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Alexander Krane
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Corporate information
Harbour Energy plc (Harbour or the company) is a limited liability company incorporated in Scotland and listed on the London Stock
Exchange. The\u00a0address of the registered of\ufb01ce is 4
th
Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN, United Kingdom.
The consolidated \ufb01nancial statements of the company and all its subsidiaries (the Group) for the year ended 31 December 2023
were authorised for issue by the board of directors on 6 March 2024.
The Group\u2019s principal activities are the acquisition, exploration, development and production of oil and gas reserves on the UK and
Norwegian continental shelves, Indonesia, Vietnam and Mexico.", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18030": { "value": "Harbour Energy plc", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18031": { "value": "limited liability company incorporated in Scotland and listed on the London Stock Exchange", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18034": { "value": "4
th
Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN, United Kingdom.", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18039": { "value": "United Kingdom", "dimensions": { "concept": "ifrs-full:PrincipalPlaceOfBusiness", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18040": { "value": "United Kingdom", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18041": { "value": "United Kingdom", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18043": { "value": "2023-12-31", "dimensions": { "concept": "ifrs-full:DateOfEndOfReportingPeriod2013", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18046": { "value": "The Group\u2019s principal activities are the acquisition, exploration, development and production of oil and gas reserves on the UK and Norwegian continental shelves, Indonesia, Vietnam and Mexico.", "dimensions": { "concept": "ifrs-full:DescriptionOfNatureOfEntitysOperationsAndPrincipalActivities", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18051": { "value": "2. Material accounting policies
Basis of preparation
The consolidated \ufb01nancial statements have been prepared on a going concern basis in accordance with UK-adopted International
Accounting Standards (IAS) in conformity with the requirements of the Companies Act 2006. The analysis used by the Directors in
adopting the going concern basis considers the various plans and commitments of the Group as well as various sensitivity and reverse
stress test analyses. The results from the downside sensitivities and reverse stress testing with regard to production and commodity
price assumptions, which in management\u2019s view re\ufb02ect two of the principal risks, indicate that material changes within one year that
would impact the going concern basis of preparation are unlikely. Further details are within the \ufb01nancial review on page 26 and viability
statement on page 59.
The presentation currency of the Group \ufb01nancial information is US dollars and all values in the Group \ufb01nancial information are presented
in millions ($ million) and all values are rounded to the nearest 1 million, except where otherwise stated.
The \ufb01nancial statements have been prepared on the historical cost basis, except for certain \ufb01nancial assets and liabilities, including
derivative \ufb01nancial instruments, which have been measured at fair value.
The accounting policies which follow set out those policies which apply in preparing the \ufb01nancial statements for the year ended
31 December 2023. All accounting policies are consistent with those adopted and disclosed in Harbour\u2019s 2022 Annual Report &
Accounts, except for the inclusion of a new policy for the cost of carbon allowances.
Basis of consolidation
The consolidated \ufb01nancial statements comprise the \ufb01nancial statements of the company and its subsidiaries as at 31 December 2023.
Subsidiaries are those entities over which the Group has control. Control is achieved where the Group has the power over the subsidiary,
has rights, or is exposed to variable returns from the subsidiary and has the ability to use its power to affect its returns. All subsidiaries
are 100 per cent owned by the Group and there are no non-controlling interests.
If the Group loses control over a subsidiary, it derecognises the related assets (including goodwill), liabilities, non-controlling interest
and\u00a0other components of equity, while any resultant gain or loss is recognised in pro\ufb01t or loss. Any investment retained is recognised
at\u00a0fair value.
The results of subsidiaries acquired or disposed of during the year are included in the income statement from the effective date of
acquisition or up to the effective date of disposal, as appropriate. Where necessary, adjustments are made to the \ufb01nancial statements
of\u00a0subsidiaries acquired to bring the accounting policies used into line with those used by other members of the Group.
All intra-group transactions and balances have been eliminated on consolidation.
Use of judgements and estimates
In preparing these \ufb01nancial statements, management has made judgements and estimates that affect the application of accounting policies
and the reported amounts of assets and liabilities, income and expenses including those that have the potential impact to materially impact
the balance sheet over the next 12 months. Actual results may differ from these estimates. The signi\ufb01cant judgements made by
management in applying the Group\u2019s accounting policies, and the key sources of estimation uncertainty, were the same as those described
in Harbour\u2019s 2022 Annual Report & Accounts, with the addition of judgements in relation to the tax risk associated with the uncertain tax
position on commodity derivatives. Disclosure regarding the judgements and estimates made in assessing the impact of climate change
and the energy transition are detailed on pages 124 to 127 and references to notes to the \ufb01nancial statements are provided.
Impact of climate change on the \ufb01nancial statements and related disclosures
Judgements and estimates made in assessing the impact of climate change and the energy transition
Harbour monitors global climate change and energy transition developments and plans. Management recognises there is a general high level
of uncertainty about the speed and scale of impacts which, together with limited historical information, provides challenges in the preparation
of forecasts and plans with a range of possible future scenarios, which may have the potential to materially impact the balance sheet.
The Group\u2019s continued strategic ambition is to achieve net zero by 2035 with an interim target of a 50 per cent reduction in Scope 1 and
2 emissions by 2030 against the 2018 baseline. This will be achieved through several opportunities, including operational ef\ufb01ciency
improvements, UK offshore electri\ufb01cation and the eventual cessation of production of mature \ufb01elds. In addition, opportunities for offshore
electri\ufb01cation are being explored and the company is investing in the development of carbon capture and storage projects in the UK.
Where the Group cannot reduce its Scope 1 and 2 emissions, it will invest in high quality, independently veri\ufb01ed, carbon offsets to
achieve the goal of net zero.
All new economic investment decisions include the cost of carbon, and opportunities are assessed on their climate-impact potential and
alignment with Harbour Energy\u2019s net zero goal, taking into consideration both GHG volumes and intensity. The corporate modelling that
supports the preparation of the \ufb01nancial statements (such as asset and goodwill impairment assessment, going concern and viability,
deferred tax asset recoverability) includes project costs related to CCS, certain limited electri\ufb01cation and other activities to reduce Scope
1 and 2 GHG emissions, the UK Emissions Trading Scheme and carbon offset purchases.
Emissions reduction incentives are part of staff remuneration through the annual bonus programme. Additionally, the cost of borrowing is
tied to our gross operated CO
2
emissions performance, with GHG metrics being linked to our RBL interest expense, further incentivising
our emissions reduction targets.
Climate change and the energy transition have the potential to signi\ufb01cantly impact the accounting estimates adopted by management
and therefore the valuation of assets and liabilities reported on the balance sheet. On an ongoing basis management continues to
assess the potential impacts on the signi\ufb01cant judgements and estimates used in the preparation of the \ufb01nancial statements. Estimates
adopted in the \ufb01nancial statements re\ufb02ect management\u2019s best estimate of future market conditions where, in particular, commodity prices
can be volatile. Commodity and carbon price curve assumptions are described below noting that there is consideration given to other
assumptions, not exhaustively, such as foreign exchange and discount rates. Notwithstanding the challenges around climate change and
the energy transition, it is management\u2019s view that the \ufb01nancial statements are consistent with the disclosures in the Strategic report.
This note provides insight into how Harbour has considered the impact on valuations of key line items in the \ufb01nancial statements and how
they could change based on the climate change scenarios and sensitivities considered. The scenarios presented show what the possible
impact could be on the \ufb01nancial statements considering both high and low commodity price outlooks. Importantly, these climate change
scenarios do not form the basis of the preparation of the \ufb01nancial statements but rather indicate how the key assumptions that underpin the
\ufb01nancial statements would be impacted by the climate change scenarios. They are also designed to challenge management\u2019s perspective
on the future business environment. It is recognised that the reality of the nature of progress of energy transition will bring greater levels
of disruption and volatility than these external scenarios expect and do not represent management\u2019s current best estimate.
Management\u2019s current best estimate for the foreseeable future, which was derived from consideration of a range of considered economic
forecasts, has been used on the same basis to prepare the \ufb01nancial statements and is represented by the Harbour scenario oil price
curve. Management continues to review these estimates and assumptions to ensure they re\ufb02ect the latest economic environment
conditions and market information available.
Impairment of property, plant and equipment, and goodwill
The energy transition has the potential to signi\ufb01cantly impact future commodity and carbon prices which would, in turn, affect the future
operating and capital costs, estimates of cessation of production, useful lives, and consequently the recoverable amount of property,
plant and equipment and goodwill. In the current period, when testing for impairment, the Harbour scenario real long-term commodity
price assumptions from 2026 for Brent crude were $70/bbl (2022: $65/bbl) and UK NBP gas 90 pence/therm (2022: 65 pence/therm)
combined with the short-term forecast period re\ufb02ecting market forward curves at the year end.
Carbon costs will develop over time and carry considerable uncertainty due to the rate of transition and maturity of regulatory regimes.
For the UK price of carbon, Harbour management\u2019s real forward price curve assumption in 2024 is \u00a350/tonne ($63/tonne) rising to
\u00a3140/tonne ($175/tonne) in 2030. The sensitivity was run on the IEA Net Zero carbon price curve. The foreign exchange rate was
assumed to be $1.00:\u00a31.25 \ufb02at for future periods to convert to nominal prices. Such assumptions are inherently uncertain and may
ultimately differ from the actual amounts.
During 2023 there was a total net pre-tax impairment charge of $239 million (2022: $170 million net reversal) across goodwill of
$25 million and property, plant and equipment of $214 million. Further details can be found in note 10 and note 12 respectively.
Further, sensitivities on the impairment of property, plant and equipment and goodwill have been prepared using various commodity price
scenarios to show the possible impact on net book carrying values. As noted, the Harbour scenario is the basis for the preparation of the
\ufb01nancial statements. Impairment sensitivities have been prepared at an average -10 per cent and +10 per cent to the Harbour scenario
average for crude, gas and carbon and selected published climate change price curves.
The sensitivity scenarios described below incorporate changes to the commodity price assumptions and assume that all other factors
remain unchanged from the Harbour scenario used for the basis of preparation of the \ufb01nancial statements. These sensitivities are stated
before any management mitigation actions to manage downside risks if the scenarios were to occur.
The ESG review on pages 39 to 44 discusses both transition and physical risk climate change scenarios. This analysis covers the transition
risks and the graphs below show the crude oil and UK NBP gas price curves for the period to 2050 for the following scenarios: IEA Net Zero
2050, IEA Stated Policies and IEA Announced Pledges.
All the scenario price curves are dependent on factors covering supply, demand, economic and geopolitical events and therefore are
inherently uncertain and subject to signi\ufb01cant volatility and hence unlikely to re\ufb02ect the future outcome.
\u2022
Harbour scenario: base price curves used for impairment testing
\u2022
IEA Net Zero Emissions by 2050 (NZE): limiting global temperature rise to 1.5
o
C
\u2022
IEA Stated Policies (STEPS): current policy commitments by sector and country
\u2022
IEA Announced Pledges (APS): current climate commitments by governments and industries
0
20
40
60
80
100
H2 2030
H1 2030
H2 2029
H1 2029
H2 2028
H1 2028
H2 2027
H1 2027
H2 2026
H1 2026
H2 2025
H1 2025
H2 2024
H1 2024
$/bbl
Crude
$/bbl
Crude
Harbour scenario
NZE
STEPS
APS
0.0
0.2
0.4
0.6
0.8
1.0
1.2
H2 2030
H1 2030
H2 2029
H1 2029
H2 2028
H1 2028
H2 2027
H1 2027
H2 2026
H1 2026
H2 2025
H1 2025
H2 2024
H1 2024
\u00a3/therm
Gas
Harbour scenario
NZE
STEPS
APS
0
30
60
90
120
150
H2 2030
H1 2030
H2 2029
H1 2029
H2 2028
H1 2028
H2 2027
H1 2027
H2 2026
H1 2026
H2 2025
H1 2025
H2 2024
H1 2024
\u00a3/tonne
Carbon
Harbour scenario
NZE
The crude price curves re\ufb02ect the published IEA price curves for all periods. For UK NBP gas there are no IEA published price curves
therefore management has derived the UK NBP gas price curves by converting from the published IEA European gas price curve.
This was achieved by converting from USD per mbtu to pence per therm and applying other known correlation coef\ufb01cients between the
European and UK gas markets. In addition, for the period 2024-2027, the derived gas price curve matches the Harbour scenario
price curve to create a scenario that was considered reasonably plausible.
Pre-development assets such as Zama in Mexico and Andaman in Indonesia are recorded in other intangible assets ahead of demonstration
of commerciality and recognition of 2P reserves and hence are not included below, however they are subject to the same management rigour
with the corporate models.
The results of the sensitivities are as follows and show the impact on the property, plant and equipment balance sheet carrying values
when it had resulted in a material decrease in carrying value.
Pre-tax sensitivity in carrying value
$ million
IEA Net Zero
IEA
IEA
+10% price
-10% price
Emissions
Stated
Announced
Carrying value
to Harbour
to Harbour
by 2050
Policies
Pledges
Commodity
$ million
scenario
scenario
(NZE)
(STEPS)
(APS)
Property, plant
Crude oil
\u2013
(86)
(221)
\u2013
\u2013
and equipment
UK NBP gas (derived)
4,717
\u2013
(21)
(9)
\u2013
\u2013
(note 12)
Carbon
\u2013
\u2013
(27)
N/A
N/A
The +/-10 per cent price curves used in the Harbour scenarios adjust long-term prices from 2027.
Under the -10 per cent price to Harbour scenario for crude there is a pre-tax impairment to property, plant and equipment on two UK
\ufb01elds of\u00a0$86 million (post-tax $40 million) and for UK NBP gas a pre-tax impairment on a single UK \ufb01eld of $21 million (post-tax
$6 million).
For crude, under the IEA NZE 2050 scenario, there is a pre-tax impairment to property, plant and equipment on a single UK \ufb01eld
of\u00a0$221 million (post-tax $104 million) and for UK NBP gas, there is a pre-tax impairment on two UK \ufb01elds of $9 million (post-tax\u00a0$3 million).
There is no impairment to property, plant and equipment across the three +10 per cent price to Harbour scenarios nor the IEA STEPS
and APS\u00a0scenarios.
Under the IEA Net Zero Emissions by 2050 scenario for carbon, there is a pre-tax impairment to property, plant and equipment
on a single UK \ufb01eld of $27 million (post-tax $13 million).
For goodwill, there are no impairments under any scenario except for the -10 per cent price to Harbour scenario for UK NBP gas which
re\ufb02ects an impairment of $4 million.
Property, plant and equipment \u2013 depreciation and expected useful lives
A signi\ufb01cant proportion of property, plant and equipment assets are expected to reach cessation of production over the next
10 to 20 years. There are no signi\ufb01cant judgements and/or critical estimation uncertainty related to climate factors.
See Accounting policy: Property, plant and equipment \u2013 oil and gas assets for further information (page 129).
Intangible assets \u2013 exploration and evaluation assets
The energy transition has the potential to affect the future development or viability of exploration and evaluation prospects. A signi\ufb01cant
portion of the Group\u2019s exploration and evaluation assets relate to prospects that could be tied back to existing infrastructure and hence
require less capital investment as these assets are less exposed to the impacts of the energy transition compared to large frontier
developments. At each balance sheet date, all exploration and evaluation prospects are reviewed against the Group\u2019s \ufb01nancial framework
to ensure that the continuation of activities is planned and expected. There are no signi\ufb01cant judgements and/or critical estimation
uncertainty related to climate factors.
See Judgements: Exploration and evaluation expenditure (page 137) and note 11 to the \ufb01nancial statements for further information.
c
Decommissioning cost and provisions
The energy transition may accelerate the decommissioning of assets which would result in an increase in the carrying value of associated
decommissioning provisions. Whilst the Group currently expects to incur decommissioning costs over the next 40 years, we anticipate the
majority of costs will be incurred between the next 10 to 20 years which will reduce the exposure to the impact of the energy transition.
Decommissioning cost estimates are based on the current regulatory and external environment. These cost estimates and recoverability
of associated deferred tax may change in the future, including as a result of the energy transition.
On the basis that all other assumptions in the calculation remain the same, a 10 per cent increase in the cost estimates, and a
10 per cent reduction in the applied discount rates used to assess the \ufb01nal decommissioning obligation, would result in increases to the
decommissioning provision of approximately $456 million and $440 million, respectively. This change would be principally offset by a
change to the value of the associated asset unless the asset is fully depreciated, in which case the change in estimate is recognised
directly within the income statement.
Currently, the timing of decommissioning expenditures has not been materially brought forward and management do not consider that
any reasonable change in the timing of decommissioning expenditure will have a material impact on the decommissioning provisions.
See Key sources of estimation uncertainty: Decommissioning costs for further information (page 137).
Cost of carbon allowances
Harbour is part of the UK Emissions Trading Scheme (UK ETS) and purchases carbon allowances under the scheme to meet its regulatory
obligations under the scheme. The costs for purchasing allowances are recorded in costs of operations matching emissions for the
period. Accruals that are required for allowances to be purchased are measured at market price. Allowances owned in excess of liabilities
to date that are available to be used in future periods are recorded in other intangible assets and measured at cost. Harbour is entitled
to receive a share of free allowances according to UK ETS regulations.
Segment reporting
The Group\u2019s activities consist of one class of business being the acquisition, exploration, development and production of oil and gas
reserves and related activities and are split geographically and managed in two Business Units: namely \u2018North Sea\u2019 and \u2018International\u2019.
Joint arrangements
A joint arrangement is one in which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an
arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
Exploration and production operations are usually conducted through joint arrangements with other parties. The Group reviews all joint
arrangements and classi\ufb01es them as either joint operations or joint ventures depending on the rights and obligations of each party to the
arrangement and whether the arrangement is structured through a separate vehicle. The Group\u2019s interest in joint operations, such as
exploration and production arrangements, are accounted for by recognising its:
\u2022
Assets, including its share of any assets held jointly
\u2022
Liabilities, including its share of any liabilities incurred jointly
\u2022
Revenue from the sale of its share of the output arising from the joint operation
\u2022
Expenses, including its share of any expenses incurred jointly
A joint venture, which normally involves the establishment of a separate legal entity, is a contractual arrangement whereby the parties
that have joint control of the arrangement have the rights to the arrangement\u2019s net assets. The results, assets and liabilities of a joint
venture are incorporated in the consolidated \ufb01nancial statements using the equity method of accounting. During 2023, the Group did
not have any interests in joint ventures.
Where the Group transacts with its joint operations, unrealised pro\ufb01ts and losses are eliminated to the extent of the Group\u2019s interest in
the joint operation.
Foreign currency translation
Each entity in the Group determines its own functional currency, being the currency of the primary economic environment in which the
entity operates, and items included in the \ufb01nancial statements of each entity are measured using that functional currency.
The consolidated \ufb01nancial statements are presented in US dollars, which is also the parent company\u2019s functional currency.
Transactions recorded in foreign currencies are initially recorded in the entity\u2019s functional currency by applying an average rate of
exchange. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency rate of exchange
ruling at the reporting date. All differences are taken to the income statement.
Non-monetary assets and liabilities denominated in foreign currencies are measured at historic cost based on exchange rates at the date
of the initial transaction and subsequently not retranslated.
On consolidation, the assets and liabilities of the Group\u2019s operations are translated at exchange rates prevailing on the balance sheet
date. Income and expense items are translated at the average monthly exchange rates for the year. Equity is held at historic cost and is
not retranslated. The resulting exchange differences are recognised as other comprehensive income and are transferred to the Group\u2019s
currency translation reserve.
When an overseas operation is disposed of, such translation differences relating to it are recognised as income or expense.
Goodwill
In the event of a business combination or acquisition of an interest in a joint operation in which the activity constitutes a business, as de\ufb01ned in
IFRS 3 Business Combinations, the acquisition method of accounting is applied. Goodwill represents the difference between the aggregate
of the fair value of purchase consideration transferred at the acquisition date and the fair value of the identi\ufb01able assets, liabilities and
contingent liabilities acquired. If however, the fair value of the purchase consideration transferred is lower than the fair value of the identi\ufb01able
assets and liabilities acquired, the difference is recognised in the income statement as negative goodwill. Goodwill is initially measured at cost.
Following initial recognition, goodwill is measured at cost less any accumulated impairment. For the purpose of impairment testing, goodwill
acquired in a business combination is, from the acquisition date, allocated to each of the Group\u2019s cash-generating units (CGUs), or groups of
CGUs, which are expected to bene\ufb01t from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned
to those units. Goodwill is treated as an asset of the relevant entity to which it relates and accordingly non-US dollar goodwill is translated
into US dollars at the closing rate of exchange at each reporting date.
Goodwill, as disclosed in note 10, is not amortised but is reviewed for impairment at least annually by assessing the recoverable amount
of the CGUs to which the goodwill relates. Where the carrying amount of the CGU and related goodwill is higher than the recoverable
amount of the CGU, an impairment loss is recognised in the income statement. The recoverable amounts of the CGUs have been
determined on a fair value less costs to sell basis. Impairment losses relating to goodwill cannot be reversed in future periods. Goodwill
acquired through business combinations has been allocated to two CGUs, being North Sea and International.
Intangible oil and gas assets
Pre-licence costs
Pre-licence costs are expensed in the period in which they are incurred.
Licence and property acquisition costs
Licence and property acquisition costs paid in connection with a right to explore in an existing exploration area are capitalised as
exploration and evaluation costs within intangible assets.
Licence and property acquisition costs are reviewed at each reporting date to con\ufb01rm that there is no indication that the carrying amount
exceeds the recoverable amount. If no future activity is planned or the related licence has been relinquished or has expired, the carrying
value of the property acquisition costs is written off through the income statement. Upon recognition of proved reserves and internal
approval for development, the relevant expenditure is transferred to oil and gas properties within development and production assets.
Exploration and evaluation costs
Once the legal right to explore has been acquired, costs directly associated with the exploration are capitalised as exploration and
evaluation (E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential
commercial resources are discovered, the exploration asset is written off.
All such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment
at least annually. This is to con\ufb01rm the continued intent to develop or otherwise extract value from the discovery. When this is no longer
the case, the costs are written off through the income statement.
When proved reserves of oil or natural gas are identi\ufb01ed and development is sanctioned by management, the relevant capitalised
expenditure is \ufb01rst assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is
transferred to oil and gas properties within development and production assets. No amortisation is charged during the exploration
and evaluation phase.
Farm-outs \u2013 in the exploration and evaluation phase
The Group does not record any expenditure made by the farmee on its account. It also does not recognise any gain or loss on its
exploration and evaluation farm-out arrangements but re-designates any costs previously capitalised in relation to the whole interest
as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously
capitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.
Property, plant and equipment \u2013 oil and gas assets
Oil and gas development and production assets are accumulated generally on a \ufb01eld-by-\ufb01eld basis. This represents expenditure on the
construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells,
including E&E expenditures incurred in \ufb01nding commercial reserves transferred from intangible E&E assets, as outlined in the intangible
asset policy above, which is capitalised as oil and gas properties within development and production assets.
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into
operation, the initial estimate of the decommissioning obligation and, for qualifying assets, where relevant, borrowing costs. The purchase
price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
An item of development and production expenditure and any signi\ufb01cant part initially recognised is derecognised upon disposal or when
no future economic bene\ufb01ts are expected. Any gain or loss arising on derecognition of the asset (calculated as the difference between
the net disposal proceeds and the carrying amount of the asset) is included in the income statement.
Expenditure on major maintenance includes re\ufb01ts, inspections or repairs comprising the cost of replacement assets or parts of assets,
inspection costs and overhaul costs. Where an asset, or part of an asset, that was separately depreciated and is now written off is
replaced and it is probable that future economic bene\ufb01ts associated with the item will \ufb02ow to the Group, the expenditure is capitalised.
All other day-to-day repairs and maintenance costs are expensed as incurred.
Depreciation, depletion and amortisation (DD&A) of oil and gas assets
All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is provided
generally on a \ufb01eld-by-\ufb01eld basis, using the unit of production method by reference to the ratio of production in the year and the related
commercial proven and probable reserves of the \ufb01eld, considering future development expenditures necessary to bring those reserves
into production.
When there is a change in the estimated total recoverable proven and probable reserves of a \ufb01eld, that change is accounted for in the
depreciation charge over the revised remaining proven and probable reserves.
Acquisitions, asset purchases and disposals
Acquisitions of oil and gas properties are accounted for using the acquisition method when the assets acquired and liabilities assumed
constitute a business.
Transactions involving the purchase of an individual \ufb01eld interest, or a group of \ufb01eld interests, which do not constitute a business, are
treated as asset purchases irrespective of whether the speci\ufb01c transactions involve the transfer of the \ufb01eld interests directly or the
transfer of an incorporated entity. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to
the assets and liabilities purchased on an appropriate basis.
Proceeds on disposal are applied to the carrying amount of the speci\ufb01c intangible asset or oil and gas property disposed of and any
surplus is recorded as a gain on disposal in the income statement.
Decommissioning
A provision for decommissioning is recognised in full when the related facilities are installed. The amount recognised is the present value
of the estimated future expenditure. A corresponding amount equivalent to the provision is also recognised as part of the cost of the
related oil and gas property. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the
present value of the estimated expenditure is dealt with from the start of the \ufb01nancial year as an adjustment to the opening provision
and the oil and gas property. The unwinding of the discount is included as a \ufb01nance cost.
Non-oil and gas assets
Property, plant and equipment \u2013 \ufb01xtures and \ufb01ttings and o\ufb03ce equipment
Fixtures and \ufb01ttings and of\ufb01ce equipment is stated at cost less accumulated depreciation and impairment. Depreciation is provided for
on a straight-line basis at rates suf\ufb01cient to write off the cost of the assets less any residual value over their estimated useful economic
lives. The depreciation periods for the principal categories of assets are as follows:
\u2022
Fixtures and \ufb01ttings: Up to 10 years
\u2022
Of\ufb01ce furniture and equipment: Up to 5 years
Intangible assets
Intangible assets principally comprise IT software/licences and carbon allowances. IT software/licences are carried at cost less any
accumulated amortisation. These assets are amortised on a straight-line basis over their useful economic lives of between three and
ten years. Carbon allowances are carried at cost and subject to impairment testing.
Impairment of non-current assets (excluding goodwill)
In accordance with IAS 36 Impairment of Assets, impairment tests are carried out on items of property, plant and equipment and
intangible assets where there is an indicator of impairment, or an indicator identi\ufb01ed that a prior year impairment may have reversed
or decreased. Such indications may be based on events or changes in the market environment, or on internal sources of information.
Impairment and reversal indicators
Property, plant and equipment and intangible assets with \ufb01nite useful lives are only tested for impairment when there is an indication
that they may be impaired. This is generally the result of signi\ufb01cant changes to the environment in which the assets are operated or when
asset performance is signi\ufb01cantly lower than expected.
The main impairment indicators used by the Group are described below:
\u2022
External sources of information:
\u2013
Signi\ufb01cant changes in the economic, technological, political or market environment in which the entity operates or to which
an asset is dedicated
\u2013
Fall in demand
\u2013
Changes in commodity prices and exchange rates
\u2022
Internal sources of information:
\u2013
Evidence of obsolescence or physical damage
\u2013
Signi\ufb01cantly lower than expected production or cost performance
\u2013
Reduction in reserves and resources, including as a result of unsuccessful results of drilling operations
\u2013
Pending expiry of licence or other rights
\u2013
In respect of capitalised exploration and evaluation costs, lack of planned future activity on the prospect or licence
\u2013
For reversals, plausible downside sensitivity scenarios are run to test the robustness of the asset carrying values
typically against changes in production and commodity prices
Measurement of recoverable amount
The cash-generating unit (CGU) applied for impairment test purposes is generally the \ufb01eld, except that a number of \ufb01eld interests may
be grouped as a single CGU where the cash in\ufb02ows of each \ufb01eld are interdependent. The carrying value of each CGU is compared
against the expected recoverable amount of the asset, which is primarily determined based on the fair value less cost of disposal
(FVLCD) method, where the fair value is determined from the estimated present value of the future net cash \ufb02ows expected to be derived
from production of commercial reserves. Standard valuation techniques are used based on the discount rates that re\ufb02ect the speci\ufb01c
characteristics of the operating entities concerned; discount rates are determined on a post-tax basis and applied to post-tax cash \ufb02ows.
Any impairment loss is recorded in the income statement under \u2018Impairment of property, plant and equipment\u2019. Impairment losses recorded
in relation to property, plant and equipment may be subsequently reversed if the recoverable amount of the assets subsequently increases
above carrying value. The increased carrying amount of an item of property, plant or equipment attributable to a reversal of an impairment
loss may not exceed the carrying amount that would have been determined (net of depreciation/amortisation) had no impairment loss been
recognised in prior periods.
Non-current assets held for sale and discontinued operations
The Group classi\ufb01es non-current assets and disposal groups as assets held for sale if their carrying amounts will be recovered principally
through a sale transaction rather than through continuing use. Non-current assets and disposal groups classi\ufb01ed as held for sale are
measured at the lower of their carrying amount and fair value less costs to sell. Costs to sell are the incremental costs directly attributable
to the disposal group, excluding \ufb01nance costs and income tax expense. The criteria for held for sale classi\ufb01cation is regarded as met only
when the sale is highly probable, and the asset or disposal group is available for immediate sale in its present condition. Management must
be committed to the plan to sell the asset and the sale expected to be completed within one year from the date of the classi\ufb01cation. Actions
required to complete the sale should indicate that it is unlikely that signi\ufb01cant changes to the sale will be made or that the decision to sell
will be withdrawn. Property, plant and equipment and intangible assets are not depreciated or amortised once classi\ufb01ed as assets held for
sale. Assets and liabilities classi\ufb01ed as held for sale are presented separately as current line items in the balance sheet.
Financial assets
Financial assets are recognised and measured in accordance with IFRS 9 Financial Instruments.
The Group uses two criteria to determine the classi\ufb01cation of \ufb01nancial assets: the Group\u2019s business model and contractual cash \ufb02ow
characteristics of the \ufb01nancial assets. Where appropriate the Group identi\ufb01es three categories of \ufb01nancial assets: amortised cost, fair
value through pro\ufb01t or loss (FVTPL), and fair value through other comprehensive income (FVOCI).
Financial assets held at amortised cost
Financial assets held at amortised cost are initially measured at fair value except for trade debtors which are initially measured at cost.
Both are subsequently carried at amortised cost using the effective interest rate (EIR) method, less impairment. The EIR amortisation
is presented within \ufb01nance income in the income statement.
Cash and cash equivalents
Cash and cash equivalents comprise cash at bank and other short-term highly liquid investments that are readily convertible to a known
amount of cash and are subject to an insigni\ufb01cant risk of changes in value.
Impairment of \ufb01nancial assets
The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through pro\ufb01t or loss.
ECLs are based on the difference between the contractual cash \ufb02ows due in accordance with the contract and all the cash \ufb02ows that the
Group expects to receive, discounted at an approximation of the original effective interest rate.
ECLs are recognised in two stages:
\u2022
12-month ECL: for credit exposures for which there has not been a signi\ufb01cant increase in credit risk since initial recognition, ECLs are
provided for credit losses that result from default events (payment, prospective or covenant) that are possible within the next 12 months
\u2022
Lifetime ECL: for those credit exposures for which there has been a signi\ufb01cant increase in credit risk since initial recognition, a loss
allowance is required for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default
For trade receivables and contract assets, the Group applies a simpli\ufb01ed approach in calculating ECLs as allowed under IFRS 9.
Provision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as
adjusted for forward-looking factors speci\ufb01c to the debtors, the economic environment and the Group\u2019s historical credit loss experience.
Credit impaired \ufb01nancial assets
At each reporting date, the Group assesses whether \ufb01nancial assets carried at amortised cost and debt \ufb01nancial assets carried at FVOCI
are credit impaired. A \ufb01nancial asset is \u2018credit impaired\u2019 when one or more events that have a detrimental impact on the estimated future
cash \ufb02ows of the \ufb01nancial asset have occurred.
Evidence that a \ufb01nancial asset is credit impaired includes the following observable data:
\u2022
Signi\ufb01cant \ufb01nancial dif\ufb01culty of the borrower or issuer
\u2022
A breach of contract such as default or past due event
\u2022
The restructuring of a loan or advance by the Group on terms that the Group would otherwise not consider
\u2022
It is becoming probable that the borrower will enter bankruptcy or other \ufb01nancial reorganisation
\u2022
The disappearance of an active market for a security because of \ufb01nancial dif\ufb01culties
Financial liabilities
Financial liabilities are recognised and measured in accordance with IFRS 9 Financial Instruments.
Financial liabilities are classi\ufb01ed, at initial recognition, as \ufb01nancial liabilities at fair value through pro\ufb01t or loss, loans and borrowings,
payables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. All \ufb01nancial liabilities are recognised
initially at fair value and, in the case of loans, borrowings and payables, net of directly attributable transaction costs which are capitalised
and amortised over the term of the borrowings. Where borrowings have been fully repaid but the borrowing facility remains, directly
attributable transaction costs that remain unamortised are presented within current and/or non-current assets.
Borrowings and loans
Interest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including
premiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement
using the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the
year in which they arise.
Derecognition
A \ufb01nancial liability is derecognised when the obligation under the liability is discharged, cancelled, or expires. When an existing \ufb01nancial
liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially
modi\ufb01ed, such an exchange or modi\ufb01cation is treated as the derecognition of the original liability and the recognition of a new liability.
The difference in the respective carrying amounts is recognised in the income statement.
Derivative \ufb01nancial instruments
The Group uses derivative \ufb01nancial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and
commodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative
\ufb01nancial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative \ufb01nancial instruments are
designated as cash \ufb02ow hedges in line with the Group\u2019s risk management policies. When derivatives do not qualify for hedge accounting
or are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.
A derivative with a positive fair value is recognised as a \ufb01nancial asset whereas a derivative with a negative fair value is recognised as a
\ufb01nancial liability. Derivatives are not offset in the \ufb01nancial statements unless the Group has both a legally enforceable right and intention
to offset. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than
12 months and it is not due to be realised or settled within 12 months. Other derivatives maturing in less than 12 months and expected
to be realised or settled in less than 12 months are presented as current assets or current liabilities.
Cash \ufb02ow hedges
The effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
hedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
transaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
recognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
Any gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
ineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
creditworthiness of the counterparty is signi\ufb01cant and may dominate the transaction and lead to losses.
Fair values
Fair value is de\ufb01ned as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date. It is determined by reference to quoted market prices adjusted for estimated transaction
costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models
and estimated discounted values of cash \ufb02ows.
For \ufb01nancial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques.
Under IFRS 9, embedded derivatives are not separated from a host \ufb01nancial asset, and are classi\ufb01ed based on their contractual terms
and the Group\u2019s business model.
Equity
Share capital
Share capital includes the total net proceeds, both nominal and share premium, on the issue of ordinary and preference shares of the company.
Capital redemption reserve
The capital redemption reserve represents the nominal value of shares transferred following the company\u2019s purchase of them.
Merger reserve
On 31 March 2021, Harbour Energy plc (formerly Premier Oil plc) acquired Chrysaor Holdings Limited as part of a reverse acquisition.
Under the terms of the merger, Premier legally acquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the
acquirer for accounting purposes, primarily as a result of its ability to appoint the Board of the enlarged group. The merger reserve
primarily represents Premier\u2019s opening balance on the legal reserve plus the fair value of the assets and liabilities acquired by Chrysaor.
Cash \ufb02ow hedge reserve
The cash \ufb02ow hedge and cost of hedging reserves represent gains and losses on derivatives classi\ufb01ed as effective cash \ufb02ow hedges.
Upon the designation of option instruments as hedging instruments, the intrinsic and time value components are separated, with only
the intrinsic component being designated as the hedging instrument and the time value component is deferred in other comprehensive
income as a \u2018cost of hedging\u2019.
Currency translation reserve
This reserve comprises exchange differences arising on consolidation of the Group\u2019s operations with a functional currency other than
the US dollar.
Share-based payments
The Group has applied the requirements of IFRS 2 Share-based Payment. The Group has share-based awards that are equity and cash
settled as de\ufb01ned by IFRS 2. The fair value of the equity-settled awards has been determined at the date of grant of the award allowing
for the effect of any market-based conditions. The fair value determined at the grant date of the equity-settled share-based payments is
expensed on a straight-line basis over the vesting period, based on the Group\u2019s estimate of shares that will eventually vest and adjusted
for the effect of non-market based vesting conditions. For cash-settled awards, a liability is recognised for the goods or service acquired.
This is measured initially at the fair value of the liability. The fair value of the liability is subsequently remeasured at each balance sheet
date until the liability is settled, and at the date of settlement, with any changes in fair value recognised in the income statement.
Inventories
All inventories, except for petroleum products, are stated at the lower of cost and net realisable value. The cost of materials is the purchase
cost, determined on a weighted average cost basis. Petroleum products and underlift and overlift positions are measured at net realisable
value using an observable year-end oil or gas market price, and are included in other debtors or creditors, respectively.
Leases
Leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use
by the Group. The \ufb01nance cost is charged to the income statement over the lease period so as to produce a constant periodic rate of
interest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of lease term
and useful life. The Group recognises right-of-use assets and lease liabilities on a gross basis and the recovery of lease costs from joint
operations\u2019 partners is recorded as other income.
Right-of-use assets and lease liabilities arising from a lease are initially measured on a present value basis re\ufb02ecting the net present
value of the \ufb01xed lease payments and amounts expected to be payable by the Group assuming leases run to full term. The Group
has applied judgement to determine the lease term for some lease contracts in which it is a lessee that include renewal options.
The assessment of whether the Group is reasonably certain to exercise such options impacts the lease term, which signi\ufb01cantly
impacts the amount of lease liabilities and right-of-use assets recognised.
\u2022
The lease payments are discounted using the Group\u2019s incremental borrowing rates of between 1.9 per cent and 8.8 per cent, being
the rate that the Group would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic
environment with similar terms and conditions
To determine the incremental borrowing rate, the Group where possible:
\u2022
Uses recent third-party \ufb01nancing received by the individual lessee as a starting point, adjusted to re\ufb02ect changes in \ufb01nancing conditions
since third-party \ufb01nancing was received
\u2022
Makes adjustments speci\ufb01c to the lease, for example term, country, currency and security
The Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in
the lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability
is reassessed and adjusted against the right-of-use asset.
Lease payments are allocated between principal and \ufb01nance cost. The \ufb01nance cost is charged to the income statement over the lease
period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.
Right-of-use assets are measured at cost comprising the following:
\u2022
The amount of the initial measurement of lease liability
\u2022
Any lease payments made at or before the commencement date less any lease incentives received
\u2022
Any initial direct costs and restoration costs
Right-of-use assets are generally depreciated over the shorter of the asset\u2019s estimated useful life and the lease term on a straight-line basis.
Payments associated with short-term leases and leases of low value assets are recognised on a straight-line basis as an expense in the
income statement. Short-term leases are leases with a lease term of 12 months or less.
For lease arrangements where all partners of a joint operation are considered to share the primary responsibility for lease payments
under a lease contract, the Group recognises its share of the respective right-of-use asset and lease liability. This situation is most
common where the parties of a joint operation co-sign the lease contract.
The Group recognises a gross lease liability for leases entered into on behalf of a joint operation where it has primary responsibility
for\u00a0making the lease payments. In such instances, if the arrangement between the Group and the joint operation represents a \ufb01nance
sublease, the Group recognises a net investment in sublease for amounts recoverable from non-operators whilst derecognising the
respective portion of the gross right-of-use asset. The gross lease liability is retained on the balance sheet.
The net investment in sublease is classi\ufb01ed as either trade and other receivables or long-term receivables on the balance sheet
according to whether or not the amounts will be recovered within 12 months of the balance sheet date. Finance income is recognised
in\u00a0respect of net investment in subleases.
Provisions for liabilities
A provision is recognised when the Group has a legal or constructive obligation as a result of a past event, it is probable that an out\ufb02ow of resources
embodying economic bene\ufb01ts will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
The expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money
is material, provisions are discounted using a current pre-tax rate that re\ufb02ects, where appropriate, the risk speci\ufb01c to the liability. Where
discounting is used, the increase in the provision due to the passage of time is recognised as part of \ufb01nance costs in the income statement.
The estimated cost of dismantling and restoring the production and related facilities at the end of the economic life of each \ufb01eld is
recognised in full when the related facilities are installed. The amount provided is the present value of the estimated future restoration
cost. A non-current asset is also recognised. Any changes to estimated costs or discount rates are dealt with prospectively.
The Group recognises provision for the estimated CO
2
emissions costs when actual emissions exceed the emission rights granted and
still held. When actual emissions exceed the amount of emission rights granted, provision is recognised for the exceeding emission rights
based on the purchase price of allowance concluded in forward contracts or market quotations at the reporting date.
Group retirement bene\ufb01ts
Payments to de\ufb01ned contribution retirement bene\ufb01t plans are charged as an expense as they fall due. Payments made to state-managed
retirement bene\ufb01t schemes are dealt with as payments to de\ufb01ned contribution plans where the Group\u2019s obligations under the schemes
are equivalent to those arising in a de\ufb01ned contribution retirement bene\ufb01t plan.
The Group operates a de\ufb01ned bene\ufb01t pension scheme, which requires contributions to be made to a separately administered fund.
The\u00a0cost of providing bene\ufb01ts is determined using the projected unit credit method, with actuarial valuations being carried out at each
balance sheet date. Actuarial gains and losses are recognised immediately in the statement of comprehensive income.
The retirement bene\ufb01t obligation recognised in the balance sheet represents the present value of the de\ufb01ned bene\ufb01t obligation as
reduced by the fair value of plan assets. Any asset resulting from this calculation is limited to the present value of available refunds
and reductions in future contributions to the plan.
Trade payables
Initial recognition of trade payables is at fair value. Subsequently they are stated at amortised cost.
Taxes
Current tax
Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to
the taxation authorities. The tax rates and laws used to compute the amount are those that are enacted or substantively enacted at the
reporting date in the countries where the Group operates and generates taxable income.
Current income tax related to items recognised directly in other comprehensive income or equity is recognised in other comprehensive
income or directly in equity, not in the income statement.
Deferred tax
Deferred taxation is recognised in respect of all timing differences arising between the tax bases of the assets and liabilities and their
carrying amounts in the \ufb01nancial statements with the following exceptions:
\u2022
Deferred income tax assets are recognised only to the extent that it is probable that the taxable pro\ufb01t will be available against which
the deductible temporary difference, carried forward tax credits or tax losses can be utilised
\u2022
Deferred income tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply when
the related asset is realised or liability is settled, based on tax rates and laws enacted or substantively enacted at the reporting date.
The carrying amount of the deferred income tax asset is reviewed at each balance sheet date and reduced to the extent that it is no
longer probable that suf\ufb01cient taxable pro\ufb01ts will be available to allow all or part of the asset to be recovered. The Group reassesses
any unrecognised deferred tax assets each year taking into account changes in oil and gas prices, the Group\u2019s proven and probable
reserves and resources pro\ufb01le and forecast capital and operating expenditures
\u2022
Deferred income tax assets and liabilities are offset only if a legally enforceable right exists to offset current assets against current tax liabilities,
the deferred income tax relates to the same tax authority and that same tax authority permits the Group to make a single net payment
Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited in other comprehensive
income, in which case the deferred tax is also dealt with in other comprehensive income.
Revenue from contracts with customers
Revenue from contracts with customers is recognised when the Group satis\ufb01es a performance obligation by transferring a good or
service to a customer. A good or service is transferred when the customer obtains control of that good or service. Revenue associated
with the sale of crude oil, natural gas, and natural gas liquids (NGLs) is measured based on the consideration speci\ufb01ed in contracts with
customers with reference to quoted market prices in active markets, adjusted according to speci\ufb01c terms and conditions as applicable
according to the sales contracts. The transfer of control of oil, natural gas, natural gas liquids and other items sold by the Group occurs
when title passes at the point the customer takes physical delivery. The Group principally satis\ufb01es its performance obligations at a point
in time and the amounts of revenue recognised relating to performance obligations satis\ufb01ed over time are not signi\ufb01cant.
Over/underlift
Differences between the production sold and the Group\u2019s share of production result in an overlift or an underlift. Underlift positions are
measured at net realisable value using an observable year-end oil or gas market price. Overlift positions are measured using the sales
price that generated the overlift. Underlift and overlift positions are included in receivables or payables respectively. Movements during
the accounting period are recognised within cost of sales.
Interest income
Interest income is recognised on an accruals basis, by reference to the principal outstanding and at the effective interest rate applicable.
Borrowing costs
Borrowing costs directly attributable to the acquisition, construction or production of an asset that necessarily takes a substantial period
of time to get ready for its intended use or sale (a qualifying asset) are capitalised as part of the cost of the respective assets. Where
the funds used to \ufb01nance a project form part of general borrowings, the amount capitalised is calculated using a weighted average of
rates applicable to relevant general borrowings of the Group during the period. All other borrowing costs are recognised in the income
statement in the period in which they are incurred.
New accounting standards and interpretations
The Group applied for the \ufb01rst time certain standards and amendments, which are effective for annual periods beginning on or after
1 January 2023 (unless otherwise stated). The Group has not early adopted any other standard, interpretation or amendment that
has been issued but is not yet effective.
Disclosure of Accounting Policies \u2013 Amendments to IAS 1 and IFRS Practice Statement 2
The amendments to IAS 1 and IFRS Practice Statement 2 Making Materiality Judgements provide guidance and examples to help entities
apply materiality judgements to accounting policy disclosures. The amendments aim to help entities provide accounting policy disclosures
that are more useful by replacing the requirement for entities to disclose their \u2018signi\ufb01cant\u2019 accounting policies with a requirement to
disclose their \u2018material\u2019 accounting policies and adding guidance on how entities apply the concept of materiality in making decisions
about accounting policy disclosures.
The amendments have had an impact on the Group\u2019s disclosures removing accounting policies not considered to be material along with
associated notes, but not on the measurement, recognition or presentation of any items in the Group\u2019s \ufb01nancial statements.
De\ufb01nition of Accounting Estimates \u2013 Amendments to IAS 8
The amendments to IAS 8 clarify the distinction between changes in accounting estimates, changes in accounting policies and the
correction of errors. They also clarify how entities use measurement techniques and inputs to develop accounting estimates.
The amendments had no impact on the Group\u2019s consolidated \ufb01nancial statements.
Deferred Tax related to Assets and Liabilities arising from a Single Transaction \u2013 Amendments to IAS 12
The amendments to IAS 12 Income Tax narrow the scope of the initial recognition exception, so that it no longer applies to transactions
that give rise to equal taxable and deductible temporary differences such as leases and decommissioning liabilities.
The amendments had no impact on the Group\u2019s consolidated \ufb01nancial statements.
International Tax Reform\u2014Pillar Two Model Rules \u2013 Amendments to IAS 12
The amendments to IAS 12 have been introduced in response to the OECD\u2019s BEPS Pillar Two rules and include:
\u2022
a mandatory temporary exception to the recognition and disclosure of deferred taxes arising from the jurisdictional implementation
of the Pillar Two model rules; and
\u2022
disclosure requirements for affected entities to help users of the \ufb01nancial statements better understand an entity\u2019s exposure to
Pillar Two income taxes arising from that legislation, particularly before its effective date.
The mandatory temporary exception \u2013 the use of which is required to be disclosed \u2013 applies immediately. The remaining disclosure
requirements apply for annual reporting periods beginning on or after 1 January 2023, but not for any interim periods ending on or
before 31 December 2023.
IFRS 17 Insurance Contracts
IFRS 17 Insurance Contracts is a comprehensive new accounting standard for insurance contracts covering recognition and
measurement, presentation and disclosure. IFRS 17 replaces IFRS 4 Insurance Contracts. IFRS 17 applies to all types of insurance
contracts (ie life, non-life, direct insurance and re-insurance), regardless of the type of entities that issue them as well as to certain
guarantees and \ufb01nancial instruments with discretionary participation features; a few scope exceptions will apply. The overall objective
of IFRS 17 is to provide a comprehensive accounting model for insurance contracts that is more useful and consistent for insurers,
covering all relevant accounting aspects. IFRS 17 is based on a general model, supplemented by:
\u2022
A speci\ufb01c adaptation for contracts with direct participation features (the variable fee approach)
\u2022
A simpli\ufb01ed approach (the premium allocation approach) mainly for short-duration contracts
The new standard had no impact on the Group\u2019s consolidated \ufb01nancial statements.
Signi\ufb01cant accounting judgements and estimates
The preparation of the Group\u2019s \ufb01nancial statements in conformity with IFRS requires management to make judgements, estimates
and assumptions at the date of the \ufb01nancial statements. Estimates and assumptions are continuously evaluated and are based on
management experience and other factors, including expectations of future events that are believed to be reasonable under the
circumstances. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to
the carrying amount of the assets or liabilities affected in future periods. In particular, the Group has identi\ufb01ed the following areas
where signi\ufb01cant judgement, estimates and assumptions are required.
Judgements
The signi\ufb01cant accounting judgements for the Group are considered to be:
\u2022
the carrying value of intangible exploration and evaluation assets, in relation to whether commercial determination of an exploration
prospect had been reached;
\u2022
the carrying value of property, plant and equipment regarding assessing assets for indicators of impairment;
\u2022
decommissioning costs in relation to the timing of when decommissioning would occur;
\u2022
tax including assessment of risks around tax uncertainties and the recognition of deferred tax assets; and
\u2022
the application of the going concern basis of accounting (see \u2018Basis of preparation\u2019 section above).
Key sources of estimation uncertainty
Details of the Group\u2019s critical accounting estimates are set out in these \ufb01nancial statements and are considered to be:
\u2022
the carrying value of property, plant and equipment and goodwill, where the key assumptions relate to oil and gas prices expected
to be realised, the estimation of 2P reserves and the associated production pro\ufb01les;
\u2022
decommissioning costs where the key assumptions relate to the discount and in\ufb02ation rates applied, applicable rig rates and expected
timing of cessation of production (COP) on each \ufb01eld;
\u2022
the provision for, or disclosure of, areas of uncertainty for tax purposes where the key assumptions are driven by technical analysis
corroborated by external advice; and
\u2022
recognition of net deferred tax liabilities, where key assumptions relate to oil and gas prices expected to be realised, and production pro\ufb01les.
The results from downside sensitivities prepared with regard to production and commodity price assumptions, which in management\u2019s
view re\ufb02ect the principal risks, indicate that material changes that would impact the carrying amounts of assets and liabilities within
the next \ufb01nancial year are unlikely.
Further information is provided in the Audit and Risk Committee report on pages 76 to 79.", "dimensions": { "concept": "ifrs-full:DisclosureOfMaterialAccountingPolicyInformationExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18054": { "value": "Basis of preparation
The consolidated \ufb01nancial statements have been prepared on a going concern basis in accordance with UK-adopted International
Accounting Standards (IAS) in conformity with the requirements of the Companies Act 2006. The analysis used by the Directors in
adopting the going concern basis considers the various plans and commitments of the Group as well as various sensitivity and reverse
stress test analyses. The results from the downside sensitivities and reverse stress testing with regard to production and commodity
price assumptions, which in management\u2019s view re\ufb02ect two of the principal risks, indicate that material changes within one year that
would impact the going concern basis of preparation are unlikely. Further details are within the \ufb01nancial review on page 26 and viability
statement on page 59.
The presentation currency of the Group \ufb01nancial information is US dollars and all values in the Group \ufb01nancial information are presented
in millions ($ million) and all values are rounded to the nearest 1 million, except where otherwise stated.
The \ufb01nancial statements have been prepared on the historical cost basis, except for certain \ufb01nancial assets and liabilities, including
derivative \ufb01nancial instruments, which have been measured at fair value.
The accounting policies which follow set out those policies which apply in preparing the \ufb01nancial statements for the year ended
31 December 2023. All accounting policies are consistent with those adopted and disclosed in Harbour\u2019s 2022 Annual Report &
Accounts, except for the inclusion of a new policy for the cost of carbon allowances.", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18055": { "value": "Basis of preparation
The consolidated \ufb01nancial statements have been prepared on a going concern basis in accordance with UK-adopted International
Accounting Standards (IAS) in conformity with the requirements of the Companies Act 2006. The analysis used by the Directors in
adopting the going concern basis considers the various plans and commitments of the Group as well as various sensitivity and reverse
stress test analyses. The results from the downside sensitivities and reverse stress testing with regard to production and commodity
price assumptions, which in management\u2019s view re\ufb02ect two of the principal risks, indicate that material changes within one year that
would impact the going concern basis of preparation are unlikely. Further details are within the \ufb01nancial review on page 26 and viability
statement on page 59.
The presentation currency of the Group \ufb01nancial information is US dollars and all values in the Group \ufb01nancial information are presented
in millions ($ million) and all values are rounded to the nearest 1 million, except where otherwise stated.
The \ufb01nancial statements have been prepared on the historical cost basis, except for certain \ufb01nancial assets and liabilities, including
derivative \ufb01nancial instruments, which have been measured at fair value.
The accounting policies which follow set out those policies which apply in preparing the \ufb01nancial statements for the year ended
31 December 2023. All accounting policies are consistent with those adopted and disclosed in Harbour\u2019s 2022 Annual Report &
Accounts, except for the inclusion of a new policy for the cost of carbon allowances.", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18059": { "value": "The consolidated \ufb01nancial statements have been prepared on a going concern basis in accordance with UK-adopted International
Accounting Standards (IAS) in conformity with the requirements of the Companies Act 2006. The analysis used by the Directors in
adopting the going concern basis considers the various plans and commitments of the Group as well as various sensitivity and reverse
stress test analyses. The results from the downside sensitivities and reverse stress testing with regard to production and commodity
price assumptions, which in management\u2019s view re\ufb02ect two of the principal risks, indicate that material changes within one year that
would impact the going concern basis of preparation are unlikely. Further details are within the \ufb01nancial review on page 26 and viability
statement on page 59.", "dimensions": { "concept": "ifrs-full:DisclosureOfGoingConcernExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18078": { "value": "Basis of consolidation
The consolidated \ufb01nancial statements comprise the \ufb01nancial statements of the company and its subsidiaries as at 31 December 2023.
Subsidiaries are those entities over which the Group has control. Control is achieved where the Group has the power over the subsidiary,
has rights, or is exposed to variable returns from the subsidiary and has the ability to use its power to affect its returns. All subsidiaries
are 100 per cent owned by the Group and there are no non-controlling interests.
If the Group loses control over a subsidiary, it derecognises the related assets (including goodwill), liabilities, non-controlling interest
and\u00a0other components of equity, while any resultant gain or loss is recognised in pro\ufb01t or loss. Any investment retained is recognised
at\u00a0fair value.
The results of subsidiaries acquired or disposed of during the year are included in the income statement from the effective date of
acquisition or up to the effective date of disposal, as appropriate. Where necessary, adjustments are made to the \ufb01nancial statements
of\u00a0subsidiaries acquired to bring the accounting policies used into line with those used by other members of the Group.
All intra-group transactions and balances have been eliminated on consolidation.", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18079": { "value": "Basis of consolidation
The consolidated \ufb01nancial statements comprise the \ufb01nancial statements of the company and its subsidiaries as at 31 December 2023.
Subsidiaries are those entities over which the Group has control. Control is achieved where the Group has the power over the subsidiary,
has rights, or is exposed to variable returns from the subsidiary and has the ability to use its power to affect its returns. All subsidiaries
are 100 per cent owned by the Group and there are no non-controlling interests.
If the Group loses control over a subsidiary, it derecognises the related assets (including goodwill), liabilities, non-controlling interest
and\u00a0other components of equity, while any resultant gain or loss is recognised in pro\ufb01t or loss. Any investment retained is recognised
at\u00a0fair value.
The results of subsidiaries acquired or disposed of during the year are included in the income statement from the effective date of
acquisition or up to the effective date of disposal, as appropriate. Where necessary, adjustments are made to the \ufb01nancial statements
of\u00a0subsidiaries acquired to bring the accounting policies used into line with those used by other members of the Group.
All intra-group transactions and balances have been eliminated on consolidation.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSubsidiariesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18126": { "value": "Impact of climate change on the \ufb01nancial statements and related disclosures
Judgements and estimates made in assessing the impact of climate change and the energy transition
Harbour monitors global climate change and energy transition developments and plans. Management recognises there is a general high level
of uncertainty about the speed and scale of impacts which, together with limited historical information, provides challenges in the preparation
of forecasts and plans with a range of possible future scenarios, which may have the potential to materially impact the balance sheet.
The Group\u2019s continued strategic ambition is to achieve net zero by 2035 with an interim target of a 50 per cent reduction in Scope 1 and
2 emissions by 2030 against the 2018 baseline. This will be achieved through several opportunities, including operational ef\ufb01ciency
improvements, UK offshore electri\ufb01cation and the eventual cessation of production of mature \ufb01elds. In addition, opportunities for offshore
electri\ufb01cation are being explored and the company is investing in the development of carbon capture and storage projects in the UK.
Where the Group cannot reduce its Scope 1 and 2 emissions, it will invest in high quality, independently veri\ufb01ed, carbon offsets to
achieve the goal of net zero.
All new economic investment decisions include the cost of carbon, and opportunities are assessed on their climate-impact potential and
alignment with Harbour Energy\u2019s net zero goal, taking into consideration both GHG volumes and intensity. The corporate modelling that
supports the preparation of the \ufb01nancial statements (such as asset and goodwill impairment assessment, going concern and viability,
deferred tax asset recoverability) includes project costs related to CCS, certain limited electri\ufb01cation and other activities to reduce Scope
1 and 2 GHG emissions, the UK Emissions Trading Scheme and carbon offset purchases.
Emissions reduction incentives are part of staff remuneration through the annual bonus programme. Additionally, the cost of borrowing is
tied to our gross operated CO
2
emissions performance, with GHG metrics being linked to our RBL interest expense, further incentivising
our emissions reduction targets.
Climate change and the energy transition have the potential to signi\ufb01cantly impact the accounting estimates adopted by management
and therefore the valuation of assets and liabilities reported on the balance sheet. On an ongoing basis management continues to
assess the potential impacts on the signi\ufb01cant judgements and estimates used in the preparation of the \ufb01nancial statements. Estimates
adopted in the \ufb01nancial statements re\ufb02ect management\u2019s best estimate of future market conditions where, in particular, commodity prices
can be volatile. Commodity and carbon price curve assumptions are described below noting that there is consideration given to other
assumptions, not exhaustively, such as foreign exchange and discount rates. Notwithstanding the challenges around climate change and
the energy transition, it is management\u2019s view that the \ufb01nancial statements are consistent with the disclosures in the Strategic report.
This note provides insight into how Harbour has considered the impact on valuations of key line items in the \ufb01nancial statements and how
they could change based on the climate change scenarios and sensitivities considered. The scenarios presented show what the possible
impact could be on the \ufb01nancial statements considering both high and low commodity price outlooks. Importantly, these climate change
scenarios do not form the basis of the preparation of the \ufb01nancial statements but rather indicate how the key assumptions that underpin the
\ufb01nancial statements would be impacted by the climate change scenarios. They are also designed to challenge management\u2019s perspective
on the future business environment. It is recognised that the reality of the nature of progress of energy transition will bring greater levels
of disruption and volatility than these external scenarios expect and do not represent management\u2019s current best estimate.
Management\u2019s current best estimate for the foreseeable future, which was derived from consideration of a range of considered economic
forecasts, has been used on the same basis to prepare the \ufb01nancial statements and is represented by the Harbour scenario oil price
curve. Management continues to review these estimates and assumptions to ensure they re\ufb02ect the latest economic environment
conditions and market information available.
Impairment of property, plant and equipment, and goodwill
The energy transition has the potential to signi\ufb01cantly impact future commodity and carbon prices which would, in turn, affect the future
operating and capital costs, estimates of cessation of production, useful lives, and consequently the recoverable amount of property,
plant and equipment and goodwill. In the current period, when testing for impairment, the Harbour scenario real long-term commodity
price assumptions from 2026 for Brent crude were $70/bbl (2022: $65/bbl) and UK NBP gas 90 pence/therm (2022: 65 pence/therm)
combined with the short-term forecast period re\ufb02ecting market forward curves at the year end.
Carbon costs will develop over time and carry considerable uncertainty due to the rate of transition and maturity of regulatory regimes.
For the UK price of carbon, Harbour management\u2019s real forward price curve assumption in 2024 is \u00a350/tonne ($63/tonne) rising to
\u00a3140/tonne ($175/tonne) in 2030. The sensitivity was run on the IEA Net Zero carbon price curve. The foreign exchange rate was
assumed to be $1.00:\u00a31.25 \ufb02at for future periods to convert to nominal prices. Such assumptions are inherently uncertain and may
ultimately differ from the actual amounts.
During 2023 there was a total net pre-tax impairment charge of $239 million (2022: $170 million net reversal) across goodwill of
$25 million and property, plant and equipment of $214 million. Further details can be found in note 10 and note 12 respectively.
Further, sensitivities on the impairment of property, plant and equipment and goodwill have been prepared using various commodity price
scenarios to show the possible impact on net book carrying values. As noted, the Harbour scenario is the basis for the preparation of the
\ufb01nancial statements. Impairment sensitivities have been prepared at an average -10 per cent and +10 per cent to the Harbour scenario
average for crude, gas and carbon and selected published climate change price curves.
The sensitivity scenarios described below incorporate changes to the commodity price assumptions and assume that all other factors
remain unchanged from the Harbour scenario used for the basis of preparation of the \ufb01nancial statements. These sensitivities are stated
before any management mitigation actions to manage downside risks if the scenarios were to occur.
The ESG review on pages 39 to 44 discusses both transition and physical risk climate change scenarios. This analysis covers the transition
risks and the graphs below show the crude oil and UK NBP gas price curves for the period to 2050 for the following scenarios: IEA Net Zero
2050, IEA Stated Policies and IEA Announced Pledges.
All the scenario price curves are dependent on factors covering supply, demand, economic and geopolitical events and therefore are
inherently uncertain and subject to signi\ufb01cant volatility and hence unlikely to re\ufb02ect the future outcome.
\u2022
Harbour scenario: base price curves used for impairment testing
\u2022
IEA Net Zero Emissions by 2050 (NZE): limiting global temperature rise to 1.5
o
C
\u2022
IEA Stated Policies (STEPS): current policy commitments by sector and country
\u2022
IEA Announced Pledges (APS): current climate commitments by governments and industries
0
20
40
60
80
100
H2 2030
H1 2030
H2 2029
H1 2029
H2 2028
H1 2028
H2 2027
H1 2027
H2 2026
H1 2026
H2 2025
H1 2025
H2 2024
H1 2024
$/bbl
Crude
$/bbl
Crude
Harbour scenario
NZE
STEPS
APS
0.0
0.2
0.4
0.6
0.8
1.0
1.2
H2 2030
H1 2030
H2 2029
H1 2029
H2 2028
H1 2028
H2 2027
H1 2027
H2 2026
H1 2026
H2 2025
H1 2025
H2 2024
H1 2024
\u00a3/therm
Gas
Harbour scenario
NZE
STEPS
APS
0
30
60
90
120
150
H2 2030
H1 2030
H2 2029
H1 2029
H2 2028
H1 2028
H2 2027
H1 2027
H2 2026
H1 2026
H2 2025
H1 2025
H2 2024
H1 2024
\u00a3/tonne
Carbon
Harbour scenario
NZE
The crude price curves re\ufb02ect the published IEA price curves for all periods. For UK NBP gas there are no IEA published price curves
therefore management has derived the UK NBP gas price curves by converting from the published IEA European gas price curve.
This was achieved by converting from USD per mbtu to pence per therm and applying other known correlation coef\ufb01cients between the
European and UK gas markets. In addition, for the period 2024-2027, the derived gas price curve matches the Harbour scenario
price curve to create a scenario that was considered reasonably plausible.
Pre-development assets such as Zama in Mexico and Andaman in Indonesia are recorded in other intangible assets ahead of demonstration
of commerciality and recognition of 2P reserves and hence are not included below, however they are subject to the same management rigour
with the corporate models.
The results of the sensitivities are as follows and show the impact on the property, plant and equipment balance sheet carrying values
when it had resulted in a material decrease in carrying value.
Pre-tax sensitivity in carrying value
$ million
IEA Net Zero
IEA
IEA
+10% price
-10% price
Emissions
Stated
Announced
Carrying value
to Harbour
to Harbour
by 2050
Policies
Pledges
Commodity
$ million
scenario
scenario
(NZE)
(STEPS)
(APS)
Property, plant
Crude oil
\u2013
(86)
(221)
\u2013
\u2013
and equipment
UK NBP gas (derived)
4,717
\u2013
(21)
(9)
\u2013
\u2013
(note 12)
Carbon
\u2013
\u2013
(27)
N/A
N/A
The +/-10 per cent price curves used in the Harbour scenarios adjust long-term prices from 2027.
Under the -10 per cent price to Harbour scenario for crude there is a pre-tax impairment to property, plant and equipment on two UK
\ufb01elds of\u00a0$86 million (post-tax $40 million) and for UK NBP gas a pre-tax impairment on a single UK \ufb01eld of $21 million (post-tax
$6 million).
For crude, under the IEA NZE 2050 scenario, there is a pre-tax impairment to property, plant and equipment on a single UK \ufb01eld
of\u00a0$221 million (post-tax $104 million) and for UK NBP gas, there is a pre-tax impairment on two UK \ufb01elds of $9 million (post-tax\u00a0$3 million).
There is no impairment to property, plant and equipment across the three +10 per cent price to Harbour scenarios nor the IEA STEPS
and APS\u00a0scenarios.
Under the IEA Net Zero Emissions by 2050 scenario for carbon, there is a pre-tax impairment to property, plant and equipment
on a single UK \ufb01eld of $27 million (post-tax $13 million).
For goodwill, there are no impairments under any scenario except for the -10 per cent price to Harbour scenario for UK NBP gas which
re\ufb02ects an impairment of $4 million.
Property, plant and equipment \u2013 depreciation and expected useful lives
A signi\ufb01cant proportion of property, plant and equipment assets are expected to reach cessation of production over the next
10 to 20 years. There are no signi\ufb01cant judgements and/or critical estimation uncertainty related to climate factors.
See Accounting policy: Property, plant and equipment \u2013 oil and gas assets for further information (page 129).
Intangible assets \u2013 exploration and evaluation assets
The energy transition has the potential to affect the future development or viability of exploration and evaluation prospects. A signi\ufb01cant
portion of the Group\u2019s exploration and evaluation assets relate to prospects that could be tied back to existing infrastructure and hence
require less capital investment as these assets are less exposed to the impacts of the energy transition compared to large frontier
developments. At each balance sheet date, all exploration and evaluation prospects are reviewed against the Group\u2019s \ufb01nancial framework
to ensure that the continuation of activities is planned and expected. There are no signi\ufb01cant judgements and/or critical estimation
uncertainty related to climate factors.
See Judgements: Exploration and evaluation expenditure (page 137) and note 11 to the \ufb01nancial statements for further information.
c
Decommissioning cost and provisions
The energy transition may accelerate the decommissioning of assets which would result in an increase in the carrying value of associated
decommissioning provisions. Whilst the Group currently expects to incur decommissioning costs over the next 40 years, we anticipate the
majority of costs will be incurred between the next 10 to 20 years which will reduce the exposure to the impact of the energy transition.
Decommissioning cost estimates are based on the current regulatory and external environment. These cost estimates and recoverability
of associated deferred tax may change in the future, including as a result of the energy transition.
On the basis that all other assumptions in the calculation remain the same, a 10 per cent increase in the cost estimates, and a
10 per cent reduction in the applied discount rates used to assess the \ufb01nal decommissioning obligation, would result in increases to the
decommissioning provision of approximately $456 million and $440 million, respectively. This change would be principally offset by a
change to the value of the associated asset unless the asset is fully depreciated, in which case the change in estimate is recognised
directly within the income statement.
Currently, the timing of decommissioning expenditures has not been materially brought forward and management do not consider that
any reasonable change in the timing of decommissioning expenditure will have a material impact on the decommissioning provisions.
See Key sources of estimation uncertainty: Decommissioning costs for further information (page 137).
Cost of carbon allowances
Harbour is part of the UK Emissions Trading Scheme (UK ETS) and purchases carbon allowances under the scheme to meet its regulatory
obligations under the scheme. The costs for purchasing allowances are recorded in costs of operations matching emissions for the
period. Accruals that are required for allowances to be purchased are measured at market price. Allowances owned in excess of liabilities
to date that are available to be used in future periods are recorded in other intangible assets and measured at cost. Harbour is entitled
to receive a share of free allowances according to UK ETS regulations.Signi\ufb01cant accounting judgements and estimates
The preparation of the Group\u2019s \ufb01nancial statements in conformity with IFRS requires management to make judgements, estimates
and assumptions at the date of the \ufb01nancial statements. Estimates and assumptions are continuously evaluated and are based on
management experience and other factors, including expectations of future events that are believed to be reasonable under the
circumstances. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to
the carrying amount of the assets or liabilities affected in future periods. In particular, the Group has identi\ufb01ed the following areas
where signi\ufb01cant judgement, estimates and assumptions are required.
Judgements
The signi\ufb01cant accounting judgements for the Group are considered to be:
\u2022
the carrying value of intangible exploration and evaluation assets, in relation to whether commercial determination of an exploration
prospect had been reached;
\u2022
the carrying value of property, plant and equipment regarding assessing assets for indicators of impairment;
\u2022
decommissioning costs in relation to the timing of when decommissioning would occur;
\u2022
tax including assessment of risks around tax uncertainties and the recognition of deferred tax assets; and
\u2022
the application of the going concern basis of accounting (see \u2018Basis of preparation\u2019 section above).
Key sources of estimation uncertainty
Details of the Group\u2019s critical accounting estimates are set out in these \ufb01nancial statements and are considered to be:
\u2022
the carrying value of property, plant and equipment and goodwill, where the key assumptions relate to oil and gas prices expected
to be realised, the estimation of 2P reserves and the associated production pro\ufb01les;
\u2022
decommissioning costs where the key assumptions relate to the discount and in\ufb02ation rates applied, applicable rig rates and expected
timing of cessation of production (COP) on each \ufb01eld;
\u2022
the provision for, or disclosure of, areas of uncertainty for tax purposes where the key assumptions are driven by technical analysis
corroborated by external advice; and
\u2022
recognition of net deferred tax liabilities, where key assumptions relate to oil and gas prices expected to be realised, and production pro\ufb01les.
The results from downside sensitivities prepared with regard to production and commodity price assumptions, which in management\u2019s
view re\ufb02ect the principal risks, indicate that material changes that would impact the carrying amounts of assets and liabilities within
the next \ufb01nancial year are unlikely.
Further information is provided in the Audit and Risk Committee report on pages 76 to 79.", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18167": { "value": "Impairment of property, plant and equipment, and goodwill
The energy transition has the potential to signi\ufb01cantly impact future commodity and carbon prices which would, in turn, affect the future
operating and capital costs, estimates of cessation of production, useful lives, and consequently the recoverable amount of property,
plant and equipment and goodwill. In the current period, when testing for impairment, the Harbour scenario real long-term commodity
price assumptions from 2026 for Brent crude were $70/bbl (2022: $65/bbl) and UK NBP gas 90 pence/therm (2022: 65 pence/therm)
combined with the short-term forecast period re\ufb02ecting market forward curves at the year end.
Carbon costs will develop over time and carry considerable uncertainty due to the rate of transition and maturity of regulatory regimes.
For the UK price of carbon, Harbour management\u2019s real forward price curve assumption in 2024 is \u00a350/tonne ($63/tonne) rising to
\u00a3140/tonne ($175/tonne) in 2030. The sensitivity was run on the IEA Net Zero carbon price curve. The foreign exchange rate was
assumed to be $1.00:\u00a31.25 \ufb02at for future periods to convert to nominal prices. Such assumptions are inherently uncertain and may
ultimately differ from the actual amounts.
During 2023 there was a total net pre-tax impairment charge of $239 million (2022: $170 million net reversal) across goodwill of
$25 million and property, plant and equipment of $214 million. Further details can be found in note 10 and note 12 respectively.
Further, sensitivities on the impairment of property, plant and equipment and goodwill have been prepared using various commodity price
scenarios to show the possible impact on net book carrying values. As noted, the Harbour scenario is the basis for the preparation of the
\ufb01nancial statements. Impairment sensitivities have been prepared at an average -10 per cent and +10 per cent to the Harbour scenario
average for crude, gas and carbon and selected published climate change price curves.
The sensitivity scenarios described below incorporate changes to the commodity price assumptions and assume that all other factors
remain unchanged from the Harbour scenario used for the basis of preparation of the \ufb01nancial statements. These sensitivities are stated
before any management mitigation actions to manage downside risks if the scenarios were to occur.
The ESG review on pages 39 to 44 discusses both transition and physical risk climate change scenarios. This analysis covers the transition
risks and the graphs below show the crude oil and UK NBP gas price curves for the period to 2050 for the following scenarios: IEA Net Zero
2050, IEA Stated Policies and IEA Announced Pledges.
All the scenario price curves are dependent on factors covering supply, demand, economic and geopolitical events and therefore are
inherently uncertain and subject to signi\ufb01cant volatility and hence unlikely to re\ufb02ect the future outcome.
\u2022
Harbour scenario: base price curves used for impairment testing
\u2022
IEA Net Zero Emissions by 2050 (NZE): limiting global temperature rise to 1.5
o
C
\u2022
IEA Stated Policies (STEPS): current policy commitments by sector and country
\u2022
IEA Announced Pledges (APS): current climate commitments by governments and industries
0
20
40
60
80
100
H2 2030
H1 2030
H2 2029
H1 2029
H2 2028
H1 2028
H2 2027
H1 2027
H2 2026
H1 2026
H2 2025
H1 2025
H2 2024
H1 2024
$/bbl
Crude
$/bbl
Crude
Harbour scenario
NZE
STEPS
APS
0.0
0.2
0.4
0.6
0.8
1.0
1.2
H2 2030
H1 2030
H2 2029
H1 2029
H2 2028
H1 2028
H2 2027
H1 2027
H2 2026
H1 2026
H2 2025
H1 2025
H2 2024
H1 2024
\u00a3/therm
Gas
Harbour scenario
NZE
STEPS
APS
0
30
60
90
120
150
H2 2030
H1 2030
H2 2029
H1 2029
H2 2028
H1 2028
H2 2027
H1 2027
H2 2026
H1 2026
H2 2025
H1 2025
H2 2024
H1 2024
\u00a3/tonne
Carbon
Harbour scenario
NZE
The crude price curves re\ufb02ect the published IEA price curves for all periods. For UK NBP gas there are no IEA published price curves
therefore management has derived the UK NBP gas price curves by converting from the published IEA European gas price curve.
This was achieved by converting from USD per mbtu to pence per therm and applying other known correlation coef\ufb01cients between the
European and UK gas markets. In addition, for the period 2024-2027, the derived gas price curve matches the Harbour scenario
price curve to create a scenario that was considered reasonably plausible.
Pre-development assets such as Zama in Mexico and Andaman in Indonesia are recorded in other intangible assets ahead of demonstration
of commerciality and recognition of 2P reserves and hence are not included below, however they are subject to the same management rigour
with the corporate models.
The results of the sensitivities are as follows and show the impact on the property, plant and equipment balance sheet carrying values
when it had resulted in a material decrease in carrying value.
Pre-tax sensitivity in carrying value
$ million
IEA Net Zero
IEA
IEA
+10% price
-10% price
Emissions
Stated
Announced
Carrying value
to Harbour
to Harbour
by 2050
Policies
Pledges
Commodity
$ million
scenario
scenario
(NZE)
(STEPS)
(APS)
Property, plant
Crude oil
\u2013
(86)
(221)
\u2013
\u2013
and equipment
UK NBP gas (derived)
4,717
\u2013
(21)
(9)
\u2013
\u2013
(note 12)
Carbon
\u2013
\u2013
(27)
N/A
N/A
The +/-10 per cent price curves used in the Harbour scenarios adjust long-term prices from 2027.
Under the -10 per cent price to Harbour scenario for crude there is a pre-tax impairment to property, plant and equipment on two UK
\ufb01elds of\u00a0$86 million (post-tax $40 million) and for UK NBP gas a pre-tax impairment on a single UK \ufb01eld of $21 million (post-tax
$6 million).
For crude, under the IEA NZE 2050 scenario, there is a pre-tax impairment to property, plant and equipment on a single UK \ufb01eld
of\u00a0$221 million (post-tax $104 million) and for UK NBP gas, there is a pre-tax impairment on two UK \ufb01elds of $9 million (post-tax\u00a0$3 million).
There is no impairment to property, plant and equipment across the three +10 per cent price to Harbour scenarios nor the IEA STEPS
and APS\u00a0scenarios.
Under the IEA Net Zero Emissions by 2050 scenario for carbon, there is a pre-tax impairment to property, plant and equipment
on a single UK \ufb01eld of $27 million (post-tax $13 million).
For goodwill, there are no impairments under any scenario except for the -10 per cent price to Harbour scenario for UK NBP gas which
re\ufb02ects an impairment of $4 million.Impairment testing of goodwill
In accordance with IAS 36 Impairment of Assets, goodwill is reviewed for impairment at the year end or more frequently if there are
indications that goodwill might be impaired. In assessing whether goodwill has been impaired, the carrying amount of the CGU for
goodwill is compared with its recoverable amount. At the year end, the Group tested for impairment in accordance with the accounting
policy and recognised a goodwill impairment of $25 million in the International CGU (2022: $ nil) related to the Vietnam business being
classed as an asset held for sale as per note 17.Key assumptions used in calculations
Assumptions involved in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas
prices, discount rates and the level and timing of expenditures, all of which are inherently uncertain.
Commodity and carbon prices
Management\u2019s commodity price curve assumptions are benchmarked against a range of external forward price curves on a regular basis.
The \ufb01rst three years re\ufb02ect the market forward prices curves transitioning to a long-term price thereafter. The long-term commodity prices
and carbon prices are shown in note 2 to the \ufb01nancial statements on page 123.
Production volumes and oil and gas reserves
Based on life of \ufb01eld production pro\ufb01les for each asset within the CGU. Proven and probable reserves are estimates of the amount of
oil and gas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates its reserves using standard
recognised evaluation techniques and they are assessed at least annually by management and by an independent consultant. Proven
and probable reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices.
Costs
Operating expenditure, capital investment and decommissioning costs, which have been in\ufb02ated at 2.5 per cent per annum from
1 January 2027, are derived from the Group\u2019s business plan.
Discount rates
Represent management\u2019s estimate of the Group\u2019s country-based weighted average cost of capital (WACC), considering both debt and
equity. The cost of equity is derived from an expected return on investment by the Group\u2019s investors, and the cost of debt is based on
its interest-bearing borrowings. Segment-speci\ufb01c risk is incorporated by applying a beta factor based on publicly available market data.
The discount rate is based on an assessment of a relevant peer group\u2019s post-tax WACC.
Foreign exchange rates
Based on management\u2019s long-term rate assumptions, with reference to a range of underlying economic indicators.
Sensitivity to changes in assumptions used in calculations
The Group has run sensitivities on its long-term commodity price assumptions, which have been based on long-range forecasts from
external \ufb01nancial analysts, using alternate long-term price assumptions, and discount rates. These are considered to be reasonably
possible changes for the purposes of sensitivity analysis. As shown in note 2 to the \ufb01nancial statements the sensitivity analysis on
commodity prices re\ufb02ecting a 10 per cent reduction in the long-term oil and gas price deck applied in the impairment test would result
in a reduction to the goodwill impairment of $4 million. A 1 per cent increase in the discount rate would result in a further impairment
to goodwill of $1 million.During the year, the Group recognised a pre-tax impairment charge of $214 million (post-tax $109 million) (2022: net impairment credit
of $170 million; post-tax $50 million). This comprised a pre-tax impairment charge representing a write-down of property, plant and
equipment assets of $108 million (2022: $163 million) across two CGUs in the UK of $70 million. Of these CGUs, one was driven
primarily by a signi\ufb01cant reduction in the gas price forward curve, and the other by a revised decommissioning cost pro\ufb01le. In addition,
there was a Vietnam fair value impairment on the held for sale asset of $38 million and a pre-tax impairment charge of $106 million
(2022: $82 million credit) in respect of revisions to decommissioning estimates on the Group\u2019s non-producing assets with no remaining
net book value (see note 20).
In 2022, a net pre-tax impairment credit of $170 million was recognised as a result of impairment reversals on North Sea assets of
$251 million driven by a higher forward curve and long-term price assumption for gas, and a pre-tax impairment credit of $82 million
in respect of revisions to decommissioning estimates on the Group\u2019s non-producing assets with no remaining net book value. This was
partially offset by an impairment to property, plant and equipment of $163 million from a single CGU in the UK North Sea, driven primarily
by the contracted price realised for crude sales being negatively impacted by the pricing differential between Urals and Brent crude and
a revised operating cost pro\ufb01le for the \ufb01eld.
Key assumptions used in calculations
Assumptions used in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas
prices, discount rates and the level and timing of expenditures, all of which are inherently uncertain.
Commodity and carbon prices
The Group uses the fair value less cost of disposal method (FVLCD) to calculate the recoverable amount of the cash-generating
units (CGU) consistent with a level 3 fair value measurement (see note 22). In determining the recoverable value, appropriate discounted-
cash-\ufb02ow valuation models were used, incorporating market-based assumptions. Management\u2019s commodity price curve assumptions are
benchmarked against a range of external forward price curves on a regular basis. Individual \ufb01eld price differentials are then applied. The
\ufb01rst three years re\ufb02ect the market forward price curves transitioning to a long-term price from 2027, thereafter in\ufb02ated at 2.5 per cent
per annum. The long-term commodity prices used were $70 per barrel for crude and 90 pence per therm for gas.
Production volumes and oil and gas reserves
Production volumes are based on life of \ufb01eld production pro\ufb01les for each asset within the CGU. Proven and probable reserves are
estimates of the amount of oil and gas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates
its reserves using standard recognised evaluation techniques, assessed at least annually by management. Proven and probable
reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices.
Costs
Operating expenditure, capital expenditure and decommissioning costs are derived from the Group\u2019s business plan. The discount
rate re\ufb02ects management\u2019s estimate of the Group\u2019s country-based weighted average cost of capital (WACC). Foreign exchange rates
are based on management\u2019s long-term rate assumptions, with reference to a range of underlying economic indicators.
Sensitivity to changes in assumptions used in calculations
Reductions or increases in the long-term oil and gas prices of 10 per cent are considered to be reasonably possible changes for the
purpose of sensitivity analysis. As shown in note 2 to the \ufb01nancial statements the decreases to the long-term oil and gas prices from
1 January 2027 speci\ufb01ed above would result in a further pre-tax impairment of $86 million (post-tax $40 million) and $21 million
(post-tax $6 million), respectively.
Considering the discount rates, the Group believes a 1 per cent increase in the post-tax discount rate is considered to be a reasonable
possibility for the purpose of sensitivity analysis. A 1 per cent increase in the post-tax discount rate would lead to a further pre-tax
impairment of $24 million (post-tax $11 million), and a 1 per cent decrease in the post-tax discount rate would have no impact on the
post-tax impairment charge.", "dimensions": { "concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18554": { "value": "Segment reporting
The Group\u2019s activities consist of one class of business being the acquisition, exploration, development and production of oil and gas
reserves and related activities and are split geographically and managed in two Business Units: namely \u2018North Sea\u2019 and \u2018International\u2019.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSegmentReportingExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18560": { "value": "Joint arrangements
A joint arrangement is one in which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an
arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
Exploration and production operations are usually conducted through joint arrangements with other parties. The Group reviews all joint
arrangements and classi\ufb01es them as either joint operations or joint ventures depending on the rights and obligations of each party to the
arrangement and whether the arrangement is structured through a separate vehicle. The Group\u2019s interest in joint operations, such as
exploration and production arrangements, are accounted for by recognising its:
\u2022
Assets, including its share of any assets held jointly
\u2022
Liabilities, including its share of any liabilities incurred jointly
\u2022
Revenue from the sale of its share of the output arising from the joint operation
\u2022
Expenses, including its share of any expenses incurred jointly
A joint venture, which normally involves the establishment of a separate legal entity, is a contractual arrangement whereby the parties
that have joint control of the arrangement have the rights to the arrangement\u2019s net assets. The results, assets and liabilities of a joint
venture are incorporated in the consolidated \ufb01nancial statements using the equity method of accounting. During 2023, the Group did
not have any interests in joint ventures.
Where the Group transacts with its joint operations, unrealised pro\ufb01ts and losses are eliminated to the extent of the Group\u2019s interest in
the joint operation.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18561": { "value": "Joint arrangements
A joint arrangement is one in which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an
arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
Exploration and production operations are usually conducted through joint arrangements with other parties. The Group reviews all joint
arrangements and classi\ufb01es them as either joint operations or joint ventures depending on the rights and obligations of each party to the
arrangement and whether the arrangement is structured through a separate vehicle. The Group\u2019s interest in joint operations, such as
exploration and production arrangements, are accounted for by recognising its:
\u2022
Assets, including its share of any assets held jointly
\u2022
Liabilities, including its share of any liabilities incurred jointly
\u2022
Revenue from the sale of its share of the output arising from the joint operation
\u2022
Expenses, including its share of any expenses incurred jointly
A joint venture, which normally involves the establishment of a separate legal entity, is a contractual arrangement whereby the parties
that have joint control of the arrangement have the rights to the arrangement\u2019s net assets. The results, assets and liabilities of a joint
venture are incorporated in the consolidated \ufb01nancial statements using the equity method of accounting. During 2023, the Group did
not have any interests in joint ventures.
Where the Group transacts with its joint operations, unrealised pro\ufb01ts and losses are eliminated to the extent of the Group\u2019s interest in
the joint operation.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociatesAndJointVenturesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18609": { "value": "Foreign currency translation
Each entity in the Group determines its own functional currency, being the currency of the primary economic environment in which the
entity operates, and items included in the \ufb01nancial statements of each entity are measured using that functional currency.
The consolidated \ufb01nancial statements are presented in US dollars, which is also the parent company\u2019s functional currency.
Transactions recorded in foreign currencies are initially recorded in the entity\u2019s functional currency by applying an average rate of
exchange. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency rate of exchange
ruling at the reporting date. All differences are taken to the income statement.
Non-monetary assets and liabilities denominated in foreign currencies are measured at historic cost based on exchange rates at the date
of the initial transaction and subsequently not retranslated.
On consolidation, the assets and liabilities of the Group\u2019s operations are translated at exchange rates prevailing on the balance sheet
date. Income and expense items are translated at the average monthly exchange rates for the year. Equity is held at historic cost and is
not retranslated. The resulting exchange differences are recognised as other comprehensive income and are transferred to the Group\u2019s
currency translation reserve.
When an overseas operation is disposed of, such translation differences relating to it are recognised as income or expense.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18612": { "value": "Each entity in the Group determines its own functional currency, being the currency of the primary economic environment in which the
entity operates, and items included in the \ufb01nancial statements of each entity are measured using that functional currency.
The consolidated \ufb01nancial statements are presented in US dollars, which is also the parent company\u2019s functional currency.
Transactions recorded in foreign currencies are initially recorded in the entity\u2019s functional currency by applying an average rate of
exchange. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency rate of exchange
ruling at the reporting date. All differences are taken to the income statement.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18629": { "value": "Goodwill
In the event of a business combination or acquisition of an interest in a joint operation in which the activity constitutes a business, as de\ufb01ned in
IFRS 3 Business Combinations, the acquisition method of accounting is applied. Goodwill represents the difference between the aggregate
of the fair value of purchase consideration transferred at the acquisition date and the fair value of the identi\ufb01able assets, liabilities and
contingent liabilities acquired. If however, the fair value of the purchase consideration transferred is lower than the fair value of the identi\ufb01able
assets and liabilities acquired, the difference is recognised in the income statement as negative goodwill. Goodwill is initially measured at cost.
Following initial recognition, goodwill is measured at cost less any accumulated impairment. For the purpose of impairment testing, goodwill
acquired in a business combination is, from the acquisition date, allocated to each of the Group\u2019s cash-generating units (CGUs), or groups of
CGUs, which are expected to bene\ufb01t from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned
to those units. Goodwill is treated as an asset of the relevant entity to which it relates and accordingly non-US dollar goodwill is translated
into US dollars at the closing rate of exchange at each reporting date.
Goodwill, as disclosed in note 10, is not amortised but is reviewed for impairment at least annually by assessing the recoverable amount
of the CGUs to which the goodwill relates. Where the carrying amount of the CGU and related goodwill is higher than the recoverable
amount of the CGU, an impairment loss is recognised in the income statement. The recoverable amounts of the CGUs have been
determined on a fair value less costs to sell basis. Impairment losses relating to goodwill cannot be reversed in future periods. Goodwill
acquired through business combinations has been allocated to two CGUs, being North Sea and International.
Intangible oil and gas assets
Pre-licence costs
Pre-licence costs are expensed in the period in which they are incurred.
Licence and property acquisition costs
Licence and property acquisition costs paid in connection with a right to explore in an existing exploration area are capitalised as
exploration and evaluation costs within intangible assets.
Licence and property acquisition costs are reviewed at each reporting date to con\ufb01rm that there is no indication that the carrying amount
exceeds the recoverable amount. If no future activity is planned or the related licence has been relinquished or has expired, the carrying
value of the property acquisition costs is written off through the income statement. Upon recognition of proved reserves and internal
approval for development, the relevant expenditure is transferred to oil and gas properties within development and production assets.
Exploration and evaluation costs
Once the legal right to explore has been acquired, costs directly associated with the exploration are capitalised as exploration and
evaluation (E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential
commercial resources are discovered, the exploration asset is written off.
All such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment
at least annually. This is to con\ufb01rm the continued intent to develop or otherwise extract value from the discovery. When this is no longer
the case, the costs are written off through the income statement.
When proved reserves of oil or natural gas are identi\ufb01ed and development is sanctioned by management, the relevant capitalised
expenditure is \ufb01rst assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is
transferred to oil and gas properties within development and production assets. No amortisation is charged during the exploration
and evaluation phase.
Farm-outs \u2013 in the exploration and evaluation phase
The Group does not record any expenditure made by the farmee on its account. It also does not recognise any gain or loss on its
exploration and evaluation farm-out arrangements but re-designates any costs previously capitalised in relation to the whole interest
as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously
capitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.Intangible assets
Intangible assets principally comprise IT software/licences and carbon allowances. IT software/licences are carried at cost less any
accumulated amortisation. These assets are amortised on a straight-line basis over their useful economic lives of between three and
ten years. Carbon allowances are carried at cost and subject to impairment testing.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18630": { "value": "Goodwill
In the event of a business combination or acquisition of an interest in a joint operation in which the activity constitutes a business, as de\ufb01ned in
IFRS 3 Business Combinations, the acquisition method of accounting is applied. Goodwill represents the difference between the aggregate
of the fair value of purchase consideration transferred at the acquisition date and the fair value of the identi\ufb01able assets, liabilities and
contingent liabilities acquired. If however, the fair value of the purchase consideration transferred is lower than the fair value of the identi\ufb01able
assets and liabilities acquired, the difference is recognised in the income statement as negative goodwill. Goodwill is initially measured at cost.
Following initial recognition, goodwill is measured at cost less any accumulated impairment. For the purpose of impairment testing, goodwill
acquired in a business combination is, from the acquisition date, allocated to each of the Group\u2019s cash-generating units (CGUs), or groups of
CGUs, which are expected to bene\ufb01t from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned
to those units. Goodwill is treated as an asset of the relevant entity to which it relates and accordingly non-US dollar goodwill is translated
into US dollars at the closing rate of exchange at each reporting date.
Goodwill, as disclosed in note 10, is not amortised but is reviewed for impairment at least annually by assessing the recoverable amount
of the CGUs to which the goodwill relates. Where the carrying amount of the CGU and related goodwill is higher than the recoverable
amount of the CGU, an impairment loss is recognised in the income statement. The recoverable amounts of the CGUs have been
determined on a fair value less costs to sell basis. Impairment losses relating to goodwill cannot be reversed in future periods. Goodwill
acquired through business combinations has been allocated to two CGUs, being North Sea and International.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18644": { "value": "Goodwill, as disclosed in note 10, is not amortised but is reviewed for impairment at least annually by assessing the recoverable amount
of the CGUs to which the goodwill relates. Where the carrying amount of the CGU and related goodwill is higher than the recoverable
amount of the CGU, an impairment loss is recognised in the income statement. The recoverable amounts of the CGUs have been
determined on a fair value less costs to sell basis. Impairment losses relating to goodwill cannot be reversed in future periods. Goodwill
acquired through business combinations has been allocated to two CGUs, being North Sea and International.Impairment of non-current assets (excluding goodwill)
In accordance with IAS 36 Impairment of Assets, impairment tests are carried out on items of property, plant and equipment and
intangible assets where there is an indicator of impairment, or an indicator identi\ufb01ed that a prior year impairment may have reversed
or decreased. Such indications may be based on events or changes in the market environment, or on internal sources of information.
Impairment and reversal indicators
Property, plant and equipment and intangible assets with \ufb01nite useful lives are only tested for impairment when there is an indication
that they may be impaired. This is generally the result of signi\ufb01cant changes to the environment in which the assets are operated or when
asset performance is signi\ufb01cantly lower than expected.
The main impairment indicators used by the Group are described below:
\u2022
External sources of information:
\u2013
Signi\ufb01cant changes in the economic, technological, political or market environment in which the entity operates or to which
an asset is dedicated
\u2013
Fall in demand
\u2013
Changes in commodity prices and exchange rates
\u2022
Internal sources of information:
\u2013
Evidence of obsolescence or physical damage
\u2013
Signi\ufb01cantly lower than expected production or cost performance
\u2013
Reduction in reserves and resources, including as a result of unsuccessful results of drilling operations
\u2013
Pending expiry of licence or other rights
\u2013
In respect of capitalised exploration and evaluation costs, lack of planned future activity on the prospect or licence
\u2013
For reversals, plausible downside sensitivity scenarios are run to test the robustness of the asset carrying values
typically against changes in production and commodity prices
Measurement of recoverable amount
The cash-generating unit (CGU) applied for impairment test purposes is generally the \ufb01eld, except that a number of \ufb01eld interests may
be grouped as a single CGU where the cash in\ufb02ows of each \ufb01eld are interdependent. The carrying value of each CGU is compared
against the expected recoverable amount of the asset, which is primarily determined based on the fair value less cost of disposal
(FVLCD) method, where the fair value is determined from the estimated present value of the future net cash \ufb02ows expected to be derived
from production of commercial reserves. Standard valuation techniques are used based on the discount rates that re\ufb02ect the speci\ufb01c
characteristics of the operating entities concerned; discount rates are determined on a post-tax basis and applied to post-tax cash \ufb02ows.
Any impairment loss is recorded in the income statement under \u2018Impairment of property, plant and equipment\u2019. Impairment losses recorded
in relation to property, plant and equipment may be subsequently reversed if the recoverable amount of the assets subsequently increases
above carrying value. The increased carrying amount of an item of property, plant or equipment attributable to a reversal of an impairment
loss may not exceed the carrying amount that would have been determined (net of depreciation/amortisation) had no impairment loss been
recognised in prior periods.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfNonfinancialAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18645": { "value": "Goodwill, as disclosed in note 10, is not amortised but is reviewed for impairment at least annually by assessing the recoverable amount
of the CGUs to which the goodwill relates. Where the carrying amount of the CGU and related goodwill is higher than the recoverable
amount of the CGU, an impairment loss is recognised in the income statement. The recoverable amounts of the CGUs have been
determined on a fair value less costs to sell basis. Impairment losses relating to goodwill cannot be reversed in future periods. Goodwill
acquired through business combinations has been allocated to two CGUs, being North Sea and International.Impairment of non-current assets (excluding goodwill)
In accordance with IAS 36 Impairment of Assets, impairment tests are carried out on items of property, plant and equipment and
intangible assets where there is an indicator of impairment, or an indicator identi\ufb01ed that a prior year impairment may have reversed
or decreased. Such indications may be based on events or changes in the market environment, or on internal sources of information.
Impairment and reversal indicators
Property, plant and equipment and intangible assets with \ufb01nite useful lives are only tested for impairment when there is an indication
that they may be impaired. This is generally the result of signi\ufb01cant changes to the environment in which the assets are operated or when
asset performance is signi\ufb01cantly lower than expected.
The main impairment indicators used by the Group are described below:
\u2022
External sources of information:
\u2013
Signi\ufb01cant changes in the economic, technological, political or market environment in which the entity operates or to which
an asset is dedicated
\u2013
Fall in demand
\u2013
Changes in commodity prices and exchange rates
\u2022
Internal sources of information:
\u2013
Evidence of obsolescence or physical damage
\u2013
Signi\ufb01cantly lower than expected production or cost performance
\u2013
Reduction in reserves and resources, including as a result of unsuccessful results of drilling operations
\u2013
Pending expiry of licence or other rights
\u2013
In respect of capitalised exploration and evaluation costs, lack of planned future activity on the prospect or licence
\u2013
For reversals, plausible downside sensitivity scenarios are run to test the robustness of the asset carrying values
typically against changes in production and commodity prices
Measurement of recoverable amount
The cash-generating unit (CGU) applied for impairment test purposes is generally the \ufb01eld, except that a number of \ufb01eld interests may
be grouped as a single CGU where the cash in\ufb02ows of each \ufb01eld are interdependent. The carrying value of each CGU is compared
against the expected recoverable amount of the asset, which is primarily determined based on the fair value less cost of disposal
(FVLCD) method, where the fair value is determined from the estimated present value of the future net cash \ufb02ows expected to be derived
from production of commercial reserves. Standard valuation techniques are used based on the discount rates that re\ufb02ect the speci\ufb01c
characteristics of the operating entities concerned; discount rates are determined on a post-tax basis and applied to post-tax cash \ufb02ows.
Any impairment loss is recorded in the income statement under \u2018Impairment of property, plant and equipment\u2019. Impairment losses recorded
in relation to property, plant and equipment may be subsequently reversed if the recoverable amount of the assets subsequently increases
above carrying value. The increased carrying amount of an item of property, plant or equipment attributable to a reversal of an impairment
loss may not exceed the carrying amount that would have been determined (net of depreciation/amortisation) had no impairment loss been
recognised in prior periods.Impairment of \ufb01nancial assets
The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through pro\ufb01t or loss.
ECLs are based on the difference between the contractual cash \ufb02ows due in accordance with the contract and all the cash \ufb02ows that the
Group expects to receive, discounted at an approximation of the original effective interest rate.
ECLs are recognised in two stages:
\u2022
12-month ECL: for credit exposures for which there has not been a signi\ufb01cant increase in credit risk since initial recognition, ECLs are
provided for credit losses that result from default events (payment, prospective or covenant) that are possible within the next 12 months
\u2022
Lifetime ECL: for those credit exposures for which there has been a signi\ufb01cant increase in credit risk since initial recognition, a loss
allowance is required for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default
For trade receivables and contract assets, the Group applies a simpli\ufb01ed approach in calculating ECLs as allowed under IFRS 9.
Provision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as
adjusted for forward-looking factors speci\ufb01c to the debtors, the economic environment and the Group\u2019s historical credit loss experience.
Credit impaired \ufb01nancial assets
At each reporting date, the Group assesses whether \ufb01nancial assets carried at amortised cost and debt \ufb01nancial assets carried at FVOCI
are credit impaired. A \ufb01nancial asset is \u2018credit impaired\u2019 when one or more events that have a detrimental impact on the estimated future
cash \ufb02ows of the \ufb01nancial asset have occurred.
Evidence that a \ufb01nancial asset is credit impaired includes the following observable data:
\u2022
Signi\ufb01cant \ufb01nancial dif\ufb01culty of the borrower or issuer
\u2022
A breach of contract such as default or past due event
\u2022
The restructuring of a loan or advance by the Group on terms that the Group would otherwise not consider
\u2022
It is becoming probable that the borrower will enter bankruptcy or other \ufb01nancial reorganisation
\u2022
The disappearance of an active market for a security because of \ufb01nancial dif\ufb01culties", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18656": { "value": "Intangible oil and gas assets
Pre-licence costs
Pre-licence costs are expensed in the period in which they are incurred.
Licence and property acquisition costs
Licence and property acquisition costs paid in connection with a right to explore in an existing exploration area are capitalised as
exploration and evaluation costs within intangible assets.
Licence and property acquisition costs are reviewed at each reporting date to con\ufb01rm that there is no indication that the carrying amount
exceeds the recoverable amount. If no future activity is planned or the related licence has been relinquished or has expired, the carrying
value of the property acquisition costs is written off through the income statement. Upon recognition of proved reserves and internal
approval for development, the relevant expenditure is transferred to oil and gas properties within development and production assets.
Exploration and evaluation costs
Once the legal right to explore has been acquired, costs directly associated with the exploration are capitalised as exploration and
evaluation (E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential
commercial resources are discovered, the exploration asset is written off.
All such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment
at least annually. This is to con\ufb01rm the continued intent to develop or otherwise extract value from the discovery. When this is no longer
the case, the costs are written off through the income statement.
When proved reserves of oil or natural gas are identi\ufb01ed and development is sanctioned by management, the relevant capitalised
expenditure is \ufb01rst assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is
transferred to oil and gas properties within development and production assets. No amortisation is charged during the exploration
and evaluation phase.
Farm-outs \u2013 in the exploration and evaluation phase
The Group does not record any expenditure made by the farmee on its account. It also does not recognise any gain or loss on its
exploration and evaluation farm-out arrangements but re-designates any costs previously capitalised in relation to the whole interest
as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously
capitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.Intangible assets
Intangible assets principally comprise IT software/licences and carbon allowances. IT software/licences are carried at cost less any
accumulated amortisation. These assets are amortised on a straight-line basis over their useful economic lives of between three and
ten years. Carbon allowances are carried at cost and subject to impairment testing.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsOtherThanGoodwillExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18657": { "value": "Intangible oil and gas assets
Pre-licence costs
Pre-licence costs are expensed in the period in which they are incurred.
Licence and property acquisition costs
Licence and property acquisition costs paid in connection with a right to explore in an existing exploration area are capitalised as
exploration and evaluation costs within intangible assets.
Licence and property acquisition costs are reviewed at each reporting date to con\ufb01rm that there is no indication that the carrying amount
exceeds the recoverable amount. If no future activity is planned or the related licence has been relinquished or has expired, the carrying
value of the property acquisition costs is written off through the income statement. Upon recognition of proved reserves and internal
approval for development, the relevant expenditure is transferred to oil and gas properties within development and production assets.
Exploration and evaluation costs
Once the legal right to explore has been acquired, costs directly associated with the exploration are capitalised as exploration and
evaluation (E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential
commercial resources are discovered, the exploration asset is written off.
All such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment
at least annually. This is to con\ufb01rm the continued intent to develop or otherwise extract value from the discovery. When this is no longer
the case, the costs are written off through the income statement.
When proved reserves of oil or natural gas are identi\ufb01ed and development is sanctioned by management, the relevant capitalised
expenditure is \ufb01rst assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is
transferred to oil and gas properties within development and production assets. No amortisation is charged during the exploration
and evaluation phase.
Farm-outs \u2013 in the exploration and evaluation phase
The Group does not record any expenditure made by the farmee on its account. It also does not recognise any gain or loss on its
exploration and evaluation farm-out arrangements but re-designates any costs previously capitalised in relation to the whole interest
as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously
capitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.
Property, plant and equipment \u2013 oil and gas assets
Oil and gas development and production assets are accumulated generally on a \ufb01eld-by-\ufb01eld basis. This represents expenditure on the
construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells,
including E&E expenditures incurred in \ufb01nding commercial reserves transferred from intangible E&E assets, as outlined in the intangible
asset policy above, which is capitalised as oil and gas properties within development and production assets.
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into
operation, the initial estimate of the decommissioning obligation and, for qualifying assets, where relevant, borrowing costs. The purchase
price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
An item of development and production expenditure and any signi\ufb01cant part initially recognised is derecognised upon disposal or when
no future economic bene\ufb01ts are expected. Any gain or loss arising on derecognition of the asset (calculated as the difference between
the net disposal proceeds and the carrying amount of the asset) is included in the income statement.
Expenditure on major maintenance includes re\ufb01ts, inspections or repairs comprising the cost of replacement assets or parts of assets,
inspection costs and overhaul costs. Where an asset, or part of an asset, that was separately depreciated and is now written off is
replaced and it is probable that future economic bene\ufb01ts associated with the item will \ufb02ow to the Group, the expenditure is capitalised.
All other day-to-day repairs and maintenance costs are expensed as incurred.
Depreciation, depletion and amortisation (DD&A) of oil and gas assets
All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is provided
generally on a \ufb01eld-by-\ufb01eld basis, using the unit of production method by reference to the ratio of production in the year and the related
commercial proven and probable reserves of the \ufb01eld, considering future development expenditures necessary to bring those reserves
into production.
When there is a change in the estimated total recoverable proven and probable reserves of a \ufb01eld, that change is accounted for in the
depreciation charge over the revised remaining proven and probable reserves.
Acquisitions, asset purchases and disposals
Acquisitions of oil and gas properties are accounted for using the acquisition method when the assets acquired and liabilities assumed
constitute a business.
Transactions involving the purchase of an individual \ufb01eld interest, or a group of \ufb01eld interests, which do not constitute a business, are
treated as asset purchases irrespective of whether the speci\ufb01c transactions involve the transfer of the \ufb01eld interests directly or the
transfer of an incorporated entity. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to
the assets and liabilities purchased on an appropriate basis.
Proceeds on disposal are applied to the carrying amount of the speci\ufb01c intangible asset or oil and gas property disposed of and any
surplus is recorded as a gain on disposal in the income statement.
Decommissioning
A provision for decommissioning is recognised in full when the related facilities are installed. The amount recognised is the present value
of the estimated future expenditure. A corresponding amount equivalent to the provision is also recognised as part of the cost of the
related oil and gas property. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the
present value of the estimated expenditure is dealt with from the start of the \ufb01nancial year as an adjustment to the opening provision
and the oil and gas property. The unwinding of the discount is included as a \ufb01nance cost.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForOilAndGasAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18709": { "value": "Exploration and evaluation costs
Once the legal right to explore has been acquired, costs directly associated with the exploration are capitalised as exploration and
evaluation (E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential
commercial resources are discovered, the exploration asset is written off.
All such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment
at least annually. This is to con\ufb01rm the continued intent to develop or otherwise extract value from the discovery. When this is no longer
the case, the costs are written off through the income statement.
When proved reserves of oil or natural gas are identi\ufb01ed and development is sanctioned by management, the relevant capitalised
expenditure is \ufb01rst assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is
transferred to oil and gas properties within development and production assets. No amortisation is charged during the exploration
and evaluation phase.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForExplorationAndEvaluationExpenditures", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18730": { "value": "Property, plant and equipment \u2013 oil and gas assets
Oil and gas development and production assets are accumulated generally on a \ufb01eld-by-\ufb01eld basis. This represents expenditure on the
construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells,
including E&E expenditures incurred in \ufb01nding commercial reserves transferred from intangible E&E assets, as outlined in the intangible
asset policy above, which is capitalised as oil and gas properties within development and production assets.
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into
operation, the initial estimate of the decommissioning obligation and, for qualifying assets, where relevant, borrowing costs. The purchase
price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
An item of development and production expenditure and any signi\ufb01cant part initially recognised is derecognised upon disposal or when
no future economic bene\ufb01ts are expected. Any gain or loss arising on derecognition of the asset (calculated as the difference between
the net disposal proceeds and the carrying amount of the asset) is included in the income statement.
Expenditure on major maintenance includes re\ufb01ts, inspections or repairs comprising the cost of replacement assets or parts of assets,
inspection costs and overhaul costs. Where an asset, or part of an asset, that was separately depreciated and is now written off is
replaced and it is probable that future economic bene\ufb01ts associated with the item will \ufb02ow to the Group, the expenditure is capitalised.
All other day-to-day repairs and maintenance costs are expensed as incurred.
Depreciation, depletion and amortisation (DD&A) of oil and gas assets
All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is provided
generally on a \ufb01eld-by-\ufb01eld basis, using the unit of production method by reference to the ratio of production in the year and the related
commercial proven and probable reserves of the \ufb01eld, considering future development expenditures necessary to bring those reserves
into production.
When there is a change in the estimated total recoverable proven and probable reserves of a \ufb01eld, that change is accounted for in the
depreciation charge over the revised remaining proven and probable reserves.
Acquisitions, asset purchases and disposals
Acquisitions of oil and gas properties are accounted for using the acquisition method when the assets acquired and liabilities assumed
constitute a business.
Transactions involving the purchase of an individual \ufb01eld interest, or a group of \ufb01eld interests, which do not constitute a business, are
treated as asset purchases irrespective of whether the speci\ufb01c transactions involve the transfer of the \ufb01eld interests directly or the
transfer of an incorporated entity. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to
the assets and liabilities purchased on an appropriate basis.
Proceeds on disposal are applied to the carrying amount of the speci\ufb01c intangible asset or oil and gas property disposed of and any
surplus is recorded as a gain on disposal in the income statement.
Decommissioning
A provision for decommissioning is recognised in full when the related facilities are installed. The amount recognised is the present value
of the estimated future expenditure. A corresponding amount equivalent to the provision is also recognised as part of the cost of the
related oil and gas property. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the
present value of the estimated expenditure is dealt with from the start of the \ufb01nancial year as an adjustment to the opening provision
and the oil and gas property. The unwinding of the discount is included as a \ufb01nance cost.
Non-oil and gas assets
Property, plant and equipment \u2013 \ufb01xtures and \ufb01ttings and o\ufb03ce equipment
Fixtures and \ufb01ttings and of\ufb01ce equipment is stated at cost less accumulated depreciation and impairment. Depreciation is provided for
on a straight-line basis at rates suf\ufb01cient to write off the cost of the assets less any residual value over their estimated useful economic
lives. The depreciation periods for the principal categories of assets are as follows:
\u2022
Fixtures and \ufb01ttings: Up to 10 years
\u2022
Of\ufb01ce furniture and equipment: Up to 5 years ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18747": { "value": "Depreciation, depletion and amortisation (DD&A) of oil and gas assets
All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is provided
generally on a \ufb01eld-by-\ufb01eld basis, using the unit of production method by reference to the ratio of production in the year and the related
commercial proven and probable reserves of the \ufb01eld, considering future development expenditures necessary to bring those reserves
into production.
When there is a change in the estimated total recoverable proven and probable reserves of a \ufb01eld, that change is accounted for in the
depreciation charge over the revised remaining proven and probable reserves.Fixtures and \ufb01ttings and of\ufb01ce equipment is stated at cost less accumulated depreciation and impairment. Depreciation is provided for
on a straight-line basis at rates suf\ufb01cient to write off the cost of the assets less any residual value over their estimated useful economic
lives. The depreciation periods for the principal categories of assets are as follows:
\u2022
Fixtures and \ufb01ttings: Up to 10 years
\u2022
Of\ufb01ce furniture and equipment: Up to 5 years ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18794": { "value": "Decommissioning
A provision for decommissioning is recognised in full when the related facilities are installed. The amount recognised is the present value
of the estimated future expenditure. A corresponding amount equivalent to the provision is also recognised as part of the cost of the
related oil and gas property. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the
present value of the estimated expenditure is dealt with from the start of the \ufb01nancial year as an adjustment to the opening provision
and the oil and gas property. The unwinding of the discount is included as a \ufb01nance cost.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18914": { "value": "Non-current assets held for sale and discontinued operations
The Group classi\ufb01es non-current assets and disposal groups as assets held for sale if their carrying amounts will be recovered principally
through a sale transaction rather than through continuing use. Non-current assets and disposal groups classi\ufb01ed as held for sale are
measured at the lower of their carrying amount and fair value less costs to sell. Costs to sell are the incremental costs directly attributable
to the disposal group, excluding \ufb01nance costs and income tax expense. The criteria for held for sale classi\ufb01cation is regarded as met only
when the sale is highly probable, and the asset or disposal group is available for immediate sale in its present condition. Management must
be committed to the plan to sell the asset and the sale expected to be completed within one year from the date of the classi\ufb01cation. Actions
required to complete the sale should indicate that it is unlikely that signi\ufb01cant changes to the sale will be made or that the decision to sell
will be withdrawn. Property, plant and equipment and intangible assets are not depreciated or amortised once classi\ufb01ed as assets held for
sale. Assets and liabilities classi\ufb01ed as held for sale are presented separately as current line items in the balance sheet.", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncurrentAssetsHeldForSaleAndDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18927": { "value": "Financial assets
Financial assets are recognised and measured in accordance with IFRS 9 Financial Instruments.
The Group uses two criteria to determine the classi\ufb01cation of \ufb01nancial assets: the Group\u2019s business model and contractual cash \ufb02ow
characteristics of the \ufb01nancial assets. Where appropriate the Group identi\ufb01es three categories of \ufb01nancial assets: amortised cost, fair
value through pro\ufb01t or loss (FVTPL), and fair value through other comprehensive income (FVOCI).
Financial assets held at amortised cost
Financial assets held at amortised cost are initially measured at fair value except for trade debtors which are initially measured at cost.
Both are subsequently carried at amortised cost using the effective interest rate (EIR) method, less impairment. The EIR amortisation
is presented within \ufb01nance income in the income statement.
Cash and cash equivalents
Cash and cash equivalents comprise cash at bank and other short-term highly liquid investments that are readily convertible to a known
amount of cash and are subject to an insigni\ufb01cant risk of changes in value.
Impairment of \ufb01nancial assets
The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through pro\ufb01t or loss.
ECLs are based on the difference between the contractual cash \ufb02ows due in accordance with the contract and all the cash \ufb02ows that the
Group expects to receive, discounted at an approximation of the original effective interest rate.
ECLs are recognised in two stages:
\u2022
12-month ECL: for credit exposures for which there has not been a signi\ufb01cant increase in credit risk since initial recognition, ECLs are
provided for credit losses that result from default events (payment, prospective or covenant) that are possible within the next 12 months
\u2022
Lifetime ECL: for those credit exposures for which there has been a signi\ufb01cant increase in credit risk since initial recognition, a loss
allowance is required for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default
For trade receivables and contract assets, the Group applies a simpli\ufb01ed approach in calculating ECLs as allowed under IFRS 9.
Provision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as
adjusted for forward-looking factors speci\ufb01c to the debtors, the economic environment and the Group\u2019s historical credit loss experience.
Credit impaired \ufb01nancial assets
At each reporting date, the Group assesses whether \ufb01nancial assets carried at amortised cost and debt \ufb01nancial assets carried at FVOCI
are credit impaired. A \ufb01nancial asset is \u2018credit impaired\u2019 when one or more events that have a detrimental impact on the estimated future
cash \ufb02ows of the \ufb01nancial asset have occurred.
Evidence that a \ufb01nancial asset is credit impaired includes the following observable data:
\u2022
Signi\ufb01cant \ufb01nancial dif\ufb01culty of the borrower or issuer
\u2022
A breach of contract such as default or past due event
\u2022
The restructuring of a loan or advance by the Group on terms that the Group would otherwise not consider
\u2022
It is becoming probable that the borrower will enter bankruptcy or other \ufb01nancial reorganisation
\u2022
The disappearance of an active market for a security because of \ufb01nancial dif\ufb01culties
Financial liabilities
Financial liabilities are recognised and measured in accordance with IFRS 9 Financial Instruments.
Financial liabilities are classi\ufb01ed, at initial recognition, as \ufb01nancial liabilities at fair value through pro\ufb01t or loss, loans and borrowings,
payables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. All \ufb01nancial liabilities are recognised
initially at fair value and, in the case of loans, borrowings and payables, net of directly attributable transaction costs which are capitalised
and amortised over the term of the borrowings. Where borrowings have been fully repaid but the borrowing facility remains, directly
attributable transaction costs that remain unamortised are presented within current and/or non-current assets.
Borrowings and loans
Interest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including
premiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement
using the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the
year in which they arise.
Derecognition
A \ufb01nancial liability is derecognised when the obligation under the liability is discharged, cancelled, or expires. When an existing \ufb01nancial
liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially
modi\ufb01ed, such an exchange or modi\ufb01cation is treated as the derecognition of the original liability and the recognition of a new liability.
The difference in the respective carrying amounts is recognised in the income statement.
Derivative \ufb01nancial instruments
The Group uses derivative \ufb01nancial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and
commodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative
\ufb01nancial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative \ufb01nancial instruments are
designated as cash \ufb02ow hedges in line with the Group\u2019s risk management policies. When derivatives do not qualify for hedge accounting
or are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.
A derivative with a positive fair value is recognised as a \ufb01nancial asset whereas a derivative with a negative fair value is recognised as a
\ufb01nancial liability. Derivatives are not offset in the \ufb01nancial statements unless the Group has both a legally enforceable right and intention
to offset. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than
12 months and it is not due to be realised or settled within 12 months. Other derivatives maturing in less than 12 months and expected
to be realised or settled in less than 12 months are presented as current assets or current liabilities.
Cash \ufb02ow hedges
The effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
hedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
transaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
recognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
Any gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
ineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
creditworthiness of the counterparty is signi\ufb01cant and may dominate the transaction and lead to losses.
Fair values
Fair value is de\ufb01ned as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date. It is determined by reference to quoted market prices adjusted for estimated transaction
costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models
and estimated discounted values of cash \ufb02ows.
For \ufb01nancial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques.
Under IFRS 9, embedded derivatives are not separated from a host \ufb01nancial asset, and are classi\ufb01ed based on their contractual terms
and the Group\u2019s business model.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18928": { "value": "Financial assets
Financial assets are recognised and measured in accordance with IFRS 9 Financial Instruments.
The Group uses two criteria to determine the classi\ufb01cation of \ufb01nancial assets: the Group\u2019s business model and contractual cash \ufb02ow
characteristics of the \ufb01nancial assets. Where appropriate the Group identi\ufb01es three categories of \ufb01nancial assets: amortised cost, fair
value through pro\ufb01t or loss (FVTPL), and fair value through other comprehensive income (FVOCI).
Financial assets held at amortised cost
Financial assets held at amortised cost are initially measured at fair value except for trade debtors which are initially measured at cost.
Both are subsequently carried at amortised cost using the effective interest rate (EIR) method, less impairment. The EIR amortisation
is presented within \ufb01nance income in the income statement.
Cash and cash equivalents
Cash and cash equivalents comprise cash at bank and other short-term highly liquid investments that are readily convertible to a known
amount of cash and are subject to an insigni\ufb01cant risk of changes in value.
Impairment of \ufb01nancial assets
The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through pro\ufb01t or loss.
ECLs are based on the difference between the contractual cash \ufb02ows due in accordance with the contract and all the cash \ufb02ows that the
Group expects to receive, discounted at an approximation of the original effective interest rate.
ECLs are recognised in two stages:
\u2022
12-month ECL: for credit exposures for which there has not been a signi\ufb01cant increase in credit risk since initial recognition, ECLs are
provided for credit losses that result from default events (payment, prospective or covenant) that are possible within the next 12 months
\u2022
Lifetime ECL: for those credit exposures for which there has been a signi\ufb01cant increase in credit risk since initial recognition, a loss
allowance is required for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default
For trade receivables and contract assets, the Group applies a simpli\ufb01ed approach in calculating ECLs as allowed under IFRS 9.
Provision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as
adjusted for forward-looking factors speci\ufb01c to the debtors, the economic environment and the Group\u2019s historical credit loss experience.
Credit impaired \ufb01nancial assets
At each reporting date, the Group assesses whether \ufb01nancial assets carried at amortised cost and debt \ufb01nancial assets carried at FVOCI
are credit impaired. A \ufb01nancial asset is \u2018credit impaired\u2019 when one or more events that have a detrimental impact on the estimated future
cash \ufb02ows of the \ufb01nancial asset have occurred.
Evidence that a \ufb01nancial asset is credit impaired includes the following observable data:
\u2022
Signi\ufb01cant \ufb01nancial dif\ufb01culty of the borrower or issuer
\u2022
A breach of contract such as default or past due event
\u2022
The restructuring of a loan or advance by the Group on terms that the Group would otherwise not consider
\u2022
It is becoming probable that the borrower will enter bankruptcy or other \ufb01nancial reorganisation
\u2022
The disappearance of an active market for a security because of \ufb01nancial dif\ufb01culties", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18940": { "value": "Cash and cash equivalents
Cash and cash equivalents comprise cash at bank and other short-term highly liquid investments that are readily convertible to a known
amount of cash and are subject to an insigni\ufb01cant risk of changes in value.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f18946": { "value": "Impairment of \ufb01nancial assets
The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through pro\ufb01t or loss.
ECLs are based on the difference between the contractual cash \ufb02ows due in accordance with the contract and all the cash \ufb02ows that the
Group expects to receive, discounted at an approximation of the original effective interest rate.
ECLs are recognised in two stages:
\u2022
12-month ECL: for credit exposures for which there has not been a signi\ufb01cant increase in credit risk since initial recognition, ECLs are
provided for credit losses that result from default events (payment, prospective or covenant) that are possible within the next 12 months
\u2022
Lifetime ECL: for those credit exposures for which there has been a signi\ufb01cant increase in credit risk since initial recognition, a loss
allowance is required for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default
For trade receivables and contract assets, the Group applies a simpli\ufb01ed approach in calculating ECLs as allowed under IFRS 9.
Provision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as
adjusted for forward-looking factors speci\ufb01c to the debtors, the economic environment and the Group\u2019s historical credit loss experience.
Credit impaired \ufb01nancial assets
At each reporting date, the Group assesses whether \ufb01nancial assets carried at amortised cost and debt \ufb01nancial assets carried at FVOCI
are credit impaired. A \ufb01nancial asset is \u2018credit impaired\u2019 when one or more events that have a detrimental impact on the estimated future
cash \ufb02ows of the \ufb01nancial asset have occurred.
Evidence that a \ufb01nancial asset is credit impaired includes the following observable data:
\u2022
Signi\ufb01cant \ufb01nancial dif\ufb01culty of the borrower or issuer
\u2022
A breach of contract such as default or past due event
\u2022
The restructuring of a loan or advance by the Group on terms that the Group would otherwise not consider
\u2022
It is becoming probable that the borrower will enter bankruptcy or other \ufb01nancial reorganisation
\u2022
The disappearance of an active market for a security because of \ufb01nancial dif\ufb01culties", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfFinancialAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19015": { "value": "Financial liabilities
Financial liabilities are recognised and measured in accordance with IFRS 9 Financial Instruments.
Financial liabilities are classi\ufb01ed, at initial recognition, as \ufb01nancial liabilities at fair value through pro\ufb01t or loss, loans and borrowings,
payables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. All \ufb01nancial liabilities are recognised
initially at fair value and, in the case of loans, borrowings and payables, net of directly attributable transaction costs which are capitalised
and amortised over the term of the borrowings. Where borrowings have been fully repaid but the borrowing facility remains, directly
attributable transaction costs that remain unamortised are presented within current and/or non-current assets.
Borrowings and loans
Interest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including
premiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement
using the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the
year in which they arise.
Derecognition
A \ufb01nancial liability is derecognised when the obligation under the liability is discharged, cancelled, or expires. When an existing \ufb01nancial
liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially
modi\ufb01ed, such an exchange or modi\ufb01cation is treated as the derecognition of the original liability and the recognition of a new liability.
The difference in the respective carrying amounts is recognised in the income statement. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19024": { "value": "Borrowings and loans
Interest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including
premiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement
using the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the
year in which they arise.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19032": { "value": "Derecognition
A \ufb01nancial liability is derecognised when the obligation under the liability is discharged, cancelled, or expires. When an existing \ufb01nancial
liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially
modi\ufb01ed, such an exchange or modi\ufb01cation is treated as the derecognition of the original liability and the recognition of a new liability.
The difference in the respective carrying amounts is recognised in the income statement.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerecognitionOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19041": { "value": "Derivative \ufb01nancial instruments
The Group uses derivative \ufb01nancial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and
commodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative
\ufb01nancial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative \ufb01nancial instruments are
designated as cash \ufb02ow hedges in line with the Group\u2019s risk management policies. When derivatives do not qualify for hedge accounting
or are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.
A derivative with a positive fair value is recognised as a \ufb01nancial asset whereas a derivative with a negative fair value is recognised as a
\ufb01nancial liability. Derivatives are not offset in the \ufb01nancial statements unless the Group has both a legally enforceable right and intention
to offset. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than
12 months and it is not due to be realised or settled within 12 months. Other derivatives maturing in less than 12 months and expected
to be realised or settled in less than 12 months are presented as current assets or current liabilities.
Cash \ufb02ow hedges
The effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
hedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
transaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
recognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
Any gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
ineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
creditworthiness of the counterparty is signi\ufb01cant and may dominate the transaction and lead to losses.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19042": { "value": "Derivative \ufb01nancial instruments
The Group uses derivative \ufb01nancial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and
commodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative
\ufb01nancial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative \ufb01nancial instruments are
designated as cash \ufb02ow hedges in line with the Group\u2019s risk management policies. When derivatives do not qualify for hedge accounting
or are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.
A derivative with a positive fair value is recognised as a \ufb01nancial asset whereas a derivative with a negative fair value is recognised as a
\ufb01nancial liability. Derivatives are not offset in the \ufb01nancial statements unless the Group has both a legally enforceable right and intention
to offset. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than
12 months and it is not due to be realised or settled within 12 months. Other derivatives maturing in less than 12 months and expected
to be realised or settled in less than 12 months are presented as current assets or current liabilities.
Cash \ufb02ow hedges
The effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
hedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
transaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
recognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
Any gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
ineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
creditworthiness of the counterparty is signi\ufb01cant and may dominate the transaction and lead to losses.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19043": { "value": "Derivative \ufb01nancial instruments
The Group uses derivative \ufb01nancial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and
commodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative
\ufb01nancial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative \ufb01nancial instruments are
designated as cash \ufb02ow hedges in line with the Group\u2019s risk management policies. When derivatives do not qualify for hedge accounting
or are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.
A derivative with a positive fair value is recognised as a \ufb01nancial asset whereas a derivative with a negative fair value is recognised as a
\ufb01nancial liability. Derivatives are not offset in the \ufb01nancial statements unless the Group has both a legally enforceable right and intention
to offset. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than
12 months and it is not due to be realised or settled within 12 months. Other derivatives maturing in less than 12 months and expected
to be realised or settled in less than 12 months are presented as current assets or current liabilities.
Cash \ufb02ow hedges
The effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
hedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
transaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
recognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
Any gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
ineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
creditworthiness of the counterparty is signi\ufb01cant and may dominate the transaction and lead to losses.
Fair values
Fair value is de\ufb01ned as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date. It is determined by reference to quoted market prices adjusted for estimated transaction
costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models
and estimated discounted values of cash \ufb02ows.
For \ufb01nancial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques.
Under IFRS 9, embedded derivatives are not separated from a host \ufb01nancial asset, and are classi\ufb01ed based on their contractual terms
and the Group\u2019s business model.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19058": { "value": "Cash \ufb02ow hedges
The effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
hedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
transaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
recognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
Any gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
ineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
creditworthiness of the counterparty is signi\ufb01cant and may dominate the transaction and lead to losses.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19106": { "value": "Fair values
Fair value is de\ufb01ned as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date. It is determined by reference to quoted market prices adjusted for estimated transaction
costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models
and estimated discounted values of cash \ufb02ows.
For \ufb01nancial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques.
Under IFRS 9, embedded derivatives are not separated from a host \ufb01nancial asset, and are classi\ufb01ed based on their contractual terms
and the Group\u2019s business model.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19120": { "value": "Share capital Share capital includes the total net proceeds, both nominal and share premium, on the issue of ordinary and preference shares of the company. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIssuedCapitalExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19124": { "value": "Capital redemption reserve
The capital redemption reserve represents the nominal value of shares transferred following the company\u2019s purchase of them.
Merger reserve
On 31 March 2021, Harbour Energy plc (formerly Premier Oil plc) acquired Chrysaor Holdings Limited as part of a reverse acquisition.
Under the terms of the merger, Premier legally acquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the
acquirer for accounting purposes, primarily as a result of its ability to appoint the Board of the enlarged group. The merger reserve
primarily represents Premier\u2019s opening balance on the legal reserve plus the fair value of the assets and liabilities acquired by Chrysaor.
Cash \ufb02ow hedge reserve
The cash \ufb02ow hedge and cost of hedging reserves represent gains and losses on derivatives classi\ufb01ed as effective cash \ufb02ow hedges.
Upon the designation of option instruments as hedging instruments, the intrinsic and time value components are separated, with only
the intrinsic component being designated as the hedging instrument and the time value component is deferred in other comprehensive
income as a \u2018cost of hedging\u2019.
Currency translation reserve
This reserve comprises exchange differences arising on consolidation of the Group\u2019s operations with a functional currency other than
the US dollar.", "dimensions": { "concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19142": { "value": "Share-based payments
The Group has applied the requirements of IFRS 2 Share-based Payment. The Group has share-based awards that are equity and cash
settled as de\ufb01ned by IFRS 2. The fair value of the equity-settled awards has been determined at the date of grant of the award allowing
for the effect of any market-based conditions. The fair value determined at the grant date of the equity-settled share-based payments is
expensed on a straight-line basis over the vesting period, based on the Group\u2019s estimate of shares that will eventually vest and adjusted
for the effect of non-market based vesting conditions. For cash-settled awards, a liability is recognised for the goods or service acquired.
This is measured initially at the fair value of the liability. The fair value of the liability is subsequently remeasured at each balance sheet
date until the liability is settled, and at the date of settlement, with any changes in fair value recognised in the income statement.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSharebasedPaymentTransactionsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19153": { "value": "Inventories
All inventories, except for petroleum products, are stated at the lower of cost and net realisable value. The cost of materials is the purchase
cost, determined on a weighted average cost basis. Petroleum products and underlift and overlift positions are measured at net realisable
value using an observable year-end oil or gas market price, and are included in other debtors or creditors, respectively.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForMeasuringInventories", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19182": { "value": "Leases
Leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use
by the Group. The \ufb01nance cost is charged to the income statement over the lease period so as to produce a constant periodic rate of
interest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of lease term
and useful life. The Group recognises right-of-use assets and lease liabilities on a gross basis and the recovery of lease costs from joint
operations\u2019 partners is recorded as other income.
Right-of-use assets and lease liabilities arising from a lease are initially measured on a present value basis re\ufb02ecting the net present
value of the \ufb01xed lease payments and amounts expected to be payable by the Group assuming leases run to full term. The Group
has applied judgement to determine the lease term for some lease contracts in which it is a lessee that include renewal options.
The assessment of whether the Group is reasonably certain to exercise such options impacts the lease term, which signi\ufb01cantly
impacts the amount of lease liabilities and right-of-use assets recognised.
\u2022
The lease payments are discounted using the Group\u2019s incremental borrowing rates of between 1.9 per cent and 8.8 per cent, being
the rate that the Group would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic
environment with similar terms and conditions
To determine the incremental borrowing rate, the Group where possible:
\u2022
Uses recent third-party \ufb01nancing received by the individual lessee as a starting point, adjusted to re\ufb02ect changes in \ufb01nancing conditions
since third-party \ufb01nancing was received
\u2022
Makes adjustments speci\ufb01c to the lease, for example term, country, currency and security
The Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in
the lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability
is reassessed and adjusted against the right-of-use asset.
Lease payments are allocated between principal and \ufb01nance cost. The \ufb01nance cost is charged to the income statement over the lease
period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.
Right-of-use assets are measured at cost comprising the following:
\u2022
The amount of the initial measurement of lease liability
\u2022
Any lease payments made at or before the commencement date less any lease incentives received
\u2022
Any initial direct costs and restoration costs
Right-of-use assets are generally depreciated over the shorter of the asset\u2019s estimated useful life and the lease term on a straight-line basis.
Payments associated with short-term leases and leases of low value assets are recognised on a straight-line basis as an expense in the
income statement. Short-term leases are leases with a lease term of 12 months or less.
For lease arrangements where all partners of a joint operation are considered to share the primary responsibility for lease payments
under a lease contract, the Group recognises its share of the respective right-of-use asset and lease liability. This situation is most
common where the parties of a joint operation co-sign the lease contract.
The Group recognises a gross lease liability for leases entered into on behalf of a joint operation where it has primary responsibility
for\u00a0making the lease payments. In such instances, if the arrangement between the Group and the joint operation represents a \ufb01nance
sublease, the Group recognises a net investment in sublease for amounts recoverable from non-operators whilst derecognising the
respective portion of the gross right-of-use asset. The gross lease liability is retained on the balance sheet.
The net investment in sublease is classi\ufb01ed as either trade and other receivables or long-term receivables on the balance sheet
according to whether or not the amounts will be recovered within 12 months of the balance sheet date. Finance income is recognised
in\u00a0respect of net investment in subleases.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19259": { "value": "Provisions for liabilities
A provision is recognised when the Group has a legal or constructive obligation as a result of a past event, it is probable that an out\ufb02ow of resources
embodying economic bene\ufb01ts will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
The expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money
is material, provisions are discounted using a current pre-tax rate that re\ufb02ects, where appropriate, the risk speci\ufb01c to the liability. Where
discounting is used, the increase in the provision due to the passage of time is recognised as part of \ufb01nance costs in the income statement.
The estimated cost of dismantling and restoring the production and related facilities at the end of the economic life of each \ufb01eld is
recognised in full when the related facilities are installed. The amount provided is the present value of the estimated future restoration
cost. A non-current asset is also recognised. Any changes to estimated costs or discount rates are dealt with prospectively.
The Group recognises provision for the estimated CO
2
emissions costs when actual emissions exceed the emission rights granted and
still held. When actual emissions exceed the amount of emission rights granted, provision is recognised for the exceeding emission rights
based on the purchase price of allowance concluded in forward contracts or market quotations at the reporting date.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19276": { "value": "Group retirement bene\ufb01ts
Payments to de\ufb01ned contribution retirement bene\ufb01t plans are charged as an expense as they fall due. Payments made to state-managed
retirement bene\ufb01t schemes are dealt with as payments to de\ufb01ned contribution plans where the Group\u2019s obligations under the schemes
are equivalent to those arising in a de\ufb01ned contribution retirement bene\ufb01t plan.
The Group operates a de\ufb01ned bene\ufb01t pension scheme, which requires contributions to be made to a separately administered fund.
The\u00a0cost of providing bene\ufb01ts is determined using the projected unit credit method, with actuarial valuations being carried out at each
balance sheet date. Actuarial gains and losses are recognised immediately in the statement of comprehensive income.
The retirement bene\ufb01t obligation recognised in the balance sheet represents the present value of the de\ufb01ned bene\ufb01t obligation as
reduced by the fair value of plan assets. Any asset resulting from this calculation is limited to the present value of available refunds
and reductions in future contributions to the plan.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19289": { "value": "Trade payables Initial recognition of trade payables is at fair value. Subsequently they are stated at amortised cost.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19293": { "value": "Taxes
Current tax
Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to
the taxation authorities. The tax rates and laws used to compute the amount are those that are enacted or substantively enacted at the
reporting date in the countries where the Group operates and generates taxable income.
Current income tax related to items recognised directly in other comprehensive income or equity is recognised in other comprehensive
income or directly in equity, not in the income statement.
Deferred tax
Deferred taxation is recognised in respect of all timing differences arising between the tax bases of the assets and liabilities and their
carrying amounts in the \ufb01nancial statements with the following exceptions:
\u2022
Deferred income tax assets are recognised only to the extent that it is probable that the taxable pro\ufb01t will be available against which
the deductible temporary difference, carried forward tax credits or tax losses can be utilised
\u2022
Deferred income tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply when
the related asset is realised or liability is settled, based on tax rates and laws enacted or substantively enacted at the reporting date.
The carrying amount of the deferred income tax asset is reviewed at each balance sheet date and reduced to the extent that it is no
longer probable that suf\ufb01cient taxable pro\ufb01ts will be available to allow all or part of the asset to be recovered. The Group reassesses
any unrecognised deferred tax assets each year taking into account changes in oil and gas prices, the Group\u2019s proven and probable
reserves and resources pro\ufb01le and forecast capital and operating expenditures
\u2022
Deferred income tax assets and liabilities are offset only if a legally enforceable right exists to offset current assets against current tax liabilities,
the deferred income tax relates to the same tax authority and that same tax authority permits the Group to make a single net payment
Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited in other comprehensive
income, in which case the deferred tax is also dealt with in other comprehensive income.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19302": { "value": "Deferred tax
Deferred taxation is recognised in respect of all timing differences arising between the tax bases of the assets and liabilities and their
carrying amounts in the \ufb01nancial statements with the following exceptions:
\u2022
Deferred income tax assets are recognised only to the extent that it is probable that the taxable pro\ufb01t will be available against which
the deductible temporary difference, carried forward tax credits or tax losses can be utilised
\u2022
Deferred income tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply when
the related asset is realised or liability is settled, based on tax rates and laws enacted or substantively enacted at the reporting date.
The carrying amount of the deferred income tax asset is reviewed at each balance sheet date and reduced to the extent that it is no
longer probable that suf\ufb01cient taxable pro\ufb01ts will be available to allow all or part of the asset to be recovered. The Group reassesses
any unrecognised deferred tax assets each year taking into account changes in oil and gas prices, the Group\u2019s proven and probable
reserves and resources pro\ufb01le and forecast capital and operating expenditures
\u2022
Deferred income tax assets and liabilities are offset only if a legally enforceable right exists to offset current assets against current tax liabilities,
the deferred income tax relates to the same tax authority and that same tax authority permits the Group to make a single net payment
Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited in other comprehensive
income, in which case the deferred tax is also dealt with in other comprehensive income.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19346": { "value": "Revenue from contracts with customers
Revenue from contracts with customers is recognised when the Group satis\ufb01es a performance obligation by transferring a good or
service to a customer. A good or service is transferred when the customer obtains control of that good or service. Revenue associated
with the sale of crude oil, natural gas, and natural gas liquids (NGLs) is measured based on the consideration speci\ufb01ed in contracts with
customers with reference to quoted market prices in active markets, adjusted according to speci\ufb01c terms and conditions as applicable
according to the sales contracts. The transfer of control of oil, natural gas, natural gas liquids and other items sold by the Group occurs
when title passes at the point the customer takes physical delivery. The Group principally satis\ufb01es its performance obligations at a point
in time and the amounts of revenue recognised relating to performance obligations satis\ufb01ed over time are not signi\ufb01cant.
Over/underlift
Differences between the production sold and the Group\u2019s share of production result in an overlift or an underlift. Underlift positions are
measured at net realisable value using an observable year-end oil or gas market price. Overlift positions are measured using the sales
price that generated the overlift. Underlift and overlift positions are included in receivables or payables respectively. Movements during
the accounting period are recognised within cost of sales.
Interest income
Interest income is recognised on an accruals basis, by reference to the principal outstanding and at the effective interest rate applicable.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19361": { "value": "Interest income Interest income is recognised on an accruals basis, by reference to the principal outstanding and at the effective interest rate applicable.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInterestIncomeAndExpenseExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19366": { "value": "Borrowing costs
Borrowing costs directly attributable to the acquisition, construction or production of an asset that necessarily takes a substantial period
of time to get ready for its intended use or sale (a qualifying asset) are capitalised as part of the cost of the respective assets. Where
the funds used to \ufb01nance a project form part of general borrowings, the amount capitalised is calculated using a weighted average of
rates applicable to relevant general borrowings of the Group during the period. All other borrowing costs are recognised in the income
statement in the period in which they are incurred.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingCostsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19375": { "value": "New accounting standards and interpretations
The Group applied for the \ufb01rst time certain standards and amendments, which are effective for annual periods beginning on or after
1 January 2023 (unless otherwise stated). The Group has not early adopted any other standard, interpretation or amendment that
has been issued but is not yet effective.
Disclosure of Accounting Policies \u2013 Amendments to IAS 1 and IFRS Practice Statement 2
The amendments to IAS 1 and IFRS Practice Statement 2 Making Materiality Judgements provide guidance and examples to help entities
apply materiality judgements to accounting policy disclosures. The amendments aim to help entities provide accounting policy disclosures
that are more useful by replacing the requirement for entities to disclose their \u2018signi\ufb01cant\u2019 accounting policies with a requirement to
disclose their \u2018material\u2019 accounting policies and adding guidance on how entities apply the concept of materiality in making decisions
about accounting policy disclosures.
The amendments have had an impact on the Group\u2019s disclosures removing accounting policies not considered to be material along with
associated notes, but not on the measurement, recognition or presentation of any items in the Group\u2019s \ufb01nancial statements.
De\ufb01nition of Accounting Estimates \u2013 Amendments to IAS 8
The amendments to IAS 8 clarify the distinction between changes in accounting estimates, changes in accounting policies and the
correction of errors. They also clarify how entities use measurement techniques and inputs to develop accounting estimates.
The amendments had no impact on the Group\u2019s consolidated \ufb01nancial statements.
Deferred Tax related to Assets and Liabilities arising from a Single Transaction \u2013 Amendments to IAS 12
The amendments to IAS 12 Income Tax narrow the scope of the initial recognition exception, so that it no longer applies to transactions
that give rise to equal taxable and deductible temporary differences such as leases and decommissioning liabilities.
The amendments had no impact on the Group\u2019s consolidated \ufb01nancial statements.
International Tax Reform\u2014Pillar Two Model Rules \u2013 Amendments to IAS 12
The amendments to IAS 12 have been introduced in response to the OECD\u2019s BEPS Pillar Two rules and include:
\u2022
a mandatory temporary exception to the recognition and disclosure of deferred taxes arising from the jurisdictional implementation
of the Pillar Two model rules; and
\u2022
disclosure requirements for affected entities to help users of the \ufb01nancial statements better understand an entity\u2019s exposure to
Pillar Two income taxes arising from that legislation, particularly before its effective date.
The mandatory temporary exception \u2013 the use of which is required to be disclosed \u2013 applies immediately. The remaining disclosure
requirements apply for annual reporting periods beginning on or after 1 January 2023, but not for any interim periods ending on or
before 31 December 2023.
IFRS 17 Insurance Contracts
IFRS 17 Insurance Contracts is a comprehensive new accounting standard for insurance contracts covering recognition and
measurement, presentation and disclosure. IFRS 17 replaces IFRS 4 Insurance Contracts. IFRS 17 applies to all types of insurance
contracts (ie life, non-life, direct insurance and re-insurance), regardless of the type of entities that issue them as well as to certain
guarantees and \ufb01nancial instruments with discretionary participation features; a few scope exceptions will apply. The overall objective
of IFRS 17 is to provide a comprehensive accounting model for insurance contracts that is more useful and consistent for insurers,
covering all relevant accounting aspects. IFRS 17 is based on a general model, supplemented by:
\u2022
A speci\ufb01c adaptation for contracts with direct participation features (the variable fee approach)
\u2022
A simpli\ufb01ed approach (the premium allocation approach) mainly for short-duration contracts
The new standard had no impact on the Group\u2019s consolidated \ufb01nancial statements.", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19376": { "value": "New accounting standards and interpretations
The Group applied for the \ufb01rst time certain standards and amendments, which are effective for annual periods beginning on or after
1 January 2023 (unless otherwise stated). The Group has not early adopted any other standard, interpretation or amendment that
has been issued but is not yet effective.
Disclosure of Accounting Policies \u2013 Amendments to IAS 1 and IFRS Practice Statement 2
The amendments to IAS 1 and IFRS Practice Statement 2 Making Materiality Judgements provide guidance and examples to help entities
apply materiality judgements to accounting policy disclosures. The amendments aim to help entities provide accounting policy disclosures
that are more useful by replacing the requirement for entities to disclose their \u2018signi\ufb01cant\u2019 accounting policies with a requirement to
disclose their \u2018material\u2019 accounting policies and adding guidance on how entities apply the concept of materiality in making decisions
about accounting policy disclosures.
The amendments have had an impact on the Group\u2019s disclosures removing accounting policies not considered to be material along with
associated notes, but not on the measurement, recognition or presentation of any items in the Group\u2019s \ufb01nancial statements.
De\ufb01nition of Accounting Estimates \u2013 Amendments to IAS 8
The amendments to IAS 8 clarify the distinction between changes in accounting estimates, changes in accounting policies and the
correction of errors. They also clarify how entities use measurement techniques and inputs to develop accounting estimates.
The amendments had no impact on the Group\u2019s consolidated \ufb01nancial statements.
Deferred Tax related to Assets and Liabilities arising from a Single Transaction \u2013 Amendments to IAS 12
The amendments to IAS 12 Income Tax narrow the scope of the initial recognition exception, so that it no longer applies to transactions
that give rise to equal taxable and deductible temporary differences such as leases and decommissioning liabilities.
The amendments had no impact on the Group\u2019s consolidated \ufb01nancial statements.
International Tax Reform\u2014Pillar Two Model Rules \u2013 Amendments to IAS 12
The amendments to IAS 12 have been introduced in response to the OECD\u2019s BEPS Pillar Two rules and include:
\u2022
a mandatory temporary exception to the recognition and disclosure of deferred taxes arising from the jurisdictional implementation
of the Pillar Two model rules; and
\u2022
disclosure requirements for affected entities to help users of the \ufb01nancial statements better understand an entity\u2019s exposure to
Pillar Two income taxes arising from that legislation, particularly before its effective date.
The mandatory temporary exception \u2013 the use of which is required to be disclosed \u2013 applies immediately. The remaining disclosure
requirements apply for annual reporting periods beginning on or after 1 January 2023, but not for any interim periods ending on or
before 31 December 2023.
IFRS 17 Insurance Contracts
IFRS 17 Insurance Contracts is a comprehensive new accounting standard for insurance contracts covering recognition and
measurement, presentation and disclosure. IFRS 17 replaces IFRS 4 Insurance Contracts. IFRS 17 applies to all types of insurance
contracts (ie life, non-life, direct insurance and re-insurance), regardless of the type of entities that issue them as well as to certain
guarantees and \ufb01nancial instruments with discretionary participation features; a few scope exceptions will apply. The overall objective
of IFRS 17 is to provide a comprehensive accounting model for insurance contracts that is more useful and consistent for insurers,
covering all relevant accounting aspects. IFRS 17 is based on a general model, supplemented by:
\u2022
A speci\ufb01c adaptation for contracts with direct participation features (the variable fee approach)
\u2022
A simpli\ufb01ed approach (the premium allocation approach) mainly for short-duration contracts
The new standard had no impact on the Group\u2019s consolidated \ufb01nancial statements.
Signi\ufb01cant accounting judgements and estimates
The preparation of the Group\u2019s \ufb01nancial statements in conformity with IFRS requires management to make judgements, estimates
and assumptions at the date of the \ufb01nancial statements. Estimates and assumptions are continuously evaluated and are based on
management experience and other factors, including expectations of future events that are believed to be reasonable under the
circumstances. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to
the carrying amount of the assets or liabilities affected in future periods. In particular, the Group has identi\ufb01ed the following areas
where signi\ufb01cant judgement, estimates and assumptions are required.
Judgements
The signi\ufb01cant accounting judgements for the Group are considered to be:
\u2022
the carrying value of intangible exploration and evaluation assets, in relation to whether commercial determination of an exploration
prospect had been reached;
\u2022
the carrying value of property, plant and equipment regarding assessing assets for indicators of impairment;
\u2022
decommissioning costs in relation to the timing of when decommissioning would occur;
\u2022
tax including assessment of risks around tax uncertainties and the recognition of deferred tax assets; and
\u2022
the application of the going concern basis of accounting (see \u2018Basis of preparation\u2019 section above).
Key sources of estimation uncertainty
Details of the Group\u2019s critical accounting estimates are set out in these \ufb01nancial statements and are considered to be:
\u2022
the carrying value of property, plant and equipment and goodwill, where the key assumptions relate to oil and gas prices expected
to be realised, the estimation of 2P reserves and the associated production pro\ufb01les;
\u2022
decommissioning costs where the key assumptions relate to the discount and in\ufb02ation rates applied, applicable rig rates and expected
timing of cessation of production (COP) on each \ufb01eld;
\u2022
the provision for, or disclosure of, areas of uncertainty for tax purposes where the key assumptions are driven by technical analysis
corroborated by external advice; and
\u2022
recognition of net deferred tax liabilities, where key assumptions relate to oil and gas prices expected to be realised, and production pro\ufb01les.
The results from downside sensitivities prepared with regard to production and commodity price assumptions, which in management\u2019s
view re\ufb02ect the principal risks, indicate that material changes that would impact the carrying amounts of assets and liabilities within
the next \ufb01nancial year are unlikely.
Further information is provided in the Audit and Risk Committee report on pages 76 to 79.", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesAccountingEstimatesAndErrorsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19500": { "value": "3. Segment information
The chief operating decision maker, who is responsible for allocating resources and assessing performance of the Group\u2019s business
segments, has been identi\ufb01ed as the Chief Executive Of\ufb01cer.
The Group\u2019s activities consist of one class of business being the acquisition, exploration, development and production of oil and gas
reserves and related activities, and are split geographically and managed in two regions, namely \u2018North Sea\u2019 and \u2018International\u2019. The North
Sea segment includes the UK and Norwegian continental shelves, and the \u2018International\u2019 segment includes Indonesia, Vietnam and Mexico.
Information on major customers can be found in note 4.
Income statement
2023
2022
$ million
$ million
Revenue
North Sea
3,478
5,082
International
237
308
Total Group sales revenue
3,715
5,390
Other income
North Sea
36
41
International
\u2013
\u2013
Total Group revenue and other income
3,751
5,431
Operating pro\ufb01t
North Sea
898
2,388
International
15
153
Group operating pro\ufb01t
913
2,541
Finance income
104
279
Finance expenses
(420)
(358)
Pro\ufb01t before income tax
597
2,462
Income tax expense
(565)
(2,454)
Pro\ufb01t for the \ufb01nancial year
32
8
Balance sheet
2023
2022
$ million
$ million
Segment assets
North Sea
8,632
11,346
International
1,265
1,220
Total assets
9,897
12,566
Segment liabilities
North Sea
(7,818)
(10,938)
International
(539)
(607)
Total liabilities
(8,357)
(11,545)
Other information
\n \n
2023
2022
$ million
$ million
Capital additions
North Sea
611
576
International
110
109
Total capital additions
721
685
Depreciation, depletion and amortisation
North Sea
1,369
1,471
International
61
75
Total depreciation, depletion and amortisation
1,430
1,546
Exploration and evaluation expenses and new ventures
North Sea
36
34
International
\u2013
8
Total exploration and evaluation expenses and new ventures
36
42
Exploration costs written-o\ufb00
North Sea
38
71
International
1
19
(7)
Total exploration costs written-o\ufb00
57
64
1
In 2022, International included a credit to the income statement related to a change to the decommissioning estimate in the Falkland Islands Business Unit.", "dimensions": { "concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19874": { "value": "4. Revenue from contracts with customers and other income \n \n
2023
2022
$ million
$ million
Type of goods
Crude oil sales
2,086
2,792
Gas sales
1,415
2,322
Condensate sales
179
238
Total revenue from contracts with customers
1
3,680
5,352
Tariff income
30
30
Other revenue
5
8
Total revenue from production activities
3,715
5,390
Other income
2
36
41
Total revenue and other income
3,751
5,431
1
Revenues from contracts with customers of $4,591 million (2022: $8,537 million) include crude oil sales of $2,179 million (2022: $3,545 million) and gas sales of $2,233 million
(2022: $4,754 million). This was prior to realised hedging losses in the period of $93 million (2022: $753 million) on crude oil and $818 million (2022: $2,432 million) on gas sales.
2
Other income mainly represents partner recoveries related to lease obligations and, in 2023 a receipt related to the Viking CCS Development Agreement that was signed in March.
Approximately 88 per cent (2022: 84 per cent) of the revenues were attributable to sales to energy trading companies of the Shell group.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19875": { "value": "4. Revenue from contracts with customers and other income \n \n
2023
2022
$ million
$ million
Type of goods
Crude oil sales
2,086
2,792
Gas sales
1,415
2,322
Condensate sales
179
238
Total revenue from contracts with customers
1
3,680
5,352
Tariff income
30
30
Other revenue
5
8
Total revenue from production activities
3,715
5,390
Other income
2
36
41
Total revenue and other income
3,751
5,431
1
Revenues from contracts with customers of $4,591 million (2022: $8,537 million) include crude oil sales of $2,179 million (2022: $3,545 million) and gas sales of $2,233 million
(2022: $4,754 million). This was prior to realised hedging losses in the period of $93 million (2022: $753 million) on crude oil and $818 million (2022: $2,432 million) on gas sales.
2
Other income mainly represents partner recoveries related to lease obligations and, in 2023 a receipt related to the Viking CCS Development Agreement that was signed in March.
Approximately 88 per cent (2022: 84 per cent) of the revenues were attributable to sales to energy trading companies of the Shell group.", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19876": { "value": "4. Revenue from contracts with customers and other income \n \n
2023
2022
$ million
$ million
Type of goods
Crude oil sales
2,086
2,792
Gas sales
1,415
2,322
Condensate sales
179
238
Total revenue from contracts with customers
1
3,680
5,352
Tariff income
30
30
Other revenue
5
8
Total revenue from production activities
3,715
5,390
Other income
2
36
41
Total revenue and other income
3,751
5,431
1
Revenues from contracts with customers of $4,591 million (2022: $8,537 million) include crude oil sales of $2,179 million (2022: $3,545 million) and gas sales of $2,233 million
(2022: $4,754 million). This was prior to realised hedging losses in the period of $93 million (2022: $753 million) on crude oil and $818 million (2022: $2,432 million) on gas sales.
2
Other income mainly represents partner recoveries related to lease obligations and, in 2023 a receipt related to the Viking CCS Development Agreement that was signed in March.
Approximately 88 per cent (2022: 84 per cent) of the revenues were attributable to sales to energy trading companies of the Shell group.", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19877": { "value": "4. Revenue from contracts with customers and other income \n \n
2023
2022
$ million
$ million
Type of goods
Crude oil sales
2,086
2,792
Gas sales
1,415
2,322
Condensate sales
179
238
Total revenue from contracts with customers
1
3,680
5,352
Tariff income
30
30
Other revenue
5
8
Total revenue from production activities
3,715
5,390
Other income
2
36
41
Total revenue and other income
3,751
5,431
1
Revenues from contracts with customers of $4,591 million (2022: $8,537 million) include crude oil sales of $2,179 million (2022: $3,545 million) and gas sales of $2,233 million
(2022: $4,754 million). This was prior to realised hedging losses in the period of $93 million (2022: $753 million) on crude oil and $818 million (2022: $2,432 million) on gas sales.
2
Other income mainly represents partner recoveries related to lease obligations and, in 2023 a receipt related to the Viking CCS Development Agreement that was signed in March.
Approximately 88 per cent (2022: 84 per cent) of the revenues were attributable to sales to energy trading companies of the Shell group.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExpenseExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19988": { "value": "5. Operating pro\ufb01t \n \n
2023
2022
Note
$ million
$ million
Cost of operations
Production, insurance and transportation costs
1,171
1,114
Gas purchases
12
36
Royalties
4
5
Depreciation of oil and gas assets
12
1,192
1,319
Depreciation of right-of-use oil and gas assets
13
230
219
Capitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(27)
(30)
Amortisation of capacity rights
\u2013
1
Movement in over/underlift balances and hydrocarbon inventories
(225)
181
Total cost of operations
2,357
2,845
Impairment expense/(reversal) of property, plant and equipment
12
108
(88)
Impairment loss/(gain) due to increase/(decrease) in decommissioning provisions
on oil and gas tangible assets
12
106
(82)
Impairment of goodwill
10
25
\u2013
Exploration costs written-off
1
11
57
64
Exploration and evaluation expenditure and new ventures
2
36
42
Gain on disposal
3
\u2013
(12)
General and administrative expenses
Depreciation of right-of-use non-oil and gas assets
13
9
11
Depreciation of non-oil and gas assets
12
3
5
Amortisation of non-oil and gas intangible assets
11
23
21
Other administrative costs
4
114
84
Total general and administrative expenses
149
121
Auditor\u2019s remuneration
Audit fees
Fees payable to the company\u2019s auditor for the company\u2019s Annual Report
3
3
Audit of the company\u2019s subsidiaries pursuant to legislation
1
1
Non-audit fees
5
Other services pursuant to legislation \u2013 interim review
\u2013
\u2013
Other services
6
1
1
1
Exploration costs written-off of $57 million (2022: $64 million) includes $13 million related to the Ix-1EXP well in Mexico, $15 million related to the JDE well in Norway, and also includes
costs associated with licence relinquishments and uncommercial well evaluations and $4 million related to an increase in decommissioning provisions in the North Sea (note 11).
2
Exploration and evaluation expenditure and new ventures of $36 million (2022: $42 million) includes $29 million (2022: $28 million) of early project costs on new ventures incurred in
respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $7 million (2022: $13 million) of ongoing pre-licence costs.
3
The gain on disposal in 2022 of $12 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the
period for tax claims to be submitted.
4
Other administrative costs in 2023 include consultancy costs of $33 million (2022: $9 million).
5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the company\u2019s website.
The use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
con\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
6
Other non-audit services in 2023 primarily relate to transaction related activities.", "dimensions": { "concept": "ifrs-full:DisclosureOfProfitLossFromOperatingActivitiesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19989": { "value": "5. Operating pro\ufb01t \n \n
2023
2022
Note
$ million
$ million
Cost of operations
Production, insurance and transportation costs
1,171
1,114
Gas purchases
12
36
Royalties
4
5
Depreciation of oil and gas assets
12
1,192
1,319
Depreciation of right-of-use oil and gas assets
13
230
219
Capitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(27)
(30)
Amortisation of capacity rights
\u2013
1
Movement in over/underlift balances and hydrocarbon inventories
(225)
181
Total cost of operations
2,357
2,845
Impairment expense/(reversal) of property, plant and equipment
12
108
(88)
Impairment loss/(gain) due to increase/(decrease) in decommissioning provisions
on oil and gas tangible assets
12
106
(82)
Impairment of goodwill
10
25
\u2013
Exploration costs written-off
1
11
57
64
Exploration and evaluation expenditure and new ventures
2
36
42
Gain on disposal
3
\u2013
(12)
General and administrative expenses
Depreciation of right-of-use non-oil and gas assets
13
9
11
Depreciation of non-oil and gas assets
12
3
5
Amortisation of non-oil and gas intangible assets
11
23
21
Other administrative costs
4
114
84
Total general and administrative expenses
149
121
Auditor\u2019s remuneration
Audit fees
Fees payable to the company\u2019s auditor for the company\u2019s Annual Report
3
3
Audit of the company\u2019s subsidiaries pursuant to legislation
1
1
Non-audit fees
5
Other services pursuant to legislation \u2013 interim review
\u2013
\u2013
Other services
6
1
1
1
Exploration costs written-off of $57 million (2022: $64 million) includes $13 million related to the Ix-1EXP well in Mexico, $15 million related to the JDE well in Norway, and also includes
costs associated with licence relinquishments and uncommercial well evaluations and $4 million related to an increase in decommissioning provisions in the North Sea (note 11).
2
Exploration and evaluation expenditure and new ventures of $36 million (2022: $42 million) includes $29 million (2022: $28 million) of early project costs on new ventures incurred in
respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $7 million (2022: $13 million) of ongoing pre-licence costs.
3
The gain on disposal in 2022 of $12 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the
period for tax claims to be submitted.
4
Other administrative costs in 2023 include consultancy costs of $33 million (2022: $9 million).
5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the company\u2019s website.
The use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
con\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
6
Other non-audit services in 2023 primarily relate to transaction related activities.", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralAndAdministrativeExpenseExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19990": { "value": "5. Operating pro\ufb01t \n \n
2023
2022
Note
$ million
$ million
Cost of operations
Production, insurance and transportation costs
1,171
1,114
Gas purchases
12
36
Royalties
4
5
Depreciation of oil and gas assets
12
1,192
1,319
Depreciation of right-of-use oil and gas assets
13
230
219
Capitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(27)
(30)
Amortisation of capacity rights
\u2013
1
Movement in over/underlift balances and hydrocarbon inventories
(225)
181
Total cost of operations
2,357
2,845
Impairment expense/(reversal) of property, plant and equipment
12
108
(88)
Impairment loss/(gain) due to increase/(decrease) in decommissioning provisions
on oil and gas tangible assets
12
106
(82)
Impairment of goodwill
10
25
\u2013
Exploration costs written-off
1
11
57
64
Exploration and evaluation expenditure and new ventures
2
36
42
Gain on disposal
3
\u2013
(12)
General and administrative expenses
Depreciation of right-of-use non-oil and gas assets
13
9
11
Depreciation of non-oil and gas assets
12
3
5
Amortisation of non-oil and gas intangible assets
11
23
21
Other administrative costs
4
114
84
Total general and administrative expenses
149
121
Auditor\u2019s remuneration
Audit fees
Fees payable to the company\u2019s auditor for the company\u2019s Annual Report
3
3
Audit of the company\u2019s subsidiaries pursuant to legislation
1
1
Non-audit fees
5
Other services pursuant to legislation \u2013 interim review
\u2013
\u2013
Other services
6
1
1
1
Exploration costs written-off of $57 million (2022: $64 million) includes $13 million related to the Ix-1EXP well in Mexico, $15 million related to the JDE well in Norway, and also includes
costs associated with licence relinquishments and uncommercial well evaluations and $4 million related to an increase in decommissioning provisions in the North Sea (note 11).
2
Exploration and evaluation expenditure and new ventures of $36 million (2022: $42 million) includes $29 million (2022: $28 million) of early project costs on new ventures incurred in
respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $7 million (2022: $13 million) of ongoing pre-licence costs.
3
The gain on disposal in 2022 of $12 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the
period for tax claims to be submitted.
4
Other administrative costs in 2023 include consultancy costs of $33 million (2022: $9 million).
5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the company\u2019s website.
The use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
con\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
6
Other non-audit services in 2023 primarily relate to transaction related activities.
6. Staff costs
\n \n
2023
2022
$ million
$ million
Wages and salaries and other staff costs
325
306
Social security costs
25
30
Pension costs
29
30
Total sta\ufb00 costs
379
366
\n \n
2023
2022
Average annual number of employees employed by the Group worldwide was:
No.
No.
Offshore based
534
559
Of\ufb01ce and administration
1,271
1,273
Total sta\ufb00
1,805
1,832
Staff costs above are recharged to joint venture partners where applicable, or are capitalised to the extent that they are directly
attributable to capital or decommissioning projects. The above costs include share-based payments as disclosed in note 25.
All employees were engaged in the acquisition, exploration, development and production of oil and gas reserves, and energy transition activities.
The Group operates a de\ufb01ned contribution scheme and one de\ufb01ned bene\ufb01t pension scheme for which further details are provided in
note 26.
7. Finance income and \ufb01nance expenses
\n \n
2023
2022
Note
$ million
$ million
Finance income
Bank interest
19
10
Other interest and \ufb01nance gains
6
20
Lease \ufb01nance income
2
2
Realised gains on interest rate swaps
\u2013
6
Realised gains on foreign exchange forward contracts
9
1
Gains on derivatives
1
68
38
Foreign exchange gains
2
\u2013
202
Total \ufb01nance income
104
279
Finance expenses
Interest payable on reserve based lending
15
71
Interest payable on bond
27
27
Other interest and \ufb01nance expenses
17
12
Lease interest
13
51
25
Losses on derivatives
1
\u2013
48
Finance expense on deferred revenue
19
4
20
Foreign exchange losses
57
\u2013
Bank and \ufb01nancing fees
3
100
91
Unwinding of discount on decommissioning and other provisions
20
156
65
427
359
Finance costs capitalised during the year
4
(7)
(1)
Total \ufb01nance expense
420
358
1
Gains and losses on derivatives mainly relates to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2022: $48 million loss on derivatives).
Gains on derivatives in 2022 included mark to market gains on unrealised interest rate and foreign exchange derivatives.
2
In 2022, signi\ufb01cant unrealised foreign exchange gains arose mainly from the revaluation of open gas hedges denominated in sterling.
3
Bank and \ufb01nancing fees include an amount of $48 million (2022: $55 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s long-term
borrowings (note 21).
4
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 6.0 per cent to the
expenditures on the qualifying assets (2022: 4.4 per cent).
8. Income tax
\n \n
2023
2022
$ million
$ million
Current income tax expense
UK corporation tax
641
672
Overseas tax
14
53
Adjustments in respect of prior years
22
(19)
Total current income tax expense
677
706
Deferred tax (credit)/expense
UK corporation tax
1
(74)
1,772
Overseas tax
(18)
(8)
Adjustments in respect of prior years
(20)
(16)
Total deferred tax (credit)/expense
(112)
1,748
Total tax expense reported in the income statement
565
2,454
The tax expense/(credit) in the statement of comprehensive income is as follows:
Tax expense/(credit) on cash \ufb02ow hedges
2,376
(1,006)
1
2022 includes a $1,469 million charge in respect of the revaluation of the deferred tax on the balance sheet due to the introduction of the Energy Pro\ufb01ts Levy.
Reconciliation of tax expense and the accounting pro\ufb01t before taxation multiplied by the statutory rate of corporation tax and supplementary
charge applying to UK oil and gas production operations for the years ended 31 December 2023 and 2022 is as follows:
\n \n
2023
2022
$ million
$ million
Pro\ufb01t before income tax
597
2,462
At the Group\u2019s statutory income tax rate of 75.0% (2022: 55.0%)
448
1,354
E\ufb00ects of:
Expenses/(income) not deductible/(taxable) for tax purposes
101
(12)
Interest not deductible for supplementary charge and Energy Pro\ufb01ts Levy
60
53
Adjustments in respect of prior years
2
(36)
Remeasurement of deferred tax
13
(72)
Deferred Energy Pro\ufb01ts Levy
\u2013
1,469
Impact of different tax rates
(29)
(190)
Expenses not deductible for Energy Pro\ufb01ts Levy
52
8
Energy Pro\ufb01ts Levy investment allowance
(64)
(81)
Investment allowance
(18)
(39)
Total tax expense reported in the consolidated income statement at the e\ufb00ective tax rate of 95% (2022: 100%)
565
2,454
The effective tax rate for the year was 95 per cent, compared to 100 per cent for 2022.
The tax expense reconciliation has been prepared based on the statutory rate of taxation applying to UK oil and gas production because
the majority of Group pro\ufb01t was generated on the UK continental shelf. UK oil and gas production is taxed at a rate of 30 per cent
(2022: 30 per cent), a supplementary charge of 10 per cent (2022: 10 per cent), and with effect from 1 January 2023, the Energy
Pro\ufb01ts Levy (EPL) of 35 per cent (2022: 25 per cent) to give an overall tax rate of 75 per cent (2022: 65 per cent). As the EPL was
introduced part way through the previous \ufb01nancial year, a blended average rate of 55 per cent was applied.
The future effective tax rate is impacted by the mix of jurisdictions in which the Group operates. The UK statutory tax rate for oil and
gas production operations is expected to remain a primary in\ufb02uence on the effective tax rate. The Energy Pro\ufb01ts Levy at the 35 per cent
rate is currently in place until 31 March 2028.
Deferred tax
The principal components of deferred tax are set out in the following tables:
\n \n
2023
2022
Note
$ million
$ million
Deferred tax assets
7
1,406
Deferred tax liabilities
(1,291)
(397)
(1,284)
1,009
Reclassi\ufb01cation of deferred tax liabilities directly associated with assets held for sale
17
31
\u2013
Total deferred tax
(1,253)
1,009
The origination of and reversal of temporary differences are, as shown in the next table, related primarily to movements in the carrying amounts
and tax base values of expenditure and the timing of when these items are charged and/or credited against accounting and taxable pro\ufb01t.
\n \n
Accelerated
capital
Fair value of
allowances
Decommissioning
Losses
derivatives
Other
Overseas
Total
$ million
$ million
$ million
$ million
$ million
$ million
$ million
As at 1 January 2022
(2,820)
2,013
1,314
1,392
39
(187)
1,751
Deferred tax (expense)/credit
(658)
(362)
(745)
49
(40)
8
(1,748)
Comprehensive income
\u2013
\u2013
\u2013
1,006
\u2013
\u2013
1,006
Foreign exchange
82
(86)
\u2013
5
(2)
1
\u2013
As at 31 December 2022
(3,396)
1,565
569
2,452
(3)
(178)
1,009
Deferred tax (expense)/credit
546
(25)
(388)
(61)
22
18
112
Comprehensive expense
\u2013
\u2013
\u2013
(2,376)
1
\u2013
(2,375)
Foreign exchange
(51)
34
\u2013
(9)
1
(5)
(30)
As at 31 December 2023
(2,901)
1,574
181
6
21
(165)
(1,284)
The Group\u2019s deferred tax assets as at 31 December 2023 are recognised to the extent that taxable pro\ufb01ts are expected to arise against
which the tax assets can be utilised. The Group assessed the recoverability of its UK ring fenced losses and allowances using corporate
assumptions which are consistent with the Group\u2019s impairment assessment. Based on those assumptions, the Group expects to fully
utilise its recognised UK tax losses and allowances. The recovery of the Group\u2019s UK decommissioning deferred tax asset is additionally
supported by the ability to carry back decommissioning tax losses and set these against ring fence taxable pro\ufb01ts of prior periods.
The EPL increased to a rate of 35 per cent from 25 per cent with effect from 1 January 2023. The EPL will currently be in place until
31 March 2028. Any temporary differences subject to the EPL expected to reverse in this period have consequently been remeasured to the
higher rate. Ring fence tax losses cannot be offset against pro\ufb01ts subject to EPL nor are deductions given for expenditure incurred on
decommissioning. Consequently, the deferred tax assets representing future decommissioning deductions and ring fence tax losses are not
impacted by EPL with the effect of EPL primarily being on the deferred tax liability associated with accelerated capital allowances. The closing
deferred tax liability for the period of $1,284 million includes $1,014 million of deferred tax liabilities arising from the impact of EPL.
In line with other sensitivity analysis undertaken, we have assessed the impact on the recoverability of deferred tax assets based on an
average -10 per cent to the Harbour scenario average crude price curves. The sensitivity analysis indicates that there would no material
impact to the recoverability of deferred tax assets.
The Group has unrecognised UK tax losses and allowances as at 31 December 2023 of approximately $181 million (2022: $202 million)
in respect of ring fence losses, $138 million (2022: $111 million) in respect of ring fence investment allowance and $803 million
(2022: $807 million) in respect of non-ring fence losses.
The Group also has unrecognised tax losses of approximately $168 million (2022: $157 million) in respect of its international operations.
These losses include amounts of $13 million which will expire within 10 years and $24 million which will expire within \ufb01ve years.
The overseas deferred tax relates mainly to temporary differences associated with \ufb01xed asset balances.
No deferred tax liabilities have been provided on unremitted earnings of overseas subsidiaries, because due to the application of
withholding reliefs under international double taxation treaties and dividend exemptions under UK and Netherlands legislation no
additional taxation is expected to arise on future distribution.
Legislation was introduced in UK Finance Act 2021 to increase the main rate of UK corporation tax for non-ring fence pro\ufb01ts from
19 per cent to 25 per cent from 1 April 2023. This change does not have a material impact on the Group as the UK pro\ufb01ts are primarily
subject to the UK ring fence tax rate.
Global minimum corporation tax rate \u2013 Pillar Two requirements
The legislation implementing the Organisation for Economic Co-operation and Development\u2019s (OECD) proposals for a global minimum
corporation tax rate (Pillar Two) was substantively enacted into UK law on 20 June 2023. The rules have effect from 1 January 2024
and therefore the rules do not impact the Group\u2019s results to 31 December 2023.
The Group has applied the mandatory exception to recognising and disclosing information about the deferred tax assets and liabilities
related to Pillar Two income taxes in accordance with the amendments to IAS 12 published by the IASB on 23 May 2023.
The Group has performed an assessment of the Group\u2019s potential exposure to Pillar Two income taxes for periods from 1 January 2024.
The assessment of the potential exposure to Pillar Two income taxes is based on the most recent tax \ufb01lings, country-by-country reporting
and \ufb01nancial statements for the constituent entities in the Group. Based on the assessment, the Pillar Two effective tax rates in most of
the jurisdictions in which the Group operates are above 15 per cent and the transitional safe harbour relief is expected to apply. On this
basis the Group does not expect a material exposure to Pillar Two income taxes in any jurisdictions.
Uncertain tax positions
During the period an uncertain tax position has been identi\ufb01ed in certain UK subsidiaries relating to the timing of the taxation of fair value
movements and realised gains and losses on hedges entered into in order to manage commodity price risk. On the strength of independent
advice, management considers that there is no expectation of a net additional out\ufb02ow of funds. As such no additional liability has been
recognised in the consolidated \ufb01nancial statements as at 31 December 2023. However, a contingent liability exists as the UK Tax Authorities
could take an alternative view on whether the fair value movements on the hedged instruments are disregarded for tax purposes. While not
considered a likely outcome, if the UK Tax Authorities were to disagree and successfully challenge the position, a possible liability currently
estimated not to exceed $120 million could arise because of the differences in tax rates across the periods in question.", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19991": { "value": "5. Operating pro\ufb01t \n \n
2023
2022
Note
$ million
$ million
Cost of operations
Production, insurance and transportation costs
1,171
1,114
Gas purchases
12
36
Royalties
4
5
Depreciation of oil and gas assets
12
1,192
1,319
Depreciation of right-of-use oil and gas assets
13
230
219
Capitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(27)
(30)
Amortisation of capacity rights
\u2013
1
Movement in over/underlift balances and hydrocarbon inventories
(225)
181
Total cost of operations
2,357
2,845
Impairment expense/(reversal) of property, plant and equipment
12
108
(88)
Impairment loss/(gain) due to increase/(decrease) in decommissioning provisions
on oil and gas tangible assets
12
106
(82)
Impairment of goodwill
10
25
\u2013
Exploration costs written-off
1
11
57
64
Exploration and evaluation expenditure and new ventures
2
36
42
Gain on disposal
3
\u2013
(12)
General and administrative expenses
Depreciation of right-of-use non-oil and gas assets
13
9
11
Depreciation of non-oil and gas assets
12
3
5
Amortisation of non-oil and gas intangible assets
11
23
21
Other administrative costs
4
114
84
Total general and administrative expenses
149
121
Auditor\u2019s remuneration
Audit fees
Fees payable to the company\u2019s auditor for the company\u2019s Annual Report
3
3
Audit of the company\u2019s subsidiaries pursuant to legislation
1
1
Non-audit fees
5
Other services pursuant to legislation \u2013 interim review
\u2013
\u2013
Other services
6
1
1
1
Exploration costs written-off of $57 million (2022: $64 million) includes $13 million related to the Ix-1EXP well in Mexico, $15 million related to the JDE well in Norway, and also includes
costs associated with licence relinquishments and uncommercial well evaluations and $4 million related to an increase in decommissioning provisions in the North Sea (note 11).
2
Exploration and evaluation expenditure and new ventures of $36 million (2022: $42 million) includes $29 million (2022: $28 million) of early project costs on new ventures incurred in
respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $7 million (2022: $13 million) of ongoing pre-licence costs.
3
The gain on disposal in 2022 of $12 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the
period for tax claims to be submitted.
4
Other administrative costs in 2023 include consultancy costs of $33 million (2022: $9 million).
5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the company\u2019s website.
The use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
con\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
6
Other non-audit services in 2023 primarily relate to transaction related activities.", "dimensions": { "concept": "ifrs-full:DisclosureOfCostOfSalesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f19992": { "value": "5. Operating pro\ufb01t \n \n
2023
2022
Note
$ million
$ million
Cost of operations
Production, insurance and transportation costs
1,171
1,114
Gas purchases
12
36
Royalties
4
5
Depreciation of oil and gas assets
12
1,192
1,319
Depreciation of right-of-use oil and gas assets
13
230
219
Capitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(27)
(30)
Amortisation of capacity rights
\u2013
1
Movement in over/underlift balances and hydrocarbon inventories
(225)
181
Total cost of operations
2,357
2,845
Impairment expense/(reversal) of property, plant and equipment
12
108
(88)
Impairment loss/(gain) due to increase/(decrease) in decommissioning provisions
on oil and gas tangible assets
12
106
(82)
Impairment of goodwill
10
25
\u2013
Exploration costs written-off
1
11
57
64
Exploration and evaluation expenditure and new ventures
2
36
42
Gain on disposal
3
\u2013
(12)
General and administrative expenses
Depreciation of right-of-use non-oil and gas assets
13
9
11
Depreciation of non-oil and gas assets
12
3
5
Amortisation of non-oil and gas intangible assets
11
23
21
Other administrative costs
4
114
84
Total general and administrative expenses
149
121
Auditor\u2019s remuneration
Audit fees
Fees payable to the company\u2019s auditor for the company\u2019s Annual Report
3
3
Audit of the company\u2019s subsidiaries pursuant to legislation
1
1
Non-audit fees
5
Other services pursuant to legislation \u2013 interim review
\u2013
\u2013
Other services
6
1
1
1
Exploration costs written-off of $57 million (2022: $64 million) includes $13 million related to the Ix-1EXP well in Mexico, $15 million related to the JDE well in Norway, and also includes
costs associated with licence relinquishments and uncommercial well evaluations and $4 million related to an increase in decommissioning provisions in the North Sea (note 11).
2
Exploration and evaluation expenditure and new ventures of $36 million (2022: $42 million) includes $29 million (2022: $28 million) of early project costs on new ventures incurred in
respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $7 million (2022: $13 million) of ongoing pre-licence costs.
3
The gain on disposal in 2022 of $12 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the
period for tax claims to be submitted.
4
Other administrative costs in 2023 include consultancy costs of $33 million (2022: $9 million).
5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the company\u2019s website.
The use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
con\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
6
Other non-audit services in 2023 primarily relate to transaction related activities.", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f20304": { "value": "6. Staff costs \n \n
2023
2022
$ million
$ million
Wages and salaries and other staff costs
325
306
Social security costs
25
30
Pension costs
29
30
Total sta\ufb00 costs
379
366
\n \n
2023
2022
Average annual number of employees employed by the Group worldwide was:
No.
No.
Offshore based
534
559
Of\ufb01ce and administration
1,271
1,273
Total sta\ufb00
1,805
1,832
Staff costs above are recharged to joint venture partners where applicable, or are capitalised to the extent that they are directly
attributable to capital or decommissioning projects. The above costs include share-based payments as disclosed in note 25.
All employees were engaged in the acquisition, exploration, development and production of oil and gas reserves, and energy transition activities.
The Group operates a de\ufb01ned contribution scheme and one de\ufb01ned bene\ufb01t pension scheme for which further details are provided in
note 26.", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutEmployeesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f20305": { "value": "6. Staff costs \n \n
2023
2022
$ million
$ million
Wages and salaries and other staff costs
325
306
Social security costs
25
30
Pension costs
29
30
Total sta\ufb00 costs
379
366
\n \n
2023
2022
Average annual number of employees employed by the Group worldwide was:
No.
No.
Offshore based
534
559
Of\ufb01ce and administration
1,271
1,273
Total sta\ufb00
1,805
1,832
Staff costs above are recharged to joint venture partners where applicable, or are capitalised to the extent that they are directly
attributable to capital or decommissioning projects. The above costs include share-based payments as disclosed in note 25.
All employees were engaged in the acquisition, exploration, development and production of oil and gas reserves, and energy transition activities.
The Group operates a de\ufb01ned contribution scheme and one de\ufb01ned bene\ufb01t pension scheme for which further details are provided in
note 26.25. Share-based payments
The company currently operates a Long Term Incentive Plan (LTIP) for certain employees and a Share Incentive Plan (SIP), a Save As You Earn
(SAYE) scheme for UK-based employees, and an Expatriate SIP for expatriate employees only.
For the year ended 31 December 2023, the total cost recognised by the company for share-based payment transactions was $46 million
(2022: $36 million). A credit of $46 million (2022: $36 million) has been recorded in retained earnings for all equity-settled payments of
the company.
Like other elements of remuneration, this charge is processed through the time-writing system which allocates cost, based on time spent
by individuals, to various entities within the Group. Part of this cost is therefore recharged to the relevant subsidiary undertakings, part is
capitalised as directly attributable to capital projects and part is charged to the income statement as operating costs, pre-licence
exploration costs or general and administration costs.
Details of the various share incentive plans currently in operation are set out below.
2017 Long Term Incentive Plan (2017 LTIP)
Discretionary share awards are granted to employees under the company\u2019s Long Term Incentive Plan (LTIP).
The following types of award have been granted under the 2017 LTIP:
\u2022
Performance share awards (PSAs):
vesting is subject to a Performance Target, normally measured over a three-year period from 1\u00a0January
based on total shareholder return (TSR) relative to (i) the FTSE 100 index, and (ii) a bespoke peer group of oil and gas companies, and aligns
to longer-term strategic objectives
\u2022
Conditional share awards (CSAs):
vesting is only subject to continued employment
\u2022
Deferred bonus share (DBS) awards:
certain employees are required to defer a portion of their annual bonus into shares which vest
over a three-year period subject to continued employment
All LTIP awards are granted in the form of nil-cost options or conditional share awards and therefore there is no exercise price payable
on the exercise of these awards.
For further details of the LTIP awards, including the performance conditions of the PSAs granted in 2023, please refer to the Directors\u2019
remuneration report (page 97).
The following table shows the movement in the number of LTIP awards:
\n \n
2023
2022
million shares
million shares
Outstanding at 1 January
27.8
20.5
Granted
15.1
10.3
Vested
(8.7)
(1.6)
Forfeited
(0.5)
(1.4)
Outstanding at 31 December
1
33.7
27.8
1
This includes 0.6 million cash settled awards at 31 December 2023 (2022: 1.6 million), which are revalued using the year-end share price.
LTIP awards totalling 8.7 million shares were vested during the period. The weighted average remaining contractual life of the LTIP awards
at 31 December 2023 was 2.2 years (2022: 1.5 years).
Key assumptions used to calculate the fair value of awards
The fair value of PSAs which are subject to TSR conditions is determined using a Monte Carlo simulation. The fair value of all other
awards is calculated using the share price at the date of grant, adjusted for dividends not received during the vesting period.
The following table lists the inputs to the model used in respect of the PSAs granted during the \ufb01nancial year:
2023
2022
Share price at date of grant
\u00a32.44 \u2013 \u00a32.90
\u00a35.00 \u2013 \u00a35.19
Dividend yield
0%
0%
Expected term
2.9 \u2013 3.0 years
3.0 years
Risk free rate
3.3% \u2013 4.2%
1.4% \u2013 1.6%
Share price volatility of the company
49.2% \u2013 50.2%
50.5% \u2013 51.3%
The weighted average fair value of the PSAs granted in 2023 was $2.86 (2022: $4.02).
Expected volatility was determined by reference to both the historical volatility of the company and the historical volatility of a group
of comparable quoted companies over a period in line with the expected term assumption.
Share Incentive Plan (SIP)
Under the SIP, employees are invited to make contributions to buy partnership shares. If an employee agrees to buy partnership shares
the company currently matches the number of partnership shares bought with an award of shares (matching shares), on a one-for-one
basis. In 2023, 0.3 million matching shares were awarded to employees (2022: 0.4 million). The SIP matching shares are valued based
on the quoted share price on the grant date.
Save As You Earn (SAYE) scheme
Under the SAYE scheme, UK qualifying employees with one month or more continuous service can join the scheme. Under the SAYE
scheme, employees can save up to a maximum of \u00a3500 per month through payroll deductions for a period of three years, after which
time they can acquire shares at the option price, which is set at a discount of up to 20 per cent to the prevailing market price at the
grant date, determined in accordance with SAYE scheme rules. In 2023, 3.1 million SAYE options were granted (2022: 1.6 million).
The SAYE options outstanding at 31 December 2023 had exercise prices ranging from \u00a32.21 to \u00a34.12 (2022: \u00a34.12 to \u00a35.53) and
a weighted average remaining contractual life of 2.8 years (2022: 2.8 years).
26. Group pension schemes
De\ufb01ned contribution schemes
The Group operates de\ufb01ned contribution retirement bene\ufb01t schemes. The only obligation of the Group with respect to the retirement
bene\ufb01t schemes is to make speci\ufb01ed contributions. Payments to the de\ufb01ned contribution schemes are charged as an expense as they
fall due. The total cost charged to income of $29 million (2022: $30 million) represents contributions payable to these schemes by the
Group at rates speci\ufb01ed in the rules of the schemes.", "dimensions": { "concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f20392": { "value": "7. Finance income and \ufb01nance expenses \n \n
2023
2022
Note
$ million
$ million
Finance income
Bank interest
19
10
Other interest and \ufb01nance gains
6
20
Lease \ufb01nance income
2
2
Realised gains on interest rate swaps
\u2013
6
Realised gains on foreign exchange forward contracts
9
1
Gains on derivatives
1
68
38
Foreign exchange gains
2
\u2013
202
Total \ufb01nance income
104
279
Finance expenses
Interest payable on reserve based lending
15
71
Interest payable on bond
27
27
Other interest and \ufb01nance expenses
17
12
Lease interest
13
51
25
Losses on derivatives
1
\u2013
48
Finance expense on deferred revenue
19
4
20
Foreign exchange losses
57
\u2013
Bank and \ufb01nancing fees
3
100
91
Unwinding of discount on decommissioning and other provisions
20
156
65
427
359
Finance costs capitalised during the year
4
(7)
(1)
Total \ufb01nance expense
420
358
1
Gains and losses on derivatives mainly relates to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2022: $48 million loss on derivatives).
Gains on derivatives in 2022 included mark to market gains on unrealised interest rate and foreign exchange derivatives.
2
In 2022, signi\ufb01cant unrealised foreign exchange gains arose mainly from the revaluation of open gas hedges denominated in sterling.
3
Bank and \ufb01nancing fees include an amount of $48 million (2022: $55 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s long-term
borrowings (note 21).
4
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 6.0 per cent to the
expenditures on the qualifying assets (2022: 4.4 per cent).", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f20393": { "value": "7. Finance income and \ufb01nance expenses \n \n
2023
2022
Note
$ million
$ million
Finance income
Bank interest
19
10
Other interest and \ufb01nance gains
6
20
Lease \ufb01nance income
2
2
Realised gains on interest rate swaps
\u2013
6
Realised gains on foreign exchange forward contracts
9
1
Gains on derivatives
1
68
38
Foreign exchange gains
2
\u2013
202
Total \ufb01nance income
104
279
Finance expenses
Interest payable on reserve based lending
15
71
Interest payable on bond
27
27
Other interest and \ufb01nance expenses
17
12
Lease interest
13
51
25
Losses on derivatives
1
\u2013
48
Finance expense on deferred revenue
19
4
20
Foreign exchange losses
57
\u2013
Bank and \ufb01nancing fees
3
100
91
Unwinding of discount on decommissioning and other provisions
20
156
65
427
359
Finance costs capitalised during the year
4
(7)
(1)
Total \ufb01nance expense
420
358
1
Gains and losses on derivatives mainly relates to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2022: $48 million loss on derivatives).
Gains on derivatives in 2022 included mark to market gains on unrealised interest rate and foreign exchange derivatives.
2
In 2022, signi\ufb01cant unrealised foreign exchange gains arose mainly from the revaluation of open gas hedges denominated in sterling.
3
Bank and \ufb01nancing fees include an amount of $48 million (2022: $55 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s long-term
borrowings (note 21).
4
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 6.0 per cent to the
expenditures on the qualifying assets (2022: 4.4 per cent).", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f20394": { "value": "7. Finance income and \ufb01nance expenses \n \n
2023
2022
Note
$ million
$ million
Finance income
Bank interest
19
10
Other interest and \ufb01nance gains
6
20
Lease \ufb01nance income
2
2
Realised gains on interest rate swaps
\u2013
6
Realised gains on foreign exchange forward contracts
9
1
Gains on derivatives
1
68
38
Foreign exchange gains
2
\u2013
202
Total \ufb01nance income
104
279
Finance expenses
Interest payable on reserve based lending
15
71
Interest payable on bond
27
27
Other interest and \ufb01nance expenses
17
12
Lease interest
13
51
25
Losses on derivatives
1
\u2013
48
Finance expense on deferred revenue
19
4
20
Foreign exchange losses
57
\u2013
Bank and \ufb01nancing fees
3
100
91
Unwinding of discount on decommissioning and other provisions
20
156
65
427
359
Finance costs capitalised during the year
4
(7)
(1)
Total \ufb01nance expense
420
358
1
Gains and losses on derivatives mainly relates to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2022: $48 million loss on derivatives).
Gains on derivatives in 2022 included mark to market gains on unrealised interest rate and foreign exchange derivatives.
2
In 2022, signi\ufb01cant unrealised foreign exchange gains arose mainly from the revaluation of open gas hedges denominated in sterling.
3
Bank and \ufb01nancing fees include an amount of $48 million (2022: $55 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s long-term
borrowings (note 21).
4
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 6.0 per cent to the
expenditures on the qualifying assets (2022: 4.4 per cent).", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f20395": { "value": "7. Finance income and \ufb01nance expenses \n \n
2023
2022
Note
$ million
$ million
Finance income
Bank interest
19
10
Other interest and \ufb01nance gains
6
20
Lease \ufb01nance income
2
2
Realised gains on interest rate swaps
\u2013
6
Realised gains on foreign exchange forward contracts
9
1
Gains on derivatives
1
68
38
Foreign exchange gains
2
\u2013
202
Total \ufb01nance income
104
279
Finance expenses
Interest payable on reserve based lending
15
71
Interest payable on bond
27
27
Other interest and \ufb01nance expenses
17
12
Lease interest
13
51
25
Losses on derivatives
1
\u2013
48
Finance expense on deferred revenue
19
4
20
Foreign exchange losses
57
\u2013
Bank and \ufb01nancing fees
3
100
91
Unwinding of discount on decommissioning and other provisions
20
156
65
427
359
Finance costs capitalised during the year
4
(7)
(1)
Total \ufb01nance expense
420
358
1
Gains and losses on derivatives mainly relates to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2022: $48 million loss on derivatives).
Gains on derivatives in 2022 included mark to market gains on unrealised interest rate and foreign exchange derivatives.
2
In 2022, signi\ufb01cant unrealised foreign exchange gains arose mainly from the revaluation of open gas hedges denominated in sterling.
3
Bank and \ufb01nancing fees include an amount of $48 million (2022: $55 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s long-term
borrowings (note 21).
4
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 6.0 per cent to the
expenditures on the qualifying assets (2022: 4.4 per cent).", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f20396": { "value": "7. Finance income and \ufb01nance expenses \n \n
2023
2022
Note
$ million
$ million
Finance income
Bank interest
19
10
Other interest and \ufb01nance gains
6
20
Lease \ufb01nance income
2
2
Realised gains on interest rate swaps
\u2013
6
Realised gains on foreign exchange forward contracts
9
1
Gains on derivatives
1
68
38
Foreign exchange gains
2
\u2013
202
Total \ufb01nance income
104
279
Finance expenses
Interest payable on reserve based lending
15
71
Interest payable on bond
27
27
Other interest and \ufb01nance expenses
17
12
Lease interest
13
51
25
Losses on derivatives
1
\u2013
48
Finance expense on deferred revenue
19
4
20
Foreign exchange losses
57
\u2013
Bank and \ufb01nancing fees
3
100
91
Unwinding of discount on decommissioning and other provisions
20
156
65
427
359
Finance costs capitalised during the year
4
(7)
(1)
Total \ufb01nance expense
420
358
1
Gains and losses on derivatives mainly relates to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2022: $48 million loss on derivatives).
Gains on derivatives in 2022 included mark to market gains on unrealised interest rate and foreign exchange derivatives.
2
In 2022, signi\ufb01cant unrealised foreign exchange gains arose mainly from the revaluation of open gas hedges denominated in sterling.
3
Bank and \ufb01nancing fees include an amount of $48 million (2022: $55 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s long-term
borrowings (note 21).
4
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 6.0 per cent to the
expenditures on the qualifying assets (2022: 4.4 per cent).", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f20397": { "value": "7. Finance income and \ufb01nance expenses \n \n
2023
2022
Note
$ million
$ million
Finance income
Bank interest
19
10
Other interest and \ufb01nance gains
6
20
Lease \ufb01nance income
2
2
Realised gains on interest rate swaps
\u2013
6
Realised gains on foreign exchange forward contracts
9
1
Gains on derivatives
1
68
38
Foreign exchange gains
2
\u2013
202
Total \ufb01nance income
104
279
Finance expenses
Interest payable on reserve based lending
15
71
Interest payable on bond
27
27
Other interest and \ufb01nance expenses
17
12
Lease interest
13
51
25
Losses on derivatives
1
\u2013
48
Finance expense on deferred revenue
19
4
20
Foreign exchange losses
57
\u2013
Bank and \ufb01nancing fees
3
100
91
Unwinding of discount on decommissioning and other provisions
20
156
65
427
359
Finance costs capitalised during the year
4
(7)
(1)
Total \ufb01nance expense
420
358
1
Gains and losses on derivatives mainly relates to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2022: $48 million loss on derivatives).
Gains on derivatives in 2022 included mark to market gains on unrealised interest rate and foreign exchange derivatives.
2
In 2022, signi\ufb01cant unrealised foreign exchange gains arose mainly from the revaluation of open gas hedges denominated in sterling.
3
Bank and \ufb01nancing fees include an amount of $48 million (2022: $55 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s long-term
borrowings (note 21).
4
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 6.0 per cent to the
expenditures on the qualifying assets (2022: 4.4 per cent).", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f20639": { "value": "8. Income tax \n \n
2023
2022
$ million
$ million
Current income tax expense
UK corporation tax
641
672
Overseas tax
14
53
Adjustments in respect of prior years
22
(19)
Total current income tax expense
677
706
Deferred tax (credit)/expense
UK corporation tax
1
(74)
1,772
Overseas tax
(18)
(8)
Adjustments in respect of prior years
(20)
(16)
Total deferred tax (credit)/expense
(112)
1,748
Total tax expense reported in the income statement
565
2,454
The tax expense/(credit) in the statement of comprehensive income is as follows:
Tax expense/(credit) on cash \ufb02ow hedges
2,376
(1,006)
1
2022 includes a $1,469 million charge in respect of the revaluation of the deferred tax on the balance sheet due to the introduction of the Energy Pro\ufb01ts Levy.
Reconciliation of tax expense and the accounting pro\ufb01t before taxation multiplied by the statutory rate of corporation tax and supplementary
charge applying to UK oil and gas production operations for the years ended 31 December 2023 and 2022 is as follows:
\n \n
2023
2022
$ million
$ million
Pro\ufb01t before income tax
597
2,462
At the Group\u2019s statutory income tax rate of 75.0% (2022: 55.0%)
448
1,354
E\ufb00ects of:
Expenses/(income) not deductible/(taxable) for tax purposes
101
(12)
Interest not deductible for supplementary charge and Energy Pro\ufb01ts Levy
60
53
Adjustments in respect of prior years
2
(36)
Remeasurement of deferred tax
13
(72)
Deferred Energy Pro\ufb01ts Levy
\u2013
1,469
Impact of different tax rates
(29)
(190)
Expenses not deductible for Energy Pro\ufb01ts Levy
52
8
Energy Pro\ufb01ts Levy investment allowance
(64)
(81)
Investment allowance
(18)
(39)
Total tax expense reported in the consolidated income statement at the e\ufb00ective tax rate of 95% (2022: 100%)
565
2,454
The effective tax rate for the year was 95 per cent, compared to 100 per cent for 2022.
The tax expense reconciliation has been prepared based on the statutory rate of taxation applying to UK oil and gas production because
the majority of Group pro\ufb01t was generated on the UK continental shelf. UK oil and gas production is taxed at a rate of 30 per cent
(2022: 30 per cent), a supplementary charge of 10 per cent (2022: 10 per cent), and with effect from 1 January 2023, the Energy
Pro\ufb01ts Levy (EPL) of 35 per cent (2022: 25 per cent) to give an overall tax rate of 75 per cent (2022: 65 per cent). As the EPL was
introduced part way through the previous \ufb01nancial year, a blended average rate of 55 per cent was applied.
The future effective tax rate is impacted by the mix of jurisdictions in which the Group operates. The UK statutory tax rate for oil and
gas production operations is expected to remain a primary in\ufb02uence on the effective tax rate. The Energy Pro\ufb01ts Levy at the 35 per cent
rate is currently in place until 31 March 2028.
Deferred tax
The principal components of deferred tax are set out in the following tables:
\n \n
2023
2022
Note
$ million
$ million
Deferred tax assets
7
1,406
Deferred tax liabilities
(1,291)
(397)
(1,284)
1,009
Reclassi\ufb01cation of deferred tax liabilities directly associated with assets held for sale
17
31
\u2013
Total deferred tax
(1,253)
1,009
The origination of and reversal of temporary differences are, as shown in the next table, related primarily to movements in the carrying amounts
and tax base values of expenditure and the timing of when these items are charged and/or credited against accounting and taxable pro\ufb01t.
\n \n
Accelerated
capital
Fair value of
allowances
Decommissioning
Losses
derivatives
Other
Overseas
Total
$ million
$ million
$ million
$ million
$ million
$ million
$ million
As at 1 January 2022
(2,820)
2,013
1,314
1,392
39
(187)
1,751
Deferred tax (expense)/credit
(658)
(362)
(745)
49
(40)
8
(1,748)
Comprehensive income
\u2013
\u2013
\u2013
1,006
\u2013
\u2013
1,006
Foreign exchange
82
(86)
\u2013
5
(2)
1
\u2013
As at 31 December 2022
(3,396)
1,565
569
2,452
(3)
(178)
1,009
Deferred tax (expense)/credit
546
(25)
(388)
(61)
22
18
112
Comprehensive expense
\u2013
\u2013
\u2013
(2,376)
1
\u2013
(2,375)
Foreign exchange
(51)
34
\u2013
(9)
1
(5)
(30)
As at 31 December 2023
(2,901)
1,574
181
6
21
(165)
(1,284)
The Group\u2019s deferred tax assets as at 31 December 2023 are recognised to the extent that taxable pro\ufb01ts are expected to arise against
which the tax assets can be utilised. The Group assessed the recoverability of its UK ring fenced losses and allowances using corporate
assumptions which are consistent with the Group\u2019s impairment assessment. Based on those assumptions, the Group expects to fully
utilise its recognised UK tax losses and allowances. The recovery of the Group\u2019s UK decommissioning deferred tax asset is additionally
supported by the ability to carry back decommissioning tax losses and set these against ring fence taxable pro\ufb01ts of prior periods.
The EPL increased to a rate of 35 per cent from 25 per cent with effect from 1 January 2023. The EPL will currently be in place until
31 March 2028. Any temporary differences subject to the EPL expected to reverse in this period have consequently been remeasured to the
higher rate. Ring fence tax losses cannot be offset against pro\ufb01ts subject to EPL nor are deductions given for expenditure incurred on
decommissioning. Consequently, the deferred tax assets representing future decommissioning deductions and ring fence tax losses are not
impacted by EPL with the effect of EPL primarily being on the deferred tax liability associated with accelerated capital allowances. The closing
deferred tax liability for the period of $1,284 million includes $1,014 million of deferred tax liabilities arising from the impact of EPL.
In line with other sensitivity analysis undertaken, we have assessed the impact on the recoverability of deferred tax assets based on an
average -10 per cent to the Harbour scenario average crude price curves. The sensitivity analysis indicates that there would no material
impact to the recoverability of deferred tax assets.
The Group has unrecognised UK tax losses and allowances as at 31 December 2023 of approximately $181 million (2022: $202 million)
in respect of ring fence losses, $138 million (2022: $111 million) in respect of ring fence investment allowance and $803 million
(2022: $807 million) in respect of non-ring fence losses.
The Group also has unrecognised tax losses of approximately $168 million (2022: $157 million) in respect of its international operations.
These losses include amounts of $13 million which will expire within 10 years and $24 million which will expire within \ufb01ve years.
The overseas deferred tax relates mainly to temporary differences associated with \ufb01xed asset balances.
No deferred tax liabilities have been provided on unremitted earnings of overseas subsidiaries, because due to the application of
withholding reliefs under international double taxation treaties and dividend exemptions under UK and Netherlands legislation no
additional taxation is expected to arise on future distribution.
Legislation was introduced in UK Finance Act 2021 to increase the main rate of UK corporation tax for non-ring fence pro\ufb01ts from
19 per cent to 25 per cent from 1 April 2023. This change does not have a material impact on the Group as the UK pro\ufb01ts are primarily
subject to the UK ring fence tax rate.
Global minimum corporation tax rate \u2013 Pillar Two requirements
The legislation implementing the Organisation for Economic Co-operation and Development\u2019s (OECD) proposals for a global minimum
corporation tax rate (Pillar Two) was substantively enacted into UK law on 20 June 2023. The rules have effect from 1 January 2024
and therefore the rules do not impact the Group\u2019s results to 31 December 2023.
The Group has applied the mandatory exception to recognising and disclosing information about the deferred tax assets and liabilities
related to Pillar Two income taxes in accordance with the amendments to IAS 12 published by the IASB on 23 May 2023.
The Group has performed an assessment of the Group\u2019s potential exposure to Pillar Two income taxes for periods from 1 January 2024.
The assessment of the potential exposure to Pillar Two income taxes is based on the most recent tax \ufb01lings, country-by-country reporting
and \ufb01nancial statements for the constituent entities in the Group. Based on the assessment, the Pillar Two effective tax rates in most of
the jurisdictions in which the Group operates are above 15 per cent and the transitional safe harbour relief is expected to apply. On this
basis the Group does not expect a material exposure to Pillar Two income taxes in any jurisdictions.
Uncertain tax positions
During the period an uncertain tax position has been identi\ufb01ed in certain UK subsidiaries relating to the timing of the taxation of fair value
movements and realised gains and losses on hedges entered into in order to manage commodity price risk. On the strength of independent
advice, management considers that there is no expectation of a net additional out\ufb02ow of funds. As such no additional liability has been
recognised in the consolidated \ufb01nancial statements as at 31 December 2023. However, a contingent liability exists as the UK Tax Authorities
could take an alternative view on whether the fair value movements on the hedged instruments are disregarded for tax purposes. While not
considered a likely outcome, if the UK Tax Authorities were to disagree and successfully challenge the position, a possible liability currently
estimated not to exceed $120 million could arise because of the differences in tax rates across the periods in question.", "dimensions": { "concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f20882": { "value": "Deferred tax
The principal components of deferred tax are set out in the following tables:
\n \n
2023
2022
Note
$ million
$ million
Deferred tax assets
7
1,406
Deferred tax liabilities
(1,291)
(397)
(1,284)
1,009
Reclassi\ufb01cation of deferred tax liabilities directly associated with assets held for sale
17
31
\u2013
Total deferred tax
(1,253)
1,009
The origination of and reversal of temporary differences are, as shown in the next table, related primarily to movements in the carrying amounts
and tax base values of expenditure and the timing of when these items are charged and/or credited against accounting and taxable pro\ufb01t.
\n \n
Accelerated
capital
Fair value of
allowances
Decommissioning
Losses
derivatives
Other
Overseas
Total
$ million
$ million
$ million
$ million
$ million
$ million
$ million
As at 1 January 2022
(2,820)
2,013
1,314
1,392
39
(187)
1,751
Deferred tax (expense)/credit
(658)
(362)
(745)
49
(40)
8
(1,748)
Comprehensive income
\u2013
\u2013
\u2013
1,006
\u2013
\u2013
1,006
Foreign exchange
82
(86)
\u2013
5
(2)
1
\u2013
As at 31 December 2022
(3,396)
1,565
569
2,452
(3)
(178)
1,009
Deferred tax (expense)/credit
546
(25)
(388)
(61)
22
18
112
Comprehensive expense
\u2013
\u2013
\u2013
(2,376)
1
\u2013
(2,375)
Foreign exchange
(51)
34
\u2013
(9)
1
(5)
(30)
As at 31 December 2023
(2,901)
1,574
181
6
21
(165)
(1,284)
The Group\u2019s deferred tax assets as at 31 December 2023 are recognised to the extent that taxable pro\ufb01ts are expected to arise against
which the tax assets can be utilised. The Group assessed the recoverability of its UK ring fenced losses and allowances using corporate
assumptions which are consistent with the Group\u2019s impairment assessment. Based on those assumptions, the Group expects to fully
utilise its recognised UK tax losses and allowances. The recovery of the Group\u2019s UK decommissioning deferred tax asset is additionally
supported by the ability to carry back decommissioning tax losses and set these against ring fence taxable pro\ufb01ts of prior periods.
The EPL increased to a rate of 35 per cent from 25 per cent with effect from 1 January 2023. The EPL will currently be in place until
31 March 2028. Any temporary differences subject to the EPL expected to reverse in this period have consequently been remeasured to the
higher rate. Ring fence tax losses cannot be offset against pro\ufb01ts subject to EPL nor are deductions given for expenditure incurred on
decommissioning. Consequently, the deferred tax assets representing future decommissioning deductions and ring fence tax losses are not
impacted by EPL with the effect of EPL primarily being on the deferred tax liability associated with accelerated capital allowances. The closing
deferred tax liability for the period of $1,284 million includes $1,014 million of deferred tax liabilities arising from the impact of EPL.
In line with other sensitivity analysis undertaken, we have assessed the impact on the recoverability of deferred tax assets based on an
average -10 per cent to the Harbour scenario average crude price curves. The sensitivity analysis indicates that there would no material
impact to the recoverability of deferred tax assets.
The Group has unrecognised UK tax losses and allowances as at 31 December 2023 of approximately $181 million (2022: $202 million)
in respect of ring fence losses, $138 million (2022: $111 million) in respect of ring fence investment allowance and $803 million
(2022: $807 million) in respect of non-ring fence losses.
The Group also has unrecognised tax losses of approximately $168 million (2022: $157 million) in respect of its international operations.
These losses include amounts of $13 million which will expire within 10 years and $24 million which will expire within \ufb01ve years.
The overseas deferred tax relates mainly to temporary differences associated with \ufb01xed asset balances.
No deferred tax liabilities have been provided on unremitted earnings of overseas subsidiaries, because due to the application of
withholding reliefs under international double taxation treaties and dividend exemptions under UK and Netherlands legislation no
additional taxation is expected to arise on future distribution.
Legislation was introduced in UK Finance Act 2021 to increase the main rate of UK corporation tax for non-ring fence pro\ufb01ts from
19 per cent to 25 per cent from 1 April 2023. This change does not have a material impact on the Group as the UK pro\ufb01ts are primarily
subject to the UK ring fence tax rate.", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f21226": { "value": "9. Earnings per share (EPS)
Basic EPS is calculated by dividing the pro\ufb01t after tax attributable to ordinary shareholders of the Group by the weighted average number
of ordinary shares in issue during the year.
Diluted EPS is calculated by dividing the pro\ufb01t after tax attributable to ordinary shareholders by the weighted average number of ordinary
shares in issue during the year plus the weighted average number of ordinary shares that would be issued on conversion of all the
dilutive potential ordinary shares into ordinary shares.
The following table re\ufb02ects the income and share data used in the basic and diluted EPS calculations:
2023
2022
Earnings for the year ($ millions)
Earnings for the purpose of basic earnings per share
32
8
Effect of dilutive potential ordinary shares
\u2013
\u2013
Earnings for the purpose of diluted earnings per share
32
8
Number of ordinary shares (millions)
Weighted average number of ordinary shares for the purpose of basic earnings per share
1
804
900
Dilutive potential ordinary shares
2
2
12
Weighted average number of ordinary shares for the purpose of diluted earnings per share
806
912
Earnings per share ($ cents)
Basic
4
1
Diluted
4
1
1
During the current period 76.8 million ordinary shares were repurchased as part of the share buyback programme.
2
Excludes certain share options outstanding at 31 December 2023 as their option price was greater than market price. ", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f21336": { "value": "10. Goodwill
Goodwill represents the difference between the aggregate of the fair value of purchase consideration transferred at the acquisition date
and the fair value of the identi\ufb01able assets.
2023
2022
Cost and net book value
$ million
$ million
At 1 January
1,327
1,327
Impairment charge
(25)
\u2013
At 31 December
1,302
1,327
The goodwill balance consists of balances arising from the completion of the all-share merger between Premier Oil plc and Chrysaor
Holdings Limited in March 2021, on Chrysaor Holdings Limited\u2019s acquisition of the ConocoPhillips UK business, and of the UK North Sea
assets from Shell, which completed on 30 September 2019 and 1 November 2017, respectively.
Goodwill acquired through business combinations has been allocated to two groups of cash-generating units (CGUs), being the North
Sea, of $1,278 million (2022: $1,278 million), and International, of $24 million (2022: $49 million).
Impairment testing of goodwill
In accordance with IAS 36 Impairment of Assets, goodwill is reviewed for impairment at the year end or more frequently if there are
indications that goodwill might be impaired. In assessing whether goodwill has been impaired, the carrying amount of the CGU for
goodwill is compared with its recoverable amount. At the year end, the Group tested for impairment in accordance with the accounting
policy and recognised a goodwill impairment of $25 million in the International CGU (2022: $ nil) related to the Vietnam business being
classed as an asset held for sale as per note 17.
Determining recoverable amount
The recoverable amounts of the CGU and \ufb01elds have been determined on a fair value less costs to sell basis. The key assumptions
used in determining the fair value are often subjective, such as the future long-term oil and gas price assumption, or the operational
performance of the assets. Discounted cash \ufb02ow models comprising asset-by-asset life of \ufb01eld projections using level 3 inputs (based
on the IFRS 13 fair value hierarchy) have been used to determine the recoverable amounts.
The cash \ufb02ows have been modelled on a post-tax and post-decommissioning basis, in\ufb02ated at 2.5 per cent per annum from 1 January 2027,
and discounted at the Group\u2019s post-tax discount rate of between 9.0 per cent and 12.4 per cent (pre-tax 12.0 \u2013 15.5 per cent) (2022: 8.5
\u2013 11.0 per cent post-tax; pre-tax 12.1 per cent \u2013 14.1 per cent). Risks speci\ufb01c to assets within the CGU are re\ufb02ected within the cash \ufb02ow forecasts.
Key assumptions used in calculations
Assumptions involved in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas
prices, discount rates and the level and timing of expenditures, all of which are inherently uncertain.
Commodity and carbon prices
Management\u2019s commodity price curve assumptions are benchmarked against a range of external forward price curves on a regular basis.
The \ufb01rst three years re\ufb02ect the market forward prices curves transitioning to a long-term price thereafter. The long-term commodity prices
and carbon prices are shown in note 2 to the \ufb01nancial statements on page 123.
Production volumes and oil and gas reserves
Based on life of \ufb01eld production pro\ufb01les for each asset within the CGU. Proven and probable reserves are estimates of the amount of
oil and gas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates its reserves using standard
recognised evaluation techniques and they are assessed at least annually by management and by an independent consultant. Proven
and probable reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices.
Costs
Operating expenditure, capital investment and decommissioning costs, which have been in\ufb02ated at 2.5 per cent per annum from
1 January 2027, are derived from the Group\u2019s business plan.
Discount rates
Represent management\u2019s estimate of the Group\u2019s country-based weighted average cost of capital (WACC), considering both debt and
equity. The cost of equity is derived from an expected return on investment by the Group\u2019s investors, and the cost of debt is based on
its interest-bearing borrowings. Segment-speci\ufb01c risk is incorporated by applying a beta factor based on publicly available market data.
The discount rate is based on an assessment of a relevant peer group\u2019s post-tax WACC.
Foreign exchange rates
Based on management\u2019s long-term rate assumptions, with reference to a range of underlying economic indicators.
Sensitivity to changes in assumptions used in calculations
The Group has run sensitivities on its long-term commodity price assumptions, which have been based on long-range forecasts from
external \ufb01nancial analysts, using alternate long-term price assumptions, and discount rates. These are considered to be reasonably
possible changes for the purposes of sensitivity analysis. As shown in note 2 to the \ufb01nancial statements the sensitivity analysis on
commodity prices re\ufb02ecting a 10 per cent reduction in the long-term oil and gas price deck applied in the impairment test would result
in a reduction to the goodwill impairment of $4 million. A 1 per cent increase in the discount rate would result in a further impairment
to goodwill of $1 million.", "dimensions": { "concept": "ifrs-full:DisclosureOfGoodwillExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f21337": { "value": "10. Goodwill
Goodwill represents the difference between the aggregate of the fair value of purchase consideration transferred at the acquisition date
and the fair value of the identi\ufb01able assets.
2023
2022
Cost and net book value
$ million
$ million
At 1 January
1,327
1,327
Impairment charge
(25)
\u2013
At 31 December
1,302
1,327
The goodwill balance consists of balances arising from the completion of the all-share merger between Premier Oil plc and Chrysaor
Holdings Limited in March 2021, on Chrysaor Holdings Limited\u2019s acquisition of the ConocoPhillips UK business, and of the UK North Sea
assets from Shell, which completed on 30 September 2019 and 1 November 2017, respectively.
Goodwill acquired through business combinations has been allocated to two groups of cash-generating units (CGUs), being the North
Sea, of $1,278 million (2022: $1,278 million), and International, of $24 million (2022: $49 million).
Impairment testing of goodwill
In accordance with IAS 36 Impairment of Assets, goodwill is reviewed for impairment at the year end or more frequently if there are
indications that goodwill might be impaired. In assessing whether goodwill has been impaired, the carrying amount of the CGU for
goodwill is compared with its recoverable amount. At the year end, the Group tested for impairment in accordance with the accounting
policy and recognised a goodwill impairment of $25 million in the International CGU (2022: $ nil) related to the Vietnam business being
classed as an asset held for sale as per note 17.
Determining recoverable amount
The recoverable amounts of the CGU and \ufb01elds have been determined on a fair value less costs to sell basis. The key assumptions
used in determining the fair value are often subjective, such as the future long-term oil and gas price assumption, or the operational
performance of the assets. Discounted cash \ufb02ow models comprising asset-by-asset life of \ufb01eld projections using level 3 inputs (based
on the IFRS 13 fair value hierarchy) have been used to determine the recoverable amounts.
The cash \ufb02ows have been modelled on a post-tax and post-decommissioning basis, in\ufb02ated at 2.5 per cent per annum from 1 January 2027,
and discounted at the Group\u2019s post-tax discount rate of between 9.0 per cent and 12.4 per cent (pre-tax 12.0 \u2013 15.5 per cent) (2022: 8.5
\u2013 11.0 per cent post-tax; pre-tax 12.1 per cent \u2013 14.1 per cent). Risks speci\ufb01c to assets within the CGU are re\ufb02ected within the cash \ufb02ow forecasts.
Key assumptions used in calculations
Assumptions involved in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas
prices, discount rates and the level and timing of expenditures, all of which are inherently uncertain.
Commodity and carbon prices
Management\u2019s commodity price curve assumptions are benchmarked against a range of external forward price curves on a regular basis.
The \ufb01rst three years re\ufb02ect the market forward prices curves transitioning to a long-term price thereafter. The long-term commodity prices
and carbon prices are shown in note 2 to the \ufb01nancial statements on page 123.
Production volumes and oil and gas reserves
Based on life of \ufb01eld production pro\ufb01les for each asset within the CGU. Proven and probable reserves are estimates of the amount of
oil and gas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates its reserves using standard
recognised evaluation techniques and they are assessed at least annually by management and by an independent consultant. Proven
and probable reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices.
Costs
Operating expenditure, capital investment and decommissioning costs, which have been in\ufb02ated at 2.5 per cent per annum from
1 January 2027, are derived from the Group\u2019s business plan.
Discount rates
Represent management\u2019s estimate of the Group\u2019s country-based weighted average cost of capital (WACC), considering both debt and
equity. The cost of equity is derived from an expected return on investment by the Group\u2019s investors, and the cost of debt is based on
its interest-bearing borrowings. Segment-speci\ufb01c risk is incorporated by applying a beta factor based on publicly available market data.
The discount rate is based on an assessment of a relevant peer group\u2019s post-tax WACC.
Foreign exchange rates
Based on management\u2019s long-term rate assumptions, with reference to a range of underlying economic indicators.
Sensitivity to changes in assumptions used in calculations
The Group has run sensitivities on its long-term commodity price assumptions, which have been based on long-range forecasts from
external \ufb01nancial analysts, using alternate long-term price assumptions, and discount rates. These are considered to be reasonably
possible changes for the purposes of sensitivity analysis. As shown in note 2 to the \ufb01nancial statements the sensitivity analysis on
commodity prices re\ufb02ecting a 10 per cent reduction in the long-term oil and gas price deck applied in the impairment test would result
in a reduction to the goodwill impairment of $4 million. A 1 per cent increase in the discount rate would result in a further impairment
to goodwill of $1 million.
11. Other intangible assets
Oil and gas
Non-oil and
Carbon
assets
gas assets
1
allowances
2
Total
Note
$ million
$ million
$ million
$ million
Cost
At 1 January 2022
813
119
\u2013
932
Additions during the year
111
31
\u2013
142
Transfers to property, plant and equipment
12
(29)
\u2013
\u2013
(29)
Reduction in decommissioning asset
20
(12)
\u2013
\u2013
(12)
Exploration write-off
3
(64)
\u2013
\u2013
(64)
Currency translation adjustment
(2)
(13)
\u2013
(15)
At 31 December 2022
817
137
\u2013
954
Additions during the year
210
20
\u2013
230
Transfers from property, plant and equipment
12
\u2013
7
\u2013
7
Reclassi\ufb01cation from trade and other receivables
2
\u2013
\u2013
86
86
Increase in decommissioning asset
20
4
\u2013
\u2013
4
Exploration write-off
3
(57)
\u2013
\u2013
(57)
Currency translation adjustment
42
8
\u2013
50
At 31 December 2023
1,016
172
86
1,274
Amortisation
At 1 January 2022
\u2013
60
\u2013
60
Charge for the year
\u2013
21
\u2013
21
Currency translation adjustment
\u2013
(7)
\u2013
(7)
At 31 December 2022
\u2013
74
\u2013
74
Charge for the year
\u2013
23
\u2013
23
Currency translation adjustment
\u2013
5
\u2013
5
At 31 December 2023
\u2013
102
\u2013
102
Net book value
At 31 December 2022
817
63
\u2013
880
At 31 December 2023
1,016
70
86
1,172
1
Non-oil and gas assets relate primarily to Group IT software.
2
On 31 December 2023, the Group reclassi\ufb01ed purchases of UK ETS carbon allowances of $61 million and Voluntary Emissions Reductions (VER) credits of $25 million from trade and
other receivables to intangible assets, $43 million of which are expected to be released to the income statement in the next 12 months.
3
The exploration write-off of $57 million (2022: $64 million) includes $13 million related to the Ix-1EXP well in Mexico, $15 million related to the JDE well in Norway and also includes costs
associated with licence relinquishments and uncommercial well evaluations and $4 million related to an increase in decommissioning provisions in the North Sea (note 20)
(2022: $6 million credit).", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f21459": { "value": "11. Other intangible assets
Oil and gas
Non-oil and
Carbon
assets
gas assets
1
allowances
2
Total
Note
$ million
$ million
$ million
$ million
Cost
At 1 January 2022
813
119
\u2013
932
Additions during the year
111
31
\u2013
142
Transfers to property, plant and equipment
12
(29)
\u2013
\u2013
(29)
Reduction in decommissioning asset
20
(12)
\u2013
\u2013
(12)
Exploration write-off
3
(64)
\u2013
\u2013
(64)
Currency translation adjustment
(2)
(13)
\u2013
(15)
At 31 December 2022
817
137
\u2013
954
Additions during the year
210
20
\u2013
230
Transfers from property, plant and equipment
12
\u2013
7
\u2013
7
Reclassi\ufb01cation from trade and other receivables
2
\u2013
\u2013
86
86
Increase in decommissioning asset
20
4
\u2013
\u2013
4
Exploration write-off
3
(57)
\u2013
\u2013
(57)
Currency translation adjustment
42
8
\u2013
50
At 31 December 2023
1,016
172
86
1,274
Amortisation
At 1 January 2022
\u2013
60
\u2013
60
Charge for the year
\u2013
21
\u2013
21
Currency translation adjustment
\u2013
(7)
\u2013
(7)
At 31 December 2022
\u2013
74
\u2013
74
Charge for the year
\u2013
23
\u2013
23
Currency translation adjustment
\u2013
5
\u2013
5
At 31 December 2023
\u2013
102
\u2013
102
Net book value
At 31 December 2022
817
63
\u2013
880
At 31 December 2023
1,016
70
86
1,172
1
Non-oil and gas assets relate primarily to Group IT software.
2
On 31 December 2023, the Group reclassi\ufb01ed purchases of UK ETS carbon allowances of $61 million and Voluntary Emissions Reductions (VER) credits of $25 million from trade and
other receivables to intangible assets, $43 million of which are expected to be released to the income statement in the next 12 months.
3
The exploration write-off of $57 million (2022: $64 million) includes $13 million related to the Ix-1EXP well in Mexico, $15 million related to the JDE well in Norway and also includes costs
associated with licence relinquishments and uncommercial well evaluations and $4 million related to an increase in decommissioning provisions in the North Sea (note 20)
(2022: $6 million credit).
12. Property, plant and equipment
\n \n
Fixtures and
Oil and gas
\ufb01ttings & of\ufb01ce
assets
equipment
Total
Note
$ million
$ million
$ million
Cost
At 1 January 2022
12,022
30
12,052
Additions
1
532
11
543
Transfers from intangible assets
11
29
\u2013
29
Decrease in decommissioning asset
2
20
(778)
\u2013
(778)
Currency translation adjustment
(369)
(3)
(372)
At 31 December 2022
11,436
38
11,474
Additions
1
482
9
491
Transfers to intangible assets
11
\u2013
(7)
(7)
Reclassi\ufb01cation of asset held for sale
17
(198)
\u2013
(198)
Decrease in decommissioning asset
2
20
(22)
\u2013
(22)
Currency translation adjustment
159
2
161
At 31 December 2023
11,857
42
11,899
Accumulated depreciation
At 1 January 2022
4,785
21
4,806
Charge for the year
1,319
5
1,324
Net impairment reversal
(170)
\u2013
(170)
Currency translation adjustment
(174)
(2)
(176)
At 31 December 2022
5,760
24
5,784
Charge for the year
1,192
3
1,195
Impairment charge
214
\u2013
214
Reclassi\ufb01cation of asset held for sale
17
(103)
\u2013
(103)
Currency translation adjustment
91
1
92
At 31 December 2023
7,154
28
7,182
Net book value
At 31 December 2022
5,676
14
5,690
At 31 December 2023
4,703
14
4,717
1
Included within property, plant and equipment additions of $491 million (2022: $543 million) are associated cash \ufb02ows of $496 million (2022: $477 million) and non-cash \ufb02ow
movements of $5 million (2022: $66 million), represented by a $30 million decrease in capital accruals (2022: $43 million increase), $18 million of capitalised lease depreciation
(2022: $22 million) and $7 million of capitalised interest (2022: $1 million).
2
A decrease in the decommissioning assets of $22 million (2022: $778 million) was made during the year as a result of both an update to the decommissioning estimates and new
obligations (note 20).
During the year, the Group recognised a pre-tax impairment charge of $214 million (post-tax $109 million) (2022: net impairment credit
of $170 million; post-tax $50 million). This comprised a pre-tax impairment charge representing a write-down of property, plant and
equipment assets of $108 million (2022: $163 million) across two CGUs in the UK of $70 million. Of these CGUs, one was driven
primarily by a signi\ufb01cant reduction in the gas price forward curve, and the other by a revised decommissioning cost pro\ufb01le. In addition,
there was a Vietnam fair value impairment on the held for sale asset of $38 million and a pre-tax impairment charge of $106 million
(2022: $82 million credit) in respect of revisions to decommissioning estimates on the Group\u2019s non-producing assets with no remaining
net book value (see note 20).
In 2022, a net pre-tax impairment credit of $170 million was recognised as a result of impairment reversals on North Sea assets of
$251 million driven by a higher forward curve and long-term price assumption for gas, and a pre-tax impairment credit of $82 million
in respect of revisions to decommissioning estimates on the Group\u2019s non-producing assets with no remaining net book value. This was
partially offset by an impairment to property, plant and equipment of $163 million from a single CGU in the UK North Sea, driven primarily
by the contracted price realised for crude sales being negatively impacted by the pricing differential between Urals and Brent crude and
a revised operating cost pro\ufb01le for the \ufb01eld.
Key assumptions used in calculations
Assumptions used in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas
prices, discount rates and the level and timing of expenditures, all of which are inherently uncertain.
Commodity and carbon prices
The Group uses the fair value less cost of disposal method (FVLCD) to calculate the recoverable amount of the cash-generating
units (CGU) consistent with a level 3 fair value measurement (see note 22). In determining the recoverable value, appropriate discounted-
cash-\ufb02ow valuation models were used, incorporating market-based assumptions. Management\u2019s commodity price curve assumptions are
benchmarked against a range of external forward price curves on a regular basis. Individual \ufb01eld price differentials are then applied. The
\ufb01rst three years re\ufb02ect the market forward price curves transitioning to a long-term price from 2027, thereafter in\ufb02ated at 2.5 per cent
per annum. The long-term commodity prices used were $70 per barrel for crude and 90 pence per therm for gas.
Production volumes and oil and gas reserves
Production volumes are based on life of \ufb01eld production pro\ufb01les for each asset within the CGU. Proven and probable reserves are
estimates of the amount of oil and gas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates
its reserves using standard recognised evaluation techniques, assessed at least annually by management. Proven and probable
reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices.
Costs
Operating expenditure, capital expenditure and decommissioning costs are derived from the Group\u2019s business plan. The discount
rate re\ufb02ects management\u2019s estimate of the Group\u2019s country-based weighted average cost of capital (WACC). Foreign exchange rates
are based on management\u2019s long-term rate assumptions, with reference to a range of underlying economic indicators.
Sensitivity to changes in assumptions used in calculations
Reductions or increases in the long-term oil and gas prices of 10 per cent are considered to be reasonably possible changes for the
purpose of sensitivity analysis. As shown in note 2 to the \ufb01nancial statements the decreases to the long-term oil and gas prices from
1 January 2027 speci\ufb01ed above would result in a further pre-tax impairment of $86 million (post-tax $40 million) and $21 million
(post-tax $6 million), respectively.
Considering the discount rates, the Group believes a 1 per cent increase in the post-tax discount rate is considered to be a reasonable
possibility for the purpose of sensitivity analysis. A 1 per cent increase in the post-tax discount rate would lead to a further pre-tax
impairment of $24 million (post-tax $11 million), and a 1 per cent decrease in the post-tax discount rate would have no impact on the
post-tax impairment charge.
13. Leases
This note provides information for leases where the Group is a lessee.
Balance sheet
\n \n
Land and
Offshore
buildings
Drilling rigs
FPSO
facilities
Equipment
Total
Right-of-use assets
Note
$ million
$ million
$ million
$ million
$ million
$ million
Cost
At 1 January 2022
100
153
509
\u2013
18
780
Additions during the year
1
\u2013
\u2013
\u2013
338
\u2013
338
Cost revisions/remeasurements
3
33
53
(4)
4
89
Disposals
(6)
\u2013
\u2013
\u2013
\u2013
(6)
Currency translation adjustment
(9)
(17)
\u2013
\u2013
(2)
(28)
At 31 December 2022
88
169
562
334
20
1,173
Additions during the year
1
25
\u2013
\u2013
\u2013
1
26
Cost revisions/remeasurements
1
48
63
(6)
4
110
Reclassi\ufb01cation as asset held for sale
17
(5)
\u2013
(71)
\u2013
\u2013
(76)
Disposals
(4)
(19)
\u2013
\u2013
\u2013
(23)
Currency translation adjustment
4
10
\u2013
\u2013
1
15
At 31 December 2023
109
208
554
328
26
1,225
Accumulated depreciation
At 1 January 2022
22
98
102
\u2013
7
229
Charge for the year
12
43
107
61
7
230
Disposals
(6)
\u2013
\u2013
\u2013
\u2013
(6)
Currency translation adjustment
(2)
(12)
\u2013
\u2013
(1)
(15)
At 31 December 2022
26
129
209
61
13
438
Charge for the year
9
42
94
89
5
239
Reclassi\ufb01cation of asset held for sale
17
(2)
\u2013
(23)
\u2013
\u2013
(25)
Disposals
(4)
(19)
\u2013
\u2013
\u2013
(23)
Currency translation adjustment
1
7
\u2013
\u2013
1
9
At 31 December 2023
30
159
280
150
19
638
Net book value
At 31 December 2022
62
40
353
273
7
735
At 31 December 2023
79
49
274
178
7
587
1
Additions of $26 million mainly related to new land and buildings were made to the right-of-use assets during the year (2022: total additions of $338 million related to the Tolmount
offshore facilities).
2023
2022
Right-of-use liabilities
Note
$ million
$ million
At 1 January
825
654
Additions
28
338
Remeasurement
110
89
Finance costs charged to income statement
7
51
25
Finance costs charged to decommissioning provision
20
1
1
Reclassi\ufb01cation of liabilities as held for sale
17
(95)
\u2013
Lease payments
(262)
(254)
Currency translation adjustment
15
(28)
At 31 December
673
825
Classi\ufb01ed as
Current
199
221
Non-current
474
604
Total lease liabilities
673
825
The signi\ufb01cant portion of the Group\u2019s lease liabilities represent lease arrangements for an FPSO vessel on the Catcher asset, and
offshore facilities on the Tolmount asset.
The lease liabilities and associated right-of-use-assets have been calculated by reference to in-substance \ufb01xed lease payments in the
underlying agreements incurred throughout the non-cancellable period of the lease along with periods covered by options to extend the
lease where the Group is reasonably certain that such options will be exercised. When assessing whether extension options were likely
to be exercised, assumptions are consistent with those applied when testing for impairment.
Income statement
2023
2022
Depreciation charge of right-of-use assets
Note
$ million
$ million
Land and buildings \u2013 non-oil and gas assets
8
11
Land and buildings \u2013 oil and gas assets
1
1
Drilling rigs
42
43
FPSO
94
107
Offshore facilities
89
61
Equipment \u2013 non-oil and gas assets
1
\u2013
Equipment \u2013 oil and gas assets
4
7
239
230
Capitalisation of IFRS 16 lease depreciation
1
Drilling rigs
(25)
(26)
Equipment
(2)
(4)
Depreciation charge included within the consolidated income statement
212
200
Lease interest
7
51
25
1
Of the $27 million (2022: $30 million) capitalised IFRS 16 lease depreciation, $18 million (2022: $22 million) has been capitalised within property, plant and equipment and $9 million
(2022: $8 million) within provisions (note 20).
The total cash out\ufb02ow for leases in 2023 was $259 million (2022: $254 million).", "dimensions": { "concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f21460": { "value": "11. Other intangible assets
Oil and gas
Non-oil and
Carbon
assets
gas assets
1
allowances
2
Total
Note
$ million
$ million
$ million
$ million
Cost
At 1 January 2022
813
119
\u2013
932
Additions during the year
111
31
\u2013
142
Transfers to property, plant and equipment
12
(29)
\u2013
\u2013
(29)
Reduction in decommissioning asset
20
(12)
\u2013
\u2013
(12)
Exploration write-off
3
(64)
\u2013
\u2013
(64)
Currency translation adjustment
(2)
(13)
\u2013
(15)
At 31 December 2022
817
137
\u2013
954
Additions during the year
210
20
\u2013
230
Transfers from property, plant and equipment
12
\u2013
7
\u2013
7
Reclassi\ufb01cation from trade and other receivables
2
\u2013
\u2013
86
86
Increase in decommissioning asset
20
4
\u2013
\u2013
4
Exploration write-off
3
(57)
\u2013
\u2013
(57)
Currency translation adjustment
42
8
\u2013
50
At 31 December 2023
1,016
172
86
1,274
Amortisation
At 1 January 2022
\u2013
60
\u2013
60
Charge for the year
\u2013
21
\u2013
21
Currency translation adjustment
\u2013
(7)
\u2013
(7)
At 31 December 2022
\u2013
74
\u2013
74
Charge for the year
\u2013
23
\u2013
23
Currency translation adjustment
\u2013
5
\u2013
5
At 31 December 2023
\u2013
102
\u2013
102
Net book value
At 31 December 2022
817
63
\u2013
880
At 31 December 2023
1,016
70
86
1,172
1
Non-oil and gas assets relate primarily to Group IT software.
2
On 31 December 2023, the Group reclassi\ufb01ed purchases of UK ETS carbon allowances of $61 million and Voluntary Emissions Reductions (VER) credits of $25 million from trade and
other receivables to intangible assets, $43 million of which are expected to be released to the income statement in the next 12 months.
3
The exploration write-off of $57 million (2022: $64 million) includes $13 million related to the Ix-1EXP well in Mexico, $15 million related to the JDE well in Norway and also includes costs
associated with licence relinquishments and uncommercial well evaluations and $4 million related to an increase in decommissioning provisions in the North Sea (note 20)
(2022: $6 million credit).", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f21463": { "value": "
Oil and gas
Non-oil and
Carbon
assets
gas assets
1
allowances
2
Total
Note
$ million
$ million
$ million
$ million
Cost
At 1 January 2022
813
119
\u2013
932
Additions during the year
111
31
\u2013
142
Transfers to property, plant and equipment
12
(29)
\u2013
\u2013
(29)
Reduction in decommissioning asset
20
(12)
\u2013
\u2013
(12)
Exploration write-off
3
(64)
\u2013
\u2013
(64)
Currency translation adjustment
(2)
(13)
\u2013
(15)
At 31 December 2022
817
137
\u2013
954
Additions during the year
210
20
\u2013
230
Transfers from property, plant and equipment
12
\u2013
7
\u2013
7
Reclassi\ufb01cation from trade and other receivables
2
\u2013
\u2013
86
86
Increase in decommissioning asset
20
4
\u2013
\u2013
4
Exploration write-off
3
(57)
\u2013
\u2013
(57)
Currency translation adjustment
42
8
\u2013
50
At 31 December 2023
1,016
172
86
1,274
Amortisation
At 1 January 2022
\u2013
60
\u2013
60
Charge for the year
\u2013
21
\u2013
21
Currency translation adjustment
\u2013
(7)
\u2013
(7)
At 31 December 2022
\u2013
74
\u2013
74
Charge for the year
\u2013
23
\u2013
23
Currency translation adjustment
\u2013
5
\u2013
5
At 31 December 2023
\u2013
102
\u2013
102
Net book value
At 31 December 2022
817
63
\u2013
880
At 31 December 2023
1,016
70
86
1,172
\n \n
Fixtures and
Oil and gas
\ufb01ttings & of\ufb01ce
assets
equipment
Total
Note
$ million
$ million
$ million
Cost
At 1 January 2022
12,022
30
12,052
Additions
1
532
11
543
Transfers from intangible assets
11
29
\u2013
29
Decrease in decommissioning asset
2
20
(778)
\u2013
(778)
Currency translation adjustment
(369)
(3)
(372)
At 31 December 2022
11,436
38
11,474
Additions
1
482
9
491
Transfers to intangible assets
11
\u2013
(7)
(7)
Reclassi\ufb01cation of asset held for sale
17
(198)
\u2013
(198)
Decrease in decommissioning asset
2
20
(22)
\u2013
(22)
Currency translation adjustment
159
2
161
At 31 December 2023
11,857
42
11,899
Accumulated depreciation
At 1 January 2022
4,785
21
4,806
Charge for the year
1,319
5
1,324
Net impairment reversal
(170)
\u2013
(170)
Currency translation adjustment
(174)
(2)
(176)
At 31 December 2022
5,760
24
5,784
Charge for the year
1,192
3
1,195
Impairment charge
214
\u2013
214
Reclassi\ufb01cation of asset held for sale
17
(103)
\u2013
(103)
Currency translation adjustment
91
1
92
At 31 December 2023
7,154
28
7,182
Net book value
At 31 December 2022
5,676
14
5,690
At 31 December 2023
4,703
14
4,717
\n \n
Land and
Offshore
buildings
Drilling rigs
FPSO
facilities
Equipment
Total
Right-of-use assets
Note
$ million
$ million
$ million
$ million
$ million
$ million
Cost
At 1 January 2022
100
153
509
\u2013
18
780
Additions during the year
1
\u2013
\u2013
\u2013
338
\u2013
338
Cost revisions/remeasurements
3
33
53
(4)
4
89
Disposals
(6)
\u2013
\u2013
\u2013
\u2013
(6)
Currency translation adjustment
(9)
(17)
\u2013
\u2013
(2)
(28)
At 31 December 2022
88
169
562
334
20
1,173
Additions during the year
1
25
\u2013
\u2013
\u2013
1
26
Cost revisions/remeasurements
1
48
63
(6)
4
110
Reclassi\ufb01cation as asset held for sale
17
(5)
\u2013
(71)
\u2013
\u2013
(76)
Disposals
(4)
(19)
\u2013
\u2013
\u2013
(23)
Currency translation adjustment
4
10
\u2013
\u2013
1
15
At 31 December 2023
109
208
554
328
26
1,225
Accumulated depreciation
At 1 January 2022
22
98
102
\u2013
7
229
Charge for the year
12
43
107
61
7
230
Disposals
(6)
\u2013
\u2013
\u2013
\u2013
(6)
Currency translation adjustment
(2)
(12)
\u2013
\u2013
(1)
(15)
At 31 December 2022
26
129
209
61
13
438
Charge for the year
9
42
94
89
5
239
Reclassi\ufb01cation of asset held for sale
17
(2)
\u2013
(23)
\u2013
\u2013
(25)
Disposals
(4)
(19)
\u2013
\u2013
\u2013
(23)
Currency translation adjustment
1
7
\u2013
\u2013
1
9
At 31 December 2023
30
159
280
150
19
638
Net book value
At 31 December 2022
62
40
353
273
7
735
At 31 December 2023
79
49
274
178
7
587
2023
2022
Depreciation charge of right-of-use assets
Note
$ million
$ million
Land and buildings \u2013 non-oil and gas assets
8
11
Land and buildings \u2013 oil and gas assets
1
1
Drilling rigs
42
43
FPSO
94
107
Offshore facilities
89
61
Equipment \u2013 non-oil and gas assets
1
\u2013
Equipment \u2013 oil and gas assets
4
7
239
230
Capitalisation of IFRS 16 lease depreciation
1
Drilling rigs
(25)
(26)
Equipment
(2)
(4)
Depreciation charge included within the consolidated income statement
212
200
Lease interest
7
51
25
", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f21848": { "value": "12. Property, plant and equipment \n \n
Fixtures and
Oil and gas
\ufb01ttings & of\ufb01ce
assets
equipment
Total
Note
$ million
$ million
$ million
Cost
At 1 January 2022
12,022
30
12,052
Additions
1
532
11
543
Transfers from intangible assets
11
29
\u2013
29
Decrease in decommissioning asset
2
20
(778)
\u2013
(778)
Currency translation adjustment
(369)
(3)
(372)
At 31 December 2022
11,436
38
11,474
Additions
1
482
9
491
Transfers to intangible assets
11
\u2013
(7)
(7)
Reclassi\ufb01cation of asset held for sale
17
(198)
\u2013
(198)
Decrease in decommissioning asset
2
20
(22)
\u2013
(22)
Currency translation adjustment
159
2
161
At 31 December 2023
11,857
42
11,899
Accumulated depreciation
At 1 January 2022
4,785
21
4,806
Charge for the year
1,319
5
1,324
Net impairment reversal
(170)
\u2013
(170)
Currency translation adjustment
(174)
(2)
(176)
At 31 December 2022
5,760
24
5,784
Charge for the year
1,192
3
1,195
Impairment charge
214
\u2013
214
Reclassi\ufb01cation of asset held for sale
17
(103)
\u2013
(103)
Currency translation adjustment
91
1
92
At 31 December 2023
7,154
28
7,182
Net book value
At 31 December 2022
5,676
14
5,690
At 31 December 2023
4,703
14
4,717
1
Included within property, plant and equipment additions of $491 million (2022: $543 million) are associated cash \ufb02ows of $496 million (2022: $477 million) and non-cash \ufb02ow
movements of $5 million (2022: $66 million), represented by a $30 million decrease in capital accruals (2022: $43 million increase), $18 million of capitalised lease depreciation
(2022: $22 million) and $7 million of capitalised interest (2022: $1 million).
2
A decrease in the decommissioning assets of $22 million (2022: $778 million) was made during the year as a result of both an update to the decommissioning estimates and new
obligations (note 20).
During the year, the Group recognised a pre-tax impairment charge of $214 million (post-tax $109 million) (2022: net impairment credit
of $170 million; post-tax $50 million). This comprised a pre-tax impairment charge representing a write-down of property, plant and
equipment assets of $108 million (2022: $163 million) across two CGUs in the UK of $70 million. Of these CGUs, one was driven
primarily by a signi\ufb01cant reduction in the gas price forward curve, and the other by a revised decommissioning cost pro\ufb01le. In addition,
there was a Vietnam fair value impairment on the held for sale asset of $38 million and a pre-tax impairment charge of $106 million
(2022: $82 million credit) in respect of revisions to decommissioning estimates on the Group\u2019s non-producing assets with no remaining
net book value (see note 20).
In 2022, a net pre-tax impairment credit of $170 million was recognised as a result of impairment reversals on North Sea assets of
$251 million driven by a higher forward curve and long-term price assumption for gas, and a pre-tax impairment credit of $82 million
in respect of revisions to decommissioning estimates on the Group\u2019s non-producing assets with no remaining net book value. This was
partially offset by an impairment to property, plant and equipment of $163 million from a single CGU in the UK North Sea, driven primarily
by the contracted price realised for crude sales being negatively impacted by the pricing differential between Urals and Brent crude and
a revised operating cost pro\ufb01le for the \ufb01eld.
Key assumptions used in calculations
Assumptions used in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas
prices, discount rates and the level and timing of expenditures, all of which are inherently uncertain.
Commodity and carbon prices
The Group uses the fair value less cost of disposal method (FVLCD) to calculate the recoverable amount of the cash-generating
units (CGU) consistent with a level 3 fair value measurement (see note 22). In determining the recoverable value, appropriate discounted-
cash-\ufb02ow valuation models were used, incorporating market-based assumptions. Management\u2019s commodity price curve assumptions are
benchmarked against a range of external forward price curves on a regular basis. Individual \ufb01eld price differentials are then applied. The
\ufb01rst three years re\ufb02ect the market forward price curves transitioning to a long-term price from 2027, thereafter in\ufb02ated at 2.5 per cent
per annum. The long-term commodity prices used were $70 per barrel for crude and 90 pence per therm for gas.
Production volumes and oil and gas reserves
Production volumes are based on life of \ufb01eld production pro\ufb01les for each asset within the CGU. Proven and probable reserves are
estimates of the amount of oil and gas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates
its reserves using standard recognised evaluation techniques, assessed at least annually by management. Proven and probable
reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices.
Costs
Operating expenditure, capital expenditure and decommissioning costs are derived from the Group\u2019s business plan. The discount
rate re\ufb02ects management\u2019s estimate of the Group\u2019s country-based weighted average cost of capital (WACC). Foreign exchange rates
are based on management\u2019s long-term rate assumptions, with reference to a range of underlying economic indicators.
Sensitivity to changes in assumptions used in calculations
Reductions or increases in the long-term oil and gas prices of 10 per cent are considered to be reasonably possible changes for the
purpose of sensitivity analysis. As shown in note 2 to the \ufb01nancial statements the decreases to the long-term oil and gas prices from
1 January 2027 speci\ufb01ed above would result in a further pre-tax impairment of $86 million (post-tax $40 million) and $21 million
(post-tax $6 million), respectively.
Considering the discount rates, the Group believes a 1 per cent increase in the post-tax discount rate is considered to be a reasonable
possibility for the purpose of sensitivity analysis. A 1 per cent increase in the post-tax discount rate would lead to a further pre-tax
impairment of $24 million (post-tax $11 million), and a 1 per cent decrease in the post-tax discount rate would have no impact on the
post-tax impairment charge.", "dimensions": { "concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f22266": { "value": "13. Leases
This note provides information for leases where the Group is a lessee.
Balance sheet
\n \n
Land and
Offshore
buildings
Drilling rigs
FPSO
facilities
Equipment
Total
Right-of-use assets
Note
$ million
$ million
$ million
$ million
$ million
$ million
Cost
At 1 January 2022
100
153
509
\u2013
18
780
Additions during the year
1
\u2013
\u2013
\u2013
338
\u2013
338
Cost revisions/remeasurements
3
33
53
(4)
4
89
Disposals
(6)
\u2013
\u2013
\u2013
\u2013
(6)
Currency translation adjustment
(9)
(17)
\u2013
\u2013
(2)
(28)
At 31 December 2022
88
169
562
334
20
1,173
Additions during the year
1
25
\u2013
\u2013
\u2013
1
26
Cost revisions/remeasurements
1
48
63
(6)
4
110
Reclassi\ufb01cation as asset held for sale
17
(5)
\u2013
(71)
\u2013
\u2013
(76)
Disposals
(4)
(19)
\u2013
\u2013
\u2013
(23)
Currency translation adjustment
4
10
\u2013
\u2013
1
15
At 31 December 2023
109
208
554
328
26
1,225
Accumulated depreciation
At 1 January 2022
22
98
102
\u2013
7
229
Charge for the year
12
43
107
61
7
230
Disposals
(6)
\u2013
\u2013
\u2013
\u2013
(6)
Currency translation adjustment
(2)
(12)
\u2013
\u2013
(1)
(15)
At 31 December 2022
26
129
209
61
13
438
Charge for the year
9
42
94
89
5
239
Reclassi\ufb01cation of asset held for sale
17
(2)
\u2013
(23)
\u2013
\u2013
(25)
Disposals
(4)
(19)
\u2013
\u2013
\u2013
(23)
Currency translation adjustment
1
7
\u2013
\u2013
1
9
At 31 December 2023
30
159
280
150
19
638
Net book value
At 31 December 2022
62
40
353
273
7
735
At 31 December 2023
79
49
274
178
7
587
1
Additions of $26 million mainly related to new land and buildings were made to the right-of-use assets during the year (2022: total additions of $338 million related to the Tolmount
offshore facilities).
2023
2022
Right-of-use liabilities
Note
$ million
$ million
At 1 January
825
654
Additions
28
338
Remeasurement
110
89
Finance costs charged to income statement
7
51
25
Finance costs charged to decommissioning provision
20
1
1
Reclassi\ufb01cation of liabilities as held for sale
17
(95)
\u2013
Lease payments
(262)
(254)
Currency translation adjustment
15
(28)
At 31 December
673
825
Classi\ufb01ed as
Current
199
221
Non-current
474
604
Total lease liabilities
673
825
The signi\ufb01cant portion of the Group\u2019s lease liabilities represent lease arrangements for an FPSO vessel on the Catcher asset, and
offshore facilities on the Tolmount asset.
The lease liabilities and associated right-of-use-assets have been calculated by reference to in-substance \ufb01xed lease payments in the
underlying agreements incurred throughout the non-cancellable period of the lease along with periods covered by options to extend the
lease where the Group is reasonably certain that such options will be exercised. When assessing whether extension options were likely
to be exercised, assumptions are consistent with those applied when testing for impairment.
Income statement
2023
2022
Depreciation charge of right-of-use assets
Note
$ million
$ million
Land and buildings \u2013 non-oil and gas assets
8
11
Land and buildings \u2013 oil and gas assets
1
1
Drilling rigs
42
43
FPSO
94
107
Offshore facilities
89
61
Equipment \u2013 non-oil and gas assets
1
\u2013
Equipment \u2013 oil and gas assets
4
7
239
230
Capitalisation of IFRS 16 lease depreciation
1
Drilling rigs
(25)
(26)
Equipment
(2)
(4)
Depreciation charge included within the consolidated income statement
212
200
Lease interest
7
51
25
1
Of the $27 million (2022: $30 million) capitalised IFRS 16 lease depreciation, $18 million (2022: $22 million) has been capitalised within property, plant and equipment and $9 million
(2022: $8 million) within provisions (note 20).
The total cash out\ufb02ow for leases in 2023 was $259 million (2022: $254 million).", "dimensions": { "concept": "ifrs-full:DisclosureOfLeasesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23033": { "value": "14. Inventories \n \n
2023
2022
$ million
$ million
Hydrocarbons
49
22
Consumables and subsea supplies
151
121
Total inventories
200
143
Inventories of consumables and subsea supplies include a provision of $28 million (2022: $25 million) where it is considered that the
net realisable value is lower than the original cost.
Inventories recognised as an expense during the year ended 31 December 2023 amounted to $1 million (2022: $22 million).
These\u00a0expenses are included within production costs.", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23075": { "value": "15. Trade and other receivables \n \n
2023
2022
$ million
$ million
Trade receivables
359
392
Underlift position
146
69
Other debtors
67
97
Prepayments and accrued income
223
785
Corporation tax receivable
37
60
Total trade and other receivables
832
1,403
Trade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2023, there were no trade
receivables that were past due (2022: nil).
Other debtors include the current element of the unamortised portion of issue costs and bank fees of $19 million related to the RBL (note 27)
and includes amounts due from joint venture partners.
Prepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas.
The carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
Other long-term receivables
\n \n
2023
2022
$ million
$ million
Net investment in sublease
1
44
Decommissioning funding asset
1
56
62
Other receivables
2
127
164
Prepayments and accrued income
\u2013
28
Total other long-term receivables
184
298
1
The decommissioning funding asset relates to the Decommissioning liability agreement entered into with E.ON whereby E.ON agreed to part fund Premier\u2019s share of decommissioning the
Johnston and Ravenspurn North assets. Under the terms of the agreement, E.ON will reimburse 70 per cent of the decommissioning costs between a range of \u00a340 million to \u00a3130 million
based on Premier\u2019s net share of the total decommissioning cost of the two assets. This results in maximum possible funding of \u00a363 million from E.ON. At 31 December 2023, a long-term
decommissioning funding asset of $56 million (2022: $62 million) has been recognised utilising the year-end US dollar/pound sterling exchange rate and underlying assumptions
consistent with those used for the corresponding decommissioning provision.
2
Other receivables includes $39 million in cash held in escrow accounts for expected future decommissioning expenditure in Indonesia and Vietnam (2022: $123 million), and $21 million
(2022: $23 million) held as security for the Mexican letters of credit. Also included are the non-current element of the unamortised portion of issue costs and bank fees of $42 million
related to the RBL (note 27).", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23076": { "value": "15. Trade and other receivables \n \n
2023
2022
$ million
$ million
Trade receivables
359
392
Underlift position
146
69
Other debtors
67
97
Prepayments and accrued income
223
785
Corporation tax receivable
37
60
Total trade and other receivables
832
1,403
Trade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2023, there were no trade
receivables that were past due (2022: nil).
Other debtors include the current element of the unamortised portion of issue costs and bank fees of $19 million related to the RBL (note 27)
and includes amounts due from joint venture partners.
Prepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas.
The carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
Other long-term receivables
\n \n
2023
2022
$ million
$ million
Net investment in sublease
1
44
Decommissioning funding asset
1
56
62
Other receivables
2
127
164
Prepayments and accrued income
\u2013
28
Total other long-term receivables
184
298
1
The decommissioning funding asset relates to the Decommissioning liability agreement entered into with E.ON whereby E.ON agreed to part fund Premier\u2019s share of decommissioning the
Johnston and Ravenspurn North assets. Under the terms of the agreement, E.ON will reimburse 70 per cent of the decommissioning costs between a range of \u00a340 million to \u00a3130 million
based on Premier\u2019s net share of the total decommissioning cost of the two assets. This results in maximum possible funding of \u00a363 million from E.ON. At 31 December 2023, a long-term
decommissioning funding asset of $56 million (2022: $62 million) has been recognised utilising the year-end US dollar/pound sterling exchange rate and underlying assumptions
consistent with those used for the corresponding decommissioning provision.
2
Other receivables includes $39 million in cash held in escrow accounts for expected future decommissioning expenditure in Indonesia and Vietnam (2022: $123 million), and $21 million
(2022: $23 million) held as security for the Mexican letters of credit. Also included are the non-current element of the unamortised portion of issue costs and bank fees of $42 million
related to the RBL (note 27).", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23077": { "value": "15. Trade and other receivables \n \n
2023
2022
$ million
$ million
Trade receivables
359
392
Underlift position
146
69
Other debtors
67
97
Prepayments and accrued income
223
785
Corporation tax receivable
37
60
Total trade and other receivables
832
1,403
Trade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2023, there were no trade
receivables that were past due (2022: nil).
Other debtors include the current element of the unamortised portion of issue costs and bank fees of $19 million related to the RBL (note 27)
and includes amounts due from joint venture partners.
Prepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas.
The carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
Other long-term receivables
\n \n
2023
2022
$ million
$ million
Net investment in sublease
1
44
Decommissioning funding asset
1
56
62
Other receivables
2
127
164
Prepayments and accrued income
\u2013
28
Total other long-term receivables
184
298
1
The decommissioning funding asset relates to the Decommissioning liability agreement entered into with E.ON whereby E.ON agreed to part fund Premier\u2019s share of decommissioning the
Johnston and Ravenspurn North assets. Under the terms of the agreement, E.ON will reimburse 70 per cent of the decommissioning costs between a range of \u00a340 million to \u00a3130 million
based on Premier\u2019s net share of the total decommissioning cost of the two assets. This results in maximum possible funding of \u00a363 million from E.ON. At 31 December 2023, a long-term
decommissioning funding asset of $56 million (2022: $62 million) has been recognised utilising the year-end US dollar/pound sterling exchange rate and underlying assumptions
consistent with those used for the corresponding decommissioning provision.
2
Other receivables includes $39 million in cash held in escrow accounts for expected future decommissioning expenditure in Indonesia and Vietnam (2022: $123 million), and $21 million
(2022: $23 million) held as security for the Mexican letters of credit. Also included are the non-current element of the unamortised portion of issue costs and bank fees of $42 million
related to the RBL (note 27).", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23078": { "value": "15. Trade and other receivables \n \n
2023
2022
$ million
$ million
Trade receivables
359
392
Underlift position
146
69
Other debtors
67
97
Prepayments and accrued income
223
785
Corporation tax receivable
37
60
Total trade and other receivables
832
1,403
Trade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2023, there were no trade
receivables that were past due (2022: nil).
Other debtors include the current element of the unamortised portion of issue costs and bank fees of $19 million related to the RBL (note 27)
and includes amounts due from joint venture partners.
Prepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas.
The carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
Other long-term receivables
\n \n
2023
2022
$ million
$ million
Net investment in sublease
1
44
Decommissioning funding asset
1
56
62
Other receivables
2
127
164
Prepayments and accrued income
\u2013
28
Total other long-term receivables
184
298
1
The decommissioning funding asset relates to the Decommissioning liability agreement entered into with E.ON whereby E.ON agreed to part fund Premier\u2019s share of decommissioning the
Johnston and Ravenspurn North assets. Under the terms of the agreement, E.ON will reimburse 70 per cent of the decommissioning costs between a range of \u00a340 million to \u00a3130 million
based on Premier\u2019s net share of the total decommissioning cost of the two assets. This results in maximum possible funding of \u00a363 million from E.ON. At 31 December 2023, a long-term
decommissioning funding asset of $56 million (2022: $62 million) has been recognised utilising the year-end US dollar/pound sterling exchange rate and underlying assumptions
consistent with those used for the corresponding decommissioning provision.
2
Other receivables includes $39 million in cash held in escrow accounts for expected future decommissioning expenditure in Indonesia and Vietnam (2022: $123 million), and $21 million
(2022: $23 million) held as security for the Mexican letters of credit. Also included are the non-current element of the unamortised portion of issue costs and bank fees of $42 million
related to the RBL (note 27).", "dimensions": { "concept": "ifrs-full:DisclosureOfTaxReceivablesAndPayablesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23079": { "value": "15. Trade and other receivables \n \n
2023
2022
$ million
$ million
Trade receivables
359
392
Underlift position
146
69
Other debtors
67
97
Prepayments and accrued income
223
785
Corporation tax receivable
37
60
Total trade and other receivables
832
1,403
Trade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2023, there were no trade
receivables that were past due (2022: nil).
Other debtors include the current element of the unamortised portion of issue costs and bank fees of $19 million related to the RBL (note 27)
and includes amounts due from joint venture partners.
Prepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas.
The carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
Other long-term receivables
\n \n
2023
2022
$ million
$ million
Net investment in sublease
1
44
Decommissioning funding asset
1
56
62
Other receivables
2
127
164
Prepayments and accrued income
\u2013
28
Total other long-term receivables
184
298
1
The decommissioning funding asset relates to the Decommissioning liability agreement entered into with E.ON whereby E.ON agreed to part fund Premier\u2019s share of decommissioning the
Johnston and Ravenspurn North assets. Under the terms of the agreement, E.ON will reimburse 70 per cent of the decommissioning costs between a range of \u00a340 million to \u00a3130 million
based on Premier\u2019s net share of the total decommissioning cost of the two assets. This results in maximum possible funding of \u00a363 million from E.ON. At 31 December 2023, a long-term
decommissioning funding asset of $56 million (2022: $62 million) has been recognised utilising the year-end US dollar/pound sterling exchange rate and underlying assumptions
consistent with those used for the corresponding decommissioning provision.
2
Other receivables includes $39 million in cash held in escrow accounts for expected future decommissioning expenditure in Indonesia and Vietnam (2022: $123 million), and $21 million
(2022: $23 million) held as security for the Mexican letters of credit. Also included are the non-current element of the unamortised portion of issue costs and bank fees of $42 million
related to the RBL (note 27).", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23085": { "value": "\n \n
2023
2022
$ million
$ million
Trade receivables
359
392
Underlift position
146
69
Other debtors
67
97
Prepayments and accrued income
223
785
Corporation tax receivable
37
60
Total trade and other receivables
832
1,403
Trade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2023, there were no trade
receivables that were past due (2022: nil).
Other debtors include the current element of the unamortised portion of issue costs and bank fees of $19 million related to the RBL (note 27)
and includes amounts due from joint venture partners.
Prepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas.
The carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
Other long-term receivables
\n \n
2023
2022
$ million
$ million
Net investment in sublease
1
44
Decommissioning funding asset
1
56
62
Other receivables
2
127
164
Prepayments and accrued income
\u2013
28
Total other long-term receivables
184
298
", "dimensions": { "concept": "ifrs-full:DisclosureOfPrepaymentsAndOtherAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23226": { "value": "16. Cash and cash equivalents \n \n
2023
2022
$ million
$ million
Cash at banks and in hand
280
500
Cash at bank earns interest at \ufb02oating rates based on daily bank deposit rates. The Group only deposits cash with major banks of high
quality credit standing.
17. Assets held for sale
In August 2023, Harbour announced that it had entered into a Sale and Purchase Agreement to sell its business in Vietnam, which holds
its 53.125 per cent interest in Chim S\u00e1o and Dua producing \ufb01elds to Big Energy Joint Stock Company for a consideration of $84 million.
The transaction, which is subject to government approvals, has an effective date of 1 January 2023. The assets and liabilities of Vietnam
have been classi\ufb01ed as assets held for sale in the balance sheet as at 31 December 2023 as completion is expected to be achieved
within 12 months from entering into the SPA.
The Group\u2019s Vietnam operations are included in the International segment however are not considered a major geographical area or line
of business and therefore the disposal has not been classi\ufb01ed as discontinued operations.
The major classes of assets and liabilities of the Group as held for sale as at 31 December 2023 are as follows:
\n \n
2023
Current
Note
$ million
Assets
Property, plant and equipment
12
95
Right-of-use-assets
13
51
Other receivables and working capital
188
Assets held for sale
334
Liabilities
Provisions
20
87
Lease creditor
13
95
Trade and other payables
29
Deferred tax
8
31
Liabilities directly associated with assets held for sale
242
Net assets directly associated with disposal group
92
Impairment loss recorded
38
Immediately before the classi\ufb01cation of the disposal group as assets held for sale, the recoverable amount was estimated for the disposal
group and no impairment loss was identi\ufb01ed. The assets in the disposal group are held at the lower of their carrying amount and fair value
less costs to sell. As at 31 December 2023, an impairment of $38 million was recognised as the fair value less cost to sell, being the
expected consideration adjusted for items agreed under the SPA, was below the carrying amount of the disposal group. Following the
impairment charge the net assets directly associated with the disposal group held on the consolidated balance sheet were $92 million.19. Trade and other payables \n \n
2023
2022
$ million
$ million
Current
Trade payables
52
47
Overlift position
33
132
Other payables
143
118
Matured \ufb01nancial instruments
48
258
Accruals
600
682
Deferred income
1
10
15
886
1,252
Non-current
Other payables
13
11
Deferred income
1
\u2013
8
13
19
1
Deferred income includes $10 million (2022: $23 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100 million from FlowStream
in return for granting them 15 per cent of production from the Solan \ufb01eld until suf\ufb01cient barrels have been delivered to achieve the rate of return within the agreement. This balance is being
released to the income statement within revenue as barrels are delivered to FlowStream from production from Solan. The estimated fair value includes unobservable inputs and is level 3 in
the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has decreased by $13 million in the year re\ufb02ecting the impact of barrels delivered to FlowStream
($15 million) and a change in estimate following an increase in the oil price resulting in a debit of $4 million to the income statement within \ufb01nance expense (note 7).21. Borrowings and facilities
The Group\u2019s borrowings are carried at amortised cost:
\n \n
2023
2022
$ million
$ million
Reserve based lending (RBL) facility
1
\u2013
702
Bond
493
491
Exploration \ufb01nance facility
\u2013
11
Other loans
16
34
Total borrowings
509
1,238
Classi\ufb01ed within
Non-current liabilities
493
1,216
Current liabilities
16
22
Total borrowings
509
1,238
1
The reserve based lending (RBL) facility was fully repaid in the year, leaving $61 million of unamortised fees and related costs to be amortised over the remaining term of the facility which
have been reclassi\ufb01ed within current and non-current assets as appropriate.
The RBL facility was amended and extended in November 2023, and the key terms of the amended facility are:
\u2022
Term matures 31 December 2029
\u2022
Facility size of $2.75 billion, with a $1.75 billion letter of credit sub-limit
\u2022
Debt availability at $1.346 billion effective 24 November 2023
\u2022
Debt availability to be redetermined on an annual basis
\u2022
Interest at compounded SOFR plus a margin of 3.2 per cent, rising to a margin of 3.4 per cent from November 2025 and 3.6 per cent
from November 2027
\u2022
A margin adjustment linked to carbon-emission reductions
\u2022
Straight-line amortisation of letter of credit sub-limit from January 2027 to six months before maturity. No material cash collateralisation
required until\u00a02028
\u2022
Liquidity and leverage covenant tests
\u2022
A syndication group of 15 banks
Certain fees are also payable, including fees on available commitments at 40 per cent of the applicable margin and commission
on letters of credit issued at 50 per cent of the applicable margin.
In October 2021, the Group issued a $500 million bond under Rule 144A and with a tenor of \ufb01ve years to maturity. The coupon was
set at 5.50 per cent and interest is payable semi-annually.
At the balance sheet date, the outstanding RBL balance excluding incremental arrangement fees and related costs was $nil
(2022: $775 million). As at 31 December 2023, $1,340 million remained available for drawdown under the RBL facility
(2022: $1,972 million).
The Group has facilities to issue up to $1,750 million of letters of credit, of which $1,186 million was in issue as at 31 December
(2022: $966 million), mainly in respect of future abandonment liabilities.
A further $34 million of arrangement fees and related costs were capitalised during the year following amendments to the RBL facility
which became effective from November 2023.
During the year $48 million (2022: $55 million) of arrangement fees and related costs have been amortised and are included within
\ufb01nancing costs.
At 31 December 2023, $68 million of arrangement fees and related costs remain capitalised (2022: $82 million), of which $21 million
is\u00a0due to be amortised within the next 12 months (2022: $20 million). $61 million of these arrangement fees relate to the RBL facility,
$19 million of which have been reclassi\ufb01ed within current assets, and $42 million, which are due to be amortised beyond the next
12\u00a0months, have been reclassi\ufb01ed to non-current assets (note 15).
Bond interest of $6 million (2022: $6 million comprising both bond and RBL interest) had accrued by the balance sheet date and
has been classi\ufb01ed within accruals.
Since 2019, the Group has been operating within an exploration \ufb01nance facility (EFF), of NOK 1 billion, in relation to part-\ufb01nancing
the exploration activities of Harbour Energy Norge AS. This facility was repaid in full in February 2023.
Other loans represent a commercial \ufb01nancing arrangement with Baker Hughes (formerly BHGE), that covered a three-year work
programme for drilling, completion and subsea tie-in of development wells on Harbour\u2019s operated assets. The loan will be repaid
based on production performance, subject to a cap.
The table below details the change in the carrying amount of the Group\u2019s borrowings arising from \ufb01nancing cash \ufb02ows.
$ million
Total borrowings as at 1 January 2022
2,886
Repayment of RBL
(1,663)
Repayment of \ufb01nancing arrangement
(15)
Repayment of EFF loan
(38)
Proceeds from EFF loan
11
Currency translation adjustment on EFF loan
(7)
Financing arrangement interest payable
9
Amortisation of arrangement fees and related costs
55
Total borrowings as at 31 December 2022
1,238
Proceeds from drawdown of borrowing facilities
660
Repayment of RBL
(1,435)
Repayment of \ufb01nancing arrangement
(21)
Repayment of EFF loan
(11)
Arrangement fees and related costs on RBL capitalised
(34)
Financing arrangement interest payable
3
Amortisation of arrangement fees and related costs
48
Reclassi\ufb01cation of RBL arrangement fees and related costs to current and non-current assets
61
Total borrowings as at 31 December 2023
509
22. Other \ufb01nancial assets and liabilities
The Group held the following \ufb01nancial instruments at fair value at 31 December 2023. The fair values of all derivative \ufb01nancial
instruments are based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation,
which includes estimates based on unobservable inputs and is level 3 in the IFRS 13 hierarchy.
\n \n
31 December 2023
31 December 2022
Assets
Liabilities
Assets
Liabilities
$ million
$ million
$ million
$ million
Current
Measured at fair value through pro\ufb01t and loss
Foreign exchange derivatives
6
\u2013
6
\u2013
Interest rate derivatives
\u2013
\u2013
24
\u2013
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
(57)
16
\u2013
30
(57)
Measured at fair value through other comprehensive income
Commodity derivatives
154
(197)
51
(2,114)
Total current
170
(197)
81
(2,171)
Non-current
Measured at fair value through pro\ufb01t and loss
Interest rate derivatives
\u2013
\u2013
18
\u2013
\u2013
\u2013
18
\u2013
Measured at fair value through other comprehensive income
Commodity derivatives
112
(87)
85
(1,279)
Total non-current
112
(87)
103
(1,279)
Total current and non-current
282
(284)
184
(3,450)
Fair value measurements
All \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with
the hierarchy described in IFRS 13 \u2018Fair Value Measurement\u2019. The hierarchy groups fair value measurements into the following levels
based on the degree to which the fair value is observable.
\u2022
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities
\u2022
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or\u00a0indirectly
\u2022
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2023
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
\u2013
Commodity derivatives
266
\u2013
(284)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Total fair value
282
\u2013
(284)
\u2013
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2022
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
\u2013
\u2013
(57)
\u2013
Commodity derivatives
136
\u2013
(3,393)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Interest rate derivatives
42
\u2013
\u2013
\u2013
Total fair value
184
\u2013
(3,450)
\u2013
There were no transfers between fair value levels in 2022 or 2023.
Fair value movements recognised in the income statement on \ufb01nancial instruments are shown below.
2023
2022
Finance income
$ million
$ million
Change in fair value of embedded derivative within gas contract
68
\u2013
Foreign exchange derivatives
\u2013
7
Interest rate derivatives
(43)
31
25
38
2023
2022
Finance expenses
$ million
$ million
Change in fair value of embedded derivative within gas contract
\u2013
(48)
\u2013
(48)
Fair values of other \ufb01nancial instruments
The following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
2023
2022
$ million
$ million
Book value
Fair value
Book value
Fair value
Bond
(493)
(487)
(491)
(446)
The fair value of the bond is within level 2 of the fair value hierarchy and has been estimated by discounting future cash \ufb02ows by the relevant
market yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
short-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.
Cash \ufb02ow hedge accounting
The Group uses a combination of \ufb01xed price physical sales contracts and cash-settled \ufb01xed price commodity swaps and options to
manage the price risk associated with its underlying oil and gas revenues. As at 31 December 2023, all of the Group\u2019s cash-settled
\ufb01xed price commodity swap derivatives have been designated as cash \ufb02ow hedges of highly probable forecast sales of oil and gas.
The following table indicates the volumes, average hedged price and timings associated with the Group\u2019s \ufb01nancial commodity derivatives.
Volumes hedged through \ufb01xed price contracts with customers for physical delivery are excluded.
Position as at 31 December 2023
2024
2025
2026
Oil volume hedged (thousand bbls)
7,320
4,380
\u2013
Weighted average hedged price ($/bbl)
84.37
77.35
\u2013
Gas volume hedged (million therms)
759
428
90
Weighted average hedged price (p/therm)
67.19
89.68
99.28
As at 31 December 2023, the fair value of net \ufb01nancial commodity derivatives designated as cash \ufb02ow hedges, all executed under ISDA
agreements with no margining requirements, was a net payable of $66 million (2022: $3,516 million) and net unrealised pre-tax losses of
$16 million (2022: $3,185 million) were deferred in other comprehensive income in respect of the effective portion of the hedge relationships.
Amounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur.
As at 31 December 2023, net deferred pre-tax losses of $51 million (2022: $2,368 million) are expected to be released to the income
statement within one year.
Interest Rate Benchmark Reform (IBOR)
During the year, the Group transitioned to alternative benchmark rates to cater for the discontinuation of IBOR rates. Our bond is at
a \ufb01xed interest rate of 5.5 per cent whilst the RBL (undrawn at 31 December 2023) transitioned from US LIBOR to SOFR (Secured
Overnight Financing Rate).
23. Financial risk factors and risk management
The Group\u2019s principal \ufb01nancial assets and liabilities comprise trade and other receivables, cash and short-term deposits accounts, trade
payables, interest bearing loans and derivative \ufb01nancial instruments. The main purpose of these \ufb01nancial instruments is to manage
short-term cash \ufb02ow, price exposures and raise \ufb01nance for the Group\u2019s expenditure programme. Further information on the Group\u2019s
\ufb01nancial instrument risk management objectives, policies and strategies are set out in the discussion of capital management policies
in the Strategic report (see page 62).
Risk exposures and responses
The Group manages its exposure to key \ufb01nancial risks in accordance with its \ufb01nancial risk management policy. The objective of the policy
is to support the delivery of the Group\u2019s \ufb01nancial targets while protecting future \ufb01nancial security. The main risks that could adversely
affect the Group\u2019s \ufb01nancial assets, liabilities or future cash \ufb02ows are market risks comprising commodity price risk, interest rate risk and
foreign currency risk, liquidity risk, and credit risk. Management reviews and agrees policies for managing each of these risks which are
summarised in this note.
The Group\u2019s management oversees the management of \ufb01nancial risks. The Group\u2019s senior management ensures that \ufb01nancial risk-taking
activities are governed by appropriate policies and procedures and that \ufb01nancial risks are identi\ufb01ed, measured and managed in
accordance with Group policies and risk objectives. All derivative activities for risk management purposes are carried out by specialist
teams that have the appropriate skills, experience and supervision. It is the Group\u2019s policy that no trading in derivatives for speculative
purposes shall be undertaken.
Market risk
Market risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market prices.
Market risk comprises three types of risk: commodity price risk, interest rate risk and foreign currency risk. Financial instruments mainly
affected by market risk include loans and borrowings, deposits and derivative \ufb01nancial instruments.
The sensitivity analyses in the following sections relate to the position as at 31 December 2023 and 31 December 2022.
The sensitivity analyses have been prepared on the basis that the number of \ufb01nancial instruments are all constant. The sensitivity
analyses are intended to illustrate the sensitivity to changes in market variables on the composition of the Group\u2019s \ufb01nancial instruments
at the balance sheet date and show the impact on pro\ufb01t or loss and shareholders\u2019 equity, where applicable.
The following assumptions have been made in calculating the sensitivity analyses:
\u2022
The sensitivity of the relevant pro\ufb01t before tax item and/or equity is the effect of the assumed changes in respective market risks
for the full year based on the \ufb01nancial assets and \ufb01nancial liabilities held at the balance sheet date
\u2022
The sensitivities indicate the effect of a reasonable increase in each market variable. Unless otherwise stated, the effect of
a corresponding decrease in these variables is considered approximately equal and opposite
\u2022
Fair value changes from derivative instruments designated as cash \ufb02ow hedges are considered fully effective and recorded
in shareholders\u2019 equity, net of tax
\u2022
Fair value changes from derivatives and other \ufb01nancial instruments not designated as cash \ufb02ow hedges are presented as a sensitivity
to pro\ufb01t before tax only and not included in shareholders\u2019 equity
Commodity price risk
The Group is exposed to the risk of \ufb02uctuations in prevailing market commodity prices on the mix of oil and gas products. On a rolling
basis, the Group\u2019s policy is to hedge the commodity price exposure associated with 40 to 70 per cent of the next 12 months\u2019 production
(year 1), between 30 and 60 per cent of \u2018year 2\u2019 production, from \u2018year 3\u2019 up to 50 per cent of production and from \u2018year 4\u2019 up to
40 per cent of production. The Group manages these risks through the use of \ufb01xed price contracts with customers for physical delivery
and derivative \ufb01nancial instruments including \ufb01xed price swaps and options.
Commodity price sensitivity
The following table summarises the impact on the Group\u2019s pre-tax pro\ufb01t and equity from a reasonably foreseeable movement in
commodity prices on the fair value of commodity based derivative instruments held by the Group at the balance sheet date.
E\ufb00ect
on pro\ufb01t
E\ufb00ect
before tax
on equity
As at 31 December 2023
Market movement
$ million
$ million
Brent oil price
$10 /bbl increase
\u2013
(28)
Brent oil price
$10 /bbl decrease
\u2013
28
NBP gas price
\u00a30.1 /therm increase
\u2013
(28)
NBP gas price
\u00a30.1 /therm decrease
\u2013
28
Effect
on pro\ufb01t
Effect
before tax
on equity
As at 31 December 2022
Market movement
$ million
$ million
Brent oil price
$10 /bbl increase
\u2013
(49)
Brent oil price
$10 /bbl decrease
\u2013
49
NBP gas price
\u00a30.1 /therm increase
\u2013
(49)
NBP gas price
\u00a30.1 /therm decrease
\u2013
49
Interest rate risk
Interest rate risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market
interest rates. The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to the Group\u2019s long-term debt
obligation with \ufb02oating interest rates.
Fixed rate borrowings at 31 December 2023 comprise a bond which incurs interest at 5.5 per cent per annum. Following the settlement
of the RBL and exploration \ufb01nancing balances during the year, the Group has no \ufb02oating rate borrowings at 31 December 2023. As at
31 December 2022, \ufb02oating rate borrowings comprised loans under the RBL facility which incurred interest \ufb01xed either one month,
three months or six months in advance at USD LIBOR plus a margin of 3.21 per cent. Floating rate \ufb01nancial assets comprise cash and
cash equivalents which earn interest at the relevant market rate. Prior to settlement of the RBL, the Group monitored its exposure
to \ufb02uctuations in interest rates and uses interest rate derivatives to manage the \ufb01xed and \ufb02oating composition of its borrowings.
The interest rate \ufb01nancial instruments in place at the balance sheet date are shown below:
Derivative
Currency
Period of hedge
Terms
31 December 2023
Interest rate swaps
$nil million
N/A
N/A
31 December 2022
Interest rate swaps
$545 million
Jun 20 \u2013 Jun 25
Average 0.55%
The interest rate and currency pro\ufb01le of the Group\u2019s interest-bearing \ufb01nancial assets and liabilities are shown below:
\n \n
Cash
Fixed rate
Floating rate
at bank
borrowings
borrowings
Total
As at 31 December 2023
$ million
$ million
$ million
$ million
US dollar
238
(493)
\u2013
(255)
Pound sterling
28
\u2013
\u2013
28
Norwegian krone
13
\u2013
\u2013
13
Other
1
\u2013
\u2013
1
280
(493)
\u2013
(213)
\n \n
Cash
Fixed rate
Floating rate
at bank
borrowings
borrowings
Total
As at 31 December 2022
$ million
$ million
$ million
$ million
US dollar
481
(491)
(702)
(712)
Pound sterling
8
\u2013
\u2013
8
Norwegian krone
6
\u2013
(11)
(5)
Other
5
\u2013
\u2013
5
500
(491)
(713)
(704)
Interest rate sensitivity
The following table demonstrates the indicative pre-tax effect on pro\ufb01t and equity of applying a reasonably foreseeable increase in
interest rates to the Group\u2019s \ufb01nancial assets and liabilities at the balance sheet date.
\n \n
Effect
on pro\ufb01t
Effect
before tax
on equity
Market movement
$ million
$ million
31 December 2023
US dollar interest rates
+100 basis points
2
\u2013
31 December 2022
US dollar interest rates
+100 basis points
8
\u2013
Foreign currency risk
Foreign currency risk is the risk that the fair value or future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in
foreign exchange rates.
The Group is exposed to foreign currency risk primarily arising from exchange rate movements in US dollar against pound sterling.
To\u00a0mitigate exposure to movements in exchange rates, wherever possible \ufb01nancial assets and liabilities are held in currencies that
match\u00a0the functional currency of the relevant entity. The Group has subsidiaries with functional currencies of pound sterling, US dollar,
Norwegian krone, Mexican pesos and Brazilian reals. Exposures can also arise from sales or purchases denominated in currencies
other than the functional currency of the relevant entity; such exposures are monitored and hedged with agreement from the Board.
The Group enters into forward contracts as a means of hedging its exposure to foreign exchange rate risks. As at 31 December 2023, the
Group had \u00a3212 million hedged at a forward rate of between $1.2182 and $1.2742:\u00a31 for the period January 2024 to October 2024.
As at 31 December 2022, the Group had \u00a342 million hedged at forward rates of between $1.18331 and $1.24045:\u00a31 for the period
to\u00a0January 2023, and $100 million hedged at forward rates of between $1.17543 and $1.18131:\u00a31 for the period to January 2023.
Foreign currency sensitivity
The following table demonstrates the sensitivity to a reasonably foreseeable change in US dollars against pound sterling with all
other\u00a0variables held constant, of the Group\u2019s pro\ufb01t before tax (due to foreign exchange translation of monetary assets and liabilities).
The\u00a0impact of translating the net assets of foreign operations into US dollars is excluded from the sensitivity analysis.
Effect
on pro\ufb01t
Effect
Market
before tax
on equity
movement
$ million
$ million
31 December 2023
US dollar/pound sterling
10% strengthening
78
\u2013
US dollar/pound sterling
10% weakening
(78)
\u2013
31 December 2022
US dollar/pound sterling
10% strengthening
291
\u2013
US dollar/pound sterling
10% weakening
(291)
\u2013
Credit risk
Credit risk is the risk that a counterparty will not meet its obligations under a \ufb01nancial instrument or customer contract, leading to
\ufb01nancial loss. The Group trades only with recognised, creditworthy third parties. It is the Group\u2019s policy that all customers who wish to
trade on credit terms are subject to credit veri\ufb01cation procedures, which include an assessment of credit rating, short-term liquidity
and \ufb01nancial position. In addition, receivables balances are monitored on an ongoing basis, with the result that the Group\u2019s exposure
to bad debts is not signi\ufb01cant.
The Group is exposed to credit risk from its operating activities (primarily for trade receivables) and from its \ufb01nancing activities, including
deposits with banks and derivative \ufb01nancial instruments.
The Group has two ratings from two credit rating agencies: S&P Global at BB and Fitch at BB.
The Group only sells hydrocarbons to recognised and creditworthy parties, typically the trading arm of large, international oil and gas
companies. An indication of the concentration of credit risk on trade receivables is shown in note 4, whereby the revenue from one
customer exceeds 88 per cent (2022: 84 per cent) of the Group\u2019s consolidated revenue.
The credit risk on liquid funds and derivative \ufb01nancial instruments is limited because the counterparties are internationally recognised
banking institutions and are considered to represent minimal credit risk.
There are no signi\ufb01cant concentrations of credit risk within the Group unless otherwise disclosed, and credit losses are expected to be
near to zero. The maximum credit risk exposure relating to \ufb01nancial assets is represented by carrying value as at the balance sheet date.
Liquidity risk
Liquidity risk is the risk that the Group will encounter dif\ufb01culty in meeting obligations associated with \ufb01nancial liabilities that are settled
by delivering cash or another \ufb01nancial asset. The Group monitors the amount of borrowings maturing within any speci\ufb01c period and
expects to meet its \ufb01nancing commitments from the operating cash \ufb02ows of the business and existing committed lines of credit.
The table below summarises the maturity pro\ufb01le of the Group\u2019s \ufb01nancial liabilities based on contractual undiscounted payments:
\n \n
Within 1 year
1 to 2 years
2 to 5 years
Over 5 years
Total
As at 31 December 2023
$ million
$ million
$ million
$ million
$ million
Non-derivative \ufb01nancial liabilities
Bond
28
28
528
\u2013
584
Other loans
16
\u2013
\u2013
\u2013
16
Trade and other payables
825
13
\u2013
\u2013
838
Lease obligations
250
186
340
121
897
Total non-derivative \ufb01nancial liabilities
1,119
227
868
121
2,335
Derivative \ufb01nancial liabilities
Net-settled commodity derivatives
197
87
\u2013
\u2013
284
1,316
314
868
121
2,619
\n \n
Within 1 year
1 to 2 years
2 to 5 years
Over 5 years
Total
As at 31 December 2022
$ million
$ million
$ million
$ million
$ million
Non-derivative \ufb01nancial liabilities
Reserve based lending facility
61
61
881
\u2013
1,003
Bond
28
27
555
\u2013
610
Exploration \ufb01nance facility
11
\u2013
\u2013
\u2013
11
Other loans
11
9
18
\u2013
38
Trade and other payables
1,318
19
\u2013
\u2013
1,337
Lease obligations
208
180
386
61
835
Total non-derivative \ufb01nancial liabilities
1,637
296
1,840
61
3,834
Derivative \ufb01nancial liabilities
Net-settled commodity derivatives
2,308
930
155
\u2013
3,393
3,945
1,226
1,995
61
7,227
The maturity pro\ufb01les in the above tables re\ufb02ect only one side of the Group\u2019s liquidity position and will be recorded in the income
statement against future production and revenue which are not recognised on the balance sheet as assets. Interest bearing loans and
borrowings and trade payables mainly originate from the \ufb01nancing of assets used in the Group\u2019s ongoing operations such as property,
plant and equipment and working capital such as inventories. These assets are considered part of the Group\u2019s overall liquidity risk.", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23227": { "value": "16. Cash and cash equivalents \n \n
2023
2022
$ million
$ million
Cash at banks and in hand
280
500
Cash at bank earns interest at \ufb02oating rates based on daily bank deposit rates. The Group only deposits cash with major banks of high
quality credit standing.", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23377": { "value": "18. Commitments
Capital commitments
As at 31 December 2023, the Group had commitments for future capital expenditure amounting to $389 million (2022: $409 million).
Where the commitment relates to a joint arrangement, the amount represents the Group\u2019s net share of the commitment. Where the Group
is not the operator of the joint arrangement then the amounts are based on the Group\u2019s net share of committed future work programmes.", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23378": { "value": "18. Commitments
Capital commitments
As at 31 December 2023, the Group had commitments for future capital expenditure amounting to $389 million (2022: $409 million).
Where the commitment relates to a joint arrangement, the amount represents the Group\u2019s net share of the commitment. Where the Group
is not the operator of the joint arrangement then the amounts are based on the Group\u2019s net share of committed future work programmes.", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23389": { "value": "19. Trade and other payables \n \n
2023
2022
$ million
$ million
Current
Trade payables
52
47
Overlift position
33
132
Other payables
143
118
Matured \ufb01nancial instruments
48
258
Accruals
600
682
Deferred income
1
10
15
886
1,252
Non-current
Other payables
13
11
Deferred income
1
\u2013
8
13
19
1
Deferred income includes $10 million (2022: $23 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100 million from FlowStream
in return for granting them 15 per cent of production from the Solan \ufb01eld until suf\ufb01cient barrels have been delivered to achieve the rate of return within the agreement. This balance is being
released to the income statement within revenue as barrels are delivered to FlowStream from production from Solan. The estimated fair value includes unobservable inputs and is level 3 in
the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has decreased by $13 million in the year re\ufb02ecting the impact of barrels delivered to FlowStream
($15 million) and a change in estimate following an increase in the oil price resulting in a debit of $4 million to the income statement within \ufb01nance expense (note 7).", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23390": { "value": "19. Trade and other payables \n \n
2023
2022
$ million
$ million
Current
Trade payables
52
47
Overlift position
33
132
Other payables
143
118
Matured \ufb01nancial instruments
48
258
Accruals
600
682
Deferred income
1
10
15
886
1,252
Non-current
Other payables
13
11
Deferred income
1
\u2013
8
13
19
1
Deferred income includes $10 million (2022: $23 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100 million from FlowStream
in return for granting them 15 per cent of production from the Solan \ufb01eld until suf\ufb01cient barrels have been delivered to achieve the rate of return within the agreement. This balance is being
released to the income statement within revenue as barrels are delivered to FlowStream from production from Solan. The estimated fair value includes unobservable inputs and is level 3 in
the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has decreased by $13 million in the year re\ufb02ecting the impact of barrels delivered to FlowStream
($15 million) and a change in estimate following an increase in the oil price resulting in a debit of $4 million to the income statement within \ufb01nance expense (note 7).", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23391": { "value": "19. Trade and other payables \n \n
2023
2022
$ million
$ million
Current
Trade payables
52
47
Overlift position
33
132
Other payables
143
118
Matured \ufb01nancial instruments
48
258
Accruals
600
682
Deferred income
1
10
15
886
1,252
Non-current
Other payables
13
11
Deferred income
1
\u2013
8
13
19
1
Deferred income includes $10 million (2022: $23 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100 million from FlowStream
in return for granting them 15 per cent of production from the Solan \ufb01eld until suf\ufb01cient barrels have been delivered to achieve the rate of return within the agreement. This balance is being
released to the income statement within revenue as barrels are delivered to FlowStream from production from Solan. The estimated fair value includes unobservable inputs and is level 3 in
the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has decreased by $13 million in the year re\ufb02ecting the impact of barrels delivered to FlowStream
($15 million) and a change in estimate following an increase in the oil price resulting in a debit of $4 million to the income statement within \ufb01nance expense (note 7).", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23392": { "value": "19. Trade and other payables \n \n
2023
2022
$ million
$ million
Current
Trade payables
52
47
Overlift position
33
132
Other payables
143
118
Matured \ufb01nancial instruments
48
258
Accruals
600
682
Deferred income
1
10
15
886
1,252
Non-current
Other payables
13
11
Deferred income
1
\u2013
8
13
19
1
Deferred income includes $10 million (2022: $23 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100 million from FlowStream
in return for granting them 15 per cent of production from the Solan \ufb01eld until suf\ufb01cient barrels have been delivered to achieve the rate of return within the agreement. This balance is being
released to the income statement within revenue as barrels are delivered to FlowStream from production from Solan. The estimated fair value includes unobservable inputs and is level 3 in
the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has decreased by $13 million in the year re\ufb02ecting the impact of barrels delivered to FlowStream
($15 million) and a change in estimate following an increase in the oil price resulting in a debit of $4 million to the income statement within \ufb01nance expense (note 7).", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23398": { "value": "\n \n
2023
2022
$ million
$ million
Current
Trade payables
52
47
Overlift position
33
132
Other payables
143
118
Matured \ufb01nancial instruments
48
258
Accruals
600
682
Deferred income
1
10
15
886
1,252
Non-current
Other payables
13
11
Deferred income
1
\u2013
8
13
19
1
Deferred income includes $10 million (2022: $23 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100 million from FlowStream
in return for granting them 15 per cent of production from the Solan \ufb01eld until suf\ufb01cient barrels have been delivered to achieve the rate of return within the agreement. This balance is being
released to the income statement within revenue as barrels are delivered to FlowStream from production from Solan. The estimated fair value includes unobservable inputs and is level 3 in
the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has decreased by $13 million in the year re\ufb02ecting the impact of barrels delivered to FlowStream
($15 million) and a change in estimate following an increase in the oil price resulting in a debit of $4 million to the income statement within \ufb01nance expense (note 7).", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredIncomeExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23399": { "value": "\n \n
2023
2022
$ million
$ million
Current
Trade payables
52
47
Overlift position
33
132
Other payables
143
118
Matured \ufb01nancial instruments
48
258
Accruals
600
682
Deferred income
1
10
15
886
1,252
Non-current
Other payables
13
11
Deferred income
1
\u2013
8
13
19
", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23518": { "value": "20. Provisions \n \n
Decommissioning
provision
Other
Total
$ million
$ million
$ million
At 1 January 2022
5,354
27
5,381
Additions
24
\u2013
24
Changes in estimates \u2013 decrease to oil and gas tangible decommissioning assets
(720)
\u2013
(720)
Changes in estimates \u2013 decrease to oil and gas intangible decommissioning assets
(6)
\u2013
(6)
Changes in estimate \u2013 credit to income statement
\u2013
(1)
(1)
Changes in estimate on oil and gas tangible assets \u2013 credit to income statement
(82)
\u2013
(82)
Changes in estimate on oil and gas intangible assets \u2013 credit to income statement
(6)
\u2013
(6)
Amounts used
(223)
(2)
(225)
Disposal
(9)
\u2013
(9)
Interest on decommissioning lease
(1)
\u2013
(1)
Depreciation, depletion & amortisation on decommissioning right-of-use leased asset
(8)
\u2013
(8)
Unwinding of discount
65
\u2013
65
Currency translation adjustment
(247)
\u2013
(247)
At 31 December 2022
4,141
24
4,165
Additions
40
\u2013
40
Changes in estimates \u2013 decrease to oil and gas tangible decommissioning assets
(203)
\u2013
(203)
Changes in estimate on oil and gas tangible assets \u2013 debit to income statement
141
\u2013
141
Changes in estimate on oil and gas intangible assets \u2013 debit to income statement
4
\u2013
4
Changes in estimate \u2013 debit to income statement
\u2013
3
3
Amounts used
(248)
\u2013
(248)
Reclassi\ufb01cation of liabilities directly associated with assets held for sale
(87)
\u2013
(87)
Interest on decommissioning lease
(1)
\u2013
(1)
Depreciation, depletion & amortisation on decommissioning right-of-use leased asset
(9)
\u2013
(9)
Unwinding of discount
156
\u2013
156
Currency translation adjustment
87
\u2013
87
At 31 December 2023
4,021
27
4,048
\n \n
Non-current
Current
liabilities
liabilities
Total
Classi\ufb01ed within
$ million
$ million
$ million
At 31 December 2022
3,934
231
4,165
At 31 December 2023
3,818
230
4,048
Decommissioning provision
All of the $40 million decommissioning provision additions relate to oil and gas tangible assets (2022: $24 million).
The Group provides for the estimated future decommissioning costs on its oil and gas assets at the balance sheet date. The payment
dates of expected decommissioning costs are uncertain and are based on economic assumptions of the \ufb01elds concerned. The Group
currently expects to incur decommissioning costs within the next 40 years, the majority of which are anticipated to be incurred between
the next 10 to 20 years. These estimated future decommissioning costs are in\ufb02ated at the Group\u2019s long-term view of in\ufb02ation of
2.5 per cent per annum (2022: 2.5 per cent per annum) and discounted at a risk-free rate of between 4.3 per cent and 5.2 per cent
(2022: 3.5 per cent and 3.7 per cent) re\ufb02ecting a six-month (2022: six-month) rolling average of market rates over the varying lives of the
assets to calculate the present value of the decommissioning liabilities. The unwinding of the discount is presented within \ufb01nance costs.
These provisions have been created based on internal and third-party estimates. Assumptions based on the current economic
environment have been made, which management believe are a reasonable basis upon which to estimate the future liability. These
estimates are reviewed regularly to consider any material changes to the assumptions. However, actual decommissioning costs will
ultimately depend upon market prices for the necessary decommissioning work required, which will re\ufb02ect market conditions at the
relevant time. In addition, the timing of decommissioning liabilities will depend upon the dates when the \ufb01elds become economically
unviable, which in itself will depend on future commodity prices and climate change, which are inherently uncertain.
Other provisions
Other provisions relate to termination bene\ufb01t provision in Indonesia of $27 million (2022: $24 million), where the Group operates
a service, severance and compensation pay scheme under a collective labour agreement with the local workforce.", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23860": { "value": "Other provisions
Other provisions relate to termination bene\ufb01t provision in Indonesia of $27 million (2022: $24 million), where the Group operates
a service, severance and compensation pay scheme under a collective labour agreement with the local workforce.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherProvisionsContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f23868": { "value": "21. Borrowings and facilities
The Group\u2019s borrowings are carried at amortised cost:
\n \n
2023
2022
$ million
$ million
Reserve based lending (RBL) facility
1
\u2013
702
Bond
493
491
Exploration \ufb01nance facility
\u2013
11
Other loans
16
34
Total borrowings
509
1,238
Classi\ufb01ed within
Non-current liabilities
493
1,216
Current liabilities
16
22
Total borrowings
509
1,238
1
The reserve based lending (RBL) facility was fully repaid in the year, leaving $61 million of unamortised fees and related costs to be amortised over the remaining term of the facility which
have been reclassi\ufb01ed within current and non-current assets as appropriate.
The RBL facility was amended and extended in November 2023, and the key terms of the amended facility are:
\u2022
Term matures 31 December 2029
\u2022
Facility size of $2.75 billion, with a $1.75 billion letter of credit sub-limit
\u2022
Debt availability at $1.346 billion effective 24 November 2023
\u2022
Debt availability to be redetermined on an annual basis
\u2022
Interest at compounded SOFR plus a margin of 3.2 per cent, rising to a margin of 3.4 per cent from November 2025 and 3.6 per cent
from November 2027
\u2022
A margin adjustment linked to carbon-emission reductions
\u2022
Straight-line amortisation of letter of credit sub-limit from January 2027 to six months before maturity. No material cash collateralisation
required until\u00a02028
\u2022
Liquidity and leverage covenant tests
\u2022
A syndication group of 15 banks
Certain fees are also payable, including fees on available commitments at 40 per cent of the applicable margin and commission
on letters of credit issued at 50 per cent of the applicable margin.
In October 2021, the Group issued a $500 million bond under Rule 144A and with a tenor of \ufb01ve years to maturity. The coupon was
set at 5.50 per cent and interest is payable semi-annually.
At the balance sheet date, the outstanding RBL balance excluding incremental arrangement fees and related costs was $nil
(2022: $775 million). As at 31 December 2023, $1,340 million remained available for drawdown under the RBL facility
(2022: $1,972 million).
The Group has facilities to issue up to $1,750 million of letters of credit, of which $1,186 million was in issue as at 31 December
(2022: $966 million), mainly in respect of future abandonment liabilities.
A further $34 million of arrangement fees and related costs were capitalised during the year following amendments to the RBL facility
which became effective from November 2023.
During the year $48 million (2022: $55 million) of arrangement fees and related costs have been amortised and are included within
\ufb01nancing costs.
At 31 December 2023, $68 million of arrangement fees and related costs remain capitalised (2022: $82 million), of which $21 million
is\u00a0due to be amortised within the next 12 months (2022: $20 million). $61 million of these arrangement fees relate to the RBL facility,
$19 million of which have been reclassi\ufb01ed within current assets, and $42 million, which are due to be amortised beyond the next
12\u00a0months, have been reclassi\ufb01ed to non-current assets (note 15).
Bond interest of $6 million (2022: $6 million comprising both bond and RBL interest) had accrued by the balance sheet date and
has been classi\ufb01ed within accruals.
Since 2019, the Group has been operating within an exploration \ufb01nance facility (EFF), of NOK 1 billion, in relation to part-\ufb01nancing
the exploration activities of Harbour Energy Norge AS. This facility was repaid in full in February 2023.
Other loans represent a commercial \ufb01nancing arrangement with Baker Hughes (formerly BHGE), that covered a three-year work
programme for drilling, completion and subsea tie-in of development wells on Harbour\u2019s operated assets. The loan will be repaid
based on production performance, subject to a cap.
The table below details the change in the carrying amount of the Group\u2019s borrowings arising from \ufb01nancing cash \ufb02ows.
$ million
Total borrowings as at 1 January 2022
2,886
Repayment of RBL
(1,663)
Repayment of \ufb01nancing arrangement
(15)
Repayment of EFF loan
(38)
Proceeds from EFF loan
11
Currency translation adjustment on EFF loan
(7)
Financing arrangement interest payable
9
Amortisation of arrangement fees and related costs
55
Total borrowings as at 31 December 2022
1,238
Proceeds from drawdown of borrowing facilities
660
Repayment of RBL
(1,435)
Repayment of \ufb01nancing arrangement
(21)
Repayment of EFF loan
(11)
Arrangement fees and related costs on RBL capitalised
(34)
Financing arrangement interest payable
3
Amortisation of arrangement fees and related costs
48
Reclassi\ufb01cation of RBL arrangement fees and related costs to current and non-current assets
61
Total borrowings as at 31 December 2023
509
", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f24145": { "value": "22. Other \ufb01nancial assets and liabilities
The Group held the following \ufb01nancial instruments at fair value at 31 December 2023. The fair values of all derivative \ufb01nancial
instruments are based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation,
which includes estimates based on unobservable inputs and is level 3 in the IFRS 13 hierarchy.
\n \n
31 December 2023
31 December 2022
Assets
Liabilities
Assets
Liabilities
$ million
$ million
$ million
$ million
Current
Measured at fair value through pro\ufb01t and loss
Foreign exchange derivatives
6
\u2013
6
\u2013
Interest rate derivatives
\u2013
\u2013
24
\u2013
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
(57)
16
\u2013
30
(57)
Measured at fair value through other comprehensive income
Commodity derivatives
154
(197)
51
(2,114)
Total current
170
(197)
81
(2,171)
Non-current
Measured at fair value through pro\ufb01t and loss
Interest rate derivatives
\u2013
\u2013
18
\u2013
\u2013
\u2013
18
\u2013
Measured at fair value through other comprehensive income
Commodity derivatives
112
(87)
85
(1,279)
Total non-current
112
(87)
103
(1,279)
Total current and non-current
282
(284)
184
(3,450)
Fair value measurements
All \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with
the hierarchy described in IFRS 13 \u2018Fair Value Measurement\u2019. The hierarchy groups fair value measurements into the following levels
based on the degree to which the fair value is observable.
\u2022
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities
\u2022
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or\u00a0indirectly
\u2022
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2023
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
\u2013
Commodity derivatives
266
\u2013
(284)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Total fair value
282
\u2013
(284)
\u2013
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2022
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
\u2013
\u2013
(57)
\u2013
Commodity derivatives
136
\u2013
(3,393)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Interest rate derivatives
42
\u2013
\u2013
\u2013
Total fair value
184
\u2013
(3,450)
\u2013
There were no transfers between fair value levels in 2022 or 2023.
Fair value movements recognised in the income statement on \ufb01nancial instruments are shown below.
2023
2022
Finance income
$ million
$ million
Change in fair value of embedded derivative within gas contract
68
\u2013
Foreign exchange derivatives
\u2013
7
Interest rate derivatives
(43)
31
25
38
2023
2022
Finance expenses
$ million
$ million
Change in fair value of embedded derivative within gas contract
\u2013
(48)
\u2013
(48)
Fair values of other \ufb01nancial instruments
The following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
2023
2022
$ million
$ million
Book value
Fair value
Book value
Fair value
Bond
(493)
(487)
(491)
(446)
The fair value of the bond is within level 2 of the fair value hierarchy and has been estimated by discounting future cash \ufb02ows by the relevant
market yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
short-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.
Cash \ufb02ow hedge accounting
The Group uses a combination of \ufb01xed price physical sales contracts and cash-settled \ufb01xed price commodity swaps and options to
manage the price risk associated with its underlying oil and gas revenues. As at 31 December 2023, all of the Group\u2019s cash-settled
\ufb01xed price commodity swap derivatives have been designated as cash \ufb02ow hedges of highly probable forecast sales of oil and gas.
The following table indicates the volumes, average hedged price and timings associated with the Group\u2019s \ufb01nancial commodity derivatives.
Volumes hedged through \ufb01xed price contracts with customers for physical delivery are excluded.
Position as at 31 December 2023
2024
2025
2026
Oil volume hedged (thousand bbls)
7,320
4,380
\u2013
Weighted average hedged price ($/bbl)
84.37
77.35
\u2013
Gas volume hedged (million therms)
759
428
90
Weighted average hedged price (p/therm)
67.19
89.68
99.28
As at 31 December 2023, the fair value of net \ufb01nancial commodity derivatives designated as cash \ufb02ow hedges, all executed under ISDA
agreements with no margining requirements, was a net payable of $66 million (2022: $3,516 million) and net unrealised pre-tax losses of
$16 million (2022: $3,185 million) were deferred in other comprehensive income in respect of the effective portion of the hedge relationships.
Amounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur.
As at 31 December 2023, net deferred pre-tax losses of $51 million (2022: $2,368 million) are expected to be released to the income
statement within one year.
Interest Rate Benchmark Reform (IBOR)
During the year, the Group transitioned to alternative benchmark rates to cater for the discontinuation of IBOR rates. Our bond is at
a \ufb01xed interest rate of 5.5 per cent whilst the RBL (undrawn at 31 December 2023) transitioned from US LIBOR to SOFR (Secured
Overnight Financing Rate).", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialLiabilitiesHeldForTradingExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f24146": { "value": "22. Other \ufb01nancial assets and liabilities
The Group held the following \ufb01nancial instruments at fair value at 31 December 2023. The fair values of all derivative \ufb01nancial
instruments are based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation,
which includes estimates based on unobservable inputs and is level 3 in the IFRS 13 hierarchy.
\n \n
31 December 2023
31 December 2022
Assets
Liabilities
Assets
Liabilities
$ million
$ million
$ million
$ million
Current
Measured at fair value through pro\ufb01t and loss
Foreign exchange derivatives
6
\u2013
6
\u2013
Interest rate derivatives
\u2013
\u2013
24
\u2013
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
(57)
16
\u2013
30
(57)
Measured at fair value through other comprehensive income
Commodity derivatives
154
(197)
51
(2,114)
Total current
170
(197)
81
(2,171)
Non-current
Measured at fair value through pro\ufb01t and loss
Interest rate derivatives
\u2013
\u2013
18
\u2013
\u2013
\u2013
18
\u2013
Measured at fair value through other comprehensive income
Commodity derivatives
112
(87)
85
(1,279)
Total non-current
112
(87)
103
(1,279)
Total current and non-current
282
(284)
184
(3,450)
Fair value measurements
All \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with
the hierarchy described in IFRS 13 \u2018Fair Value Measurement\u2019. The hierarchy groups fair value measurements into the following levels
based on the degree to which the fair value is observable.
\u2022
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities
\u2022
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or\u00a0indirectly
\u2022
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2023
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
\u2013
Commodity derivatives
266
\u2013
(284)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Total fair value
282
\u2013
(284)
\u2013
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2022
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
\u2013
\u2013
(57)
\u2013
Commodity derivatives
136
\u2013
(3,393)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Interest rate derivatives
42
\u2013
\u2013
\u2013
Total fair value
184
\u2013
(3,450)
\u2013
There were no transfers between fair value levels in 2022 or 2023.
Fair value movements recognised in the income statement on \ufb01nancial instruments are shown below.
2023
2022
Finance income
$ million
$ million
Change in fair value of embedded derivative within gas contract
68
\u2013
Foreign exchange derivatives
\u2013
7
Interest rate derivatives
(43)
31
25
38
2023
2022
Finance expenses
$ million
$ million
Change in fair value of embedded derivative within gas contract
\u2013
(48)
\u2013
(48)
Fair values of other \ufb01nancial instruments
The following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
2023
2022
$ million
$ million
Book value
Fair value
Book value
Fair value
Bond
(493)
(487)
(491)
(446)
The fair value of the bond is within level 2 of the fair value hierarchy and has been estimated by discounting future cash \ufb02ows by the relevant
market yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
short-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.
Cash \ufb02ow hedge accounting
The Group uses a combination of \ufb01xed price physical sales contracts and cash-settled \ufb01xed price commodity swaps and options to
manage the price risk associated with its underlying oil and gas revenues. As at 31 December 2023, all of the Group\u2019s cash-settled
\ufb01xed price commodity swap derivatives have been designated as cash \ufb02ow hedges of highly probable forecast sales of oil and gas.
The following table indicates the volumes, average hedged price and timings associated with the Group\u2019s \ufb01nancial commodity derivatives.
Volumes hedged through \ufb01xed price contracts with customers for physical delivery are excluded.
Position as at 31 December 2023
2024
2025
2026
Oil volume hedged (thousand bbls)
7,320
4,380
\u2013
Weighted average hedged price ($/bbl)
84.37
77.35
\u2013
Gas volume hedged (million therms)
759
428
90
Weighted average hedged price (p/therm)
67.19
89.68
99.28
As at 31 December 2023, the fair value of net \ufb01nancial commodity derivatives designated as cash \ufb02ow hedges, all executed under ISDA
agreements with no margining requirements, was a net payable of $66 million (2022: $3,516 million) and net unrealised pre-tax losses of
$16 million (2022: $3,185 million) were deferred in other comprehensive income in respect of the effective portion of the hedge relationships.
Amounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur.
As at 31 December 2023, net deferred pre-tax losses of $51 million (2022: $2,368 million) are expected to be released to the income
statement within one year.
Interest Rate Benchmark Reform (IBOR)
During the year, the Group transitioned to alternative benchmark rates to cater for the discontinuation of IBOR rates. Our bond is at
a \ufb01xed interest rate of 5.5 per cent whilst the RBL (undrawn at 31 December 2023) transitioned from US LIBOR to SOFR (Secured
Overnight Financing Rate).", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialAssetsHeldForTradingExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f24147": { "value": "22. Other \ufb01nancial assets and liabilities
The Group held the following \ufb01nancial instruments at fair value at 31 December 2023. The fair values of all derivative \ufb01nancial
instruments are based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation,
which includes estimates based on unobservable inputs and is level 3 in the IFRS 13 hierarchy.
\n \n
31 December 2023
31 December 2022
Assets
Liabilities
Assets
Liabilities
$ million
$ million
$ million
$ million
Current
Measured at fair value through pro\ufb01t and loss
Foreign exchange derivatives
6
\u2013
6
\u2013
Interest rate derivatives
\u2013
\u2013
24
\u2013
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
(57)
16
\u2013
30
(57)
Measured at fair value through other comprehensive income
Commodity derivatives
154
(197)
51
(2,114)
Total current
170
(197)
81
(2,171)
Non-current
Measured at fair value through pro\ufb01t and loss
Interest rate derivatives
\u2013
\u2013
18
\u2013
\u2013
\u2013
18
\u2013
Measured at fair value through other comprehensive income
Commodity derivatives
112
(87)
85
(1,279)
Total non-current
112
(87)
103
(1,279)
Total current and non-current
282
(284)
184
(3,450)
Fair value measurements
All \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with
the hierarchy described in IFRS 13 \u2018Fair Value Measurement\u2019. The hierarchy groups fair value measurements into the following levels
based on the degree to which the fair value is observable.
\u2022
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities
\u2022
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or\u00a0indirectly
\u2022
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2023
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
\u2013
Commodity derivatives
266
\u2013
(284)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Total fair value
282
\u2013
(284)
\u2013
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2022
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
\u2013
\u2013
(57)
\u2013
Commodity derivatives
136
\u2013
(3,393)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Interest rate derivatives
42
\u2013
\u2013
\u2013
Total fair value
184
\u2013
(3,450)
\u2013
There were no transfers between fair value levels in 2022 or 2023.
Fair value movements recognised in the income statement on \ufb01nancial instruments are shown below.
2023
2022
Finance income
$ million
$ million
Change in fair value of embedded derivative within gas contract
68
\u2013
Foreign exchange derivatives
\u2013
7
Interest rate derivatives
(43)
31
25
38
2023
2022
Finance expenses
$ million
$ million
Change in fair value of embedded derivative within gas contract
\u2013
(48)
\u2013
(48)
Fair values of other \ufb01nancial instruments
The following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
2023
2022
$ million
$ million
Book value
Fair value
Book value
Fair value
Bond
(493)
(487)
(491)
(446)
The fair value of the bond is within level 2 of the fair value hierarchy and has been estimated by discounting future cash \ufb02ows by the relevant
market yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
short-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.
Cash \ufb02ow hedge accounting
The Group uses a combination of \ufb01xed price physical sales contracts and cash-settled \ufb01xed price commodity swaps and options to
manage the price risk associated with its underlying oil and gas revenues. As at 31 December 2023, all of the Group\u2019s cash-settled
\ufb01xed price commodity swap derivatives have been designated as cash \ufb02ow hedges of highly probable forecast sales of oil and gas.
The following table indicates the volumes, average hedged price and timings associated with the Group\u2019s \ufb01nancial commodity derivatives.
Volumes hedged through \ufb01xed price contracts with customers for physical delivery are excluded.
Position as at 31 December 2023
2024
2025
2026
Oil volume hedged (thousand bbls)
7,320
4,380
\u2013
Weighted average hedged price ($/bbl)
84.37
77.35
\u2013
Gas volume hedged (million therms)
759
428
90
Weighted average hedged price (p/therm)
67.19
89.68
99.28
As at 31 December 2023, the fair value of net \ufb01nancial commodity derivatives designated as cash \ufb02ow hedges, all executed under ISDA
agreements with no margining requirements, was a net payable of $66 million (2022: $3,516 million) and net unrealised pre-tax losses of
$16 million (2022: $3,185 million) were deferred in other comprehensive income in respect of the effective portion of the hedge relationships.
Amounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur.
As at 31 December 2023, net deferred pre-tax losses of $51 million (2022: $2,368 million) are expected to be released to the income
statement within one year.
Interest Rate Benchmark Reform (IBOR)
During the year, the Group transitioned to alternative benchmark rates to cater for the discontinuation of IBOR rates. Our bond is at
a \ufb01xed interest rate of 5.5 per cent whilst the RBL (undrawn at 31 December 2023) transitioned from US LIBOR to SOFR (Secured
Overnight Financing Rate).", "dimensions": { "concept": "ifrs-full:DisclosureOfDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f24148": { "value": "22. Other \ufb01nancial assets and liabilities
The Group held the following \ufb01nancial instruments at fair value at 31 December 2023. The fair values of all derivative \ufb01nancial
instruments are based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation,
which includes estimates based on unobservable inputs and is level 3 in the IFRS 13 hierarchy.
\n \n
31 December 2023
31 December 2022
Assets
Liabilities
Assets
Liabilities
$ million
$ million
$ million
$ million
Current
Measured at fair value through pro\ufb01t and loss
Foreign exchange derivatives
6
\u2013
6
\u2013
Interest rate derivatives
\u2013
\u2013
24
\u2013
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
(57)
16
\u2013
30
(57)
Measured at fair value through other comprehensive income
Commodity derivatives
154
(197)
51
(2,114)
Total current
170
(197)
81
(2,171)
Non-current
Measured at fair value through pro\ufb01t and loss
Interest rate derivatives
\u2013
\u2013
18
\u2013
\u2013
\u2013
18
\u2013
Measured at fair value through other comprehensive income
Commodity derivatives
112
(87)
85
(1,279)
Total non-current
112
(87)
103
(1,279)
Total current and non-current
282
(284)
184
(3,450)
Fair value measurements
All \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with
the hierarchy described in IFRS 13 \u2018Fair Value Measurement\u2019. The hierarchy groups fair value measurements into the following levels
based on the degree to which the fair value is observable.
\u2022
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities
\u2022
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or\u00a0indirectly
\u2022
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2023
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
\u2013
Commodity derivatives
266
\u2013
(284)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Total fair value
282
\u2013
(284)
\u2013
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2022
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
\u2013
\u2013
(57)
\u2013
Commodity derivatives
136
\u2013
(3,393)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Interest rate derivatives
42
\u2013
\u2013
\u2013
Total fair value
184
\u2013
(3,450)
\u2013
There were no transfers between fair value levels in 2022 or 2023.
Fair value movements recognised in the income statement on \ufb01nancial instruments are shown below.
2023
2022
Finance income
$ million
$ million
Change in fair value of embedded derivative within gas contract
68
\u2013
Foreign exchange derivatives
\u2013
7
Interest rate derivatives
(43)
31
25
38
2023
2022
Finance expenses
$ million
$ million
Change in fair value of embedded derivative within gas contract
\u2013
(48)
\u2013
(48)
Fair values of other \ufb01nancial instruments
The following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
2023
2022
$ million
$ million
Book value
Fair value
Book value
Fair value
Bond
(493)
(487)
(491)
(446)
The fair value of the bond is within level 2 of the fair value hierarchy and has been estimated by discounting future cash \ufb02ows by the relevant
market yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
short-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.
Cash \ufb02ow hedge accounting
The Group uses a combination of \ufb01xed price physical sales contracts and cash-settled \ufb01xed price commodity swaps and options to
manage the price risk associated with its underlying oil and gas revenues. As at 31 December 2023, all of the Group\u2019s cash-settled
\ufb01xed price commodity swap derivatives have been designated as cash \ufb02ow hedges of highly probable forecast sales of oil and gas.
The following table indicates the volumes, average hedged price and timings associated with the Group\u2019s \ufb01nancial commodity derivatives.
Volumes hedged through \ufb01xed price contracts with customers for physical delivery are excluded.
Position as at 31 December 2023
2024
2025
2026
Oil volume hedged (thousand bbls)
7,320
4,380
\u2013
Weighted average hedged price ($/bbl)
84.37
77.35
\u2013
Gas volume hedged (million therms)
759
428
90
Weighted average hedged price (p/therm)
67.19
89.68
99.28
As at 31 December 2023, the fair value of net \ufb01nancial commodity derivatives designated as cash \ufb02ow hedges, all executed under ISDA
agreements with no margining requirements, was a net payable of $66 million (2022: $3,516 million) and net unrealised pre-tax losses of
$16 million (2022: $3,185 million) were deferred in other comprehensive income in respect of the effective portion of the hedge relationships.
Amounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur.
As at 31 December 2023, net deferred pre-tax losses of $51 million (2022: $2,368 million) are expected to be released to the income
statement within one year.
Interest Rate Benchmark Reform (IBOR)
During the year, the Group transitioned to alternative benchmark rates to cater for the discontinuation of IBOR rates. Our bond is at
a \ufb01xed interest rate of 5.5 per cent whilst the RBL (undrawn at 31 December 2023) transitioned from US LIBOR to SOFR (Secured
Overnight Financing Rate).", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsHeldForTradingExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f24156": { "value": "\n \n
31 December 2023
31 December 2022
Assets
Liabilities
Assets
Liabilities
$ million
$ million
$ million
$ million
Current
Measured at fair value through pro\ufb01t and loss
Foreign exchange derivatives
6
\u2013
6
\u2013
Interest rate derivatives
\u2013
\u2013
24
\u2013
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
(57)
16
\u2013
30
(57)
Measured at fair value through other comprehensive income
Commodity derivatives
154
(197)
51
(2,114)
Total current
170
(197)
81
(2,171)
Non-current
Measured at fair value through pro\ufb01t and loss
Interest rate derivatives
\u2013
\u2013
18
\u2013
\u2013
\u2013
18
\u2013
Measured at fair value through other comprehensive income
Commodity derivatives
112
(87)
85
(1,279)
Total non-current
112
(87)
103
(1,279)
Total current and non-current
282
(284)
184
(3,450)
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f24157": { "value": "\n \n
31 December 2023
31 December 2022
Assets
Liabilities
Assets
Liabilities
$ million
$ million
$ million
$ million
Current
Measured at fair value through pro\ufb01t and loss
Foreign exchange derivatives
6
\u2013
6
\u2013
Interest rate derivatives
\u2013
\u2013
24
\u2013
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
(57)
16
\u2013
30
(57)
Measured at fair value through other comprehensive income
Commodity derivatives
154
(197)
51
(2,114)
Total current
170
(197)
81
(2,171)
Non-current
Measured at fair value through pro\ufb01t and loss
Interest rate derivatives
\u2013
\u2013
18
\u2013
\u2013
\u2013
18
\u2013
Measured at fair value through other comprehensive income
Commodity derivatives
112
(87)
85
(1,279)
Total non-current
112
(87)
103
(1,279)
Total current and non-current
282
(284)
184
(3,450)
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsDesignatedAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f24347": { "value": "Fair value measurements
All \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with
the hierarchy described in IFRS 13 \u2018Fair Value Measurement\u2019. The hierarchy groups fair value measurements into the following levels
based on the degree to which the fair value is observable.
\u2022
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities
\u2022
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or\u00a0indirectly
\u2022
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2023
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
\u2013
Commodity derivatives
266
\u2013
(284)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Total fair value
282
\u2013
(284)
\u2013
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2022
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
\u2013
\u2013
(57)
\u2013
Commodity derivatives
136
\u2013
(3,393)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Interest rate derivatives
42
\u2013
\u2013
\u2013
Total fair value
184
\u2013
(3,450)
\u2013
There were no transfers between fair value levels in 2022 or 2023.
Fair value movements recognised in the income statement on \ufb01nancial instruments are shown below.
2023
2022
Finance income
$ million
$ million
Change in fair value of embedded derivative within gas contract
68
\u2013
Foreign exchange derivatives
\u2013
7
Interest rate derivatives
(43)
31
25
38
2023
2022
Finance expenses
$ million
$ million
Change in fair value of embedded derivative within gas contract
\u2013
(48)
\u2013
(48)
", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f24348": { "value": "Fair value measurements
All \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with
the hierarchy described in IFRS 13 \u2018Fair Value Measurement\u2019. The hierarchy groups fair value measurements into the following levels
based on the degree to which the fair value is observable.
\u2022
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities
\u2022
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or\u00a0indirectly
\u2022
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2023
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
10
\u2013
\u2013
\u2013
Commodity derivatives
266
\u2013
(284)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Total fair value
282
\u2013
(284)
\u2013
\n \n
Financial assets
Financial liabilities
Level 2
Level 3
Level 2
Level 3
As at 31 December 2022
$ million
$ million
$ million
$ million
Fair value of embedded derivative within gas contract
\u2013
\u2013
(57)
\u2013
Commodity derivatives
136
\u2013
(3,393)
\u2013
Foreign exchange derivatives
6
\u2013
\u2013
\u2013
Interest rate derivatives
42
\u2013
\u2013
\u2013
Total fair value
184
\u2013
(3,450)
\u2013
There were no transfers between fair value levels in 2022 or 2023.
Fair value movements recognised in the income statement on \ufb01nancial instruments are shown below.
2023
2022
Finance income
$ million
$ million
Change in fair value of embedded derivative within gas contract
68
\u2013
Foreign exchange derivatives
\u2013
7
Interest rate derivatives
(43)
31
25
38
2023
2022
Finance expenses
$ million
$ million
Change in fair value of embedded derivative within gas contract
\u2013
(48)
\u2013
(48)
Fair values of other \ufb01nancial instruments
The following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
2023
2022
$ million
$ million
Book value
Fair value
Book value
Fair value
Bond
(493)
(487)
(491)
(446)
The fair value of the bond is within level 2 of the fair value hierarchy and has been estimated by discounting future cash \ufb02ows by the relevant
market yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
short-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f24767": { "value": "23. Financial risk factors and risk management
The Group\u2019s principal \ufb01nancial assets and liabilities comprise trade and other receivables, cash and short-term deposits accounts, trade
payables, interest bearing loans and derivative \ufb01nancial instruments. The main purpose of these \ufb01nancial instruments is to manage
short-term cash \ufb02ow, price exposures and raise \ufb01nance for the Group\u2019s expenditure programme. Further information on the Group\u2019s
\ufb01nancial instrument risk management objectives, policies and strategies are set out in the discussion of capital management policies
in the Strategic report (see page 62).
Risk exposures and responses
The Group manages its exposure to key \ufb01nancial risks in accordance with its \ufb01nancial risk management policy. The objective of the policy
is to support the delivery of the Group\u2019s \ufb01nancial targets while protecting future \ufb01nancial security. The main risks that could adversely
affect the Group\u2019s \ufb01nancial assets, liabilities or future cash \ufb02ows are market risks comprising commodity price risk, interest rate risk and
foreign currency risk, liquidity risk, and credit risk. Management reviews and agrees policies for managing each of these risks which are
summarised in this note.
The Group\u2019s management oversees the management of \ufb01nancial risks. The Group\u2019s senior management ensures that \ufb01nancial risk-taking
activities are governed by appropriate policies and procedures and that \ufb01nancial risks are identi\ufb01ed, measured and managed in
accordance with Group policies and risk objectives. All derivative activities for risk management purposes are carried out by specialist
teams that have the appropriate skills, experience and supervision. It is the Group\u2019s policy that no trading in derivatives for speculative
purposes shall be undertaken.
Market risk
Market risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market prices.
Market risk comprises three types of risk: commodity price risk, interest rate risk and foreign currency risk. Financial instruments mainly
affected by market risk include loans and borrowings, deposits and derivative \ufb01nancial instruments.
The sensitivity analyses in the following sections relate to the position as at 31 December 2023 and 31 December 2022.
The sensitivity analyses have been prepared on the basis that the number of \ufb01nancial instruments are all constant. The sensitivity
analyses are intended to illustrate the sensitivity to changes in market variables on the composition of the Group\u2019s \ufb01nancial instruments
at the balance sheet date and show the impact on pro\ufb01t or loss and shareholders\u2019 equity, where applicable.
The following assumptions have been made in calculating the sensitivity analyses:
\u2022
The sensitivity of the relevant pro\ufb01t before tax item and/or equity is the effect of the assumed changes in respective market risks
for the full year based on the \ufb01nancial assets and \ufb01nancial liabilities held at the balance sheet date
\u2022
The sensitivities indicate the effect of a reasonable increase in each market variable. Unless otherwise stated, the effect of
a corresponding decrease in these variables is considered approximately equal and opposite
\u2022
Fair value changes from derivative instruments designated as cash \ufb02ow hedges are considered fully effective and recorded
in shareholders\u2019 equity, net of tax
\u2022
Fair value changes from derivatives and other \ufb01nancial instruments not designated as cash \ufb02ow hedges are presented as a sensitivity
to pro\ufb01t before tax only and not included in shareholders\u2019 equity
Commodity price risk
The Group is exposed to the risk of \ufb02uctuations in prevailing market commodity prices on the mix of oil and gas products. On a rolling
basis, the Group\u2019s policy is to hedge the commodity price exposure associated with 40 to 70 per cent of the next 12 months\u2019 production
(year 1), between 30 and 60 per cent of \u2018year 2\u2019 production, from \u2018year 3\u2019 up to 50 per cent of production and from \u2018year 4\u2019 up to
40 per cent of production. The Group manages these risks through the use of \ufb01xed price contracts with customers for physical delivery
and derivative \ufb01nancial instruments including \ufb01xed price swaps and options.
Commodity price sensitivity
The following table summarises the impact on the Group\u2019s pre-tax pro\ufb01t and equity from a reasonably foreseeable movement in
commodity prices on the fair value of commodity based derivative instruments held by the Group at the balance sheet date.
E\ufb00ect
on pro\ufb01t
E\ufb00ect
before tax
on equity
As at 31 December 2023
Market movement
$ million
$ million
Brent oil price
$10 /bbl increase
\u2013
(28)
Brent oil price
$10 /bbl decrease
\u2013
28
NBP gas price
\u00a30.1 /therm increase
\u2013
(28)
NBP gas price
\u00a30.1 /therm decrease
\u2013
28
Effect
on pro\ufb01t
Effect
before tax
on equity
As at 31 December 2022
Market movement
$ million
$ million
Brent oil price
$10 /bbl increase
\u2013
(49)
Brent oil price
$10 /bbl decrease
\u2013
49
NBP gas price
\u00a30.1 /therm increase
\u2013
(49)
NBP gas price
\u00a30.1 /therm decrease
\u2013
49
Interest rate risk
Interest rate risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market
interest rates. The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to the Group\u2019s long-term debt
obligation with \ufb02oating interest rates.
Fixed rate borrowings at 31 December 2023 comprise a bond which incurs interest at 5.5 per cent per annum. Following the settlement
of the RBL and exploration \ufb01nancing balances during the year, the Group has no \ufb02oating rate borrowings at 31 December 2023. As at
31 December 2022, \ufb02oating rate borrowings comprised loans under the RBL facility which incurred interest \ufb01xed either one month,
three months or six months in advance at USD LIBOR plus a margin of 3.21 per cent. Floating rate \ufb01nancial assets comprise cash and
cash equivalents which earn interest at the relevant market rate. Prior to settlement of the RBL, the Group monitored its exposure
to \ufb02uctuations in interest rates and uses interest rate derivatives to manage the \ufb01xed and \ufb02oating composition of its borrowings.
The interest rate \ufb01nancial instruments in place at the balance sheet date are shown below:
Derivative
Currency
Period of hedge
Terms
31 December 2023
Interest rate swaps
$nil million
N/A
N/A
31 December 2022
Interest rate swaps
$545 million
Jun 20 \u2013 Jun 25
Average 0.55%
The interest rate and currency pro\ufb01le of the Group\u2019s interest-bearing \ufb01nancial assets and liabilities are shown below:
\n \n
Cash
Fixed rate
Floating rate
at bank
borrowings
borrowings
Total
As at 31 December 2023
$ million
$ million
$ million
$ million
US dollar
238
(493)
\u2013
(255)
Pound sterling
28
\u2013
\u2013
28
Norwegian krone
13
\u2013
\u2013
13
Other
1
\u2013
\u2013
1
280
(493)
\u2013
(213)
\n \n
Cash
Fixed rate
Floating rate
at bank
borrowings
borrowings
Total
As at 31 December 2022
$ million
$ million
$ million
$ million
US dollar
481
(491)
(702)
(712)
Pound sterling
8
\u2013
\u2013
8
Norwegian krone
6
\u2013
(11)
(5)
Other
5
\u2013
\u2013
5
500
(491)
(713)
(704)
Interest rate sensitivity
The following table demonstrates the indicative pre-tax effect on pro\ufb01t and equity of applying a reasonably foreseeable increase in
interest rates to the Group\u2019s \ufb01nancial assets and liabilities at the balance sheet date.
\n \n
Effect
on pro\ufb01t
Effect
before tax
on equity
Market movement
$ million
$ million
31 December 2023
US dollar interest rates
+100 basis points
2
\u2013
31 December 2022
US dollar interest rates
+100 basis points
8
\u2013
Foreign currency risk
Foreign currency risk is the risk that the fair value or future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in
foreign exchange rates.
The Group is exposed to foreign currency risk primarily arising from exchange rate movements in US dollar against pound sterling.
To\u00a0mitigate exposure to movements in exchange rates, wherever possible \ufb01nancial assets and liabilities are held in currencies that
match\u00a0the functional currency of the relevant entity. The Group has subsidiaries with functional currencies of pound sterling, US dollar,
Norwegian krone, Mexican pesos and Brazilian reals. Exposures can also arise from sales or purchases denominated in currencies
other than the functional currency of the relevant entity; such exposures are monitored and hedged with agreement from the Board.
The Group enters into forward contracts as a means of hedging its exposure to foreign exchange rate risks. As at 31 December 2023, the
Group had \u00a3212 million hedged at a forward rate of between $1.2182 and $1.2742:\u00a31 for the period January 2024 to October 2024.
As at 31 December 2022, the Group had \u00a342 million hedged at forward rates of between $1.18331 and $1.24045:\u00a31 for the period
to\u00a0January 2023, and $100 million hedged at forward rates of between $1.17543 and $1.18131:\u00a31 for the period to January 2023.
Foreign currency sensitivity
The following table demonstrates the sensitivity to a reasonably foreseeable change in US dollars against pound sterling with all
other\u00a0variables held constant, of the Group\u2019s pro\ufb01t before tax (due to foreign exchange translation of monetary assets and liabilities).
The\u00a0impact of translating the net assets of foreign operations into US dollars is excluded from the sensitivity analysis.
Effect
on pro\ufb01t
Effect
Market
before tax
on equity
movement
$ million
$ million
31 December 2023
US dollar/pound sterling
10% strengthening
78
\u2013
US dollar/pound sterling
10% weakening
(78)
\u2013
31 December 2022
US dollar/pound sterling
10% strengthening
291
\u2013
US dollar/pound sterling
10% weakening
(291)
\u2013
Credit risk
Credit risk is the risk that a counterparty will not meet its obligations under a \ufb01nancial instrument or customer contract, leading to
\ufb01nancial loss. The Group trades only with recognised, creditworthy third parties. It is the Group\u2019s policy that all customers who wish to
trade on credit terms are subject to credit veri\ufb01cation procedures, which include an assessment of credit rating, short-term liquidity
and \ufb01nancial position. In addition, receivables balances are monitored on an ongoing basis, with the result that the Group\u2019s exposure
to bad debts is not signi\ufb01cant.
The Group is exposed to credit risk from its operating activities (primarily for trade receivables) and from its \ufb01nancing activities, including
deposits with banks and derivative \ufb01nancial instruments.
The Group has two ratings from two credit rating agencies: S&P Global at BB and Fitch at BB.
The Group only sells hydrocarbons to recognised and creditworthy parties, typically the trading arm of large, international oil and gas
companies. An indication of the concentration of credit risk on trade receivables is shown in note 4, whereby the revenue from one
customer exceeds 88 per cent (2022: 84 per cent) of the Group\u2019s consolidated revenue.
The credit risk on liquid funds and derivative \ufb01nancial instruments is limited because the counterparties are internationally recognised
banking institutions and are considered to represent minimal credit risk.
There are no signi\ufb01cant concentrations of credit risk within the Group unless otherwise disclosed, and credit losses are expected to be
near to zero. The maximum credit risk exposure relating to \ufb01nancial assets is represented by carrying value as at the balance sheet date.
Liquidity risk
Liquidity risk is the risk that the Group will encounter dif\ufb01culty in meeting obligations associated with \ufb01nancial liabilities that are settled
by delivering cash or another \ufb01nancial asset. The Group monitors the amount of borrowings maturing within any speci\ufb01c period and
expects to meet its \ufb01nancing commitments from the operating cash \ufb02ows of the business and existing committed lines of credit.
The table below summarises the maturity pro\ufb01le of the Group\u2019s \ufb01nancial liabilities based on contractual undiscounted payments:
\n \n
Within 1 year
1 to 2 years
2 to 5 years
Over 5 years
Total
As at 31 December 2023
$ million
$ million
$ million
$ million
$ million
Non-derivative \ufb01nancial liabilities
Bond
28
28
528
\u2013
584
Other loans
16
\u2013
\u2013
\u2013
16
Trade and other payables
825
13
\u2013
\u2013
838
Lease obligations
250
186
340
121
897
Total non-derivative \ufb01nancial liabilities
1,119
227
868
121
2,335
Derivative \ufb01nancial liabilities
Net-settled commodity derivatives
197
87
\u2013
\u2013
284
1,316
314
868
121
2,619
\n \n
Within 1 year
1 to 2 years
2 to 5 years
Over 5 years
Total
As at 31 December 2022
$ million
$ million
$ million
$ million
$ million
Non-derivative \ufb01nancial liabilities
Reserve based lending facility
61
61
881
\u2013
1,003
Bond
28
27
555
\u2013
610
Exploration \ufb01nance facility
11
\u2013
\u2013
\u2013
11
Other loans
11
9
18
\u2013
38
Trade and other payables
1,318
19
\u2013
\u2013
1,337
Lease obligations
208
180
386
61
835
Total non-derivative \ufb01nancial liabilities
1,637
296
1,840
61
3,834
Derivative \ufb01nancial liabilities
Net-settled commodity derivatives
2,308
930
155
\u2013
3,393
3,945
1,226
1,995
61
7,227
The maturity pro\ufb01les in the above tables re\ufb02ect only one side of the Group\u2019s liquidity position and will be recorded in the income
statement against future production and revenue which are not recognised on the balance sheet as assets. Interest bearing loans and
borrowings and trade payables mainly originate from the \ufb01nancing of assets used in the Group\u2019s ongoing operations such as property,
plant and equipment and working capital such as inventories. These assets are considered part of the Group\u2019s overall liquidity risk.", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f24786": { "value": "Market risk
Market risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market prices.
Market risk comprises three types of risk: commodity price risk, interest rate risk and foreign currency risk. Financial instruments mainly
affected by market risk include loans and borrowings, deposits and derivative \ufb01nancial instruments.
The sensitivity analyses in the following sections relate to the position as at 31 December 2023 and 31 December 2022.
The sensitivity analyses have been prepared on the basis that the number of \ufb01nancial instruments are all constant. The sensitivity
analyses are intended to illustrate the sensitivity to changes in market variables on the composition of the Group\u2019s \ufb01nancial instruments
at the balance sheet date and show the impact on pro\ufb01t or loss and shareholders\u2019 equity, where applicable.
The following assumptions have been made in calculating the sensitivity analyses:
\u2022
The sensitivity of the relevant pro\ufb01t before tax item and/or equity is the effect of the assumed changes in respective market risks
for the full year based on the \ufb01nancial assets and \ufb01nancial liabilities held at the balance sheet date
\u2022
The sensitivities indicate the effect of a reasonable increase in each market variable. Unless otherwise stated, the effect of
a corresponding decrease in these variables is considered approximately equal and opposite
\u2022
Fair value changes from derivative instruments designated as cash \ufb02ow hedges are considered fully effective and recorded
in shareholders\u2019 equity, net of tax
\u2022
Fair value changes from derivatives and other \ufb01nancial instruments not designated as cash \ufb02ow hedges are presented as a sensitivity
to pro\ufb01t before tax only and not included in shareholders\u2019 equity
Commodity price risk
The Group is exposed to the risk of \ufb02uctuations in prevailing market commodity prices on the mix of oil and gas products. On a rolling
basis, the Group\u2019s policy is to hedge the commodity price exposure associated with 40 to 70 per cent of the next 12 months\u2019 production
(year 1), between 30 and 60 per cent of \u2018year 2\u2019 production, from \u2018year 3\u2019 up to 50 per cent of production and from \u2018year 4\u2019 up to
40 per cent of production. The Group manages these risks through the use of \ufb01xed price contracts with customers for physical delivery
and derivative \ufb01nancial instruments including \ufb01xed price swaps and options.
Commodity price sensitivity
The following table summarises the impact on the Group\u2019s pre-tax pro\ufb01t and equity from a reasonably foreseeable movement in
commodity prices on the fair value of commodity based derivative instruments held by the Group at the balance sheet date.
E\ufb00ect
on pro\ufb01t
E\ufb00ect
before tax
on equity
As at 31 December 2023
Market movement
$ million
$ million
Brent oil price
$10 /bbl increase
\u2013
(28)
Brent oil price
$10 /bbl decrease
\u2013
28
NBP gas price
\u00a30.1 /therm increase
\u2013
(28)
NBP gas price
\u00a30.1 /therm decrease
\u2013
28
Effect
on pro\ufb01t
Effect
before tax
on equity
As at 31 December 2022
Market movement
$ million
$ million
Brent oil price
$10 /bbl increase
\u2013
(49)
Brent oil price
$10 /bbl decrease
\u2013
49
NBP gas price
\u00a30.1 /therm increase
\u2013
(49)
NBP gas price
\u00a30.1 /therm decrease
\u2013
49
Interest rate risk
Interest rate risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market
interest rates. The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to the Group\u2019s long-term debt
obligation with \ufb02oating interest rates.
Fixed rate borrowings at 31 December 2023 comprise a bond which incurs interest at 5.5 per cent per annum. Following the settlement
of the RBL and exploration \ufb01nancing balances during the year, the Group has no \ufb02oating rate borrowings at 31 December 2023. As at
31 December 2022, \ufb02oating rate borrowings comprised loans under the RBL facility which incurred interest \ufb01xed either one month,
three months or six months in advance at USD LIBOR plus a margin of 3.21 per cent. Floating rate \ufb01nancial assets comprise cash and
cash equivalents which earn interest at the relevant market rate. Prior to settlement of the RBL, the Group monitored its exposure
to \ufb02uctuations in interest rates and uses interest rate derivatives to manage the \ufb01xed and \ufb02oating composition of its borrowings.
The interest rate \ufb01nancial instruments in place at the balance sheet date are shown below:
Derivative
Currency
Period of hedge
Terms
31 December 2023
Interest rate swaps
$nil million
N/A
N/A
31 December 2022
Interest rate swaps
$545 million
Jun 20 \u2013 Jun 25
Average 0.55%
The interest rate and currency pro\ufb01le of the Group\u2019s interest-bearing \ufb01nancial assets and liabilities are shown below:
\n \n
Cash
Fixed rate
Floating rate
at bank
borrowings
borrowings
Total
As at 31 December 2023
$ million
$ million
$ million
$ million
US dollar
238
(493)
\u2013
(255)
Pound sterling
28
\u2013
\u2013
28
Norwegian krone
13
\u2013
\u2013
13
Other
1
\u2013
\u2013
1
280
(493)
\u2013
(213)
\n \n
Cash
Fixed rate
Floating rate
at bank
borrowings
borrowings
Total
As at 31 December 2022
$ million
$ million
$ million
$ million
US dollar
481
(491)
(702)
(712)
Pound sterling
8
\u2013
\u2013
8
Norwegian krone
6
\u2013
(11)
(5)
Other
5
\u2013
\u2013
5
500
(491)
(713)
(704)
Interest rate sensitivity
The following table demonstrates the indicative pre-tax effect on pro\ufb01t and equity of applying a reasonably foreseeable increase in
interest rates to the Group\u2019s \ufb01nancial assets and liabilities at the balance sheet date.
\n \n
Effect
on pro\ufb01t
Effect
before tax
on equity
Market movement
$ million
$ million
31 December 2023
US dollar interest rates
+100 basis points
2
\u2013
31 December 2022
US dollar interest rates
+100 basis points
8
\u2013
Foreign currency risk
Foreign currency risk is the risk that the fair value or future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in
foreign exchange rates.
The Group is exposed to foreign currency risk primarily arising from exchange rate movements in US dollar against pound sterling.
To\u00a0mitigate exposure to movements in exchange rates, wherever possible \ufb01nancial assets and liabilities are held in currencies that
match\u00a0the functional currency of the relevant entity. The Group has subsidiaries with functional currencies of pound sterling, US dollar,
Norwegian krone, Mexican pesos and Brazilian reals. Exposures can also arise from sales or purchases denominated in currencies
other than the functional currency of the relevant entity; such exposures are monitored and hedged with agreement from the Board.
The Group enters into forward contracts as a means of hedging its exposure to foreign exchange rate risks. As at 31 December 2023, the
Group had \u00a3212 million hedged at a forward rate of between $1.2182 and $1.2742:\u00a31 for the period January 2024 to October 2024.
As at 31 December 2022, the Group had \u00a342 million hedged at forward rates of between $1.18331 and $1.24045:\u00a31 for the period
to\u00a0January 2023, and $100 million hedged at forward rates of between $1.17543 and $1.18131:\u00a31 for the period to January 2023.
Foreign currency sensitivity
The following table demonstrates the sensitivity to a reasonably foreseeable change in US dollars against pound sterling with all
other\u00a0variables held constant, of the Group\u2019s pro\ufb01t before tax (due to foreign exchange translation of monetary assets and liabilities).
The\u00a0impact of translating the net assets of foreign operations into US dollars is excluded from the sensitivity analysis.
Effect
on pro\ufb01t
Effect
Market
before tax
on equity
movement
$ million
$ million
31 December 2023
US dollar/pound sterling
10% strengthening
78
\u2013
US dollar/pound sterling
10% weakening
(78)
\u2013
31 December 2022
US dollar/pound sterling
10% strengthening
291
\u2013
US dollar/pound sterling
10% weakening
(291)
\u2013
", "dimensions": { "concept": "ifrs-full:DisclosureOfMarketRiskExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f25285": { "value": "Foreign currency risk
Foreign currency risk is the risk that the fair value or future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in
foreign exchange rates.
The Group is exposed to foreign currency risk primarily arising from exchange rate movements in US dollar against pound sterling.
To\u00a0mitigate exposure to movements in exchange rates, wherever possible \ufb01nancial assets and liabilities are held in currencies that
match\u00a0the functional currency of the relevant entity. The Group has subsidiaries with functional currencies of pound sterling, US dollar,
Norwegian krone, Mexican pesos and Brazilian reals. Exposures can also arise from sales or purchases denominated in currencies
other than the functional currency of the relevant entity; such exposures are monitored and hedged with agreement from the Board.
The Group enters into forward contracts as a means of hedging its exposure to foreign exchange rate risks. As at 31 December 2023, the
Group had \u00a3212 million hedged at a forward rate of between $1.2182 and $1.2742:\u00a31 for the period January 2024 to October 2024.
As at 31 December 2022, the Group had \u00a342 million hedged at forward rates of between $1.18331 and $1.24045:\u00a31 for the period
to\u00a0January 2023, and $100 million hedged at forward rates of between $1.17543 and $1.18131:\u00a31 for the period to January 2023.
Foreign currency sensitivity
The following table demonstrates the sensitivity to a reasonably foreseeable change in US dollars against pound sterling with all
other\u00a0variables held constant, of the Group\u2019s pro\ufb01t before tax (due to foreign exchange translation of monetary assets and liabilities).
The\u00a0impact of translating the net assets of foreign operations into US dollars is excluded from the sensitivity analysis.
Effect
on pro\ufb01t
Effect
Market
before tax
on equity
movement
$ million
$ million
31 December 2023
US dollar/pound sterling
10% strengthening
78
\u2013
US dollar/pound sterling
10% weakening
(78)
\u2013
31 December 2022
US dollar/pound sterling
10% strengthening
291
\u2013
US dollar/pound sterling
10% weakening
(291)
\u2013
", "dimensions": { "concept": "ifrs-full:DisclosureOfEffectOfChangesInForeignExchangeRatesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f25411": { "value": "Credit risk
Credit risk is the risk that a counterparty will not meet its obligations under a \ufb01nancial instrument or customer contract, leading to
\ufb01nancial loss. The Group trades only with recognised, creditworthy third parties. It is the Group\u2019s policy that all customers who wish to
trade on credit terms are subject to credit veri\ufb01cation procedures, which include an assessment of credit rating, short-term liquidity
and \ufb01nancial position. In addition, receivables balances are monitored on an ongoing basis, with the result that the Group\u2019s exposure
to bad debts is not signi\ufb01cant.
The Group is exposed to credit risk from its operating activities (primarily for trade receivables) and from its \ufb01nancing activities, including
deposits with banks and derivative \ufb01nancial instruments.
The Group has two ratings from two credit rating agencies: S&P Global at BB and Fitch at BB.
The Group only sells hydrocarbons to recognised and creditworthy parties, typically the trading arm of large, international oil and gas
companies. An indication of the concentration of credit risk on trade receivables is shown in note 4, whereby the revenue from one
customer exceeds 88 per cent (2022: 84 per cent) of the Group\u2019s consolidated revenue.
The credit risk on liquid funds and derivative \ufb01nancial instruments is limited because the counterparties are internationally recognised
banking institutions and are considered to represent minimal credit risk.
There are no signi\ufb01cant concentrations of credit risk within the Group unless otherwise disclosed, and credit losses are expected to be
near to zero. The maximum credit risk exposure relating to \ufb01nancial assets is represented by carrying value as at the balance sheet date.", "dimensions": { "concept": "ifrs-full:DisclosureOfCreditRiskExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f25427": { "value": "There are no signi\ufb01cant concentrations of credit risk within the Group unless otherwise disclosed, and credit losses are expected to be near to zero.", "dimensions": { "concept": "ifrs-full:DisclosureOfAllowanceForCreditLossesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f25462": { "value": "Liquidity risk
Liquidity risk is the risk that the Group will encounter dif\ufb01culty in meeting obligations associated with \ufb01nancial liabilities that are settled
by delivering cash or another \ufb01nancial asset. The Group monitors the amount of borrowings maturing within any speci\ufb01c period and
expects to meet its \ufb01nancing commitments from the operating cash \ufb02ows of the business and existing committed lines of credit.
The table below summarises the maturity pro\ufb01le of the Group\u2019s \ufb01nancial liabilities based on contractual undiscounted payments:
\n \n
Within 1 year
1 to 2 years
2 to 5 years
Over 5 years
Total
As at 31 December 2023
$ million
$ million
$ million
$ million
$ million
Non-derivative \ufb01nancial liabilities
Bond
28
28
528
\u2013
584
Other loans
16
\u2013
\u2013
\u2013
16
Trade and other payables
825
13
\u2013
\u2013
838
Lease obligations
250
186
340
121
897
Total non-derivative \ufb01nancial liabilities
1,119
227
868
121
2,335
Derivative \ufb01nancial liabilities
Net-settled commodity derivatives
197
87
\u2013
\u2013
284
1,316
314
868
121
2,619
\n \n
Within 1 year
1 to 2 years
2 to 5 years
Over 5 years
Total
As at 31 December 2022
$ million
$ million
$ million
$ million
$ million
Non-derivative \ufb01nancial liabilities
Reserve based lending facility
61
61
881
\u2013
1,003
Bond
28
27
555
\u2013
610
Exploration \ufb01nance facility
11
\u2013
\u2013
\u2013
11
Other loans
11
9
18
\u2013
38
Trade and other payables
1,318
19
\u2013
\u2013
1,337
Lease obligations
208
180
386
61
835
Total non-derivative \ufb01nancial liabilities
1,637
296
1,840
61
3,834
Derivative \ufb01nancial liabilities
Net-settled commodity derivatives
2,308
930
155
\u2013
3,393
3,945
1,226
1,995
61
7,227
The maturity pro\ufb01les in the above tables re\ufb02ect only one side of the Group\u2019s liquidity position and will be recorded in the income
statement against future production and revenue which are not recognised on the balance sheet as assets. Interest bearing loans and
borrowings and trade payables mainly originate from the \ufb01nancing of assets used in the Group\u2019s ongoing operations such as property,
plant and equipment and working capital such as inventories. These assets are considered part of the Group\u2019s overall liquidity risk.", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f25778": { "value": "24. Share capital \n \n
2023
2022
Issued and fully paid
Number
$ million
Number
$ million
Ordinary shares of 0.002p each
770,370,830
0
847,168,796
0
Ordinary non-voting deferred shares of 12.4999p each
925,532,809
171
925,532,809
171
171
171
The rights and restrictions attached to the ordinary shares are as follows:
\u2022
Dividend rights:
the rights of the holders of ordinary shares shall rank pari passu in all respects with each other in relation to dividends
\u2022
Winding up or reduction of capital:
on a return of capital on a winding up or otherwise (other than on conversion, redemption or
purchase of shares) the rights of the holders of ordinary shares to participate in the distribution of the assets of the company available
for distribution shall rank pari passu in all respects with each other
\u2022
Voting rights:
the holders of ordinary shares shall be entitled to receive notice of, attend, vote and speak at any General Meeting of the company
The rights and restrictions attached to the non-voting deferred shares are as follows:
\u2022
They will have no voting or dividend rights and, on a return of capital or on a winding up of the company, will have the right to receive the
amount paid up thereon only after holders of all ordinary shares have received, in aggregate, any amounts paid up on each ordinary
share plus \u00a310 million on each ordinary share. The non-voting deferred shares will not give the holder the right to receive notice of, nor
attend, speak or vote at, any General Meeting of the company
Issue of ordinary shares
During the year, the company issued 5,092 ordinary shares at a nominal value of 0.002 pence per share in relation to the exercise
of SAYE awards.
Purchase and cancellation of own shares
During 2023, the company repurchased 76,803,058 ordinary shares for a total consideration, including transaction costs, of
$249 million, as part of the share purchase programmes announced on 3 November 2022 and 9 March 2023, which concluded on
28 September 2023. All shares purchased were cancelled. As at 31 December 2023, the buyback programme had been completed.
Capital reduction
The capital reduction, comprising the share premium and the merger reserve, was approved by shareholders at the General Meeting held
on 11 May 2022. In connection with the capitalisation of the merger reserve, the resolutions authorising the Directors to allot new B
ordinary shares and subsequently cancel them was also passed at the General Meeting. B ordinary shares totalling $4,806 million
were issued on 25 July 2022.
On 3 August 2022, Harbour announced that the capital reduction had become effective following the con\ufb01rmation by the Court of Session,
Edinburgh on 2 August 2022 and the registration of the Court order with the Registrar of Companies in Scotland on 3 August 2022. The
share premium account ($1,505 million) and the shares arising on the capitalisation of the merger reserve ($4,806 million) were cancelled.
The capital reduction created additional distributable reserves to the value of $6,311 million.
\n \n
2023
Own shares
$ million
At 1 January 2023
21
Purchase of ESOP Trust shares
16
Release of shares
(13)
24
The own shares represent the net cost of shares in Harbour Energy plc purchased in the market or issued by the company into the
Harbour Energy plc employee bene\ufb01t (ESOP) trust. This ESOP Trust holds shares to satisfy awards under the Group\u2019s share incentive
plans. At 31 December 2023, the number of ordinary shares of 0.002 pence each held by the trust was 6,079,705 (2022: 4,487,267).", "dimensions": { "concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f25779": { "value": "24. Share capital \n \n
2023
2022
Issued and fully paid
Number
$ million
Number
$ million
Ordinary shares of 0.002p each
770,370,830
0
847,168,796
0
Ordinary non-voting deferred shares of 12.4999p each
925,532,809
171
925,532,809
171
171
171
The rights and restrictions attached to the ordinary shares are as follows:
\u2022
Dividend rights:
the rights of the holders of ordinary shares shall rank pari passu in all respects with each other in relation to dividends
\u2022
Winding up or reduction of capital:
on a return of capital on a winding up or otherwise (other than on conversion, redemption or
purchase of shares) the rights of the holders of ordinary shares to participate in the distribution of the assets of the company available
for distribution shall rank pari passu in all respects with each other
\u2022
Voting rights:
the holders of ordinary shares shall be entitled to receive notice of, attend, vote and speak at any General Meeting of the company
The rights and restrictions attached to the non-voting deferred shares are as follows:
\u2022
They will have no voting or dividend rights and, on a return of capital or on a winding up of the company, will have the right to receive the
amount paid up thereon only after holders of all ordinary shares have received, in aggregate, any amounts paid up on each ordinary
share plus \u00a310 million on each ordinary share. The non-voting deferred shares will not give the holder the right to receive notice of, nor
attend, speak or vote at, any General Meeting of the company
Issue of ordinary shares
During the year, the company issued 5,092 ordinary shares at a nominal value of 0.002 pence per share in relation to the exercise
of SAYE awards.
Purchase and cancellation of own shares
During 2023, the company repurchased 76,803,058 ordinary shares for a total consideration, including transaction costs, of
$249 million, as part of the share purchase programmes announced on 3 November 2022 and 9 March 2023, which concluded on
28 September 2023. All shares purchased were cancelled. As at 31 December 2023, the buyback programme had been completed.", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f25854": { "value": "Purchase and cancellation of own shares
During 2023, the company repurchased 76,803,058 ordinary shares for a total consideration, including transaction costs, of
$249 million, as part of the share purchase programmes announced on 3 November 2022 and 9 March 2023, which concluded on
28 September 2023. All shares purchased were cancelled. As at 31 December 2023, the buyback programme had been completed.", "dimensions": { "concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f25918": { "value": "25. Share-based payments
The company currently operates a Long Term Incentive Plan (LTIP) for certain employees and a Share Incentive Plan (SIP), a Save As You Earn
(SAYE) scheme for UK-based employees, and an Expatriate SIP for expatriate employees only.
For the year ended 31 December 2023, the total cost recognised by the company for share-based payment transactions was $46 million
(2022: $36 million). A credit of $46 million (2022: $36 million) has been recorded in retained earnings for all equity-settled payments of
the company.
Like other elements of remuneration, this charge is processed through the time-writing system which allocates cost, based on time spent
by individuals, to various entities within the Group. Part of this cost is therefore recharged to the relevant subsidiary undertakings, part is
capitalised as directly attributable to capital projects and part is charged to the income statement as operating costs, pre-licence
exploration costs or general and administration costs.
Details of the various share incentive plans currently in operation are set out below.
2017 Long Term Incentive Plan (2017 LTIP)
Discretionary share awards are granted to employees under the company\u2019s Long Term Incentive Plan (LTIP).
The following types of award have been granted under the 2017 LTIP:
\u2022
Performance share awards (PSAs):
vesting is subject to a Performance Target, normally measured over a three-year period from 1\u00a0January
based on total shareholder return (TSR) relative to (i) the FTSE 100 index, and (ii) a bespoke peer group of oil and gas companies, and aligns
to longer-term strategic objectives
\u2022
Conditional share awards (CSAs):
vesting is only subject to continued employment
\u2022
Deferred bonus share (DBS) awards:
certain employees are required to defer a portion of their annual bonus into shares which vest
over a three-year period subject to continued employment
All LTIP awards are granted in the form of nil-cost options or conditional share awards and therefore there is no exercise price payable
on the exercise of these awards.
For further details of the LTIP awards, including the performance conditions of the PSAs granted in 2023, please refer to the Directors\u2019
remuneration report (page 97).
The following table shows the movement in the number of LTIP awards:
\n \n
2023
2022
million shares
million shares
Outstanding at 1 January
27.8
20.5
Granted
15.1
10.3
Vested
(8.7)
(1.6)
Forfeited
(0.5)
(1.4)
Outstanding at 31 December
1
33.7
27.8
1
This includes 0.6 million cash settled awards at 31 December 2023 (2022: 1.6 million), which are revalued using the year-end share price.
LTIP awards totalling 8.7 million shares were vested during the period. The weighted average remaining contractual life of the LTIP awards
at 31 December 2023 was 2.2 years (2022: 1.5 years).
Key assumptions used to calculate the fair value of awards
The fair value of PSAs which are subject to TSR conditions is determined using a Monte Carlo simulation. The fair value of all other
awards is calculated using the share price at the date of grant, adjusted for dividends not received during the vesting period.
The following table lists the inputs to the model used in respect of the PSAs granted during the \ufb01nancial year:
2023
2022
Share price at date of grant
\u00a32.44 \u2013 \u00a32.90
\u00a35.00 \u2013 \u00a35.19
Dividend yield
0%
0%
Expected term
2.9 \u2013 3.0 years
3.0 years
Risk free rate
3.3% \u2013 4.2%
1.4% \u2013 1.6%
Share price volatility of the company
49.2% \u2013 50.2%
50.5% \u2013 51.3%
The weighted average fair value of the PSAs granted in 2023 was $2.86 (2022: $4.02).
Expected volatility was determined by reference to both the historical volatility of the company and the historical volatility of a group
of comparable quoted companies over a period in line with the expected term assumption.
Share Incentive Plan (SIP)
Under the SIP, employees are invited to make contributions to buy partnership shares. If an employee agrees to buy partnership shares
the company currently matches the number of partnership shares bought with an award of shares (matching shares), on a one-for-one
basis. In 2023, 0.3 million matching shares were awarded to employees (2022: 0.4 million). The SIP matching shares are valued based
on the quoted share price on the grant date.
Save As You Earn (SAYE) scheme
Under the SAYE scheme, UK qualifying employees with one month or more continuous service can join the scheme. Under the SAYE
scheme, employees can save up to a maximum of \u00a3500 per month through payroll deductions for a period of three years, after which
time they can acquire shares at the option price, which is set at a discount of up to 20 per cent to the prevailing market price at the
grant date, determined in accordance with SAYE scheme rules. In 2023, 3.1 million SAYE options were granted (2022: 1.6 million).
The SAYE options outstanding at 31 December 2023 had exercise prices ranging from \u00a32.21 to \u00a34.12 (2022: \u00a34.12 to \u00a35.53) and
a weighted average remaining contractual life of 2.8 years (2022: 2.8 years).", "dimensions": { "concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f26115": { "value": "27. Notes to the statement of cash \ufb02ows
Net cash \ufb02ows from operating activities consist of:
\n \n
2023
2022
$ million
$ million
Pro\ufb01t before taxation
597
2,462
Adjustments to reconcile pro\ufb01t before tax to net cash \ufb02ows
Finance cost, excluding foreign exchange
363
358
Finance income, excluding foreign exchange
(104)
(77)
Depreciation, depletion and amortisation
1,430
1,546
Fair value movement in unrealised carbon swaps
\u2013
2
Net impairment of property, plant and equipment
214
(170)
Impairment of goodwill
25
\u2013
Share-based payments
20
17
Decommissioning payments
(268)
(217)
Exploration costs written-off
57
64
Onerous contract payments
\u2013
(2)
Gain on disposal
\u2013
(12)
Movement in realised cash \ufb02ow hedges not yet settled
(207)
(104)
Unrealised foreign exchange loss/(gain)
49
(238)
Working capital adjustments
(Increase)/decrease in inventories
(52)
65
Decrease/(increase) in trade and other receivables
519
(75)
(Decrease)/increase in trade and other payables
(61)
63
Net tax payments
(438)
(552)
Net cash in\ufb02ow from operating activities
2,144
3,130
Reconciliation of net cash \ufb02ow to movement in net borrowings
\n \n
2023
2022
$ million
$ million
Proceeds from drawdown of borrowing facilities
(660)
\u2013
Proceeds from EFF loan
\u2013
(11)
Repayment of RBL facility
1,435
1,663
Repayment of EFF loan
11
38
Repayment of \ufb01nancing arrangement
21
15
Financing arrangement interest payable
(3)
(9)
Arrangement fees and related costs on RBL capitalised
34
\u2013
Amortisation of arrangement fees and related costs capitalised
(48)
(55)
Currency translation adjustment on EFF loan
\u2013
7
Movement in total borrowings
790
1,648
Movement in cash and cash equivalents
(220)
(199)
Decrease in net borrowings in the year
570
1,449
Opening net borrowings
(738)
(2,187)
Closing net borrowings
(168)
(738)
Analysis of net borrowings
2023
2022
$ million
$ million
Cash and cash equivalents
280
500
RBL facility
\u2013
(702)
Bond
(493)
(491)
EFF loan
\u2013
(11)
Net debt
(213)
(704)
Financing arrangement
(16)
(34)
Closing net borrowings
(229)
(738)
Non-current assets
42
\u2013
Current assets
19
\u2013
Closing net borrowings after total unamortised fees
1
(168)
(738)
1
$61 million of fees associated with the RBL are recognised in debtors.
The carrying values on the balance sheet are stated net of the unamortised portion of issue costs and bank fees of $68 million of
which $61 million relates to the RBL and is recognised in assets (note 15) and $7 million is netted against the bond (2022: $82 million
of which $73 million related to the RBL and $9 million related to the bond both of which were netted off against the borrowings).", "dimensions": { "concept": "ifrs-full:DisclosureOfCashFlowStatementExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f26500": { "value": "28. Related party disclosures
Transactions between the company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not
disclosed in this note.
Harbour Energy\u2019s Viking CCS entered into an arrangement with West Burton Energy, the independent power generation company based
in Nottinghamshire which is a subsidiary of EIG, Harbour\u2019s largest shareholder. The intention is to capture, transport and permanently
store CO
2
emissions from the West Burton B power station. Harbour Energy and West Burton Energy have begun the necessary
engineering design to connect West Burton B to the high-capacity Viking CCS storage sites located beneath the Southern North Sea.
There have not been any \ufb01nancial transactions with West Burton Energy in 2023.
Compensation of key management personnel of the Group
Remuneration of key management personnel, including directors of the Group, is shown below:
2023
2022
$ million
$ million
Salaries and short-term employee bene\ufb01ts
13
15
Payments made in lieu of pension contributions
1
1
14
16
31. Investments and amounts due from subsidiary undertakings
At 31 December 2023, the subsidiary undertakings of the company which were all wholly owned were:
\n \n
Name of company
Area of operation
Country of incorporation
Main activity
Chrysaor (U.K.) Alpha Limited
UK
UK
2
Exploration, production, and development
Chrysaor (U.K.) Beta Limited
UK
UK
2
Decommissioning activities
Chrysaor (U.K.) Sigma Limited
UK
UK
2
Exploration, production, and development
Chrysaor (U.K.) Theta Limited
UK
UK
2
Exploration, production, and development
Chrysaor CNS Limited
UK
UK
2
Exploration, production, and development
Chrysaor Developments Limited
UK
UK
2
Decommissioning activities
Chrysaor E&P Finance Limited
UK
UK
2
Financing company
Chrysaor E&P Limited
UK
UK
2
Intermediate holding company
Chrysaor Holdings Limited
1
UK
Cayman Islands
13
Intermediate holding company
Chrysaor Limited
UK
UK
2
Exploration, production, and development
Chrysaor Marketing Limited
UK
UK
2
Gas trading
Chrysaor North Sea Limited
UK
UK
2
Exploration, production, and development
Chrysaor Petroleum Company U.K. Limited
UK
UK
2
Exploration, production, and development
Chrysaor Petroleum Limited
UK
UK
2
Decommissioning activities
Chrysaor Production (U.K.) Limited
UK
UK
2
Exploration, production, and development
Chrysaor Production Holdings Limited
UK
UK
2
Intermediate holding company
Chrysaor Resources (Irish Sea) Limited
UK
UK
2
Exploration, production, and development
Ebury Gate Limited
Guernsey
Guernsey
11
Risk mitigation services
EnCore (NNS) Limited
UK
UK
2
Intermediate holding company
EnCore Oil Limited
UK
UK
2
Intermediate holding company
FP Mauritania A BV
Mauritania
Netherlands
7
Decommissioning activities
FP Mauritania B BV
Mauritania
Netherlands
7
Decommissioning activities
Harbour Energy Services Limited
UK
UK
2
Service company
(formerly Chrysaor E&P Services Limited)
Harbour Energy Norge AS
Norway
Norway
3
Exploration, production, and development
Premier Oil (EnCore Petroleum) Limited
UK
UK
2
Intermediate holding company
Premier Oil (Vietnam) Limited
Vietnam
British Virgin Islands
8
Exploration, production, and development
Premier Oil Aberdeen Services Limited
UK
UK
2
Service company
Premier Oil and Gas Services Limited
UK
UK
2
Service company
Premier Oil Andaman I Limited
Indonesia
UK
2
Exploration, production, and development
Premier Oil Andaman Limited
Indonesia
UK
2
Exploration, production, and development
Premier Oil Barakuda Limited
Indonesia
UK
2
Exploration, production and development
Premier Oil do Brasil Petroleo e Gas Ltda
Brazil
Brazil
9
Exploration, production, and development
Premier Oil E&P Holdings Limited
UK
UK
2
Intermediate holding company
Premier Oil E&P UK EU Limited
UK
UK
2
Exploration, production, and development
Premier Oil E&P UK Limited
UK
UK
2
Exploration, production, and development
Premier Oil Exploration (Mauritania) Limited
Mauritania
Jersey
6
Decommissioning activities
Premier Oil Exploration and Production
Mexico
Mexico
10
Exploration, production, and development
Mexico S.A.de C.V.
Premier Oil Far East Limited
Singapore
UK
2
Service company
Premier Oil Group Holdings Limited
1
UK
UK
2
Intermediate holding company
Premier Oil Group Limited
UK
UK
5
Intermediate holding company
Premier Oil Holdings Limited
UK
UK
2
Intermediate holding company
Premier Oil Mauritania B Limited
Mauritania
Jersey
6
Decommissioning activities
Premier Oil Mexico Holdings Limited
UK
UK
2
Intermediate holding company
Premier Oil Mexico Investments Limited
UK
UK
2
Intermediate holding company
Premier Oil Mexico Recursos S.A. de C.V.
Mexico
Mexico
10
Exploration, production, and development
Premier Oil Natuna Sea BV
Indonesia
Netherlands
7
Exploration, production, and development
Premier Oil Overseas BV
Netherlands
Netherlands
7
Intermediate holding company
Premier Oil South Andaman Limited
Indonesia
UK
2
Exploration, production, and development
Premier Oil Tuna BV
Indonesia
Netherlands
7
Exploration, production, and development
\n \n
Name of company
Area of operation
Country of incorporation
Main activity
Premier Oil UK Limited
UK
UK
5
Exploration, production, and development
Premier Oil Vietnam Offshore BV
Vietnam
Netherlands
7
Exploration, production, and development
Chrysaor (U.K.) Britannia Limited
\u2013
UK
2
Dormant company
Chrysaor (U.K.) Delta Limited
\u2013
UK
2
Non-trading
Chrysaor (U.K.) Eta Limited
\u2013
UK
2
Non-trading
Chrysaor (U.K.) Lambda Limited
\u2013
ROI
4
Dormant company
Chrysaor Production Limited
\u2013
UK
2
Non-trading
Chrysaor Resources (UK) Holdings Limited
\u2013
UK
2
Non-trading
Chrysaor (U.K.) Zeta Limited
\u2013
UK
2
Non-trading
Harbour Energy Argentina Limited
\u2013
UK
2
Dormant company
Harbour Energy Developments Limited
\u2013
UK
2
Dormant company
Harbour Energy Secretaries Limited
\u2013
UK
2
Dormant company
Harbour Energy Production Limited
\u2013
UK
2
Dormant company
Premier Oil ANS Holdings Limited
\u2013
UK
2
Non-trading
Premier Oil ANS Limited
\u2013
UK
2
Non-trading
Premier Oil B Limited
\u2013
UK
2
Dormant company
Premier Oil Congo (Marine IX) Limited
\u2013
Jersey
6
Dormant company
Premier Oil Exploration Limited
\u2013
UK
5
Non-trading
Premier Oil Exploration ONS Limited
\u2013
UK
2
Dormant company
Premier Oil Finance (Jersey) Limited
1
\u2013
Jersey
6
Non-trading
Premier Oil ONS Limited
\u2013
UK
2
Dormant company
Premier Oil Pakistan Offshore BV
\u2013
Netherlands
7
Dormant company
Premier Oil Vietnam 121 Limited
\u2013
UK
2
Non-trading
Viking CCS Limited (formerly Chrysaor Energy Limited)
\u2013
UK
2
Dormant company
Chrysaor Investments Limited
\u2013
UK
2
Liquidation
Chrysaor Petroleum Chemicals U.K. Limited
\u2013
UK
2
Liquidation
(formerly Harbour Energy Services Limited)
Chrysaor Production Oil (GB) Limited
\u2013
UK
2
Liquidation
(formerly Harbour Energy Production Limited)
Chrysaor Supply & Trading Limited
\u2013
UK
2
Liquidation
EnCore (VOG) Limited
\u2013
UK
2
Liquidation
EnCore CCS Limited
\u2013
UK
2
Liquidation
EnCore Natural Resources Limited
\u2013
UK
2
Liquidation
EnCore Oil and Gas Limited
\u2013
UK
2
Liquidation
Premier Oil Belgravia Holdings Limited
\u2013
UK
2
Liquidation
Premier Oil Belgravia Limited
\u2013
UK
2
Liquidation
Premier Oil Bukit Barat Limited
\u2013
UK
2
Liquidation
Premier Oil CCS Limited
\u2013
UK
2
Liquidation
Premier Oil E&P UK Energy Trading Limited
\u2013
UK
2
Liquidation
Premier Oil Exploration and Production (Iraq) Limited
\u2013
UK
2
Liquidation
Premier Oil Investments Limited
\u2013
UK
2
Liquidation
Premier Oil Paci\ufb01c Limited
\u2013
Hong Kong
12
Liquidation
Premier Overseas Holdings Limited
\u2013
UK
2
Liquidation
XEO Exploration Limited (formerly XEO Exploration plc)
\u2013
UK
2
Liquidation
Note:
1
Held directly by the company. All other companies are held through a subsidiary undertaking.
2
Registered of\ufb01ce \u2013 23 Lower Belgrave Street, London, United Kingdom, SW1W ONR.
3
Registered of\ufb01ce \u2013 Haakon VII\u2019s gate 1, 4
th
Floor, 0161 Oslo, Norway.
4
Registered of\ufb01ce \u2013 Riverside One, Sir John Rogerson\u2019s Quay, Dublin 2, Ireland.
5
Registered of\ufb01ce \u2013 4
th
Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN.
6
Registered of\ufb01ce \u2013 46/50 Kensington Place, 1
st
Floor, Kensington Chambers, St. Helier, JE4 0ZE, Jersey.
7
Registered of\ufb01ce \u2013 Herikerbergweg 88, 1101 CM, Amsterdam, Netherlands.
8
Registered of\ufb01ce \u2013 Commerce House, Wickhams Cay 1, Road Town, Tortola, VG1110.
9
Registered of\ufb01ce \u2013 Rua Lauro M\u00fcller, 116 \u2013 Sala 2006, Torre Rio Sul, Shopping, 20\u00ba andar, Botafogo, Rio de Janeiro \u2013 RJ \u2013 CEP: 22.290-906, Brazil.
10 Registered of\ufb01ce \u2013 Presidente Masaryk 111, Piso 1, Polanco V Seccion, Mexico City, CP 11560, Mexico.
11 Registered of\ufb01ce \u2013 Level 5, Mill Court, La Charroterie, St Peter Port, Guernsey, GY1 1EJ.
12 Registered of\ufb01ce \u2013 31/F, Tower Two, Time Square, 1 Matheson Street, Causeway Bay, Hong Kong.
13 Registered of\ufb01ce \u2013 Cricket Square, Hutchins Drive, PO Box 2681, Grand Cayman, KY1-1111.", "dimensions": { "concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f26512": { "value": "Compensation of key management personnel of the Group
Remuneration of key management personnel, including directors of the Group, is shown below:
2023
2022
$ million
$ million
Salaries and short-term employee bene\ufb01ts
13
15
Payments made in lieu of pension contributions
1
1
14
16
", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f26565": { "value": "29. Distributions made and proposed
A \ufb01nal dividend of 12 cents per ordinary share in relation to the year ended 31 December 2022 was paid on 24 May 2023 pursuant
to shareholder approval received on 10 May 2023.
An interim dividend of 12 cents per ordinary share in relation to the half year ended 30 June 2023 was paid on 18 October 2023.
\n \n
2023
2022
$ million
$ million
Cash dividends on ordinary shares declared and paid
Final dividend for 2022: 12 cents per share (2021: 11 cents per share)
99
98
Interim dividend for 2023: 12 cents per share (2022: 11 cents per share)
91
93
190
191
Proposed dividends on ordinary shares
Final dividend for 2023: 13 cents per share (2022: 12 cents per share)
100
100
Proposed dividends on ordinary shares are subject to approval at the Annual General Meeting and are not recognised as a liability as at
31 December.", "dimensions": { "concept": "ifrs-full:DisclosureOfDividendsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f26616": { "value": "0.13", "decimals": 2, "dimensions": { "concept": "ifrs-full:DividendsProposedOrDeclaredBeforeFinancialStatementsAuthorisedForIssueButNotRecognisedAsDistributionToOwnersPerShare", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD/xbrli:shares" } }, "f26617": { "value": "0.12", "decimals": 2, "dimensions": { "concept": "ifrs-full:DividendsProposedOrDeclaredBeforeFinancialStatementsAuthorisedForIssueButNotRecognisedAsDistributionToOwnersPerShare", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00", "unit": "iso4217:USD/xbrli:shares" } }, "f26620": { "value": "100000000", "decimals": -6, "dimensions": { "concept": "ifrs-full:DividendsProposedOrDeclaredBeforeFinancialStatementsAuthorisedForIssueButNotRecognisedAsDistributionToOwners", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00", "unit": "iso4217:USD" } }, "f26623": { "value": "100000000", "decimals": -6, "dimensions": { "concept": "ifrs-full:DividendsProposedOrDeclaredBeforeFinancialStatementsAuthorisedForIssueButNotRecognisedAsDistributionToOwners", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2022-01-01T00:00:00/2023-01-01T00:00:00", "unit": "iso4217:USD" } }, "f26628": { "value": "30. Post balance sheet events
On 5 March 2024 Harbour signed a new $3.0 billion fully unsecured revolving credit facility (RCF) and $1.5 billion bridge facility which
will be available at completion to fund the acquisition of the Wintershall Dea asset portfolio. The RCF has a $1.75 billion letter of credit
sub-limit, a \ufb01ve-year term from signing and will replace the existing RBL facility.
On 6 March 2024, the UK Government announced that the Energy Pro\ufb01ts Levy (EPL) would be extended for a further 12 months to
31 March 2029 from the former end date of 31 March 2028. Harbour is currently assessing the potential impact of this announcement.", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f26649": { "value": "31. Investments and amounts due from subsidiary undertakings
At 31 December 2023, the subsidiary undertakings of the company which were all wholly owned were:
\n \n
Name of company
Area of operation
Country of incorporation
Main activity
Chrysaor (U.K.) Alpha Limited
UK
UK
2
Exploration, production, and development
Chrysaor (U.K.) Beta Limited
UK
UK
2
Decommissioning activities
Chrysaor (U.K.) Sigma Limited
UK
UK
2
Exploration, production, and development
Chrysaor (U.K.) Theta Limited
UK
UK
2
Exploration, production, and development
Chrysaor CNS Limited
UK
UK
2
Exploration, production, and development
Chrysaor Developments Limited
UK
UK
2
Decommissioning activities
Chrysaor E&P Finance Limited
UK
UK
2
Financing company
Chrysaor E&P Limited
UK
UK
2
Intermediate holding company
Chrysaor Holdings Limited
1
UK
Cayman Islands
13
Intermediate holding company
Chrysaor Limited
UK
UK
2
Exploration, production, and development
Chrysaor Marketing Limited
UK
UK
2
Gas trading
Chrysaor North Sea Limited
UK
UK
2
Exploration, production, and development
Chrysaor Petroleum Company U.K. Limited
UK
UK
2
Exploration, production, and development
Chrysaor Petroleum Limited
UK
UK
2
Decommissioning activities
Chrysaor Production (U.K.) Limited
UK
UK
2
Exploration, production, and development
Chrysaor Production Holdings Limited
UK
UK
2
Intermediate holding company
Chrysaor Resources (Irish Sea) Limited
UK
UK
2
Exploration, production, and development
Ebury Gate Limited
Guernsey
Guernsey
11
Risk mitigation services
EnCore (NNS) Limited
UK
UK
2
Intermediate holding company
EnCore Oil Limited
UK
UK
2
Intermediate holding company
FP Mauritania A BV
Mauritania
Netherlands
7
Decommissioning activities
FP Mauritania B BV
Mauritania
Netherlands
7
Decommissioning activities
Harbour Energy Services Limited
UK
UK
2
Service company
(formerly Chrysaor E&P Services Limited)
Harbour Energy Norge AS
Norway
Norway
3
Exploration, production, and development
Premier Oil (EnCore Petroleum) Limited
UK
UK
2
Intermediate holding company
Premier Oil (Vietnam) Limited
Vietnam
British Virgin Islands
8
Exploration, production, and development
Premier Oil Aberdeen Services Limited
UK
UK
2
Service company
Premier Oil and Gas Services Limited
UK
UK
2
Service company
Premier Oil Andaman I Limited
Indonesia
UK
2
Exploration, production, and development
Premier Oil Andaman Limited
Indonesia
UK
2
Exploration, production, and development
Premier Oil Barakuda Limited
Indonesia
UK
2
Exploration, production and development
Premier Oil do Brasil Petroleo e Gas Ltda
Brazil
Brazil
9
Exploration, production, and development
Premier Oil E&P Holdings Limited
UK
UK
2
Intermediate holding company
Premier Oil E&P UK EU Limited
UK
UK
2
Exploration, production, and development
Premier Oil E&P UK Limited
UK
UK
2
Exploration, production, and development
Premier Oil Exploration (Mauritania) Limited
Mauritania
Jersey
6
Decommissioning activities
Premier Oil Exploration and Production
Mexico
Mexico
10
Exploration, production, and development
Mexico S.A.de C.V.
Premier Oil Far East Limited
Singapore
UK
2
Service company
Premier Oil Group Holdings Limited
1
UK
UK
2
Intermediate holding company
Premier Oil Group Limited
UK
UK
5
Intermediate holding company
Premier Oil Holdings Limited
UK
UK
2
Intermediate holding company
Premier Oil Mauritania B Limited
Mauritania
Jersey
6
Decommissioning activities
Premier Oil Mexico Holdings Limited
UK
UK
2
Intermediate holding company
Premier Oil Mexico Investments Limited
UK
UK
2
Intermediate holding company
Premier Oil Mexico Recursos S.A. de C.V.
Mexico
Mexico
10
Exploration, production, and development
Premier Oil Natuna Sea BV
Indonesia
Netherlands
7
Exploration, production, and development
Premier Oil Overseas BV
Netherlands
Netherlands
7
Intermediate holding company
Premier Oil South Andaman Limited
Indonesia
UK
2
Exploration, production, and development
Premier Oil Tuna BV
Indonesia
Netherlands
7
Exploration, production, and development
\n \n
Name of company
Area of operation
Country of incorporation
Main activity
Premier Oil UK Limited
UK
UK
5
Exploration, production, and development
Premier Oil Vietnam Offshore BV
Vietnam
Netherlands
7
Exploration, production, and development
Chrysaor (U.K.) Britannia Limited
\u2013
UK
2
Dormant company
Chrysaor (U.K.) Delta Limited
\u2013
UK
2
Non-trading
Chrysaor (U.K.) Eta Limited
\u2013
UK
2
Non-trading
Chrysaor (U.K.) Lambda Limited
\u2013
ROI
4
Dormant company
Chrysaor Production Limited
\u2013
UK
2
Non-trading
Chrysaor Resources (UK) Holdings Limited
\u2013
UK
2
Non-trading
Chrysaor (U.K.) Zeta Limited
\u2013
UK
2
Non-trading
Harbour Energy Argentina Limited
\u2013
UK
2
Dormant company
Harbour Energy Developments Limited
\u2013
UK
2
Dormant company
Harbour Energy Secretaries Limited
\u2013
UK
2
Dormant company
Harbour Energy Production Limited
\u2013
UK
2
Dormant company
Premier Oil ANS Holdings Limited
\u2013
UK
2
Non-trading
Premier Oil ANS Limited
\u2013
UK
2
Non-trading
Premier Oil B Limited
\u2013
UK
2
Dormant company
Premier Oil Congo (Marine IX) Limited
\u2013
Jersey
6
Dormant company
Premier Oil Exploration Limited
\u2013
UK
5
Non-trading
Premier Oil Exploration ONS Limited
\u2013
UK
2
Dormant company
Premier Oil Finance (Jersey) Limited
1
\u2013
Jersey
6
Non-trading
Premier Oil ONS Limited
\u2013
UK
2
Dormant company
Premier Oil Pakistan Offshore BV
\u2013
Netherlands
7
Dormant company
Premier Oil Vietnam 121 Limited
\u2013
UK
2
Non-trading
Viking CCS Limited (formerly Chrysaor Energy Limited)
\u2013
UK
2
Dormant company
Chrysaor Investments Limited
\u2013
UK
2
Liquidation
Chrysaor Petroleum Chemicals U.K. Limited
\u2013
UK
2
Liquidation
(formerly Harbour Energy Services Limited)
Chrysaor Production Oil (GB) Limited
\u2013
UK
2
Liquidation
(formerly Harbour Energy Production Limited)
Chrysaor Supply & Trading Limited
\u2013
UK
2
Liquidation
EnCore (VOG) Limited
\u2013
UK
2
Liquidation
EnCore CCS Limited
\u2013
UK
2
Liquidation
EnCore Natural Resources Limited
\u2013
UK
2
Liquidation
EnCore Oil and Gas Limited
\u2013
UK
2
Liquidation
Premier Oil Belgravia Holdings Limited
\u2013
UK
2
Liquidation
Premier Oil Belgravia Limited
\u2013
UK
2
Liquidation
Premier Oil Bukit Barat Limited
\u2013
UK
2
Liquidation
Premier Oil CCS Limited
\u2013
UK
2
Liquidation
Premier Oil E&P UK Energy Trading Limited
\u2013
UK
2
Liquidation
Premier Oil Exploration and Production (Iraq) Limited
\u2013
UK
2
Liquidation
Premier Oil Investments Limited
\u2013
UK
2
Liquidation
Premier Oil Paci\ufb01c Limited
\u2013
Hong Kong
12
Liquidation
Premier Overseas Holdings Limited
\u2013
UK
2
Liquidation
XEO Exploration Limited (formerly XEO Exploration plc)
\u2013
UK
2
Liquidation
Note:
1
Held directly by the company. All other companies are held through a subsidiary undertaking.
2
Registered of\ufb01ce \u2013 23 Lower Belgrave Street, London, United Kingdom, SW1W ONR.
3
Registered of\ufb01ce \u2013 Haakon VII\u2019s gate 1, 4
th
Floor, 0161 Oslo, Norway.
4
Registered of\ufb01ce \u2013 Riverside One, Sir John Rogerson\u2019s Quay, Dublin 2, Ireland.
5
Registered of\ufb01ce \u2013 4
th
Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN.
6
Registered of\ufb01ce \u2013 46/50 Kensington Place, 1
st
Floor, Kensington Chambers, St. Helier, JE4 0ZE, Jersey.
7
Registered of\ufb01ce \u2013 Herikerbergweg 88, 1101 CM, Amsterdam, Netherlands.
8
Registered of\ufb01ce \u2013 Commerce House, Wickhams Cay 1, Road Town, Tortola, VG1110.
9
Registered of\ufb01ce \u2013 Rua Lauro M\u00fcller, 116 \u2013 Sala 2006, Torre Rio Sul, Shopping, 20\u00ba andar, Botafogo, Rio de Janeiro \u2013 RJ \u2013 CEP: 22.290-906, Brazil.
10 Registered of\ufb01ce \u2013 Presidente Masaryk 111, Piso 1, Polanco V Seccion, Mexico City, CP 11560, Mexico.
11 Registered of\ufb01ce \u2013 Level 5, Mill Court, La Charroterie, St Peter Port, Guernsey, GY1 1EJ.
12 Registered of\ufb01ce \u2013 31/F, Tower Two, Time Square, 1 Matheson Street, Causeway Bay, Hong Kong.
13 Registered of\ufb01ce \u2013 Cricket Square, Hutchins Drive, PO Box 2681, Grand Cayman, KY1-1111.", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f26650": { "value": "31. Investments and amounts due from subsidiary undertakings
At 31 December 2023, the subsidiary undertakings of the company which were all wholly owned were:
\n \n
Name of company
Area of operation
Country of incorporation
Main activity
Chrysaor (U.K.) Alpha Limited
UK
UK
2
Exploration, production, and development
Chrysaor (U.K.) Beta Limited
UK
UK
2
Decommissioning activities
Chrysaor (U.K.) Sigma Limited
UK
UK
2
Exploration, production, and development
Chrysaor (U.K.) Theta Limited
UK
UK
2
Exploration, production, and development
Chrysaor CNS Limited
UK
UK
2
Exploration, production, and development
Chrysaor Developments Limited
UK
UK
2
Decommissioning activities
Chrysaor E&P Finance Limited
UK
UK
2
Financing company
Chrysaor E&P Limited
UK
UK
2
Intermediate holding company
Chrysaor Holdings Limited
1
UK
Cayman Islands
13
Intermediate holding company
Chrysaor Limited
UK
UK
2
Exploration, production, and development
Chrysaor Marketing Limited
UK
UK
2
Gas trading
Chrysaor North Sea Limited
UK
UK
2
Exploration, production, and development
Chrysaor Petroleum Company U.K. Limited
UK
UK
2
Exploration, production, and development
Chrysaor Petroleum Limited
UK
UK
2
Decommissioning activities
Chrysaor Production (U.K.) Limited
UK
UK
2
Exploration, production, and development
Chrysaor Production Holdings Limited
UK
UK
2
Intermediate holding company
Chrysaor Resources (Irish Sea) Limited
UK
UK
2
Exploration, production, and development
Ebury Gate Limited
Guernsey
Guernsey
11
Risk mitigation services
EnCore (NNS) Limited
UK
UK
2
Intermediate holding company
EnCore Oil Limited
UK
UK
2
Intermediate holding company
FP Mauritania A BV
Mauritania
Netherlands
7
Decommissioning activities
FP Mauritania B BV
Mauritania
Netherlands
7
Decommissioning activities
Harbour Energy Services Limited
UK
UK
2
Service company
(formerly Chrysaor E&P Services Limited)
Harbour Energy Norge AS
Norway
Norway
3
Exploration, production, and development
Premier Oil (EnCore Petroleum) Limited
UK
UK
2
Intermediate holding company
Premier Oil (Vietnam) Limited
Vietnam
British Virgin Islands
8
Exploration, production, and development
Premier Oil Aberdeen Services Limited
UK
UK
2
Service company
Premier Oil and Gas Services Limited
UK
UK
2
Service company
Premier Oil Andaman I Limited
Indonesia
UK
2
Exploration, production, and development
Premier Oil Andaman Limited
Indonesia
UK
2
Exploration, production, and development
Premier Oil Barakuda Limited
Indonesia
UK
2
Exploration, production and development
Premier Oil do Brasil Petroleo e Gas Ltda
Brazil
Brazil
9
Exploration, production, and development
Premier Oil E&P Holdings Limited
UK
UK
2
Intermediate holding company
Premier Oil E&P UK EU Limited
UK
UK
2
Exploration, production, and development
Premier Oil E&P UK Limited
UK
UK
2
Exploration, production, and development
Premier Oil Exploration (Mauritania) Limited
Mauritania
Jersey
6
Decommissioning activities
Premier Oil Exploration and Production
Mexico
Mexico
10
Exploration, production, and development
Mexico S.A.de C.V.
Premier Oil Far East Limited
Singapore
UK
2
Service company
Premier Oil Group Holdings Limited
1
UK
UK
2
Intermediate holding company
Premier Oil Group Limited
UK
UK
5
Intermediate holding company
Premier Oil Holdings Limited
UK
UK
2
Intermediate holding company
Premier Oil Mauritania B Limited
Mauritania
Jersey
6
Decommissioning activities
Premier Oil Mexico Holdings Limited
UK
UK
2
Intermediate holding company
Premier Oil Mexico Investments Limited
UK
UK
2
Intermediate holding company
Premier Oil Mexico Recursos S.A. de C.V.
Mexico
Mexico
10
Exploration, production, and development
Premier Oil Natuna Sea BV
Indonesia
Netherlands
7
Exploration, production, and development
Premier Oil Overseas BV
Netherlands
Netherlands
7
Intermediate holding company
Premier Oil South Andaman Limited
Indonesia
UK
2
Exploration, production, and development
Premier Oil Tuna BV
Indonesia
Netherlands
7
Exploration, production, and development
\n \n
Name of company
Area of operation
Country of incorporation
Main activity
Premier Oil UK Limited
UK
UK
5
Exploration, production, and development
Premier Oil Vietnam Offshore BV
Vietnam
Netherlands
7
Exploration, production, and development
Chrysaor (U.K.) Britannia Limited
\u2013
UK
2
Dormant company
Chrysaor (U.K.) Delta Limited
\u2013
UK
2
Non-trading
Chrysaor (U.K.) Eta Limited
\u2013
UK
2
Non-trading
Chrysaor (U.K.) Lambda Limited
\u2013
ROI
4
Dormant company
Chrysaor Production Limited
\u2013
UK
2
Non-trading
Chrysaor Resources (UK) Holdings Limited
\u2013
UK
2
Non-trading
Chrysaor (U.K.) Zeta Limited
\u2013
UK
2
Non-trading
Harbour Energy Argentina Limited
\u2013
UK
2
Dormant company
Harbour Energy Developments Limited
\u2013
UK
2
Dormant company
Harbour Energy Secretaries Limited
\u2013
UK
2
Dormant company
Harbour Energy Production Limited
\u2013
UK
2
Dormant company
Premier Oil ANS Holdings Limited
\u2013
UK
2
Non-trading
Premier Oil ANS Limited
\u2013
UK
2
Non-trading
Premier Oil B Limited
\u2013
UK
2
Dormant company
Premier Oil Congo (Marine IX) Limited
\u2013
Jersey
6
Dormant company
Premier Oil Exploration Limited
\u2013
UK
5
Non-trading
Premier Oil Exploration ONS Limited
\u2013
UK
2
Dormant company
Premier Oil Finance (Jersey) Limited
1
\u2013
Jersey
6
Non-trading
Premier Oil ONS Limited
\u2013
UK
2
Dormant company
Premier Oil Pakistan Offshore BV
\u2013
Netherlands
7
Dormant company
Premier Oil Vietnam 121 Limited
\u2013
UK
2
Non-trading
Viking CCS Limited (formerly Chrysaor Energy Limited)
\u2013
UK
2
Dormant company
Chrysaor Investments Limited
\u2013
UK
2
Liquidation
Chrysaor Petroleum Chemicals U.K. Limited
\u2013
UK
2
Liquidation
(formerly Harbour Energy Services Limited)
Chrysaor Production Oil (GB) Limited
\u2013
UK
2
Liquidation
(formerly Harbour Energy Production Limited)
Chrysaor Supply & Trading Limited
\u2013
UK
2
Liquidation
EnCore (VOG) Limited
\u2013
UK
2
Liquidation
EnCore CCS Limited
\u2013
UK
2
Liquidation
EnCore Natural Resources Limited
\u2013
UK
2
Liquidation
EnCore Oil and Gas Limited
\u2013
UK
2
Liquidation
Premier Oil Belgravia Holdings Limited
\u2013
UK
2
Liquidation
Premier Oil Belgravia Limited
\u2013
UK
2
Liquidation
Premier Oil Bukit Barat Limited
\u2013
UK
2
Liquidation
Premier Oil CCS Limited
\u2013
UK
2
Liquidation
Premier Oil E&P UK Energy Trading Limited
\u2013
UK
2
Liquidation
Premier Oil Exploration and Production (Iraq) Limited
\u2013
UK
2
Liquidation
Premier Oil Investments Limited
\u2013
UK
2
Liquidation
Premier Oil Paci\ufb01c Limited
\u2013
Hong Kong
12
Liquidation
Premier Overseas Holdings Limited
\u2013
UK
2
Liquidation
XEO Exploration Limited (formerly XEO Exploration plc)
\u2013
UK
2
Liquidation
Note:
1
Held directly by the company. All other companies are held through a subsidiary undertaking.
2
Registered of\ufb01ce \u2013 23 Lower Belgrave Street, London, United Kingdom, SW1W ONR.
3
Registered of\ufb01ce \u2013 Haakon VII\u2019s gate 1, 4
th
Floor, 0161 Oslo, Norway.
4
Registered of\ufb01ce \u2013 Riverside One, Sir John Rogerson\u2019s Quay, Dublin 2, Ireland.
5
Registered of\ufb01ce \u2013 4
th
Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN.
6
Registered of\ufb01ce \u2013 46/50 Kensington Place, 1
st
Floor, Kensington Chambers, St. Helier, JE4 0ZE, Jersey.
7
Registered of\ufb01ce \u2013 Herikerbergweg 88, 1101 CM, Amsterdam, Netherlands.
8
Registered of\ufb01ce \u2013 Commerce House, Wickhams Cay 1, Road Town, Tortola, VG1110.
9
Registered of\ufb01ce \u2013 Rua Lauro M\u00fcller, 116 \u2013 Sala 2006, Torre Rio Sul, Shopping, 20\u00ba andar, Botafogo, Rio de Janeiro \u2013 RJ \u2013 CEP: 22.290-906, Brazil.
10 Registered of\ufb01ce \u2013 Presidente Masaryk 111, Piso 1, Polanco V Seccion, Mexico City, CP 11560, Mexico.
11 Registered of\ufb01ce \u2013 Level 5, Mill Court, La Charroterie, St Peter Port, Guernsey, GY1 1EJ.
12 Registered of\ufb01ce \u2013 31/F, Tower Two, Time Square, 1 Matheson Street, Causeway Bay, Hong Kong.
13 Registered of\ufb01ce \u2013 Cricket Square, Hutchins Drive, PO Box 2681, Grand Cayman, KY1-1111.", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestsInOtherEntitiesExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "f27688": { "value": "Company balance sheet
As at 31 December 2023
2023
2022
Note
$ million
$ million
Assets
Non-current assets
Investments in subsidiaries
3
2,238
2,302
Long-term receivables
4
1,924
2,209
Total non-current assets
4,162
4,511
Current assets
Trade and other receivables
4
22
4
Total current assets
22
4
Current liabilities
Trade and other payables
5
(54)
(15)
Net current liabilities
(32)
(11)
Non-current liabilities
Borrowings
6
(493)
(491)
Long-term employee bene\ufb01t plan de\ufb01cit
7
(1)
(1)
Net assets
3,636
4,008
Equity and reserves
Share capital
9
171
171
Retained earnings
3,457
3,829
Other reserves
8
8
Total equity and reserves
3,636
4,008
Pro\ufb01t for the year ending 31 December 2023 was $36 million (2022: $2,704 million loss).
The notes on pages 174 to 176 form part of these \ufb01nancial statements.
The \ufb01nancial statements of Harbour Energy plc (registered number SC234781) on pages 172 and 173 were approved by the board
of directors and authorised for issue on 6 March 2024 and\u00a0signed on its behalf by:
Alexander Krane
Chief Financial Of\ufb01cer
\n \n
Capital
Share
Share
Merger
redemption
Retained
Total
capital
premium
reserve
reserve
earnings
equity
$ million
$ million
$ million
$ million
$ million
$ million
At 1 January 2022
171
1,505
4,806
8
762
7,252
Purchase and cancellation of own shares
1
\u2013
\u2013
\u2013
\u2013
(361)
(361)
Loss for the \ufb01nancial year
\u2013
\u2013
\u2013
\u2013
(2,704)
(2,704)
Capital restructuring
2
\u2013
(1,505)
(4,806)
\u2013
6,311
\u2013
Share-based payments
\u2013
\u2013
\u2013
\u2013
34
34
Purchase of ESOP Trust shares
\u2013
\u2013
\u2013
\u2013
(22)
(22)
Dividend paid
\u2013
\u2013
\u2013
\u2013
(191)
(191)
At 31 December 2022
171
\u2013
\u2013
8
3,829
4,008
Purchase and cancellation of own shares
1
\u2013
\u2013
\u2013
\u2013
(249)
(249)
Pro\ufb01t for the \ufb01nancial year
\u2013
\u2013
\u2013
\u2013
36
36
Share-based payments
\u2013
\u2013
\u2013
\u2013
46
46
Purchase of ESOP Trust shares
\u2013
\u2013
\u2013
\u2013
(15)
(15)
Dividend paid
\u2013
\u2013
\u2013
\u2013
(190)
(190)
At 31 December 2023
171
\u2013
\u2013
8
3,457
3,636
\n
1
Includes $1 million costs in relation to fees and stamp duty (2022: $2 million).
\n
2
Share premium and merger reserve balances recategorised to retained earnings following capital reduction effective 3 August 2022. Of the reserves capitalised $1.65 billion is
\n
non-distributable until 31 March 2028.
\n
Company statement of changes in equity
\n
For the year ended 31 December 2023
Notes to the company \ufb01nancial statements
1. Material accounting policies
\n
The separate \ufb01nancial statements of the company are presented as required by the Companies Act 2006. The company meets the
\n
de\ufb01nition of a qualifying entity under Financial Reporting Standard 100 (FRS 100) issued by the Financial Reporting Council (FRC).
\n
These \ufb01nancial statements have been prepared in accordance with FRS 101 \u2018Reduced Disclosure Framework\u2019.
\n
As permitted by FRS 101, the company has taken advantage of the disclosure exemptions available under that standard in relation
\n
to accounting standards issued but not yet effective or implemented, share-based payment information, \ufb01nancial instruments, capital
\n
management, presentation of comparative information in respect of certain assets, presentation of a cash \ufb02ow statement and certain
\n
related party transactions.
\n
The \ufb01nancial statements have been prepared on a going concern basis. Further information relating to the going concern assumption
\n
is provided in the Financial review on page 31.
\n
Where required, the equivalent disclosures are given in the consolidated \ufb01nancial statements. Key sources of estimation uncertainty
\n
disclosure are provided in the accounting policies and in relevant notes to the consolidated \ufb01nancial statements as applicable. Details
\n
of the company\u2019s share-based payment schemes are provided in note 25 of the consolidated \ufb01nancial statements.
\n
The \ufb01nancial statements have been prepared on the historical cost basis. The material accounting policies adopted are the same as
\n
those set out on pages 123 to 137 to the consolidated \ufb01nancial statements except that investments in subsidiaries are stated at cost
\n
less, where appropriate, provisions for impairment.
\n
2. Pro\ufb01t/loss for the year
\n
As permitted by section 408 of the Companies Act 2006, the company has elected not to present its own pro\ufb01t and loss account
\n
for the year. The company reported a pro\ufb01t for the \ufb01nancial year ended 31 December 2023 of $36 million (2022: $2,704 million loss).
\n
Other comprehensive expense for the year was $nil (2022: $nil).
\n
The auditor\u2019s remuneration for audit and other services is disclosed in note 5 to the consolidated \ufb01nancial statements.
\n
3. Fixed asset investments
\n
Net book value
2023
2022
$ million
$ million
At 1 January
2,302
4,966
Impairment
(64)
(2,664)
At 31 December
2,238
2,302
\n
The impairment of $64 million re\ufb02ects the investment in a subsidiary that is planned to enter liquidation during 2024.
\n
Further, an additional impairment review was undertaken with reference to the company\u2019s market capitalisation at the year-end date
\n
(level 1 under IFRS 13 fair value hierarchy), adjusted to re\ufb02ect a control premium and cost of disposal in order to determine the
\n
recoverable amount of the investments on a fair value less cost to sell basis. This was also tested against internal corporate valuations
\n
modelled using asset portfolio and corporate data (level 3 under IFRS 13 fair value hierarchy). This resulted in a surplus of recoverable
\n
amount over the cost of investment. Given the impairment recognised in 2022, this surplus was further assessed for reversal, however
\n
was not found to be robust when evaluated with reference to reasonable downside sensitivities. As part of this assessment, it was noted
\n
that a 10 per cent decrease in the share price would result in a $156 million increase in the impairment provision.
\n
A list of all investments in subsidiaries held at 31 December 2023, including the name and type of business, the country of operation
\n
and the country of incorporation or registration, is given in note 31 to the consolidated \ufb01nancial statements.
4. Receivables
\n\n \n
2023
2022
$ million
$ million
Current
Amounts owed by subsidiary undertakings
1
\u2013
1
Trade debtors
1
\u2013
Prepayments
21
3
22
4
Non-current
Amounts owed by subsidiary undertakings
2
1,924
2,209
\n
1
Amounts owed by subsidiary undertakings include non-interest bearing loans that are repayable on demand, although the company has con\ufb01rmed that it has no current intention to call
\n
on the loans until at least 12 months from the date of the approval of these \ufb01nancial statements.
\n
2
The above carrying value re\ufb02ects an impairment provision required under IFRS 9, which was calculated using the Group\u2019s 12-month probability of default. The closing balance at year end
\n
was $1,924 million, being the carrying value of $1,933 million reduced during the year by a charge of $9 million.
\n
The carrying values of the company\u2019s receivables approximate their fair value.
\n
5. Trade and other payables
\n\n \n
2023
2022
$ million
$ million
Amounts owed to subsidiary undertakings
\u2013
2
Amounts owed to subsidiary undertakings in respect of taxation
8
5
Other creditors
\u2013
1
Accruals
46
7
54
15
\n
The carrying values of the company\u2019s payables approximate their fair value.
\n
6. Borrowings
\n\n \n
2023
2022
Book value
Fair value
Book value
Fair value
$ million
$ million
$ million
$ million
Bond
(493)
(487)
(491)
(446)
\n
In October 2021, the company issued a $500 million bond under Rule 144A which has a tenor of \ufb01ve years to maturity. The coupon was
\n
set at 5.50 per cent and interest is payable semi-annually. Further details can be found in note 21 of the Group accounts.
7. Long-term employee bene\ufb01t plans
De\ufb01ned bene\ufb01t schemes
The company operates a \ufb01nal salary de\ufb01ned bene\ufb01t pension plan in the UK. The Plan is an HMRC registered pension plan and is subject
to standard UK pension and tax laws. Details on the bene\ufb01ts provided by the Plan are set out in the Trust Deed and Rules dated
16 October 2008 (as amended).
The Plan\u2019s assets are held in a separate trustee-administered fund to meet long-term pension liabilities to bene\ufb01ciaries. The Trustee of the Plan
is required to act in the best interest of the bene\ufb01ciaries. The appointment of trustee directors is determined by the trust documentation.
The Trustee of the Plan invests assets in line with the Statement of Investment Principles. The Statement of Investment Principles has
been established taking into consideration the liabilities of the Plan and the investment risk the Trustee is willing to accept.
Under the Scheme Funding regime introduced by the Pensions Act 2004, the Trustee is required to carry out regular actuarial valuations of the
Plan, establish a schedule of contributions and, when there is a shortfall, a recovery plan. Scheme funding valuations are carried out at least
every three years. Approximate funding updates are produced annually in years where a full scheme funding valuation is not completed.
The de\ufb01ned bene\ufb01t pension plan exposes the company to actuarial risk, such as longevity risk, interest rate risk, salary risk, investment
market risk and currency risk.
Further details of this Plan have not been provided as the Plan is not material to the \ufb01nancial position or results of the company.
De\ufb01ned contribution schemes
The company operates a de\ufb01ned contribution retirement bene\ufb01t scheme. Further details of this scheme are provided in note 26 of the
consolidated \ufb01nancial statements.
8. Commitments and guarantees
At the year-end date, the company (together with certain subsidiary undertakings) guaranteed the Group\u2019s principal borrowing facilities,
which comprise:
\u2022
$2.75 billion reserve based lending facility, of which $1.75 billion is available for drawing letters of credit;
\u2022
$500 million unsecured bond; and
\u2022
$400 million of surety bond capacity for the purposes of posting decommissioning security, which is effective from 1 January 2024.
9. Share capital and share premium
Further details of these items are disclosed in note 24 of the consolidated \ufb01nancial statements.
10. Dividends
Further details of these items are disclosed in note 29 of the consolidated \ufb01nancial statements.", "dimensions": { "concept": "ifrs-full:DisclosureOfConsolidatedAndSeparateFinancialStatementsExplanatory", "language": "en", "entity": "scheme:213800YPC42DYBKVPF97", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } } } }