other measures.
The Group monitors capital on the basis of
\u00a0
the 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
15. The equity ratio has improved primarily
\u00a0
due to a net profit in 2022. 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 2022 and
\u00a0
2021.
Years ended 31 December
USD million
2022
2021
Total equity
1,369.4
1,018.8
Total assets
2,803.0
2,947.8
Equity ratio
48.9%
34.6%
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 assets and financial liabilities,
\u00a0
including their levels in the fair
value hierarchy. It does not include the carrying amounts and fair value
\u00a0
information for financial assets and financial liabilities
\u00a0
not
measured or disclosed at fair value if the carrying
\u00a0
amount is a reasonable approximation of
\u00a0
fair value.
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2022 - USD million
Note
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
-
-
-
31 December 2022
-
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
546.4
546.4
31 December 2022
507.3
-
26.6
Interest-bearing liabilities (current)
15
-
8.4
8.4
-
8.4
* Financial assets designated at FVTOCI with no recycling of cumulative gains and losses upon derecognition
\u00a0
(equity instruments).
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2021 - USD million
Note
at FVTOCI
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
16.2
-
16.2
31 December 2021
16.2
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
873.4
873.4
31 December 2021
824.2
-
95.0
Interest-bearing liabilities (current)
15
-
-
-
-
-
-
The Group identifies and reports its segments based
\u00a0
on information provided to the executive management
\u00a0
and the Board of Directors
who are considered to collectively be the Chief
\u00a0
Operating Decision Maker. The segment information is used as the
\u00a0
basis for allocation of
resources and decision making. The Group has
\u00a0
identified its reportable segments based on
\u00a0
the nature of the risks and returns within its
business and by the location of the Group\u2019s assets and
\u00a0
operations. Inter-segment sales are based on
\u00a0
the arm\u2019s length principle and are
eliminated at the consolidated level. Segment profit/-loss
\u00a0
includes profit/-loss from inter-segment sales.
\u00a0
The Group reports the following three operating
\u00a0
segments: Kurdistan, the North Sea (which includes
\u00a0
the Group\u2019s oil and gas activities in
Norway and the UK) and West Africa (which represents
\u00a0
the Group\u2019s equity accounted investment in C\u00f4te d'Ivoire,
\u00a0
see Note 10). The
operating segments correspond to the reportable
\u00a0
segments. Remaining operating segments are
\u00a0
included in the Other category based
on a materiality assessment.
\u00a0
The country-by-country reporting for companies in
\u00a0
extractive industries in line with the Norwegian
\u00a0
Accounting Act can be found in page
87 of this report.
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
10
-
-
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
9
-
-371.3
-
-
-371.3
-
-371.3
Exploration expenses
6
-
-96.5
-
-
-96.5
-
-96.5
Operating profit/-loss
567.6
-120.2
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
-64.4
-85.0
Tax income/-expense
8
-
38.4
-
-
38.4
-
38.4
578.0
-114.5
6.1
-8.6
461.1
-77.1
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
688.0
2,803.0
Non-current liabilities
68.1
391.8
-
-
459.9
528.4
988.4
Current liabilities
97.5
284.3
-
41.6
423.4
21.9
445.3
Total liabilities
165.6
676.1
-
41.6
883.3
550.3
1,433.6
USD million
Total
Un-
Full-Year ending
West
reporting
allocated/
Total
31 December 2021
Note
Kurdistan
North Sea
Africa
Other
segments
eliminated
Group
COMPREHENSIVE INCOME INFORMATION
Revenues
3
594.3
409.8
-
-
1,004.1
-
1,004.1
Inter-segment sales
-
2.6
-
-
2.6
-2.6
-
Production costs
-99.6
-119.5
-
-
-219.1
0.3
-218.8
Movement in overlift/underlift
-
-18.3
-
-
-18.3
-
-18.3
Depreciation, depletion and amortization
-121.2
-81.7
-
-
-202.9
-3.1
-206.0
Cost of goods sold
4
-220.9
-219.4
-
-
-440.3
-2.7
-443.1
Gross profit
373.4
193.0
-
-
566.4
-5.4
561.0
Share of profit/-loss from Joint Venture
10
-
-
-
-
-
-
-
Other income
-
-
-
-
0.5
-
0.5
Administrative expenses
\u00a0
5
-0.3
-8.5
-
-1.8
-10.6
-5.6
-16.2
Other operating expenses
5
-2.2
-
-
-9.8
-12.0
-
-12.0
Impairment of oil and gas assets
9
-
-80.1
-
-
-80.1
-
-80.1
Exploration expenses
6
-2.8
-129.6
-
-
-132.3
-
-132.3
Operating profit/-loss
368.1
-24.8
-
-11.6
331.8
-11.0
320.9
Net financial income/-expense
7
22.7
-35.7
-
1.0
-12.0
-88.8
-100.7
Tax income/-expense
8
-
-15.9
-
-0.3
-16.3
-
-16.3
390.8
-76.4
-
-10.9
303.5
-99.7
203.9
FINANCIAL POSITION INFORMATION
Non-current assets
679.8
964.1
-
-
1,643.9
26.6
1,670.5
Current assets
372.2
367.1
-
11.5
750.8
526.5
1,277.3
Total assets
1,052.0
1,331.2
-
11.5
2,394.7
553.1
2,947.8
Non-current liabilities
63.2
691.2
-
-
754.4
788.8
1,543.2
Current liabilities
78.0
248.5
-
36.3
362.8
23.0
385.8
Total liabilities
141.2
939.8
-
36.3
1,117.2
811.7
1,929.0
1 January - 31 December
USD million
2022
2021
Exploration expenses (G&G and field surveys)
-10.2
-19.1
Seismic costs
-18.5
-37.6
Exploration expenses capitalized in previous years carried to cost
-3.9
-13.4
Exploration expenses capitalized during the year carried to cost
-48.3
-40.7
Other exploration expenses
-15.6
-21.5
Total exploration expenses
-96.5
-132.3
Exploration expenses in 2022 were related to exploration
\u00a0
activities in the North Sea, including expensing
\u00a0
of exploration wells
(Edinburgh, Overly and Uer wells) and seismic purchase.
\u00a0
Exploration expenses in 2021 were related to
\u00a0
exploration activities in the
North Sea, including expensing of exploration wells
\u00a0
(Black Vulture, Gomez and Mugnetind wells) and seismic
\u00a0
purchase.
Note 7
Financial income and financial expenses
1 January - 31 December
USD million
2022
2021
Interest income
12.9
1.7
Other financial income
1.0
24.3
Currency exchange gains recognized in the income statement (net)
-
-
Financial income
13.9
26.0
Interest expenses
-57.5
-74.2
Currency exchange loss recognized in the income statement (net)
-6.6
-5.8
Other financial expenses
-34.8
-46.8
Financial expenses
-98.9
-126.7
Net financial income/-expenses
-85.0
-100.7
Other financial expenses in 2022 were mainly related
\u00a0
to the accretion expenses (i.e., unwinding of discount
\u00a0
related to the ARO
provisions and lease liabilities, see Note 16),
\u00a0
amortization of borrowing issue costs and incurred put
\u00a0
option premium. Other financial
expenses and other financial income in 2021 also
\u00a0
included accounting effects from IFRS 9 assessments
\u00a0
related to the Tawke license
arrears from 2020 and 2021 entitlement and override
\u00a0
invoices (presented gross).
Years ended 31 December
USD million
2022
2021
Non-current
Asset retirement obligations (ARO)
368.2
386.3
Other long-term obligations
4.9
3.6
Total non-current provisions for other liabilities and charges
373.1
389.9
Lease liabilities
6.5
12.5
Total non-current lease liabilities
6.5
12.5
Current
Asset retirement obligations (ARO)
20.5
69.7
Other provisions and charges
39.8
34.8
Total current provisions for other liabilities and charges
60.2
104.4
Current lease liabilities
6.8
15.7
Total current lease liabilities
6.8
15.7
Total provisions for other liabilities and charges and lease liabilities
446.6
522.6
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 2022 were between 4.5 percent
\u00a0
and 4.8 percent (yearend 2021:
between 3.2 percent and 3.7 percent). The credit
\u00a0
margin included in the discount rates at yearend
\u00a0
2022 was 0.8 percent (yearend 2021:
2.3 percent).
Asset
Other
retirement
non-
USD million
obligations
current
Provisions as of 1 January 2021
523.3
3.4
Decommissioning spend
-86.8
-
Increase/-decrease in existing provisions
0.9
0.2
Amounts charged against provisions
-
-
Effects of change in the discount rate
0.9
-
Accretion expenses (unwinding of discount)
17.7
-
Reclassification and transfer
-
-
Provisions as of 31 December 2021
456.0
3.6
Decommissioning spend
-70.5
-
Increase/-decrease in existing provisions
25.0
1.3
Amounts charged against provisions
-
-
Effects of change in the discount rate
-37.0
-
Accretion expenses (unwinding of discount)
15.2
-
Reclassification and transfer
-
-
Provisions as of 31 December 2022
388.7
4.9
Lease liabilities
The recognized lease liabilities in the balance sheet
\u00a0
are mainly related to rig lease and office rent.
In 2021, DNO entered into a rig lease
agreement to perform decommissioning, plugging and abandonment
\u00a0
at the Schooner and Ketch fields in the UK part of
\u00a0
the North Sea.
The rig lease was entered into with DNO as
\u00a0
the operator of the licenses at the initial signing
\u00a0
and subsequently partly allocated to the
license partners (presented under non-current and
\u00a0
current receivables). The rig lease was recognized
\u00a0
on a gross basis, rather than
based on DNO\u2019s working interest share (60 percent).
\u00a0
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. Extension
\u00a0
options are included in the lease liability when,
\u00a0
based on the management\u2019s
judgement, it is reasonably certain that an extension
\u00a0
will be exercised. Lease payments related
\u00a0
to short-term leases and leases of low-
value assets are recognized under lifting costs and
\u00a0
exploration costs, or tangible assets and
\u00a0
capitalized exploration. Total lease
payments related to short-term leases and low-value
\u00a0
assets were USD 56 million (2021: USD 56.6
\u00a0
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
2022
2021
Within one year
7.0
16.6
6.5
13.1
-
-
Total undiscounted lease liabilities end of the period
\u00a0
13.5
29.7
.
Note 17
Trade and other payables
Years ended 31 December
USD million
2022
2021
Trade payables
62.7
85.7
Public duties payable
4.1
6.1
Prepayments from customers
12.7
-
Overlift
9.0
17.3
Other accrued expenses
155.7
123.4
Total trade and other payables
244.1
232.6
Trade payables are non-interest bearing and are normally settled
\u00a0
within 30 days.
Trade payables and other accrued expenses include items of working
\u00a0
capital related to participation in licenses in Kurdistan
\u00a0
and the
North Sea, and prepayment from customers related
\u00a0
to oil sales in the North Sea.
The overlift payable relates to North Sea overlifted
\u00a0
volumes, valued at production cost including depreciation.
The following table provides details of the
\u00a0
Group\u2019s related party transactions in 2022. See also
\u00a0
Note 5 on remuneration.
1 January - 31 December
Related party (USD million)
Transaction
2022
2021
RAK Petroleum plc
Service agreement
-1.1
-0.1
Total related party transactions
-1.1
-0.1
Prior to the completion of the agreement entered
\u00a0
between DNO and RAK Petroleum in October 2022
\u00a0
(see Note 10), RAK Petroleum,
through its subsidiary RAK Petroleum Holdings B.V., was the Company\u2019s largest shareholder
\u00a0
and the Company\u2019s Executive Chairman
Bijan Mossavar-Rahmani also served as Executive Chairman
\u00a0
of RAK Petroleum. The Company had an
\u00a0
agreement with RAK Petroleum
for services including administrative and commercial
\u00a0
support, travel and other expenses. See also Note
\u00a0
3 in the parent company
accounts relating to reimbursement of expenses to
\u00a0
the members of the Board of Directors.
There are additional transactions between Group companies,
\u00a0
see Note 20 in the parent company accounts.
A portion of the overhead expenses in the
\u00a0
Company are charged to the subsidiaries through
\u00a0
the hourly rate for services provided by the
Company.
1 January - 31 December
2022
2021
Net profit/-loss attributable to ordinary equity holders of the parent (USD million)
384.9
203.9
Weighted average number of ordinary shares excluding treasury shares (millions)
986.97
975.43
Earnings per share, basic (USD per share)
0.39
0.21
Earnings per share, diluted (USD per share)
0.39
0.21
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 2022.
Payments from Kurdistan
After yearend 2022, DNO has received a total
\u00a0
of USD 114.1 million from the KRG (net to DNO) representing DNO\u2019s entitlement
\u00a0
share of
the August and September 2022 oil deliveries
\u00a0
to the export market from the Tawke license and the Baeshiqa license. The payment
received for September oil deliveries reflects changed
\u00a0
oil pricing as proposed by the KRG in
\u00a0
September 2022 (see notes 12 and 18)
resulting in USD 5.2 million (net to DNO) lower
\u00a0
payment compared to the invoices issued
\u00a0
by DNO for the respective month.
DNO receives 11 awards in Norway's APA licensing round
On 10 January 2023, the Company announced
\u00a0
that its wholly-owned subsidiary DNO Norge
\u00a0
AS has been awarded participation in 11
exploration licenses, of which one is an operatorship,
\u00a0
under Norway's APA 2022 licensing round. Of the 11 new licenses, nine are in the
North Sea and two in the Norwegian Sea.
Discovery at the R\u00f8ver S\u00f8r prospect
On 9 February 2023, DNO confirmed an oil and
\u00a0
gas discovery on the R\u00f8ver S\u00f8r prospect in
\u00a0
the Norwegian North Sea license PL923 in
which the Company holds a 20 percent interest.
\u00a0
The discovery well and a follow-on appraisal
\u00a0
sidetrack encountered hydrocarbons in
three Jurassic Brent Group sandstone reservoirs (Ness,
\u00a0
Etive and Oseberg formations). Preliminary estimates
\u00a0
of gross recoverable
resources are in the range of 17-47 MMboe. The
\u00a0
partners, which in addition to the Company\u2019s wholly-owned
\u00a0
subsidiary DNO Norge AS,
include Equinor Energy AS (operator), Petoro AS and
\u00a0
Wellesley Petroleum AS, consider the discovery to be
\u00a0
commercial. Together with
a string of recent discoveries in the area, R\u00f8ver
\u00a0
S\u00f8r may be tied back to the Equinor-operated
\u00a0
Troll field about 10 kilometers to the east.
The Company\u2019s Board of Directors approve dividend payment
\u00a0
On 9 February 2023, the Company announced
\u00a0
that pursuant to the authorization granted at
\u00a0
the 2022 AGM, the Board of Directors has
decided to distribute a dividend payment of NOK
\u00a0
0.25 per share. Payment of the dividend was
\u00a0
made on 22 February 2023.
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
DNO Oman Block 30 Limited
Guernsey
100
North Limited
Guernsey
100
DNO Tunisia Limited
Guernsey
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 of 33.33
\u00a0
percent is accounted for
using the equity method. DNO ASA, DNO Technical Services AS and DNO North Sea plc provide
\u00a0
technical support and services to the
various companies in the Group. The other subsidiaries
\u00a0
from the table above had minimal activity during
\u00a0
the year. Northstar Norge AS
(DNO North Sea (Norge) AS) was liquidated during
\u00a0
2022 and DNO Technical Services Limited was renamed to Northstar Limited.
Net reserves by region/field as of 31 December 2022
Proven (1P)
Proven and probable (2P)
Proven, probable and possible (3P)
MMboe
Oil
NGL
Gas
Total
Oil
NGL
Gas
Total
Oil
NGL
Gas
Total
Tawke
126.1
126.1
157.3
157.3
208.0
208.0
Peshkabir
64.8
64.8
88.0
88.0
108.0
108.0
Total Kurdistan
190.9
-
-
190.9
245.3
-
-
245.3
316.0
-
-
316.0
Blane
0.3
-
0.3
0.8
-
0.8
1.2
-
1.2
UK
0.1
0.1
0.1
0.1
0.1
0.1
Total UK
0.4
-
-
0.4
0.9
-
-
0.9
1.3
-
-
1.3
Alve
0.3
0.3
1.6
2.3
0.6
0.9
3.0
4.5
0.8
1.4
4.7
6.9
Andvare
0.1
0.5
2.6
3.2
0.2
0.8
3.7
4.7
0.3
1.2
5.1
6.7
Berling
1.0
0.7
3.5
5.2
1.5
1.1
4.9
7.4
2.1
1.5
6.3
9.9
Brage
0.9
0.1
0.2
1.2
1.3
0.2
0.4
1.9
2.1
0.3
0.7
3.1
Fenja
1.7
0.1
0.6
2.4
2.7
0.1
0.8
3.5
4.0
0.1
1.1
5.1
Marulk
-
0.2
0.6
0.8
-
0.2
0.8
1.0
-
0.2
0.9
1.1
Oda
1.3
-
0.1
1.4
1.5
0.1
0.1
1.7
1.7
0.1
0.1
1.9
Ringhorne East
1.3
1.3
1.8
1.8
2.3
2.3
Tambar
1.4
0.1
0.3
1.7
2.0
0.1
0.4
2.5
2.4
0.1
0.5
3.0
Tambar East
0.2
-
-
0.3
0.7
0.1
0.1
0.9
1.3
0.2
0.2
1.6
Trym
0.2
1.0
1.2
0.3
1.0
1.3
0.4
1.5
1.9
Ula
1.2
0.1
1.3
1.7
0.2
1.9
1.8
0.2
2.0
Vilje
2.3
2.3
2.5
2.5
2.7
2.7
Total Norway
11.9
2.1
10.5
24.6
16.8
3.8
15.2
35.6
21.9
5.3
21.1
48.1
Subtotal Consolidated reserves
215.9
281.8
365.4
C\u00f4te d'Ivoire
0.2
-
4.2
4.4
0.4
-
9.9
10.3
0.7
-
20.6
21.3
Total West Africa
0.2
-
4.2
4.4
0.4
-
9.9
10.3
0.7
-
20.6
21.3
Subtotal Equity accounted reserves
4.4
10.3
21.3
Total Group
220.3
292.1
386.7
Reserves development by segment (net to DNO)
Kurdistan
North Sea
Subtotal
West Africa
Total Group
MMboe
1P
2P
3P
1P
2P
3P
1P
2P
3P
1P
2P
3P
1P
2P
3P
As of 1 January 2021
175.8
295.4
453.7
41.1
64.4
96.0
216.9
359.9
549.6
-
-
-
216.9
359.9
549.6
Production
-29.8
-29.8
-29.8
-4.7
-4.7
-4.7
-34.5
-34.5
-34.5
-
-
-
-34.5
-34.5
-34.5
Acquisitions
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Divestments
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
New developments
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Revision of previous estimates
16.1
1.8
-75.4
-2.4
-5.8
-19.1
13.7
-4.0
-94.4
-
-
-
13.7
-4.0
-94.4
As of 31 December 2021
162.2
267.4
348.5
33.9
54.0
72.1
196.1
321.4
420.6
-
-
-
196.1
321.4
420.6
Production
-29.3
-29.3
-29.3
-4.9
-4.9
-4.9
-34.2
-34.2
-34.2
-1.2
-1.2
-1.2
-35.4
-35.4
-35.4
Acquisitions
-
-
-
-
-
-
-
-
-
5.6
11.5
22.5
5.6
11.5
22.5
Divestments
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
New developments
-
-
-
8.4
12.1
16.5
8.4
12.1
16.5
-
-
-
8.4
12.1
16.5
Revision of previous estimates
58.1
7.2
-3.2
-12.5
-24.8
-34.3
45.6
-17.6
-37.6
-
-
-
45.6
-17.6
-37.6
As of 31 December 2022
190.9
245.3
316.0
25.0
36.5
49.3
215.9
281.8
365.4
4.4
10.3
21.3
220.3
292.1
386.7
Net Entitlement (NE) reserves by segment
Kurdistan
North Sea
Subtotal
West Africa
Total Group
MMboe
1P
2P
3P
1P
2P
3P
1P
2P
3P
1P
2P
3P
1P
2P
3P
As of 31 December 2021
56.5
77.7
88.8
33.9
54.0
72.1
90.4
131.7
160.9
-
-
-
90.4
131.7
160.9
As of 31 December 2022
63.8
74.3
84.7
25.0
36.5
49.4
88.8
110.8
134.1
2.7
6.3
12.0
91.5
117.1
146.1
The reserves and contingent resources are according
\u00a0
to the Annual Statement of Reserves and Resources
\u00a0
(ASRR) dated 15 March
2023. The reported reserves fall within class 1-3 of
\u00a0
the Norwegian Petroleum Directorate (NPD)
\u00a0
classification and 2C resources fall
within classes 4, 5 and 7 of the NPD classification.
International petroleum consultants DeGolyer and
\u00a0
MacNaughton carried out an independent assessment
\u00a0
of the Tawke license
(containing the Tawke and Peshkabir fields) and the Baeshiqa license (containing the Baeshiqa
\u00a0
and Zartik structures) in the Kurdistan
region of Iraq. International petroleum consultants RPS
\u00a0
Energy Consultants carried out an independent
\u00a0
assessment of DNO's licenses
in Norway and the UK. The Company used reserves
\u00a0
and resources numbers reported by the operating
\u00a0
entity of its licenses in C\u00f4te
d\u2019Ivoire. For the producing Block CI-27 in C\u00f4te
\u00a0
d\u2019Ivoire, the numbers were based on an
\u00a0
independent assessment carried out by
international petroleum consultant Gaffney, Cline & Associates at yearend 2016, adjusted
\u00a0
for production and technical revisions to
reflect yearend 2022 values. The Company internally
\u00a0
assessed Yemen Block 47.
The estimation of oil and gas reserves involves uncertainty. The figures above
\u00a0
represent management\u2019s best judgment of the most
\u00a0
likely
quantity of economically recoverable oil and gas estimated
\u00a0
at yearend, given the information at the time
\u00a0
of reporting. The estimates
have a large spread especially for fields for
\u00a0
which there is limited data available. The uncertainty
\u00a0
will be reduced as more information
becomes available through production history and reservoir
\u00a0
appraisal. In addition, for fields in the decline
\u00a0
phase with limited remaining
volumes, fluctuations in oil prices will have a significant
\u00a0
impact on the profitability and hence the economic
\u00a0
cut-off for production.
At yearend 2022, DNO\u2019s net 1P reserves stood at 220.3
\u00a0
MMboe, compared to 196.1 MMboe at yearend
\u00a0
2021, after adjusting for
production during the year, upward technical revisions and addition of assets
\u00a0
in C\u00f4te d\u2019Ivoire. On a 2P reserves basis,
\u00a0
DNO\u2019s net
reserves stood at 292.1 MMboe, compared to 321.4
\u00a0
MMboe at yearend 2021. On a 3P reserves
\u00a0
basis, DNO\u2019s net reserves were 386.7
MMboe, compared to 420.6 MMboe at yearend 2021.
\u00a0
DNO\u2019s net 2C resources were 152.5 MMboe,
\u00a0
compared to 189.5 MMboe at
DNO\u2019s net production in 2022 totaled 35.4 MMboe (of
\u00a0
which 29.3 million barrels of oil (MMbbls)
\u00a0
were from the Tawke license in
Kurdistan, 4.8 MMboe in Norway, 1.2 MMboe in C\u00f4te d\u2019Ivoire and the balance
\u00a0
in the UK), compared to 34.5 MMboe in 2021 (of
\u00a0
which
29.8 MMbbls in Kurdistan, 4.5 MMboe in Norway and
\u00a0
the balance in the UK).
The Company\u2019s net yearend 2022 Reserve Life Index (R/P)
\u00a0
stood at 6.2 years on a 1P reserves basis,
\u00a0
8.3 years on a 2P reserves basis
and 10.9 years on a 3P reserves basis.
Net reserves in DNO\u2019s licenses governed by PSCs
\u00a0
(Kurdistan and C\u00f4te d\u2019Ivoire) are based on the
\u00a0
participation interest. NE reserves
are net to DNO after royalty and include DNO\u2019s additional
\u00a0
share of cost oil covering its advances towards
\u00a0
the government carried
interest (if any). Net reserves reflect pre-tax shares
\u00a0
while Net Entitlement (NE) reserves reflect post-tax
\u00a0
shares. NE reserves are based
on economic evaluation of the license agreements,
\u00a0
incorporating projections of future production,
\u00a0
costs and oil and gas prices. NE
reserves may therefore fluctuate over time, even if there
\u00a0
are no changes in the underlying gross
\u00a0
and net volumes.
Net and NE reserves in DNO\u2019s licenses not governed by
\u00a0
PSCs (Norway and the UK) are equivalent and
\u00a0
reflect pre-tax shares.
Payments from Kurdistan
After yearend 2022, DNO has received a total
\u00a0
of USD 114.1 million from the KRG (net to DNO) representing DNO\u2019s entitlement
\u00a0
share of
the August and September 2022 oil deliveries
\u00a0
to the export market from the Tawke license and the Baeshiqa license. The payment
received for September oil deliveries reflects changed
\u00a0
oil pricing as proposed by the KRG in
\u00a0
September 2022 (see notes 12 and 18)
resulting in USD 5.2 million (net to DNO) lower
\u00a0
payment compared to the invoices issued
\u00a0
by DNO for the respective month.
DNO receives 11 awards in Norway's APA licensing round
On 10 January 2023, the Company announced
\u00a0
that its wholly-owned subsidiary DNO Norge
\u00a0
AS has been awarded participation in 11
exploration licenses, of which one is an operatorship,
\u00a0
under Norway's APA 2022 licensing round. Of the 11 new licenses, nine are in the
North Sea and two in the Norwegian Sea.
Discovery at the R\u00f8ver S\u00f8r prospect
On 9 February 2023, DNO confirmed an oil and
\u00a0
gas discovery on the R\u00f8ver S\u00f8r prospect in
\u00a0
the Norwegian North Sea license PL923 in
which the Company holds a 20 percent interest.
\u00a0
The discovery well and a follow-on appraisal
\u00a0
sidetrack encountered hydrocarbons in
three Jurassic Brent Group sandstone reservoirs (Ness,
\u00a0
Etive and Oseberg formations). Preliminary estimates
\u00a0
of gross recoverable
resources are in the range of 17-47 MMboe. The
\u00a0
partners, which in addition to the Company\u2019s wholly-owned
\u00a0
subsidiary DNO Norge AS,
include Equinor Energy AS (operator), Petoro AS and
\u00a0
Wellesley Petroleum AS, consider the discovery to be
\u00a0
commercial. Together with
a string of recent discoveries in the area, R\u00f8ver
\u00a0
S\u00f8r may be tied back to the Equinor-operated
\u00a0
Troll field about 10 kilometers to the east.
The Company\u2019s Board of Directors approve dividend payment
\u00a0
On 9 February 2023, the Company announced
\u00a0
that pursuant to the authorization granted at
\u00a0
the 2022 AGM, the Board of Directors has
decided to distribute a dividend payment of NOK
\u00a0
0.25 per share. Payment of the dividend was
\u00a0
made on 22 February 2023.