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"f15926": {
"value": "1. Corporate information Harbour Energy plc (Harbour) is a limited liability company incorporated in Scotland and listed on the London Stock Exchange.
\nThe address of the registered of\ufb01ce is 4
\nth
\nFloor, Saltire Court, 20 Castle Terrace, Edinburgh EH1 2EN, United Kingdom.
\nThe consolidated \ufb01nancial statements of Harbour Energy plc (the company) and all its subsidiaries (the Group) for the year ended
\n31 December 2022 were authorised for issue by the board of directors on 8 March 2023.
\nThe Group\u2019s principal activities are the acquisition, exploration, development and production of oil and gas reserves on the UK and
\nNorwegian continental shelves, Indonesia, Vietnam and Mexico.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15927": {
"value": "1. Corporate information Harbour Energy plc (Harbour) is a limited liability company incorporated in Scotland and listed on the London Stock Exchange.
\nThe address of the registered of\ufb01ce is 4
\nth
\nFloor, Saltire Court, 20 Castle Terrace, Edinburgh EH1 2EN, United Kingdom.
\nThe consolidated \ufb01nancial statements of Harbour Energy plc (the company) and all its subsidiaries (the Group) for the year ended
\n31 December 2022 were authorised for issue by the board of directors on 8 March 2023.
\nThe Group\u2019s principal activities are the acquisition, exploration, development and production of oil and gas reserves on the UK and
\nNorwegian continental shelves, Indonesia, Vietnam and Mexico.
\n2. Signi\ufb01cant accounting policies
\nBasis of preparation
\nThe consolidated \ufb01nancial statements have been prepared on a going concern basis in accordance with UK-adopted International
\nAccounting Standards (IAS) in conformity with the requirements of the Companies Act 2006. The analysis used by the Directors in
\nadopting the going concern basis considers the various plans and commitments of the Group as well as various sensitivity and reverse
\nstress test analyses. The results from the downside sensitivities with regard to production and commodity price assumptions, which in
\nmanagement\u2019s view re\ufb02ect two of the principal risks, indicate that material changes within one year that would impact the going concern
\nbasis of preparation are unlikely. Further details are within the Financial review on pages 44-49 and Viability statement on page 53.
\nThe presentation currency of the Group \ufb01nancial information is US dollars and all values in the Group \ufb01nancial information are presented
\nin millions ($ million) and all values are rounded to the nearest $0.1 million, except where otherwise stated.
\nThe \ufb01nancial statements have been prepared on the historical cost basis, except for certain \ufb01nancial assets and liabilities, including
\nderivative \ufb01nancial instruments, which have been measured at fair value.
\nIn October 2020, Harbour Energy Limited entered into an agreement with Premier Oil plc (Premier) regarding an all-share merger between
\nPremier and Harbour Energy Limited\u2019s subsidiary, Chrysaor Holdings Limited (Chrysaor). Under the terms of the merger, Premier legally
\nacquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the acquiror for accounting purposes, primarily as a
\nresult of its ability to appoint the Board of the enlarged group. The transaction completed on 31 March 2021, whereupon Premier, being
\nthe legal acquirer and accounting acquiree, changed its name from Premier Oil plc to Harbour Energy plc.
\nThe consolidated \ufb01nancial statements provide comparative period information with respect to the prior year but this only includes nine
\nmonths of Premier contribution compared to a full 12 months contribution for the year ended 31 December 2022.
\nThe accounting policies, which follow, set out those policies which apply in preparing the \ufb01nancial statements for the year ended
\n31 December 2022. All accounting policies are consistent with those adopted and disclosed in Harbour\u2019s 2021 Annual Report and
\nAccounts, other than where new policies have been adopted.
\nBasis of consolidation
\nThe consolidated \ufb01nancial statements comprise the \ufb01nancial statements of the company and its subsidiaries as at 31 December 2022.
\nSubsidiaries are those entities over which the Group has control. Control is achieved where the Group has the power over the subsidiary,
\nhas rights, or is exposed to variable returns from the subsidiary and has the ability to use its power to affect its returns. All subsidiaries
\nare 100 per cent owned by the Group and there are no non-controlling interests.
\nIf the Group loses control over a subsidiary, it derecognises the related assets (including goodwill), liabilities, non-controlling interest and
\nother components of equity, while any resultant gain or loss is recognised in pro\ufb01t or loss. Any investment retained is recognised at fair value.
\nThe results of subsidiaries acquired or disposed of during the year are included in the income statement from the effective date of
\nacquisition or up to the effective date of disposal, as appropriate. Where necessary, adjustments are made to the \ufb01nancial statements
\nof subsidiaries acquired to bring the accounting policies used into line with those used by other members of the Group.
\nAll intra-group transactions and balances have been eliminated on consolidation.
\n123
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nPrior year adjustment
\nOther \ufb01nancial liabilities \u2013 commodity derivatives within current liabilities as at 31 December 2021 \u2013 included a number of \ufb01nancial
\ninstruments which had matured on the last day of the \ufb01nancial year for which the related liability should have been classi\ufb01ed within trade
\nand other payables. The relevant amounts have therefore been reclassi\ufb01ed to trade and other payables which is also held within current
\nliabilities (see note 19, Trade and other payables \u2013 matured \ufb01nancial instruments). There was no impact on any of the other primary
\nstatements. Each of the affected \ufb01nancial statement line items has been restated and the impact is summarised in the following table.
\nBalance sheet at 31 December 2021
Note
\nAs previously
\nreported
\n$ million
\nAdjustments
\n$ million
\nAs restated
\n$ million
\nOther \ufb01nancial liabilities \u2013 commodity derivatives
22
(2,526.2)
361.7
(2,164.5)
\nTrade and other payables
19
(873.6)
(361.7)
(1,235.3)
\nImpact of climate change on the \ufb01nancial statements and related disclosures
\nJudgements and estimates made in assessing the impact of climate change and the energy transition
\nHarbour monitors global climate change and energy transition developments and plans accordingly. Management recognises there is a general
\nhigh level of uncertainty about the speed and scale of impacts which, together with limited historical information, provides signi\ufb01cant challenges
\nin the preparation of forecasts and plans with a range of possible future scenarios.
\nThe Group\u2019s strategic ambition is to achieve net zero by 2035 through several opportunities, including operational improvements, UK
\noffshore electri\ufb01cation, UK carbon capture and storage (CCS) and the eventual cessation of production of mature \ufb01elds. Where the Group
\ncannot reduce its Scope 1 and 2 emissions, it will invest in carbon credits to achieve the goal of net zero (refer to the ESG review on
\npages 30-41). All new economic investment decisions include the cost of carbon, and opportunities are assessed on their climate-impact
\npotential and alignment with Harbour Energy\u2019s net zero goal, taking into consideration both GHG volumes and intensity. The corporate
\nmodelling that supports the preparation of the \ufb01nancial statements (such as asset impairment assessment, going concern and viability,
\ndeferred tax recoverability) includes project costs related to carbon, capture and storage; and certain limited electri\ufb01cation and reduction
\nof Scope 1 and 2 GHG emissions initiatives. Emissions reduction incentives are part of staff remuneration and annual bonus schemes
\n(refer to the Remuneration Committee report on pages 78-80). Additionally, the cost of borrowing is tied to our gross operated CO
\n2
\nemissions performance, with GHG metrics being linked to our RBL interest expense, further incentivising our emissions reduction targets.
\nAs a result, climate change and the energy transition have the potential to signi\ufb01cantly impact the accounting estimates adopted by
\nmanagement and therefore the valuation of assets and liabilities reported on the balance sheet. On an ongoing basis management
\ncontinues to assess the potential impacts on the signi\ufb01cant judgements and estimates used in the \ufb01nancial statements. Estimates
\nadopted in the preparation of the \ufb01nancial statements re\ufb02ect management\u2019s best estimate of future market conditions where, in
\nparticular, commodity prices can be volatile. Notwithstanding the challenges around climate change and the energy transition, it is
\nmanagement\u2019s view that the \ufb01nancial statements are consistent with the disclosures in the Strategic Report.
\nThis note provides insight into how Harbour has considered the impact on valuations of key line items in the \ufb01nancial statements and how
\nthey could change based on the climate change scenarios and sensitivities considered. The scenarios presented show what the possible
\nimpact could be on the \ufb01nancial statements considering both high and low-price curve outlooks. Importantly, these climate change
\nscenarios do not form the basis of the preparation of the \ufb01nancial statements but rather indicate how the key assumptions that underpin
\nthe \ufb01nancial statements would be impacted by the climate change scenarios. It is recognised that the reality of the nature of progress of
\nenergy transition will bring greater levels of disruption and volatility than these external scenarios expect and do not represent
\nmanagement\u2019s current best estimate.
\nManagement\u2019s current best estimate, which was derived from consideration of a range of considered economic forecasts, has been
\nused on the same basis to prepare the \ufb01nancial statements and is represented by the Harbour Scenario oil price curve. Management
\ncontinues to review these estimates and assumptions to ensure they re\ufb02ect the latest economic environment conditions and market
\ninformation available.
\nImpairment of property, plant and equipment, and goodwill
\nThe energy transition has the potential to signi\ufb01cantly impact future commodity and carbon prices which would, in turn, affect the
\nrecoverable amount of property, plant and equipment and goodwill. In the current period, the Harbour Scenario real long-term commodity
\nprice assumptions, when testing for impairment, were $65/bbl (2021: $65/bbl) and 65p/therm (2021: 60p/therm) for Brent crude and
\nUK NBP gas, respectively. The real long-term price assumptions for the UK regulatory price of carbon are \u00a380/tonne, being $100/tonne
\nat $:\u00a31.25 foreign exchange rate (2021: \u00a355/$74/tonne) and voluntary offsets $25/tonne used, with sensitivities run at $100/tonne
\n(2021: $100/tonne). Sensitivity analysis using a carbon price of $100/tonne indicates that material impairments would not arise. Such
\nassumptions are inherently uncertain and may ultimately differ from the actual amounts.
\nSee key sources of estimation uncertainty: recoverability of oil and gas assets and goodwill for further information (page 136), including
\nsensitivity analysis in relation to reasonably possible changes in price assumptions.
\n124
During 2022 there was a net pre-tax impairment credit of $170 million comprising: impairment on a single CGU asset $163 million,
\nimpairment reversals on North Sea assets $250 million and decommissioning provision reductions $83 million. In 2021, certain
\nimpairments were recognised as a result of underlying reservoir performance.
\nSensitivities on the impairment of property, plant and equipment and goodwill have been prepared using various price scenarios to
\nshow the possible impact on net book carrying values. As noted, the Harbour Scenario is the basis for the preparation of the \ufb01nancial
\nstatements and impairment sensitivities have been prepared at an average -10 per cent and +10 per cent to the Harbour Scenario
\naverage crude and selected published climate change price curves. Sensitivity analysis on carbon price $100/tonne indicates that
\nimpairments would not have a material impact on the \ufb01nancial statements.
\nThe sensitivity scenarios described below are price curves only and the modelling assumes that all other factors remain unchanged from
\nthe Harbour Scenario used for the basis of preparation of the \ufb01nancial statements. These sensitivities are stated before any management
\nmitigation actions to manage downside risks if the scenarios were to occur.
\n\u00bc
Harbour Scenario: base price curve for crude oil used for impairment testing.
\n\u00bc
NGFS Current Policies: re\ufb02ects high physical risks and low transition risks.
\n\u00bc
NGFS Delayed Transition: re\ufb02ects low physical risks and high transition risks.
\n\u00bc
IEA Net Zero 2050: re\ufb02ects low physical risks and low transition risks.
\n0
\n20
\n40
\n60
\n80
\n100
\n120
\n140
\n160
\n2020
\n2021
\n2022
\n2023
\n2024
\n2025
\n2026
\n2027
\n2028
\n2029
\n2030
\n2031
\n2032
\n2033
\n2034
\n2035
\n2036
\n2037
\n2038
\n2039
\n2040
\n2041
\n2042
\n2043
\n2044
\n2045
\n2046
\n2047
\n2048
\n2049
\n2050
\nBrent Crude
Harbour Scenario
IEA Net Zero 2050
NGFS Delayed Transition
NGFS Current Policies
\nThe graph above shows the crude oil price curves for the period to 2050 for the Harbour Scenario, NGFS Current Policies, NGFS Delayed
\nTransition and IEA Net Zero 2050. There are no climate change price curves published by NGFS or the IEA for UK NBP gas. All the scenario
\nprice curves are dependent on factors covering supply, demand, economic and geopolitical events and therefore are inherently uncertain
\nand subject to signi\ufb01cant volatility and hence unlikely to re\ufb02ect the future outcome.
\nThe results of the sensitivities are as follows and show the impact on the balance sheet carrying values.
\n$ million
Carrying value
Crude oil
\n-10% to
\nHarbour Scenario
\n+10% to
\nHarbour Scenario
\nNGFS Current
\nPolicies
\nNGFS Delayed
\nTransition
\nIEA Net Zero
\n2050
\nProperty, plant and equipment
5,690
(57)
\u2013
\u2013
\u2013
(355)
\nGoodwill
1,327
\u2013
\u2013
\u2013
\u2013
\u2013
\nThe sensitivity results show that under the -10 per cent to Harbour Scenario (oil and gas commodity prices reduced from 1 January 2023)
\nan impairment of $57 million would arise on a single North Sea CGU. The +10 per cent to Harbour Scenario (oil and gas commodity prices
\nincreased from 1 January 2023), NGFS Current and Delayed scenarios show no incremental impairments as these scenarios are all
\nfavourable to the Harbour Scenario. Furthermore, under these three scenarios, no reversal of any historic impairment is triggered as there
\nhave been no prior crude oil-price related impairments. Under the IEA Net Zero 2050 scenario there would be an impairment in property,
\nplant and equipment of $355 million with goodwill not impacted given suf\ufb01cient value headroom.
\nProperty, plant and equipment \u2013 depreciation and expected useful lives
\nThe energy transition has the potential to reduce the expected useful lives of assets and consequently accelerate depreciation charges.
\nThere are no signi\ufb01cant judgements and/or critical estimation uncertainty related to climate factors.
\nSee accounting policy: property, plant and equipment for further information (page 128).
\n125
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nIntangible assets \u2013 exploration and evaluation assets
\nThe energy transition has the potential to affect the future development or viability of exploration and evaluation prospects. A signi\ufb01cant
\nportion of the Group\u2019s exploration and evaluation assets relate to prospects that could be tied back to existing infrastructure and hence
\nrequire less capital investment as these assets are less exposed to the impacts of the energy transition compared to large frontier
\ndevelopments. At each balance sheet date, all exploration and evaluation prospects are reviewed against the Group\u2019s \ufb01nancial framework
\nto ensure that the continuation of activities is planned and expected. There are no signi\ufb01cant judgements and/or critical estimation
\nuncertainty related to climate factors.
\nSee judgements: exploration and evaluation expenditure (page 136) and note 11 for further information.
\nDecommissioning cost and provisions
\nThe energy transition may accelerate the decommissioning of assets which would result in an increase in the carrying value of associated
\ndecommissioning provisions. Whilst the Group currently expects to incur decommissioning costs over the next 40 years, we anticipate the
\nmajority of costs will be incurred between the next 10 to 20 years which will reduce the exposure to the impact of the energy transition.
\nDecommissioning cost estimates are based on the known regulatory and external environment. These cost estimates and recoverability
\nof associated deferred tax may change in the future, including as a result of the energy transition.
\nOn 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
\nreduction in the applied discount rates used to assess the \ufb01nal decommissioning obligation, would result in increases to the decommissioning
\nprovision of approximately $417 million and $162 million, respectively. This change would be principally offset by a change to the value of the
\nassociated asset unless the asset is fully depreciated, in which case the change in estimate is recognised directly within the income statement.
\nThe energy transition may accelerate the decommissioning of producing assets and therefore increase the carrying value of provisions.
\nThe Group currently expects to incur decommissioning costs over the next 40 years, the majority of which are anticipated to be incurred
\nbetween the next 10 to 20 years. Currently, the timing of decommissioning expenditures have not been materially brought forward and
\nmanagement do not consider that any reasonable change in the timing of decommissioning expenditure will have a material impact on
\nthe decommissioning provisions.
\nSee key sources of estimation uncertainty: decommissioning costs for further information (page 136).
\nSegment reporting
\nThe Group\u2019s activities consist of one class of business being the acquisition, exploration, development and production of oil and gas
\nreserves and related activities, and are split geographically and managed in two business units: namely North Sea and International.
\nJoint arrangements
\nA joint arrangement is one in which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an
\narrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
\nExploration and production operations are usually conducted through joint arrangements with other parties. The Group reviews all joint
\narrangements and classi\ufb01es them as either joint operations or joint ventures depending on the rights and obligations of each party to
\nthe arrangement and whether the arrangement is structured through a separate vehicle. The Group\u2019s interest in joint operations, such
\nas exploration and production arrangements, are accounted for by recognising its:
\n\u00bc
Assets, including its share of any assets held jointly.
\n\u00bc
Liabilities, including its share of any liabilities incurred jointly.
\n\u00bc
Revenue from the sale of its share of the output arising from the joint operation.
\n\u00bc
Expenses, including its share of any expenses incurred jointly.
\nA joint venture, which normally involves the establishment of a separate legal entity, is a contractual arrangement whereby the parties
\nthat have joint control of the arrangement have the rights to the arrangement\u2019s net assets. The results, assets and liabilities of a joint
\nventure are incorporated in the consolidated \ufb01nancial statements using the equity method of accounting. During 2022, the Group did not
\nhave any interests in joint ventures.
\nWhere the Group transacts with its joint operations, unrealised pro\ufb01ts and losses are eliminated to the extent of the Group\u2019s interest in
\nthe joint operation.
\n126
Foreign currency translation
\nEach entity in the Group determines its own functional currency, being the currency of the primary economic environment in which the
\nentity operates, and items included in the \ufb01nancial statements of each entity are measured using that functional currency.
\nThe consolidated \ufb01nancial statements are presented in US dollars, which is also the parent company\u2019s functional currency.
\nTransactions recorded in foreign currencies are initially recorded in the entity\u2019s functional currency by applying an average rate of
\nexchange. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency rate of exchange
\nruling at the reporting date. All differences are taken to the income statement.
\nNon-monetary assets and liabilities denominated in foreign currencies are measured at historic cost based on exchange rates at the date
\nof the initial transaction and subsequently not retranslated.
\nOn consolidation, the assets and liabilities of the Group\u2019s operations are translated at exchange rates prevailing on the balance sheet
\ndate. Income and expense items are translated at the average monthly exchange rates for the year. Equity is held at historic cost and is
\nnot retranslated. The resulting exchange differences are recognised as other comprehensive income and are transferred to the Group\u2019s
\ncurrency translation reserve.
\nWhen an overseas operation is disposed of, such translation differences relating to it are recognised as income or expense.
\nCurrent versus non-current classi\ufb01cation
\nThe Group presents assets and liabilities in the statement of \ufb01nancial position based on current or non-current classi\ufb01cation.
\nAn asset is current when it is:
\na. expected to be realised or intended to be sold or consumed in the normal operating cycle;
\nb. held primarily for the purpose of trading;
\nc. expected to be realised within 12 months after the reporting period; or
\nd.
cash or cash equivalent unless restricted from being exchanged or used to settle a liability for at least 12 months after the reporting period.
\nAll other assets are classi\ufb01ed as non-current.
\nA liability is current when:
\na. it is expected to be settled in the normal operating cycle;
\nb. it is held primarily for the purpose of trading;
\nc. it is due to be settled within 12 months after the reporting period, or;
\nd. there is no unconditional right to defer the settlement of the liability for at least 12 months after the reporting period.
\nThe terms of the liability that could, at the option of the counterparty, result in its settlement by the issue of equity instruments do
\nnot affect its classi\ufb01cation. The Group classi\ufb01es all other liabilities as non-current. Deferred tax assets and liabilities are classi\ufb01ed
\nas non-current assets and liabilities.
\nBusiness combinations
\nBusiness combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the
\nassets transferred, equity instruments issued and liabilities incurred or assumed at the date of completion of the acquisition. Acquisition
\ncosts incurred are expensed and included in administrative expenses. Where applicable, the consideration for the acquisition includes
\nany asset or liability resulting from a contingent consideration arrangement, measured at its fair value at acquisition.
\nThe identi\ufb01able assets, liabilities and contingent liabilities acquired that meet the conditions for recognition under IFRS 3 are recognised
\nat their fair value at the acquisition date, except that:
\n\u00bc
Deferred tax assets or liabilities and liabilities or assets related to employee bene\ufb01t arrangements are recognised and measured in
\naccordance with IAS 12 Income Taxes and IAS 19 Employee Bene\ufb01ts, respectively.
\n\u00bc
Lease arrangements that represent leases as de\ufb01ned by IFRS 16 Leases are recognised and measured in accordance with IFRS 16 Leases.
\n\u00bc
Liabilities or equity instruments related to the replacement by the Group of an acquirer\u2019s share-based payment awards are measured
\nin accordance with IFRS 2 Share-Based Payment.
\n127
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nIf the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the
\nGroup reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted during the
\nmeasurement period, or additional assets or liabilities are recognised to re\ufb02ect new information obtained about facts and circumstances
\nthat existed as of the acquisition date that, if known, would have affected the amounts recognised as of that date. The measurement period
\nis the period from the date of acquisition to the date the Group obtains complete information about facts and circumstances that existed as
\nof the acquisition date, subject to a maximum of one year.
\nGoodwill
\nIn 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
\nIFRS 3 Business Combinations, the acquisition method of accounting is applied. Goodwill represents the difference between the aggregate of
\nthe fair value of purchase consideration transferred at the acquisition date and the fair value of the identi\ufb01able assets, liabilities and contingent
\nliabilities acquired. If however, the fair value of the purchase consideration transferred is lower than the fair value of the identi\ufb01able assets and
\nliabilities acquired, the difference is recognised in the income statement as negative goodwill. Goodwill is initially measured at cost. Following
\ninitial recognition, goodwill is measured at cost less any accumulated impairment. For the purpose of impairment testing, goodwill acquired in a
\nbusiness combination is, from the acquisition date, allocated to each of the Group\u2019s cash-generating units (CGUs), or groups of CGUs, that are
\nexpected to bene\ufb01t from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Goodwill
\nis 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
\nrate of exchange at each reporting date.
\nGoodwill, as disclosed in note 10, is not amortised but is reviewed for impairment at least annually by assessing the recoverable amount of
\nthe CGUs to which the goodwill relates. Where the carrying amount of the CGU and related goodwill is higher than the recoverable amount
\nof the CGU, an impairment loss is recognised in the income statement. The recoverable amounts of the CGUs have been determined on a
\nfair value less costs to sell basis. Impairment losses relating to goodwill cannot be reversed in future periods. Goodwill acquired through
\nbusiness combinations has been allocated to two CGUs, being North Sea and International.
\nOil and gas assets
\nIntangibles
\nPre-licence costs
\nPre-licence costs are expensed in the period in which they are incurred.
\nLicence and property acquisition costs
\nLicence and property acquisition costs paid in connection with a right to explore in an existing exploration area are capitalised as exploration
\nand evaluation costs within intangible assets.
\nLicence and property acquisition costs are reviewed at each reporting date to con\ufb01rm that there is no indication that the carrying amount
\nexceeds the recoverable amount. If no future activity is planned or the related licence has been relinquished or has expired, the carrying
\nvalue of the property acquisition costs is written off through the income statement. Upon recognition of proved reserves and internal
\napproval for development, the relevant expenditure is transferred to oil and gas properties within development and production assets.
\nExploration and evaluation costs
\nOnce the legal right to explore has been acquired, costs directly associated with the exploration are capitalised as exploration and evaluation
\n(E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential commercial
\nresources are discovered, the exploration asset is written off.
\nAll such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment at
\nleast annually. This is to con\ufb01rm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the
\ncase, the costs are written off through the income statement.
\nWhen proved reserves of oil or natural gas are identi\ufb01ed and development is sanctioned by management, the relevant capitalised
\nexpenditure is \ufb01rst assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is transferred to
\noil and gas properties within development and production assets. No amortisation is charged during the exploration and evaluation phase.
\nFarm-outs \u2013 in the exploration and evaluation phase
\nThe 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
\nand evaluation farm-out arrangements but re-designates any costs previously capitalised in relation to the whole interest
\nas relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously
\ncapitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.
\nProperty, plant and equipment \u2013 oil and gas assets
\nOil and gas development and production assets are accumulated generally on a \ufb01eld-by-\ufb01eld basis. This represents expenditure on the
\nconstruction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells,
\nincluding E&E expenditures incurred in \ufb01nding commercial reserves transferred from intangible E&E assets, as outlined in the intangible
\nasset policy above, which is capitalised as oil and gas properties within development and production assets.
\n128
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into
\noperation, the initial estimate of the decommissioning obligation and, for qualifying assets, where relevant, borrowing costs. The purchase
\nprice or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
\nAn item of development and production expenditure and any signi\ufb01cant part initially recognised is derecognised upon disposal or when
\nno future economic bene\ufb01ts are expected. Any gain or loss arising on derecognition of the asset (calculated as the difference between
\nthe net disposal proceeds and the carrying amount of the asset) is included in the income statement.
\nExpenditure on major maintenance includes re\ufb01ts, inspections or repairs comprising the cost of replacement assets or parts of assets,
\ninspection costs and overhaul costs. Where an asset, or part of an asset, that was separately depreciated and is now written off is
\nreplaced and it is probable that future economic bene\ufb01ts associated with the item will \ufb02ow to the Group, the expenditure is capitalised.
\nAll other day-to-day repairs and maintenance costs are expensed as incurred.
\nDepreciation, depletion and amortisation (DD&A) of oil and gas assets
\nAll costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is provided
\ngenerally 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
\ncommercial proven and probable reserves of the \ufb01eld, considering future development expenditures necessary to bring those reserves
\ninto production.
\nWhen there is a change in the estimated total recoverable proven and probable reserves of a \ufb01eld, that change is accounted for in the
\ndepreciation charge over the revised remaining proven and probable reserves.
\nAcquisitions, asset purchases and disposals
\nAcquisitions of oil and gas properties are accounted for using the acquisition method when the assets acquired, and liabilities assumed
\nconstitute a business.
\nTransactions involving the purchase of an individual \ufb01eld interest, or a group of \ufb01eld interests, that do not constitute a business, are
\ntreated as asset purchases irrespective of whether the speci\ufb01c transactions involve the transfer of the \ufb01eld interests directly or the
\ntransfer of an incorporated entity. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to
\nthe assets and liabilities purchased on an appropriate basis.
\nProceeds on disposal are applied to the carrying amount of the speci\ufb01c intangible asset or oil and gas property disposed of and any
\nsurplus is recorded as a gain on disposal in the income statement.
\nDecommissioning
\nA provision for decommissioning is recognised in full when the related facilities are installed. The amount recognised is the present value
\nof the estimated future expenditure. A corresponding amount equivalent to the provision is also recognised as part of the cost of the
\nrelated oil and gas property. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the
\npresent value of the estimated expenditure is dealt with from the start of the \ufb01nancial year as an adjustment to the opening provision
\nand the oil and gas property. The unwinding of the discount is included as a \ufb01nance cost.
\nNon-oil and gas assets
\nProperty, plant and equipment \u2013 \ufb01xtures and \ufb01ttings and o\ufb03ce equipment
\nFixtures and \ufb01ttings and of\ufb01ce equipment is stated at cost less accumulated depreciation and impairment. Depreciation is provided for
\non 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
\nlives. The depreciation periods for the principal categories of assets are as follows:
\n\u00bc
Fixtures and \ufb01ttings: Up to 10 years.
\n\u00bc
Of\ufb01ce furniture and equipment: Up to 5 years.
\nIntangible assets
\nIntangible assets, which principally comprise IT software/licences, are carried at cost less any accumulated amortisation. These assets
\nare amortised on a straight-line basis over their useful economic lives of between three and ten years.
\nImpairment of non-current assets (excluding goodwill)
\nIn accordance with IAS 36 Impairment of Assets, impairment tests are carried out on items of property, plant and equipment and
\nintangible assets where there is an indicator of impairment, or an indicator identi\ufb01ed that a prior year impairment may have reversed
\nor decreased. Such indications may be based on events or changes in the market environment, or on internal sources of information.
\nImpairment and reversal indicators
\nProperty, plant and equipment and intangible assets with \ufb01nite useful lives are only tested for impairment when there is an indication
\nthat they may be impaired. This is generally the result of signi\ufb01cant changes to the environment in which the assets are operated or when
\nasset performance is signi\ufb01cantly lower than expected.
\n129
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nThe main impairment indicators used by the Group are described below:
\n\u00bc
External sources of information:
\n\u2013
Signi\ufb01cant changes in the economic, technological, political or market environment in which the entity operates or to which an asset
\nis dedicated.
\n\u2013
Fall in demand.
\n\u2013
Changes in commodity prices and exchange rates.
\n\u00bc
Internal sources of information:
\n\u2013
Evidence of obsolescence or physical damage.
\n\u2013
Signi\ufb01cantly lower than expected production or cost performance.
\n\u2013
Reduction in reserves and resources, including as a result of unsuccessful results of drilling operations.
\n\u2013
Pending expiry of licence or other rights.
\n\u2013
In respect of capitalised exploration and evaluation costs, lack of planned future activity on the prospect or licence.
\n\u2013
For reversals, plausible downside sensitivity scenarios are run to test the robustness of the asset carrying values typically against
\nchanges in production and commodity prices.
\nMeasurement of recoverable amount
\nThe cash-generating unit (CGU) applied for impairment test purposes is generally the \ufb01eld, except that a number of \ufb01eld interests may
\nbe grouped as a single CGU where the cash in\ufb02ows of each \ufb01eld are interdependent. The carrying value of each CGU is compared against
\nthe expected recoverable amount of the asset, which is primarily determined based on the fair value less cost of disposal (FVLCD)
\nmethod, where the fair value is determined from the estimated present value of the future net cash \ufb02ows expected to be derived from
\nproduction of commercial reserves. Standard valuation techniques are used based on the discount rates that re\ufb02ect the speci\ufb01c
\ncharacteristics of the operating entities concerned; discount rates are determined on a post-tax basis and applied to post-tax cash \ufb02ows.
\nAny impairment loss is recorded in the income statement under Impairment of property, plant and equipment. Impairment losses
\nrecorded in relation to property, plant and equipment may be subsequently reversed if the recoverable amount of the assets
\nsubsequently increases above carrying value. The increased carrying amount of an item of property, plant or equipment attributable to a
\nreversal of an impairment loss may not exceed the carrying amount that would have been determined (net of depreciation/amortisation)
\nhad no impairment loss been recognised in prior periods.
\nFinancial instruments
\nFinancial assets
\nFinancial instruments are recognised and measured in accordance with IFRS 9 Financial Instruments.
\nThe Group uses two criteria to determine the classi\ufb01cation of \ufb01nancial assets: the Group\u2019s business model and contractual cash \ufb02ow
\ncharacteristics of the \ufb01nancial assets. Where appropriate the Group identi\ufb01es three categories of \ufb01nancial assets: amortised cost,
\nfair value through pro\ufb01t or loss (FVTPL), and fair value through other comprehensive income (FVOCI).
\nFinancial assets held at amortised cost
\nFinancial assets held at amortised cost are initially measured at fair value except for trade debtors which are initially measured at cost.
\nBoth are subsequently carried at amortised cost using the effective interest rate (EIR) method, less impairment. The EIR amortisation is
\npresented within \ufb01nance income in the income statement.
\nCash and cash equivalents
\nCash and cash equivalents comprise cash at bank and other short-term highly liquid investments that are readily convertible to a known
\namount of cash and are subject to an insigni\ufb01cant risk of changes in value.
\nImpairment of \ufb01nancial assets
\nThe Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through pro\ufb01t or loss.
\nECLs are based on the difference between the contractual cash \ufb02ows due in accordance with the contract and all the cash \ufb02ows that the
\nGroup expects to receive, discounted at an approximation of the original effective interest rate.
\nECLs are recognised in two stages. For credit exposures for which there has not been a signi\ufb01cant increase in credit risk since initial recognition,
\nECLs are provided for credit losses that result from default events that are possible within the next 12 months (a 12-month ECL).
\n130
Default events could include:
\n\u00bc
Payment default, i.e. the failure to pay principal or interest when it falls due for payment.
\n\u00bc
Prospective default, when payment is not yet due, but it is clear that it will not be capable of being paid when it does fall due.
\n\u00bc
Covenant default, when the borrower fails to keep a promise (a covenant) that it has made in the contract.
\nFor those credit exposures for which there has been a signi\ufb01cant increase in credit risk since initial recognition, a loss allowance is
\nrequired for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default (a lifetime ECL).
\nFor trade receivables and contract assets, the Group applies a simpli\ufb01ed approach in calculating ECLs as allowed under IFRS 9.
\nProvision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as
\nadjusted for forward-looking factors speci\ufb01c to the debtors, the economic environment and the Group\u2019s historical credit loss experience.
\nCredit impaired \ufb01nancial assets
\nAt each reporting date, the Group assesses whether \ufb01nancial assets carried at amortised cost and debt \ufb01nancial assets carried at FVOCI
\nare credit impaired. A \ufb01nancial asset is credit impaired when one or more events that have a detrimental impact on the estimated future
\ncash \ufb02ows of the \ufb01nancial asset have occurred.
\nEvidence that a \ufb01nancial asset is credit impaired includes the following observable data:
\n\u00bc
Signi\ufb01cant \ufb01nancial dif\ufb01culty of the borrower or issuer.
\n\u00bc
A breach of contract such as default or past due event.
\n\u00bc
The restructuring of a loan or advance by the Group on terms that the Group would otherwise not consider.
\n\u00bc
It is becoming probable that the borrower will enter bankruptcy or other \ufb01nancial reorganisation.
\n\u00bc
The disappearance of an active market for a security because of \ufb01nancial dif\ufb01culties.
\nFinancial liabilities
\nFinancial liabilities are classi\ufb01ed, at initial recognition, as \ufb01nancial liabilities at fair value through pro\ufb01t or loss, loans and borrowings,
\npayables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. All \ufb01nancial liabilities are recognised
\ninitially at fair value and, in the case of loans, borrowings and payables, net of directly attributable transaction costs.
\nBorrowings and loans
\nInterest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including
\npremiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement
\nusing the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the
\nyear in which they arise.
\n Derecognition
\nA \ufb01nancial liability is derecognised when the obligation under the liability is discharged, cancelled, or expires. When an existing \ufb01nancial
\nliability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially
\nmodi\ufb01ed, such an exchange or modi\ufb01cation is treated as the derecognition of the original liability and the recognition of a new liability.
\nThe difference in the respective carrying amounts is recognised in the income statement.
\nDerivative \ufb01nancial instruments
\nThe Group uses derivative \ufb01nancial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and
\ncommodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative
\n\ufb01nancial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative \ufb01nancial instruments are
\ndesignated as cash \ufb02ow hedges in line with the Group\u2019s risk management policies. When derivatives do not qualify for hedge accounting
\nor are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.
\nCash \ufb02ow hedges
\nThe effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
\nhedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
\ntransaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
\nrecognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
\nAny gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
\nineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
\ncredit-worthiness of the counterparty is signi\ufb01cant and may dominate the transaction and lead to losses.
\n131
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nFair values
\nFair 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
\nmarket participants at the measurement date. It is determined by reference to quoted market prices adjusted for estimated transaction
\ncosts that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models
\nand estimated discounted values of cash \ufb02ows.
\nFor \ufb01nancial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques.
\nUnder IFRS 9, embedded derivatives are not separated from a host \ufb01nancial asset, and are classi\ufb01ed based on their contractual terms
\nand the Group\u2019s business model.
\nEquity
\nShare capital
\nShare capital includes the total net proceeds, both nominal and share premium, on the issue of ordinary and preference shares
\nof the company.
\nCapital redemption reserve
\nThe capital redemption reserve represents the nominal value of shares transferred following the company\u2019s purchase of them.
\nMerger reserve
\nOn 31 March 2021, Harbour Energy plc (formerly Premier Oil plc) acquired Chrysaor Holdings Limited as part of a reverse acquisition.
\nUnder the terms of the merger, Premier legally acquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the
\nacquirer for accounting purposes, primarily as a result of its ability to appoint the Board of the enlarged group. The merger reserve
\nprimarily represents Premier\u2019s opening balance on the legal reserve plus the fair value of the assets and liabilities acquired by Chrysaor.
\nCash \ufb02ow hedge reserve
\nThe cash \ufb02ow hedge and cost of hedging reserves represent gains and losses on derivatives classi\ufb01ed as effective cash \ufb02ow hedges.
\nUpon the designation of option instruments as hedging instruments, the intrinsic and time value components are separated, with only
\nthe intrinsic component being designated as the hedging instrument and the time value component is deferred in other comprehensive
\nincome as a cost of hedging.
\nCurrency translation reserve
\nThis reserve comprises exchange differences arising on consolidation of the Group\u2019s operations with a functional currency other than
\nthe US dollar.
\nShare-based payments
\nThe Group has applied the requirements of IFRS 2 Share-Based Payment. The Group has share-based awards that are equity and cash
\nsettled 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
\nfor the effect of any market-based conditions. The fair value determined at the grant date of the equity-settled share-based payments is
\nexpensed on a straight-line basis over the vesting period, based on the Group\u2019s estimate of shares that will eventually vest and adjusted
\nfor the effect of non-market based vesting conditions. For cash-settled awards, a liability is recognised for the goods or service acquired.
\nThis is measured initially at the fair value of the liability. The fair value of the liability is subsequently remeasured at each balance sheet
\ndate until the liability is settled, and at the date of settlement, with any changes in fair value recognised in the income statement.
\nInventories
\nAll inventories, except for petroleum products, are stated at the lower of cost and net realisable value. The cost of materials is the
\npurchase cost, determined on a \ufb01rst-in, \ufb01rst-out basis. Petroleum products and underlift and overlift positions are measured at net
\nrealisable value using an observable year-end oil or gas market price, and are included in other debtors or creditors, respectively.
\nLeases
\nLeases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use
\nby the Group. The \ufb01nance cost is charged to the income statement over the lease period so as to produce a constant periodic rate of
\ninterest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of lease term
\nand useful life. The Group recognises right-of-use assets and lease liabilities on a gross basis and the recovery of lease costs from
\njoint operations\u2019 partners is recorded as other income.
\n132
Right-of-use assets and lease liabilities arising from a lease are initially measured on a present value basis re\ufb02ecting the net present
\nvalue of the \ufb01xed lease payments and amounts expected to be payable by the Group assuming leases run to full term. The Group has
\napplied judgement to determine the lease term for some lease contracts in which it is a lessee that include renewal options. The
\nassessment of whether the Group is reasonably certain to exercise such options impacts the lease term, which signi\ufb01cantly impacts
\nthe amount of lease liabilities and right-of-use assets recognised.
\nThe lease payments are discounted using the Group\u2019s incremental borrowing rates of between 1.9 per cent and 6.8 per cent, being
\nthe rate that the Group would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic
\nenvironment with similar terms and conditions.
\nTo determine the incremental borrowing rate, the Group where possible:
\n\u00bc
Uses recent third party \ufb01nancing received by the individual lessee as a starting point, adjusted to re\ufb02ect changes in \ufb01nancing conditions
\nsince third party \ufb01nancing was received.
\n\u00bc
Makes adjustments speci\ufb01c to the lease, for example term, country, currency and security.
\nThe Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in
\nthe lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability
\nis reassessed and adjusted against the right-of-use asset.
\nLease payments are allocated between principal and \ufb01nance cost. The \ufb01nance cost is charged to the income statement over the lease
\nperiod so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.
\nRight-of-use assets are measured at cost comprising the following:
\n\u00bc
The amount of the initial measurement of lease liability.
\n\u00bc
Any lease payments made at or before the commencement date less any lease incentives received.
\n\u00bc
Any initial direct costs and restoration costs.
\nRight-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.
\nPayments associated with short-term leases and leases of low value assets are recognised on a straight-line basis as an expense in the
\nincome statement. Short-term leases are leases with a lease term of 12 months or less.
\nFor lease arrangements where all partners of a joint operation are considered to share the primary responsibility for lease payments
\nunder a lease contract, the Group recognises its share of the respective right-of-use asset and lease liability. This situation is most
\ncommon where the parties of a joint operation co-sign the lease contract.
\nThe Group recognises a gross lease liability for leases entered into on behalf of a joint operation where it has primary responsibility
\nfor making the lease payments. In such instances, if the arrangement between the Group and the joint operation represents a \ufb01nance
\nsublease, the Group recognises a net investment in sublease for amounts recoverable from non-operators whilst derecognising the
\nrespective portion of the gross right-of-use asset. The gross lease liability is retained on the balance sheet.
\nThe net investment in sublease is classi\ufb01ed as either trade and other receivables or long-term receivables on the balance sheet
\naccording to whether or not the amounts will be recovered within 12 months of the balance sheet date. Finance income is recognised
\nin respect of net investment in subleases.
\nProvisions for liabilities
\nA 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
\nembodying economic bene\ufb01ts will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
\nThe expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money
\nis material, provisions are discounted using a current pre-tax rate that re\ufb02ects, where appropriate, the risk speci\ufb01c to the liability. Where
\ndiscounting is used, the increase in the provision due to the passage of time is recognised as part of \ufb01nance costs in the income statement.
\nThe estimated cost of dismantling and restoring the production and related facilities at the end of the economic life of each \ufb01eld is
\nrecognised in full when the related facilities are installed. The amount provided is the present value of the estimated future restoration
\ncost. A non-current asset is also recognised. Any changes to estimated costs or discount rates are dealt with prospectively.
\nThe Group recognises provision for the estimated CO
\n2
\nemissions costs when actual emissions exceed the emission rights granted and
\nstill held. When actual emissions exceed the amount of emission rights granted, provision is recognised for the exceeding emission rights
\nbased on the purchase price of allowance concluded in forward contracts or market quotations at the reporting date.
\n133
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nGroup retirement bene\ufb01ts
\nPayments to de\ufb01ned contribution retirement bene\ufb01t plans are charged as an expense as they fall due. Payments made to state-managed
\nretirement bene\ufb01t schemes are dealt with as payments to de\ufb01ned contribution plans where the Group\u2019s obligations under the schemes
\nare equivalent to those arising in a de\ufb01ned contribution retirement bene\ufb01t plan.
\nThe Group operates a de\ufb01ned bene\ufb01t pension scheme, which requires contributions to be made to a separately administered fund.
\nThe cost of providing bene\ufb01ts is determined using the projected unit credit method, with actuarial valuations being carried out at each
\nbalance sheet date. Actuarial gains and losses are recognised immediately in the statement of comprehensive income.
\nThe retirement bene\ufb01t obligation recognised in the balance sheet represents the present value of the de\ufb01ned bene\ufb01t obligation as
\nreduced by the fair value of plan assets. Any asset resulting from this calculation is limited to the present value of available refunds
\nand reductions in future contributions to the plan.
\nTrade payables
\nInitial recognition of trade payables is at fair value. Subsequently they are stated at amortised cost.
\nTaxes
\nCurrent tax
\nCurrent tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to
\nthe taxation authorities. The tax rates and laws used to compute the amount are those that are enacted or substantively enacted at the
\nreporting date in the countries where the Group operates and generates taxable income.
\nCurrent income tax related to items recognised directly in other comprehensive income or equity is recognised in other comprehensive
\nincome or directly in equity, not in the income statement.
\nDeferred tax
\nDeferred taxation is recognised in respect of all timing differences arising between the tax bases of the assets and liabilities and their
\ncarrying amounts in the \ufb01nancial statements with the following exceptions:
\n\u00bc
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
\ndeductible temporary difference, carried forward tax credits or tax losses can be utilised.
\n\u00bc
Deferred income tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply when
\nthe related asset is realised or liability is settled, based on tax rates and laws enacted or substantively enacted at the reporting date.
\nThe carrying amount of the deferred income tax asset is reviewed at each balance sheet date and reduced to the extent that it is no
\nlonger probable that suf\ufb01cient taxable pro\ufb01ts will be available to allow all or part of the asset to be recovered. The Group reassesses
\nany unrecognised deferred tax assets each year taking into account changes in oil and gas prices, the Group\u2019s proven and probable
\nreserves and resources pro\ufb01le and forecast capital and operating expenditures.
\n\u00bc
Deferred income tax assets and liabilities are offset only if a legally enforceable right exists to offset current assets against current tax liabilities,
\nthe deferred income tax relates to the same tax authority and that same tax authority permits the Group to make a single net payment.
\nDeferred tax is charged or credited in the income statement, except when it relates to items charged or credited in other comprehensive
\nincome, in which case the deferred tax is also dealt with in other comprehensive income.
\nRevenue from contracts with customers
\nRevenue from contracts with customers is recognised when the Group satis\ufb01es a performance obligation by transferring a good or
\nservice to a customer. A good or service is transferred when the customer obtains control of that good or service. Revenue associated
\nwith the sale of crude oil, natural gas, and natural gas liquids (NGLs) is measured based on the consideration speci\ufb01ed in contracts with
\ncustomers with reference to quoted market prices in active markets, adjusted according to speci\ufb01c terms and conditions as applicable
\naccording to the sales contracts. The transfer of control of oil, natural gas, natural gas liquids and other items sold by the Group occurs
\nwhen title passes at the point the customer takes physical delivery. The Group principally satis\ufb01es its performance obligations at a point
\nin time and the amounts of revenue recognised relating to performance obligations satis\ufb01ed over time are not signi\ufb01cant.
\n134
Over/underlift
\nDifferences between the production sold and the Group\u2019s share of production result in an overlift or an underlift. Overlift and underlift
\nare valued at net realisable value using an observable year-end oil or gas market price and included within payables or receivables,
\nrespectively. Movements during the accounting period are recognised within cost of sales.
\nInterest income
\nInterest income is recognised on an accruals basis, by reference to the principal outstanding and at the effective interest rate applicable.
\nBorrowing costs
\nBorrowing costs directly attributable to the acquisition, construction or production of an asset that necessarily takes a substantial period
\nof 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
\nthe funds used to \ufb01nance a project form part of general borrowings, the amount capitalised is calculated using a weighted average of
\nrates applicable to relevant general borrowings of the Group during the period. All other borrowing costs are recognised in the income
\nstatement in the period in which they are incurred.
\nNew accounting standards and interpretations
\nThe Group adopted new and revised accounting standards and interpretations relevant to its business and effective for accounting
\nperiods beginning on or after 1 January 2022, including:
\nAmendments to IFRS 3 \u2013 Reference to the Conceptual Framework
\nThe IASB issued amendments to IFRS 3 to update the reference to the 2018 Conceptual Framework. The amendments add an exception
\nto the recognition principle for liabilities and contingent liabilities within the scope of IAS 37 or IFRIC 21 and clarify existing guidance for
\ncontingent assets. The requirements are effective for annual reporting periods beginning on or after 1 January 2022 and apply prospectively.
\nIFRS 9 Financial Instruments \u2013 Fees in the 10 per cent test for derecognition of \ufb01nancial liabilities
\nAs part of its 2018-2020 annual improvements to IFRS standards process, the IASB issued an amendment to IFRS 9. The amendment
\nclari\ufb01es the fees that an entity includes when assessing whether the terms of a new or modi\ufb01ed \ufb01nancial liability are substantially different
\nfrom the terms of the original \ufb01nancial liability. These fees include only those paid or received between the borrower and the lender, including
\nfees paid or received by either the borrower or lender on the other\u2019s behalf. An entity applies the amendment to \ufb01nancial liabilities that are
\nmodi\ufb01ed or exchanged on or after the beginning of the annual reporting period in which the entity \ufb01rst applies the amendment.
\nThe amendment is effective for annual reporting periods beginning on or after 1 January 2022 with earlier adoption permitted. The
\nGroup has applied the amendments to \ufb01nancial liabilities that are modi\ufb01ed or exchanged on or after the beginning of the annual reporting
\nperiod in which the entity \ufb01rst applies the amendment.
\nAccounting standards issued but not yet effective
\nThe new and amended standards and interpretations that are issued, but not yet effective, up to the date of issuance of the Group\u2019s
\n\ufb01nancial statements are disclosed below. The Group intends to adopt these new and amended standards and interpretations, if
\napplicable, when they become effective.
\nAmendments to IAS 1, Presentation of Financial Statements \u2013 classi\ufb01cation of liabilities as current or non-current
\nOn 23 January 2020, the IASB issued a narrow-scope amendment to IAS 1 to clarify that liabilities are classi\ufb01ed as either current or
\nnon-current depending on the rights that exist at the end of the reporting period. Liabilities are classi\ufb01ed as non-current if the entity
\nhas a substantive right to defer settlement for at least 12 months at the end of the reporting period. The Group does not consider this
\namendment to have signi\ufb01cant impact on the classi\ufb01cation of its liabilities as either current or non-current when the standard becomes
\neffective on 1 January 2023.
\nAmendments to IAS 8 \u2013 De\ufb01nition of Accounting Estimates
\nIn February 2021, the International Accounting Standards Board issued De\ufb01nition of Accounting Estimates, which amended IAS 8
\nAccounting Policies, Changes in Accounting Estimates and Errors.
\nThe amendments introduced the de\ufb01nition of accounting estimates and included other amendments to IAS 8 to help entities distinguish
\nchanges in accounting estimates from changes in accounting policies, with the distinction important because changes in accounting
\nestimates are applied prospectively only to future transactions and other future events, but changes in accounting policies are generally
\nalso applied retrospectively to past transactions and other past events. The amendments are effective for annual periods beginning on
\nor after 1 January 2023.
\n135
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nAmendments to IAS 1 and IFRS Practice Statement 2 \u2013 Disclosure of Accounting Policies
\nIn February 2021, the International Accounting Standards Board issued amendments to IAS 1 Presentation of Financial Statements
\nand IFRS Practice Statement 2 Making Materiality Judgements. The amendments to IAS 1 require companies to disclose their material
\naccounting policy information rather than their signi\ufb01cant accounting policies. The amendments to IFRS Practice Statement 2 provides
\nguidance on how to apply the concept of materiality to accounting policy disclosures. The amendments are effective for annual periods
\nbeginning on or after 1 January 2023.
\nAmendments to IAS 12 \u2013 Deferred Tax related to Assets and Liabilities arising from a Single Transaction
\nOn 7 May 2021, the IASB issued amendments to IAS 12 Income Taxes. The amendments require companies to recognise deferred tax
\non transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences. According to the
\namended guidance, a temporary difference that arises on initial recognition of an asset or liability is not subject to the initial recognition
\nexemption if that transaction gave rise to equal amounts of taxable and deductible temporary differences. The proposed amendments
\nwill typically apply to transactions such as leases for the lessee and decommissioning obligations. The amendments are effective for
\nannual reporting periods beginning on or after 1 January 2023.
\nThe amendments listed above are not expected to have a material impact on the Group.
\nSigni\ufb01cant accounting judgements and estimates
\nThe preparation of the Group\u2019s \ufb01nancial statements in conformity with IFRS requires management to make judgements, estimates
\nand assumptions at the date of the \ufb01nancial statements. Estimates and assumptions are continuously evaluated and are based on
\nmanagement experience and other factors, including expectations of future events that are believed to be reasonable under the
\ncircumstances. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to
\nthe carrying amount of the assets or liabilities affected in future periods. In particular, the Group has identi\ufb01ed the following areas
\nwhere signi\ufb01cant judgement, estimates and assumptions are required.
\nJudgements
\nThe signi\ufb01cant accounting judgements for the Group are considered to be:
\n\u00bc
the application of the going concern basis of accounting (see Basis of preparation section above);
\n\u00bc
the carrying value of intangible exploration and evaluation assets, in relation to whether commercial determination of an exploration
\nprospect had been reached;
\n\u00bc
the carrying value of property, plant and equipment regarding assessing assets for indicators of impairment;
\n\u00bc
decommissioning costs in relation to the timing of when decommissioning would occur; and
\n\u00bc
tax and recognition of deferred tax assets, relating to the extent to which future taxable pro\ufb01ts are included in the assessment
\nof recoverability, including the Energy Pro\ufb01ts Levy (EPL).
\nKey sources of estimation uncertainty
\nDetails of the Group\u2019s critical accounting estimates are set out in these \ufb01nancial statements and are considered to be:
\n\u00bc
the carrying value of property, plant and equipment and goodwill, where the key assumptions relate to oil and gas prices expected to be
\nrealised, and 2P production pro\ufb01les;
\n\u00bc
decommissioning costs where the key assumptions relate to the discount and in\ufb02ation rates applied, applicable rig rates and expected
\ntiming of cessation of production (COP) on each \ufb01eld; and
\n\u00bc
tax and recognition of deferred tax assets, where key assumptions relate to oil and gas prices expected to be realised, and production pro\ufb01les.
\nThe results from downside sensitivities prepared with regard to production and commodity price assumptions, which in management\u2019s
\nview re\ufb02ect the principal risks, indicate that material changes that would impact the carrying amounts of assets and liabilities within the
\nnext \ufb01nancial year are unlikely.
\nFurther information is provided in the Audit and Risk Committee report on pages 68 to 71.
\n136
3. Segment information
\nThe chief operating decision maker, who is responsible for allocating resources and assessing performance of the Group\u2019s business
\nsegments, has been identi\ufb01ed as the Chief Executive Of\ufb01cer.
\nThe Group\u2019s activities consist of one class of business being the acquisition, exploration, development and production of oil and gas reserves
\nand related activities, and are split geographically and managed in two regions, namely North Sea and International. The North Sea segment
\nincludes the UK and Norwegian continental shelves, and the International segment includes Indonesia, Vietnam and Mexico.
\nInformation on major customers can be found in note 4.
\nIncome statement
\n2022
\n$ million
\n2021
\n$ million
\nRevenue
\nNorth Sea
5,082.1
3,268.2
\nInternational
307.9
210.6
\nTotal Group sales revenue
5,390.0
3,478.8
\nOther income
\nNorth Sea
40.9
139.0
\nInternational
0.3
0.2
\nTotal Group revenue and other income
5,431.2
3,618.0
\nOperating pro\ufb01t
\nNorth Sea
2,388.4
699.3
\nInternational
152.5
(59.0)
\nGroup operating pro\ufb01t
2,540.9
640.3
\nFinance income
279.1
48.8
\nFinance expenses
(358.2)
(374.6)
\nPro\ufb01t before income tax
2,461.8
314.5
\nIncome tax expense
(2,453.6)
(213.4)
\nPro\ufb01t for the \ufb01nancial year
8.2
101.1
\nBalance sheet
\n2022
\n$ million
\n2021
\n$ million
\nSegment assets
\nNorth Sea
11,346.2
13,325.8
\nInternational
1,219.6
1,178.8
\nTotal assets
12,565.8
14,504.6
\nSegment liabilities
\nNorth Sea
(10,937.3)
(13,379.6)
\nInternational
(607.2)
(651.5)
\nTotal liabilities
(11,544.5)
(14,031.1)
\n137
Notes to the consolidated \ufb01nancial statements
continued
\n3. Segment information
continued
\nOther information
\n2022
\n$ million
\n2021
\n$ million
\nCapital additions
\nNorth Sea
576.2
640.7
\nInternational
108.6
68.4
\nTotal capital additions
684.8
709.1
\nDepreciation, depletion and amortisation
\nNorth Sea
1,470.4
1,299.8
\nInternational
75.4
71.2
\nTotal depreciation, depletion and amortisation
1,545.8
1,371.0
\nExploration and evaluation expenses and new ventures
\nNorth Sea
33.5
45.4
\nInternational
8.0
4.4
\nTotal exploration and evaluation expenses and new ventures
41.5
49.8
\nExploration costs written-o\ufb00
\nNorth Sea
71.6
121.1
\nInternational
(7.2)
133.9
\nTotal exploration costs written-o\ufb00
64.4
255.0
\nExploration costs written-off of $64.4 million is net of a $5.7 million credit related to a decrease in the decommissioning provisions in the North
\nSea (note 20) and includes a $7.0 million credit related to a change to the decommissioning estimate in the Falkland Islands business unit
\n(2021: $6.3 million relating to the effect of changes in decommissioning provisions on oil and gas intangible assets previously written-off).
\n4. Revenue from contracts with customers and other income
\n2022
\n$ million
\n2021
\n$ million
\nType of goods
\nCrude oil sales
2,791.9
2,023.4
\nGas sales
2,321.5
1,264.0
\nCondensate sales
238.3
163.6
\nTotal revenue from contracts with customers
\n1
\n5,351.7
3,451.0
\nTariff income
30.0
27.2
\nOther revenue
8.3
0.6
\nTotal revenue from production activities
5,390.0
3,478.8
\nOther income
\n2
\n41.2
139.2
\nTotal revenue and other income
5,431.2
3,618.0
\n1
Revenues from contracts with customers of $8,536.5 million (2021: $4,968.2 million) include crude oil sales of $3,544.7 million (2021: $2,278.1 million) and gas sales of $4,753.5 million
\n(2021: $2,526.5 million). This was prior to realised hedging losses in the period of $752.8 million (2021: $254.7 million) on crude oil and $2,432.0 million (2021: $1,262.5 million) on gas sales.
\n2
Other income mainly represents $20.3 million partner recoveries related to lease obligations (2021: $26.0 million), mark to market losses on EUA emissions hedges of $2.6 million
\n(2021: gain of $51.0 million) and $16.7 million in respect of research and development expenditure credits (RDEC) (2021: $17.5 million). Other income in 2021 included a receipt from
\nConocoPhillips in relation to an adjustment to consideration relating to Chrysaor\u2019s purchase of the ConocoPhillips UK business in 2019 (2021: $40.0 million).
\nApproximately 84 per cent (2021: 84 per cent) of the revenues were attributable to sales to energy trading companies of the Shell group.
\n138
5. Operating pro\ufb01t
\nNote
\n2022
\n$ million
\n2021
\n$ million
\nCost of operations
\nProduction, insurance and transportation costs
1,114.2
1,085.5
\nGas purchases
36.6
28.4
\nRoyalties
5.0
3.8
\nDepreciation of oil and gas assets
12
1,318.4
1,204.1
\nDepreciation of right-of-use oil and gas assets
13
218.6
153.9
\nCapitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(29.9)
(30.7)
\nOther cost of operations
\u2013
(0.5)
\nOnerous contract provision
20
\u2013
(2.3)
\nAmortisation of capacity rights
11
1.0
1.6
\nRemeasurement of royalty valuation
\u2013
(0.5)
\nRemeasurement \u2013 loss on termination of lease
\u2013
0.3
\nMovement in over/underlift balances and hydrocarbon inventories
180.9
9.6
\nTotal cost of operations
2,844.8
2,453.2
\nImpairment (reversal)/expense of property, plant and equipment
12
(87.3)
108.7
\nImpairment (gain)/loss due to (decrease)/increase in decommissioning
\nprovisions on oil and gas tangible assets
20
(82.3)
8.5
\nExploration costs written-off
\n1
\n11
64.4
255.0
\nExploration and evaluation expenditure and new ventures
\n2
\n41.5
49.8
\n(Gain)/loss on disposal
\n3
\n(12.1)
0.1
\nGeneral and administrative expenses
\nDepreciation of right-of-use non-oil and gas assets
13
11.2
10.5
\nDepreciation of non-oil and gas assets
12
5.4
5.5
\nAmortisation of non-oil and gas intangible assets
11
21.1
26.1
\nOther administrative costs
83.6
60.4
\nTotal general and administrative expenses
\n4
\n121.3
102.5
\nAuditor\u2019s remuneration
\nAudit fees
\nFees payable to the company\u2019s auditor for the company\u2019s Annual Report
2.6
2.3
\nAudit of the company\u2019s subsidiaries pursuant to legislation
0.6
0.5
\nNon-audit fees
\n5
\nOther services pursuant to legislation \u2013 interim review
0.2
0.3
\nOther services
\n6
\n0.8
0.4
\n1
Exploration costs written-off of $64.4 million includes a credit of $7.0 million related to a change to the decommissioning estimate in the Falkland Islands business unit.
\n2
Exploration and evaluation expenditure and new ventures of $41.5 million (2021: $49.8 million) includes $28.4 million (2021: $14.4 million) of early project costs on new ventures
\nincurred in respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $13.1 million (2021 $35.4 million) of ongoing pre-licence costs.
\n3
The gain on disposal of $12.1 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the period
\nfor tax claims to be submitted.
\n4
Expenses related to both short-term and low value lease arrangements are considered to be immaterial for reporting purposes.
\n5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the Group\u2019s website.
\nThe use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
\ncon\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
\n6
Other services in 2022 primarily relate to reporting accountant services provided by EY. In 2021 this also included services in respect of the merger and other corporate transactions.
\nThe Audit and Risk Committee concluded that shareholder value was best served by appointing our auditors for this work.
\n139
Notes to the consolidated \ufb01nancial statements
continued
\n6. Staff costs
\n2022
\n$ million
\n2021
\n$ million
\nWages and salaries and other staff costs
306.1
261.0
\nSocial security costs
30.1
27.9
\nPension costs
30.3
28.2
\nTotal sta\ufb00 costs
366.5
317.1
\nAverage annual number of employees employed by the Group worldwide was:
\n2022
\nNumber
\n2021
\nNumber
\nOffshore based
559
589
\nOf\ufb01ce and administration
1,273
1,218
\nTotal sta\ufb00
1,832
1,807
\nStaff costs above are recharged to joint venture partners where applicable, or are capitalised to the extent that they are directly attributable
\nto capital or decommissioning projects. The above costs include share-based payments as disclosed in note 25.
\nAll employees were engaged in the acquisition, exploration, development and production of oil and gas reserves, and energy transition activities.
\nThe Group operates two de\ufb01ned contribution schemes and one de\ufb01ned bene\ufb01t pension scheme for which further details are provided in note 26.
\n7. Finance income and \ufb01nance expenses
\nNote
\n2022
\n$ million
\n2021
\n$ million
\nFinance income
\nBank interest
10.2
0.9
\nOther interest and \ufb01nance gains
\n1
\n20.0
3.2
\nIFRS 9 modi\ufb01cation impact
\u2013
13.9
\nLease \ufb01nance income
1.7
3.2
\nFinance income on deferred revenue
19
\u2013
1.2
\nRealised gains on interest rate swaps
6.5
\u2013
\nRealised gains on foreign exchange forward contracts
0.5
10.0
\nGains on derivatives
\n2
\n38.2
14.5
\nForeign exchange gains
\n3
\n202.0
1.9
\nTotal \ufb01nance income
279.1
48.8
\nFinance expenses
\nInterest payable on reserves-based lending
71.1
101.6
\nInterest payable on bond
27.3
5.7
\nInterest payable on loan notes
\u2013
5.6
\nOther interest and \ufb01nance expenses
\n4
\n11.7
16.6
\nLease interest
13
25.1
22.3
\nRealised losses on interest rate swaps
\u2013
2.4
\nLosses on derivatives
\n5
\n48.0
14.6
\nFinance expense on deferred revenue
19
19.9
\u2013
\nForeign exchange losses
\u2013
65.2
\nBank and \ufb01nancing fees
\n6
\n91.0
63.4
\nUnwinding of discount on decommissioning and other provisions
20
65.1
78.0
\n359.2
375.4
\nFinance costs capitalised during the year
\n7
\n(1.0)
(0.8)
\nTotal \ufb01nance expense
358.2
374.6
\n1
Other interest and \ufb01nance gains includes $16.0 million (2021: $1.9 million) related to an update to the amount recognised under the decommissioning liability agreement as detailed in note 16.
\n2
Gains on derivatives mainly relates to mark to market gains on interest rate and foreign currency derivatives.
\n3
Signi\ufb01cant unrealised foreign exchange gains consist mainly of unrealised gains arising from revaluation of open gas hedges denominated in pound sterling.
\n4
Other interest includes a $9.5 million charge (2021: $11.6 million) which represents interest under a \ufb01nancing arrangement (note 21).
\n5
Losses on derivatives relate to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2021: $14.6 million).
\n6
Bank and \ufb01nancing fees include an amount of $54.9 million (2021: $38.9 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s
\nlong-term borrowings (note 21).
\n7
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 4.4 per cent to the
\nexpenditures on the qualifying assets (2021: 3.7 per cent).
\n140
8. Income tax
\nThe major components of income tax expense for the years ended 31 December 2022 and 2021 are:
\n2022
\n$ million
\n2021
\n$ million
\nCurrent income tax expense
\nUK corporation tax
671.7
202.2
\nOverseas tax
53.5
(5.2)
\nAdjustments in respect of prior years
(19.4)
(4.9)
\nTotal current income tax expense
705.8
192.1
\nDeferred tax expense
\nUK corporation tax
302.1
7.7
\nUK Energy Pro\ufb01ts Levy
1,469.5
\u2013
\nOverseas tax
(7.5)
(10.3)
\nAdjustments in respect of prior years
(16.3)
23.9
\nTotal deferred tax expense
1,747.8
21.3
\nTotal tax expense reported in the income statement
2,453.6
213.4
\nThe tax credit in the statement of comprehensive income is as follows:
\nTax credit on cash \ufb02ow hedges
(1,005.6)
(1,433.2)
\nReconciliation of tax expense and the accounting pro\ufb01t before taxation multiplied by the statutory rate of corporation tax and supplementary
\ncharge applying to UK oil and gas production operations for the years ended 31 December 2022 and 2021 is as follows:
\n2022
\n$ million
\n2021
\n$ million
\nPro\ufb01t before income tax
2,461.8
314.5
\nAt the Group\u2019s statutory income tax rate of 55.0% (2021: 40.0%)
1,354.0
125.8
\nEffects of:
\n\u2013 Expenses/(income) not deductible/(taxable) for tax purposes
(11.7)
56.8
\n\u2013 Interest not deductible for supplementary charge and Energy Pro\ufb01ts Levy
53.1
13.1
\n\u2013 Adjustments in respect of prior years
(35.8)
19.0
\n\u2013 Movement in unrecognised deferred tax assets
(72.2)
27.4
\n\u2013 Deferred Energy Pro\ufb01ts Levy
1,469.2
\u2013
\n\u2013 Impact of different tax rates
(190.3)
4.0
\n\u2013 Expenses not deductible for Energy Pro\ufb01ts Levy
8.0
\u2013
\n\u2013 Energy Pro\ufb01ts Levy investment allowance
(81.4)
\u2013
\n\u2013 Investment allowance
(39.3)
(32.7)
\nTotal tax expense reported in the consolidated income statement at the e\ufb00ective tax rate of 100% (2021: 68%)
2,453.6
213.4
\nThe effective tax rate for the year was 100 per cent, compared to 68 per cent for 2021.
\nThe tax expense/(credit) reconciliation has been prepared based on the statutory rate of taxation applying to UK oil and gas production
\nbecause 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
\ncent (2021: 30 per cent), a supplementary charge of 10 per cent (2021: 10 per cent), and with effect from 26 May 2022, the Energy
\nPro\ufb01ts Levy (EPL) of 25 per cent to give an overall tax rate of 65 per cent (2021: 40 per cent). As the EPL was introduced part way
\nthrough the \ufb01nancial year a blended average rate of 55 per cent has been applied.
\nThe 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
\nproduction operations is expected to remain a primary in\ufb02uence on the effective tax rate. The EPL will increase to a rate of 35 per cent
\nfrom 25 per cent with effect from 1 January 2023 and consequently the headline rate will increase next year to 75 per cent. The Energy
\nPro\ufb01ts Levy at the 35 per cent rate will be in place until 31 March 2028.
\n141
Notes to the consolidated \ufb01nancial statements
continued
\n8. Income tax
continued
\nDeferred tax
\nThe principal components of deferred tax are set out in the following tables:
\n2022
\n$ million
\n2021
\n$ million
\nDeferred tax assets
1,406.5
1,938.4
\nDeferred tax liabilities
(397.2)
(187.1)
\nTotal deferred tax
1,009.3
1,751.3
\nThe origination of and reversal of temporary differences are, as shown in the next table, related primarily to movements in the carrying amounts
\nand tax base values of expenditure and the timing of when these items are charged and/or credited against accounting and taxable pro\ufb01t.
\nNote
\nAccelerated
\ncapital
\nallowances
\n$ million
\nDecommissioning
\n$ million
\nLosses
\n$ million
\nFair value of
\nderivatives
\n$ million
\nOther
\n$ million
\nOverseas
\n$ million
\nTotal
\n$ million
\nAs at 1 January 2021
(2,650.5)
1,640.7
\u2013
(57.1)
51.5
(16.0)
(1,031.4)
\nDeferred tax expense
385.9
(178.2)
(216.1)
3.6
(26.8)
10.3
(21.3)
\nComprehensive income
\u2013
\u2013
\u2013
1,433.2
\u2013
\u2013
1,433.2
\nForeign exchange
13.5
(13.6)
\u2013
4.0
(1.1)
1.9
4.7
\nAdditions from business
\ncombinations and joint
\narrangements
14
(569.0)
564.0
1,530.6
8.4
15.2
(183.1)
1,366.1
\nAs at 31 December 2021
(2,820.1)
2,012.9
1,314.5
1,392.1
38.8
(186.9)
1,751.3
\nDeferred tax expense
(657.7)
(361.7)
(745.2)
49.0
(39.7)
7.5
(1,747.8)
\nComprehensive income
\u2013
\u2013
\u2013
1,005.6
\u2013
\u2013
1,005.6
\nForeign exchange
82.2
(85.9)
(0.2)
5.0
(1.8)
0.9
0.2
\nAs at 31 December 2022
(3,395.6)
1,565.3
569.1
2,451.7
(2.7)
(178.5)
1,009.3
\nThe Group\u2019s deferred tax assets as at 31 December 2022 are recognised to the extent that taxable pro\ufb01ts are expected to arise against
\nwhich the tax assets can be utilised. The Group assessed the recoverability of its UK ring fenced losses and allowances using corporate
\nassumptions which are consistent with the Group\u2019s impairment assessment. Based on those assumptions, the Group expects to fully
\nutilise its recognised UK tax losses and allowances. The recovery of the Group\u2019s UK decommissioning deferred tax asset is additionally
\nsupported by the ability to carry back decommissioning tax losses and set these against ring fence taxable pro\ufb01ts of prior periods.
\nThe EPL will increase to a rate of 35 per cent from 25 per cent with effect from 1 January 2023. The increase in rate was substantively
\nenacted on 30\u00a0November 2022. The EPL will be in place until 31 March 2028. Any temporary differences subject to the EPL expected to
\nreverse in this period have consequently been remeasured to the higher rate. This has resulted in a one-off deferred tax charge to the
\nincome statement of $1,469.2 million and a one-off deferred tax credit arising on unrealised derivative balances in other comprehensive
\nincome of $1,005.6 million. The net impact on the deferred tax asset at the end of the period as a result of the EPL is a decrease in the
\ndeferred tax asset of $463.7 million.
\nIn line with other sensitivity analysis undertaken, we have assessed the impact on the recoverability of deferred tax assets based on an
\naverage -10 per cent to the Harbour Scenario average crude price curves. The sensitivity analysis indicates that there would no material
\nimpact to the recoverability of deferred tax assets.
\nThe Group has unrecognised UK tax losses and allowances as at 31 December 2022 of approximately $201.7 million (2021: $343.1 million)
\nin respect of ring fence losses, $111.1 million (2021: $104.4 million) in respect of ring fence investment allowance and $807.2 million (2021:
\n$741.5 million) in respect of non-ring fence losses.
\nThe Group also has unrecognised tax losses of approximately $156.9 million (2021: $212.8 million) in respect of its international operations.
\nThese losses include amounts of $30.3 million which will expire, primarily within \ufb01ve years and $13.8 million expiring within 10 years.
\nThe overseas deferred tax relates mainly to temporary differences associated with \ufb01xed asset balances.
\n142
No deferred tax liabilities have been provided on unremitted earnings of overseas subsidiaries, because due to the application of
\nwithholding reliefs under international double taxation treaties and dividend exemptions under UK and Netherlands legislation no
\nadditional taxation is expected to arise on future distribution.
\nLegislation was introduced in UK Finance Act 2021 to increase the main rate of UK corporation tax for non-ring fence pro\ufb01ts from 19 per
\ncent to 25 per cent from 1 April 2023. This change does not have a material impact on the Group as the UK pro\ufb01ts are primarily subject
\nto the UK ring fence tax rate.
\n9. Earnings per share (EPS)
\nBasic EPS is calculated by dividing the pro\ufb01t after tax attributable to ordinary shareholders of the Group by the weighted average number
\nof ordinary shares in issue during the year.
\nDiluted EPS is calculated by dividing the pro\ufb01t after tax attributable to ordinary shareholders by the weighted average number of ordinary
\nshares in issue during the year plus the weighted average number of ordinary shares that would be issued on conversion of all the
\ndilutive potential ordinary shares into ordinary shares.
\nThe following table re\ufb02ects the income and share data used in the basic and diluted EPS calculations:
\n2022
2021
\nEarnings for the year ($ millions)
\nEarnings for the purpose of basic earnings per share
8.2
101.1
\nEffect of dilutive potential ordinary shares
\u2013
\u2013
\nEarnings for the purpose of diluted earnings per share
8.2
101.1
\nNumber of ordinary shares (millions)
\nWeighted average number of ordinary shares for the purpose of basic earnings per share
\n1
\n899.8
871.2
\nDilutive potential ordinary shares
\n2
\n12.3
1.3
\nWeighted average number of ordinary shares for the purpose of diluted earnings per share
912.1
872.5
\nEarnings per share ($ cents)
\nBasic
0.9
11.6
\nDiluted
0.9
11.6
\n1
During the current period 78.4 million ordinary shares were repurchased as part of the share buyback programme.
\n2
Excludes certain share options outstanding at 31 December 2022 as their option price was greater than market price.
\n10. Goodwill
\nGoodwill represents the difference between the aggregate of the fair value of purchase consideration transferred at the acquisition date
\nand the fair value of the identi\ufb01able assets.
\nNote
\n2022
\n$ million
\n2021
\n$ million
\nCost and net book value
\nAt 1 January
1,327.1
990.0
\nAdditions
14
\u2013
339.3
\nCurrency translation adjustment
\u2013
(2.2)
\nAt 31 December
1,327.1
1,327.1
\nThe goodwill balance consists of balances arising from the completion of the all-share merger between Premier Oil plc and Chrysaor Holdings
\nLimited in March 2021, on Chrysaor Holdings Limited\u2019s acquisition of the ConocoPhillips UK business, and of the UK North Sea assets from
\nShell, which completed on 30 September 2019 and 1 November 2017, respectively.
\nGoodwill acquired through business combinations has been allocated to two groups of cash-generating units (CGUs), being the North Sea,
\nof $1,278.1 million (2021: $1,278.1 million), and International, of $49.0 million (2021: $49.0 million), and these are therefore the lowest
\nlevels at which goodwill is reviewed.
\n143
Notes to the consolidated \ufb01nancial statements
continued
\n10. Goodwill
continued
\nImpairment testing of goodwill
\nIn accordance with IAS 36 Impairment of Assets, goodwill is reviewed for impairment at the year-end or more frequently if there are
\nindications that goodwill might be impaired. In assessing whether goodwill has been impaired, the carrying amount of the CGU for
\ngoodwill is compared with its recoverable amount. At the year-end, the Group tested for impairment in accordance with accounting policy
\nand no impairment was identi\ufb01ed (2021: $nil).
\nDetermining recoverable amount
\nThe recoverable amounts of the CGU and \ufb01elds have been determined on a fair value less costs to sell basis. The key assumptions
\nused in determining the fair value are often subjective, such as the future long-term oil and gas price assumption, or the operational
\nperformance of the assets. Discounted cash \ufb02ow models comprising asset-by-asset life of \ufb01eld projections using Level 3 inputs (based
\non the IFRS 13 fair value hierarchy) have been used to determine the recoverable amounts.
\nThe 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
\n2026, and discounted at the Group\u2019s post-tax discount rate of between 8.5 and 11.0 per cent (pre-tax 12.1 per cent \u2013 14.1 per cent)
\n(2021: 8.0 \u2013 10.5 per cent post-tax; pre-tax 11.4 per cent \u2013 12.8 per cent). Risks speci\ufb01c to assets within the CGU are re\ufb02ected within
\nthe cash \ufb02ow forecasts.
\nKey assumptions used in calculations
\nAssumptions involved in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas
\nprices, discount rates and the level and timing of expenditures, all of which are inherently uncertain.
\nCommodity and carbon prices
\nManagement\u2019s commodity price curve assumptions are benchmarked against a range of external forward price curves on a regular
\nbasis. The \ufb01rst three years re\ufb02ect the market forward prices curves transitioning to a long-term price thereafter. The long-term commodity
\nprices used were $65/bbl for crude and 65p/therm for gas, which are in\ufb02ated at 2.5 per cent per annum from 1 January 2026. The
\nlong-term carbon price used was \u00a380/tonne, being $100/tonne at $:\u00a31.25 foreign exchange rate, in\ufb02ated at 2.5 per cent per annum
\nfrom 1 January 2026.
\nProduction volumes
\nBased 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
\ngas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates its reserves using standard recognised
\nevaluation techniques and they are assessed at least annually by management and by an independent consultant. Proven and probable
\nreserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices.
\nCosts
\nOperating expenditure, capital expenditure and decommissioning costs, which have been in\ufb02ated at 2.5 per cent per annum from
\n1 January 2026, are derived from the Group\u2019s business plan.
\nDiscount rates
\nRepresent management\u2019s estimate of the Group\u2019s country-based weighted average cost of capital (WACC), considering both debt and
\nequity. 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
\nits interest-bearing borrowings. Segment-speci\ufb01c risk is incorporated by applying a beta factor based on publicly available market data.
\nThe discount rate is based on an assessment of a relevant peer group\u2019s post-tax WACC.
\nForeign exchange rates
\nBased on management\u2019s long-term rate assumptions, with reference to a range of underlying economic indicators.
\nSensitivity to changes in assumptions used in calculations
\nThe Group has run sensitivities on its long-term commodity price assumptions, which have been based on long-range forecasts from external
\n\ufb01nancial analysts, using alternate long-term price assumptions, and discount rates. These are considered to be reasonably possible changes
\nfor the purposes of sensitivity analysis. No impairment arose on the Group\u2019s goodwill under any of the sensitivity scenarios.
\n144
11. Other intangible assets
\nNote
\nOil and
\ngas assets
\n$ million
\nNon-oil and
\ngas assets
\n3
\n$ million
\nCapacity
\nrights
\n4
\n$ million
\nTotal
\n$ million
\nCost
\nAt 1 January 2021
391.3
94.9
10.3
496.5
\nAdditions during the year
210.0
30.2
\u2013
240.2
\nAdditions from business combinations and joint arrangements
14
596.7
0.4
\u2013
597.1
\nTransfers to property, plant and equipment
(139.5)
\u2013
\u2013
(139.5)
\nIncrease in decommissioning asset
20
10.4
\u2013
\u2013
10.4
\nPrior capitalised costs expensed
\u2013
(4.7)
\u2013
(4.7)
\nUnsuccessful exploration written-off
(255.0)
\u2013
\u2013
(255.0)
\nCurrency translation adjustment
(0.5)
(1.4)
(0.1)
(2.0)
\nAt 31 December 2021
813.4
119.4
10.2
943.0
\nAdditions during the year
111.0
30.7
\u2013
141.7
\nTransfers to property, plant and equipment
(29.0)
\u2013
\u2013
(29.0)
\nDecrease in decommissioning asset
\n1
\n20
(11.8)
\u2013
\u2013
(11.8)
\nUnsuccessful exploration written-off
\n2
\n(64.4)
\u2013
\u2013
(64.4)
\nCurrency translation adjustment
(2.5)
(12.5)
(1.4)
(16.4)
\nAt 31 December 2022
816.7
137.6
8.8
963.1
\nAmortisation
\nAt 1 January 2021
\u2013
34.8
7.6
42.4
\nCharge for the year
\u2013
26.1
1.6
27.7
\nCurrency translation adjustment
\u2013
(0.7)
(0.1)
(0.8)
\nAt 31 December 2021
\u2013
60.2
9.1
69.3
\nCharge for the year
\u2013
21.1
1.0
22.1
\nCurrency translation adjustment
\u2013
(7.0)
(1.3)
(8.3)
\nAt 31 December 2022
\u2013
74.3
8.8
83.1
\nNet book value
\nAt 31 December 2021
813.4
59.2
1.1
873.7
\nAt 31 December 2022
816.7
63.3
\u2013
880.0
\n1
A decrease to decommissioning assets of $11.8 million (2021: increase of $10.4 million) was made during the year as a result of an update to decommissioning estimates (note 20).
\n2
The exploration write-off of $64.4 million (2021: $255.0 million), which relates to costs associated with licence relinquishments and uncommercial well evaluations, is net of a
\n$5.7 million credit related to a decrease in decommissioning provisions in the North Sea (note 20) and a $7.0 million credit related to a change to the decommissioning estimate
\nin the Falkland Islands business unit (2021: $6.3 million relating to the effect of changes in decommissioning provisions on oil and gas intangible assets previously written-off).
\n3
Non-oil and gas assets relate primarily to Group IT software.
\n4
The capacity rights represent National Transmission System (NTS) entry capacity at Bacton and Teesside acquired as part of the business combination completed in 2017. These rights,
\nwhich have been amortised on a contracted volume basis, are now fully amortised.
\n145
Notes to the consolidated \ufb01nancial statements
continued
\n12. Property, plant and equipment
\nNote
\nOil and gas
\nassets
\n$ million
\nFixtures,
\n\ufb01ttings & of\ufb01ce
\nequipment
\n$ million
\nTotal
\n$ million
\nCost
\nAt 1 January 2021
9,996.0
22.8
10,018.8
\nAdditions during the year
464.5
4.4
468.9
\nAdditions from business combinations and joint arrangements
\n1
\n14
1,814.3
4.2
1,818.5
\nTransfers from intangible assets
139.5
\u2013
139.5
\nDisposals
\u2013
(0.3)
(0.3)
\nDecrease in decommissioning asset
20
(357.8)
\u2013
(357.8)
\nCurrency translation adjustment
(34.5)
(0.3)
(34.8)
\nAt 31 December 2021
12,022.0
30.8
12,052.8
\nAdditions
\n2
\n532.4
10.7
543.1
\nTransfers from intangible assets
29.0
\u2013
29.0
\nDecrease in decommissioning asset
\n3
\n20
(778.8)
\u2013
(778.8)
\nCurrency translation adjustment
(369.0)
(3.2)
(372.2)
\nAt 31 December 2022
11,435.6
38.3
11,473.9
\nAccumulated depreciation
\nAt 1 January 2021
3,480.2
16.2
3,496.4
\nCharge for the year
1,204.1
5.5
1,209.6
\nImpairment
117.2
\u2013
117.2
\nDisposals
\u2013
(0.1)
(0.1)
\nCurrency translation adjustment
(16.6)
(0.4)
(17.0)
\nAt 31 December 2021
4,784.9
21.2
4,806.1
\nCharge for the year
1,318.4
5.4
1,323.8
\nNet impairment reversal
(169.6)
\u2013
(169.6)
\nCurrency translation adjustment
(174.4)
(2.2)
(176.6)
\nAt 31 December 2022
5,759.3
24.4
5,783.7
\nNet book value
\nAt 31 December 2021
7,237.1
9.6
7,246.7
\nAt 31 December 2022
5,676.3
13.9
5,690.2
\n1
Further information on additions from business combinations and joint arrangements can be found in note 14.
\n2
Included within property, plant and equipment additions of $543.1 million (2021: $468.9 million) are associated cash \ufb02ows of $476.5 million (2021: $437.4 million) and non-cash \ufb02ow
\nmovements of $66.6 million (2021: ($31.5 million)), represented by a $44.2 million increase in capital accruals (2021: $9.0 million increase) and $22.4 million of capitalised lease
\ndepreciation (2021: $22.5 million).
\n3
A decrease in the decommissioning assets of $778.8 million (2021: $357.8 million) was made during the year as a result of both new obligations and an update to the decommissioning
\nestimates (note 20).
\nDuring the year, the Group recognised a net pre-tax impairment credit of $169.6 million (post-tax $49.8 million) (2021: impairment
\ncharge of $117.2 million; post-tax $70.3 million) comprising a pre-tax impairment reversal of $250.5 million (2021: $nil) and a pre-tax
\nimpairment credit of $82.3 million (2021: $8.5 million charge) in respect of revisions to decommissioning estimates on the Group\u2019s
\nnon-producing assets with no remaining net book value (see note 20). This is net of a pre-tax impairment charge representing a
\nwrite-down of property, plant and equipment assets of $163.2 million (2021: $108.7 million).
\nThe impairment reversal was driven by a higher forward curve and long-term price assumption for gas resulting in reversals of
\n$250.5 million covering two cash-generating groups in the North Sea business unit.
\nThe impairment to property, plant and equipment of $163.2 million arises primarily from a single CGU in the UK North Sea, driven
\nprimarily due to the contracted price realised for crude sales being negatively impacted by the pricing differential between Urals and
\nBrent crude, which is currently subject to dispute with the buyer, and also a revised operating cost pro\ufb01le for the \ufb01eld. Impairments
\non property, plant and equipment are reversible in the future.
\n146
Key assumptions used in calculations
\nAssumptions used in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas
\nprices, discount rates and the level and timing of expenditures, all of which are inherently uncertain.
\nCommodity and carbon prices
\nThe Group uses the fair value less cost of disposal method (FVLCD) to calculate the recoverable amount of the cash-generating
\nunits (CGU) consistent with a level 3 fair value measurement (see note 22). In determining the recoverable value, appropriate discounted-
\ncash-\ufb02ow valuation models were used, incorporating market-based assumptions. Management\u2019s commodity price curve assumptions
\nare benchmarked against a range of external forward price curves on a regular basis. Individual \ufb01eld price differentials are then applied.
\nThe \ufb01rst three years re\ufb02ect the market forward price curves transitioning to a long-term price from 2026, thereafter in\ufb02ated at 2.5 per
\ncent per annum. The long-term commodity prices used were $65 per barrel for crude and 65p per therm for gas.
\nProduction volumes
\nProduction volumes are based on life of \ufb01eld production pro\ufb01les for each asset within the CGU. Proven and probable reserves are
\nestimates of the amount of oil and gas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates its
\nreserves using standard recognised evaluation techniques, assessed at least annually by management. Proven and probable reserves
\nare determined using estimates of oil and gas in place, recovery factors and future commodity prices.
\nCosts
\nOperating expenditure, capital expenditure and decommissioning costs are derived from the Group\u2019s business plan. The discount rate
\nre\ufb02ects management\u2019s estimate of the Group\u2019s Weighted Average Cost of Capital (WACC), see note 10 for further details. Foreign
\nexchange rates are based on management\u2019s long-term rate assumptions, with reference to a range of underlying economic indicators.
\nSensitivity to changes in assumptions used in calculations
\nReductions or increases in the long-term oil and gas prices of 10 per cent are considered to be reasonably possible changes for the
\npurpose of sensitivity analysis. Decreases to the long-term oil and gas prices from 1 January 2026 speci\ufb01ed above would result in a
\nfurther post-tax impairment of $44.9 million. A 10 per cent increase in the long-term oil and gas price deck would reduce the post-tax
\nimpairment charge by $44.9 million. Considering the discount rates, the Group believes a one per cent increase in the post-tax discount
\nrate is considered to be a reasonable possibility for the purpose of sensitivity analysis. A one per cent increase in the post-tax discount
\nrate would lead to a further post-tax impairment of $17.6 million, and a one per cent decrease in the post-tax discount rate would reduce
\nthe post-tax impairment charge by $19.1 million.
\nSensitivity analyses indicate that reductions or increases in the long-term oil and gas prices of 10 per cent or a one per cent increase
\nor decrease in the post-tax discount rate would not have resulted in a different impairment reversal.
\n147
Notes to the consolidated \ufb01nancial statements
continued
\n13. Leases
\nThis note provides information for leases where the Group is a lessee.
\nBalance sheet
\nRight-of-use assets
Note
\nLand and
\nbuildings
\n$ million
\nDrilling rigs
\n$ million
\nFPSO
\n$ million
\nOffshore
\nfacilities
\n$ million
\nEquipment
\n$ million
\nTotal
\n$ million
\nCost
\nAt 1 January 2021
66.0
129.9
\u2013
\u2013
3.2
199.1
\nAdditions during the year
\u2013
29.0
\u2013
\u2013
15.6
44.6
\nAdditions from business combinations
\nand joint arrangements
14
41.1
\u2013
525.6
\u2013
1.2
567.9
\nCost revisions/remeasurements
\u2013
(3.7)
(15.7)
\u2013
(1.3)
(20.7)
\nDisposals
(5.4)
\u2013
\u2013
\u2013
\u2013
(5.4)
\nCurrency translation adjustment
(1.4)
(2.5)
\u2013
\u2013
(0.5)
(4.4)
\nAt 31 December 2021
100.3
152.7
509.9
\u2013
18.2
781.1
\nAdditions during the year
\n1
\n\u2013
\u2013
\u2013
338.0
\u2013
338.0
\nCost revisions/remeasurements
3.3
33.6
52.7
(3.8)
3.4
89.2
\nDisposals
(6.6)
\u2013
\u2013
\u2013
\u2013
(6.6)
\nCurrency translation adjustment
(9.6)
(17.4)
\u2013
\u2013
(1.6)
(28.6)
\nAt 31 December 2022
87.4
168.9
562.6
334.2
20.0
1,173.1
\nAccumulated depreciation
\nAt 1 January 2021
11.0
54.3
\u2013
\u2013
1.6
66.9
\nCharge for the year
11.6
44.8
102.1
\u2013
5.9
164.4
\nCurrency translation adjustment
(0.3)
(1.3)
\u2013
\u2013
(0.1)
(1.7)
\nAt 31 December 2021
22.3
97.8
102.1
\u2013
7.4
229.6
\nCharge for the year
11.8
42.5
107.4
61.1
7.0
229.8
\nDisposals
(6.4)
\u2013
\u2013
\u2013
\u2013
(6.4)
\nCurrency translation adjustment
(1.8)
(11.8)
\u2013
\u2013
(1.0)
(14.6)
\nAt 31 December 2022
25.9
128.5
209.5
61.1
13.4
438.4
\nNet book value
\nAt 31 December 2021
78.0
54.9
407.8
\u2013
10.8
551.5
\nAt 31 December 2022
61.5
40.4
353.1
273.1
6.6
734.7
\n1
Additions of $338.0 million related to the Tolmount offshore facilities were made to the right-of-use assets during the year (2021: total additions of $612.5 million arose primarily from
\nbusiness combinations of $567.9 million \u2013 see note 14) and $42.7 million from a new drilling rig contract.
\nRight-of-use liabilities
Note
\n2022
\n$ million
\n2021
\n$ million
\nAt 1 January
654.3
140.9
\nAdditions
338.0
42.7
\nAdditions from business combinations and joint arrangements
14
\u2013
637.8
\nRemeasurement
88.9
(5.0)
\nFinance costs charged to income statement
7
25.1
22.3
\nFinance costs charged to decommissioning provision
20
0.6
0.7
\nDisposals
(0.4)
(5.1)
\nLease payments
(254.0)
(160.4)
\nCurrency translation adjustment
(27.9)
(19.6)
\nAt 31 December
824.6
654.3
\nClassi\ufb01ed as
\nCurrent
220.8
165.1
\nNon-current
603.8
489.2
\nTotal lease liabilities
824.6
654.3
\n148
The signi\ufb01cant portion of the Group\u2019s lease liabilities represent lease arrangements for FPSO vessels on the Catcher and Chim S\u00e1o
\nassets, and offshore facilities on the Tolmount asset.
\nThe lease liabilities and associated right-of-use-assets have been calculated by reference to in-substance \ufb01xed lease payments in the
\nunderlying agreements incurred throughout the non-cancellable period of the lease along with periods covered by options to extend the
\nlease where the Group is reasonably certain that such options will be exercised. When assessing whether extension options were likely
\nto be exercised, assumptions are consistent with those applied when testing for impairment.
\nIncome statement
\nDepreciation charge of right-of-use assets
Note
\n2022
\n$ million
\n2021
\n$ million
\nLand and buildings \u2013 non-oil and gas assets
10.8
10.5
\nLand and buildings \u2013 oil and gas assets
1.0
1.1
\nDrilling rigs
42.5
44.8
\nOffshore facilities
61.1
\u2013
\nFPSO
107.4
102.1
\nEquipment \u2013 non-oil and gas assets
0.4
\u2013
\nEquipment \u2013 oil and gas assets
6.6
5.9
\n229.8
164.4
\nCapitalisation of IFRS 16 lease depreciation
\n1
\nDrilling rigs
(25.9)
(27.2)
\nEquipment
(4.0)
(3.5)
\nTotal depreciation charge
199.9
133.7
\nLease interest
7
25.1
22.3
\n1
Of the $29.9 million (2021: $30.7 million) capitalised IFRS 16 lease depreciation, $22.4 million (2021: $22.5 million) has been capitalised within property, plant and equipment and
\n$7.5 million (2021: $8.2 million) within provisions (note 20).
\nThe total cash out\ufb02ow for leases in 2022 was $254.0 million (2021: $160.4 million).
\n14. Business combinations and acquisition of interests in joint arrangements
\nBusiness combinations during the year ended 31 December 2021
\nIn October 2020, Harbour Energy Limited entered into an agreement with Premier Oil plc (Premier) regarding an all-share merger between
\nPremier and Harbour Energy Limited\u2019s subsidiary, Chrysaor Holdings Limited (Chrysaor). Under the terms of the merger, Premier legally
\nacquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the acquirer for accounting purposes, primarily as a
\nresult of its ability to appoint the Board of the enlarged group. The transaction completed on 31 March 2021, whereupon Premier, being
\nthe legal acquirer and accounting acquiree, changed its name from Premier Oil plc to Harbour Energy plc (Harbour).
\nThe merger constituted a reverse takeover of Premier by Chrysaor and has therefore been accounted for as a reverse acquisition in
\naccordance with IFRS 3 Business Combinations. As a result, Premier is fully consolidated in the \ufb01nancial statements with effect from
\n31\u00a0March 2021, and all results prior to this date represent those of Chrysaor only.
\nPremier was an upstream exploration and production company with its primary assets located in the UK North Sea, Vietnam and
\nIndonesia. The merger brought together two complementary businesses and created the largest independent oil and gas company
\nlisted on the London Stock Exchange with a strong balance sheet and signi\ufb01cant international growth opportunities.
\nA purchase price allocation (PPA) exercise has been performed under which the identi\ufb01able assets and liabilities of Premier were
\nrecognised at fair value.
\n149
Notes to the consolidated \ufb01nancial statements
continued
\n14. Business combinations and acquisition of interests in joint arrangements
continued
\nThe fair values of the net identi\ufb01able assets as at the date of acquisition are as follows:
\nFair value
\n$ million
\nAssets
\nExploration, evaluation and other intangible assets
597.1
\nProperty, plant and equipment \u2013 oil and gas assets
1,814.3
\nProperty, plant and equipment \u2013 non-oil and gas assets
4.2
\nProperty, plant and equipment \u2013 right-of-use assets
567.9
\nLong-term receivables
258.8
\nDeferred tax
1,549.2
\nInventories
15.2
\nTrade and other receivables
291.0
\nDerivative \ufb01nancial instruments
9.2
\nCash and cash equivalents
97.4
\n5,204.3
\nLiabilities
\nTrade and other payables
(317.5)
\nIFRS 16 lease liabilities
(637.8)
\nDeferred tax
(183.1)
\nProvision for decommissioning
(1,683.0)
\nDerivative \ufb01nancial instruments
(153.7)
\nShort-term debt
(2,219.3)
\nDeferred income
(33.6)
\nOther provisions
(34.5)
\n(5,262.5)
\nFair value of identi\ufb01able net liabilities acquired
(58.2)
\nFair value of shares acquired
285.7
\nTransaction cost adjustments
(4.6)
\nCost of acquisition
281.1
\nGoodwill recognised
339.3
\nThe fair values of the oil and gas assets and intangible assets acquired were determined using valuation techniques based on
\ndiscounted cash \ufb02ows using forward curve commodity prices and estimates of long-term prices, a discount rate based on market
\nobservable data and cost and production pro\ufb01les generally consistent with the 2P reserves acquired with each asset. Where applicable
\nother observable market information was also used. The decommissioning provisions recognised were estimated based on Harbour\u2019s
\ninternal estimates with reference to observable market data, including rig rates.
\nThe fair value of debt facilities was determined based on the total fair value of cash paid and new shares issued to creditors to satisfy
\nPremier\u2019s historical debt arrangements.
\nThe consideration was measured using the closing market price of Premier\u2019s ordinary share capital and the number of shares in issue
\nimmediately before the acquisition date. The transaction cost adjustments relate to share-based payment charges accruing prior to
\n31 March 2021 and certain transaction costs settled by Premier on behalf of Chrysaor which have been recognised as an expense
\nwithin general and administrative expenses.
\nGoodwill of $339.3 million was recognised on the acquisition, representing the excess of the total consideration transferred over the fair
\nvalue of the net assets acquired. The goodwill arose principally because of the following factors:
\n1.
The ability to deliver cost synergies as a result of combining the two businesses.
\n2.
The avoidance of costs that would otherwise have been incurred by Chrysaor as a result of an initial stock exchange listing.
\n3.
The expertise and experience of the acquired business, particularly with respect to ful\ufb01lling the obligations of a UK listed entity.
\n4.
The requirement to recognise deferred tax liabilities for the difference between the assigned fair values and the tax bases of assets acquired.
\n150
None of the goodwill is deductible for corporation tax.
\nAcquisition related costs of $26.5 million were incurred by the Group and recognised as an expense within general and administrative
\nexpenses within 2021.
\nFrom the date of acquisition to 31 December 2021, the acquired business contributed $815.6 million of revenue and a loss of $89.0 million
\nto the pro\ufb01t before tax from continuing operations of the Group. Had the acquisition completed at 1 January 2021, the business would have
\ncontributed revenue of $1,078.5 million in the year to 31 December 2021, and a loss of $93.9 million towards the pro\ufb01t before tax.
\n15. Inventories
\n2022
\n$ million
\n2021
\n$ million
\nHydrocarbons
21.5
65.4
\nConsumables and subsea supplies
121.4
146.0
\nTotal inventories
142.9
211.4
\nInventories of consumables and subsea supplies include a provision of $24.6 million (2021: $8.5 million) where it is considered that the
\nnet realisable value is lower than the original cost.
\nInventories recognised as an expense during the year ended 31 December 2022 amounted to $22.4 million (2021: $3.3 million).
\nThese expenses are included within production costs.
\n16. Trade and other receivables
\n2022
\n$ million
\n2021
\n$ million
\nTrade receivables
392.4
364.0
\nUnderlift position
69.3
147.5
\nOther debtors
97.2
74.1
\nPrepayments and accrued income
784.6
677.4
\nCorporation tax receivable
59.7
79.2
\nTotal trade and other receivables
1,403.2
1,342.2
\nTrade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2022, there were no trade
\nreceivables that were past due (2021: nil).
\nPrepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas. Other debtors mainly
\nrelate to amounts due from joint venture partners.
\nThe carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
\nOther long-term receivables
\n2022
\n$ million
\n2021
\n$ million
\nNet investment in sublease
44.0
52.9
\nDecommissioning funding asset
\n1
\n62.5
67.1
\nLong-term employee bene\ufb01t plan surplus
0.2
0.8
\nOther receivables
\n2
\n163.7
140.8
\nPrepayments and accrued income
27.6
1.4
\nTotal other long-term receivables
298.0
263.0
\n1
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
\nJohnston 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
\nbased 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 2022, a long-term
\ndecommissioning funding asset of $62.5 million (2021: $67.1 million) has been recognised utilising the year-end US dollar/pound sterling exchange rate and underlying assumptions
\nconsistent with those used for the corresponding decommissioning provision.
\n2
Other receivables includes $123.4 million in cash held in escrow accounts for expected future decommissioning expenditure in Indonesia and Vietnam (2021: $120.7 million), and
\n$22.6 million (2021: $23.9 million) held as security for the Mexican letters of credit.
\n151
Notes to the consolidated \ufb01nancial statements
continued
\n17. Cash and cash equivalents
\n2022
\n$ million
\n2021
\n$ million
\nCash at bank and in hand
499.7
698.7
\nCash at bank earns interest at \ufb02oating rates based on daily bank deposit rates. The Group only deposits cash with major banks of
\nhigh-quality credit standing.
\n18. Commitments
\nCapital commitments
\nAs at 31 December 2022, the Group had commitments for future capital expenditure amounting to $408.7 million (2021: $451.1 million).
\nWhere the commitment relates to a joint arrangement, the amount represents the Group\u2019s net share of the commitment. Where the Group
\nis not the operator of the joint arrangement then the amounts are based on the Group\u2019s net share of committed future work programmes.
\n19. Trade and other payables
\n2022
\n$ million
\n2021
\nrestated
\n$ million
\nCurrent
\nTrade payables
47.2
120.9
\nOverlift position
131.5
76.7
\nOther payables
\n1
\n117.5
148.6
\nMatured \ufb01nancial instruments
258.2
361.7
\nAccruals
682.3
482.4
\nDeferred income
\n2
\n14.5
45.0
\n1,251.2
1,235.3
\nNon-current
\nOther payables
10.8
27.6
\nDeferred income
\n2
\n8.0
4.7
\n18.8
32.3
\n1
Other payables, within current liabilities at 31 December 2021, included $24.1 million of additional completion payments payable to ConocoPhillips as part of the acquisition of the
\nConocoPhillips UK business in 2019. This amount was settled in October 2022 and no further liabilities remain payable to ConocoPhillips.
\n2
Deferred income includes $22.5 million (2021: $20.8 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100.0 million from
\nFlowStream 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.
\nThis 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
\nunobservable inputs and is level 3 in the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has increased by $1.7 million in the year re\ufb02ecting the impact
\nof barrels delivered to FlowStream resulting in a debit to the income statement within \ufb01nance expense. Deferred income of $14.5 million (2021: $16.1 million) is expected to be delivered
\nto FlowStream within the next 12 months and has been classi\ufb01ed as a current liability, with the balance of $8.0 million classi\ufb01ed as non-current liabilities.
\n152
20. Provisions
\nNote
\nDecommissioning
\nprovision
\n$ million
\nOther
\n$ million
\nTotal
\n$ million
\nAt 1 January 2021
4,197.1
13.9
4,211.0
\nAdditions
17.1
1.0
18.1
\nAdditions from business combinations and joint arrangements
1,683.0
34.5
1,717.5
\nChanges in estimates \u2013 decrease to oil and gas tangible decommissioning assets
(381.0)
\u2013
(381.0)
\nChanges in estimates \u2013 increase to oil and gas intangible decommissioning assets
14.3
\u2013
14.3
\nChanges in estimates \u2013 credit to income statement
\u2013
(2.3)
(2.3)
\nChanges in estimates on oil and gas tangible assets \u2013 debit to income statement
8.5
\u2013
8.5
\nChanges in estimates on oil and gas intangible assets \u2013 credit to income statement
(6.3)
\u2013
(6.3)
\nAmounts used
(225.9)
(9.2)
(235.1)
\nInterest on decommissioning lease
(0.7)
\u2013
(0.7)
\nDepreciation, depletion & amortisation on decommissioning right-of-use leased asset
(8.2)
\u2013
(8.2)
\nRelease of royalty provision
22
\u2013
(10.2)
(10.2)
\nUnwinding of discount
78.0
\u2013
78.0
\nCurrency translation adjustment
(22.2)
(0.2)
(22.4)
\nAt 31 December 2021
5,353.7
27.5
5,381.2
\nAdditions
24.4
\u2013
24.4
\nChanges in estimates \u2013 decrease to oil and gas tangible decommissioning assets
(720.9)
\u2013
(720.9)
\nChanges in estimates \u2013 decrease to oil and gas intangible decommissioning assets
(6.1)
\u2013
(6.1)
\nChanges in estimates \u2013 credit to income statement
\u2013
(1.2)
(1.2)
\nChanges in estimates on oil and gas tangible assets \u2013 credit to income statement
(82.3)
\u2013
(82.3)
\nChanges in estimates on oil and gas intangible assets \u2013 credit to income statement
(5.7)
\u2013
(5.7)
\nAmounts used
(222.6)
(2.3)
(224.9)
\nDisposal
(9.0)
\u2013
(9.0)
\nInterest on decommissioning lease
(0.6)
\u2013
(0.6)
\nDepreciation, depletion & amortisation on decommissioning right-of-use leased asset
(7.5)
\u2013
(7.5)
\nUnwinding of discount
65.1
\u2013
65.1
\nCurrency translation adjustment
(247.2)
\u2013
(247.2)
\nAt 31 December 2022
4,141.3
24.0
4,165.3
\nClassi\ufb01ed within
\nNon-current
\nliabilities
\n$ million
\nCurrent
\nliabilities
\n$ million
\nTotal
\n$ million
\nAt 31 December 2021
5,022.6
358.6
5,381.2
\nAt 31 December 2022
3,933.7
231.6
4,165.3
\nDecommissioning provision
\nAll of the $24.4 million decommissioning provision additions relate to oil and gas tangible assets (2021: $14.7 million related to oil and
\ngas tangible assets, and $2.4 million related to oil and gas intangible assets).
\nThe Group provides for the estimated future decommissioning costs on its oil and gas assets at the balance sheet date. The payment
\ndates of expected decommissioning costs are uncertain and are based on economic assumptions of the \ufb01elds concerned. The Group
\ncurrently expects to incur decommissioning costs within the next 40 years, the majority of which are anticipated to be incurred between
\nthe 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
\ncent per annum (2021: 2.0 per cent per annum) and discounted at a risk-free rate of between 3.5 per cent and 3.7 per cent (2021:
\n0.9 per cent and 1.8 per cent) re\ufb02ecting a six-month (2021: 24-month) rolling average of market rates over the varying lives of the assets
\nto calculate the present value of the decommissioning liabilities. The unwinding of the discount is presented within \ufb01nance costs.
\nThese provisions have been created based on internal and third-party estimates. Assumptions based on the current economic
\nenvironment have been made, which management believe are a reasonable basis upon which to estimate the future liability. These
\nestimates are reviewed regularly to consider any material changes to the assumptions. However, actual decommissioning costs will
\nultimately depend upon market prices for the necessary decommissioning work required, which will re\ufb02ect market conditions at the
\nrelevant time. In addition, the timing of decommissioning liabilities will depend upon the dates when the \ufb01elds become economically
\nunviable, which in itself will depend on future commodity prices and climate change, which are inherently uncertain.
\n153
Notes to the consolidated \ufb01nancial statements
continued
\n20. Provisions
continued
\nOther provisions
\nOther provisions relate to termination bene\ufb01t provision in Indonesia of $23.5 million (2021: $25.3 million), where the Group operates a service,
\nseverance and compensation pay scheme under a collective labour agreement with the local workforce. Other provisions at 31 December 2021
\nalso included a $2.3 million onerous contract provision in respect of the termination cost of the rig which had been operating on the Schiehallion
\n\ufb01eld, which has now been fully settled. The onerous contract had no impact on the income statement in the year.
\n21. Borrowings and facilities
\nThe Group\u2019s borrowings are carried at amortised cost:
\n2022
\n$ million
\n2021
\n$ million
\nReserves-based lending (RBL) facility
702.3
2,312.0
\nBond
491.3
489.5
\nExploration \ufb01nance facility (EFF)
10.5
44.6
\nOther loans
34.0
39.9
\nTotal borrowings
1,238.1
2,886.0
\nClassi\ufb01ed within
\nNon-current liabilities
1,216.6
2,823.7
\nCurrent liabilities
21.5
62.3
\nTotal borrowings
1,238.1
2,886.0
\nInterest of $6.2 million (2021: $17.4 million) on the RBL, bond and EFF had accrued by the balance sheet date and has been classi\ufb01ed
\nwithin accruals.
\nThe key terms of the RBL facility are:
\n\u00bc
Term matures 23 November 2027.
\n\u00bc
Facility size of $4.1 billion (with $0.75 billion accordion option).
\n\u00bc
Debt availability currently at $2.75 billion.
\n\u00bc
Debt availability to be redetermined on an annual basis.
\n\u00bc
Interest at USD LIBOR plus a margin of 3.25 per cent, rising to a margin of 3.5 per cent from November 2025.
\n\u00bc
A margin adjustment linked to carbon-emission reductions.
\n\u00bc
Liquidity and leverage covenant tests.
\n\u00bc
A syndication group of 19 banks.
\nCertain fees are also payable, including fees on available commitments at 40 per cent of the applicable margin and commission on
\nletters of credit issued at 50 per cent of the applicable margin.
\nIn October 2021, the Group issued a $500 million bond under Rule 144A and has a tenor of \ufb01ve years to maturity. The coupon was set
\nat 5.50 per cent and interest is payable semi-annually.
\nSince 2019, the Group has been operating within an exploration \ufb01nance facility, currently for NOK 1 billion, in relation to part-\ufb01nancing
\nthe exploration activities of Harbour Energy Norge AS. At the balance sheet date, the amount drawn down on the facility was NOK 104
\nmillion/$10.5 million (2021: NOK 396 million/$44.9 million).
\nDuring the year $54.9 million (2021: $38.9 million) of arrangement fees and related costs have been amortised and are included
\nwithin \ufb01nancing costs. 2021 also included a $13.9 million modi\ufb01cation gain following a maturity extension of the RBL debt prior to
\nthe completion of the merger in March 2021.
\nAt 31 December 2022, $81.5 million of arrangement fees and related costs remain capitalised (2021: $136.4 million), of which
\n$20.2 million are due to be amortised within the next 12 months (2021: $43.6 million).
\nAt the balance sheet date, the outstanding RBL balance excluding incremental arrangement fees and related costs was $775.0 million (2021:
\n$2,437.5 million). As at 31 December 2022, $1,972.0 million remained available for drawdown under the RBL facility (2021: $884 million).
\n154
The Group has facilities to issue up to $1.5 billion of letters of credit, of which $966 million was in issue as at 31 December (2021:
\n$796 million), mainly in respect of future abandonment liabilities.
\nOther loans represent a commercial \ufb01nancing arrangement with Baker Hughes (formerly BHGE), that covered a three-year work programme
\nfor drilling, completion and subsea tie-in of development wells on Harbour\u2019s operated assets. The loan will be repaid based on production
\nperformance, subject to a cap, in addition to three annual instalments of $9.0 million commencing on 1 December 2024, if required.
\nThe table below details the change in the carrying amount of the Group\u2019s borrowings arising from \ufb01nancing cash \ufb02ow.
\n$ million
\nTotal borrowings as at 1 January 2021
2,161.4
\nRepayment of RBL
(697.5)
\nRepayment of junior debt
(400.0)
\nShort-term debt arising on business combination
(2,219.3)
\nRepayment of debt \u2013 equity allocation to borrowings
942.8
\nRepayment of debt \u2013 cash allocation to borrowings
1,276.5
\nConversion of D loan notes to equity
(134.7)
\nIFRS 9 modi\ufb01cation gain
(13.9)
\nRepayment of \ufb01nancing arrangement
(9.3)
\nRepayment of EFF loan
(14.7)
\nProceeds from drawdown of borrowing facilities
1,617.5
\nProceeds from EFF loan
45.9
\nProceeds from issue of bond
500.0
\nLoan notes redemption
(135.7)
\nArrangement fees and related costs on RBL paid and capitalised
(77.2)
\nArrangement fees and related costs on bond capitalised
(10.9)
\nArrangement fees and related costs on EFF loan capitalised
(0.4)
\nCurrency translation adjustment on EFF loan
(0.6)
\nLoan notes interest capitalised
5.6
\nFinancing arrangement interest payable
11.6
\nAmortisation of arrangement fees and related costs
38.9
\nTotal borrowings as at 31 December 2021
2,886.0
\nRepayment of RBL
(1,662.5)
\nRepayment of \ufb01nancing arrangement
(15.4)
\nRepayment of EFF loan
(38.6)
\nProceeds from EFF loan
11.5
\nCurrency translation adjustment on EFF loan
(7.3)
\nFinancing arrangement interest payable
9.5
\nAmortisation of arrangement fees and related costs
54.9
\nTotal borrowings as at 31 December 2022
1,238.1
\n155
Notes to the consolidated \ufb01nancial statements
continued
\n22. Other \ufb01nancial assets and liabilities
\nThe Group held the following \ufb01nancial instruments at fair value at 31 December 2022. The fair values of all derivative \ufb01nancial instruments
\nare based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation, which includes
\nestimates based on unobservable inputs and is level 3 in the IFRS 13 hierarchy.
\nCurrent
\n31 December 2022
31 December 2021 restated
\nAssets
\n$ million
\nLiabilities
\n$ million
\nAssets
\n$ million
\nLiabilities
\n$ million
\nMeasured at fair value through pro\ufb01t and loss
\nForeign exchange derivatives
6.0
(0.1)
0.9
(2.2)
\nInterest rate derivatives
24.3
\u2013
3.3
\u2013
\nFair value of embedded derivative within gas contract
\u2013
(57.0)
\u2013
(11.5)
\nCarbon swaps
\u2013
\u2013
36.6
(15.6)
\n30.3
(57.1)
40.8
(29.3)
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
50.5
(2,114.4)
1.0
(2,135.2)
\n50.5
(2,114.4)
1.0
(2,135.2)
\nTotal current
80.8
(2,171.5)
41.8
(2,164.5)
\nNon-current
\nMeasured at fair value through pro\ufb01t and loss
\nInterest rate derivatives
18.2
\u2013
8.3
\u2013
\n18.2
\u2013
8.3
\u2013
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
84.5
(1,279.1)
1.8
(1,373.6)
\n84.5
(1,279.1)
1.8
(1,373.6)
\nTotal non-current
102.7
(1,279.1)
10.1
(1,373.6)
\nTotal current and non-current
183.5
(3,450.6)
51.9
(3,538.1)
\nFair value measurements
\nAll \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with the
\nhierarchy described in IFRS 13 Fair Value Measurement. The hierarchy groups fair value measurements into the following levels based on
\nthe degree to which the fair value is observable.
\n\u00bc
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities.
\n\u00bc
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or indirectly.
\n\u00bc
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data.
\nAs at 31 December 2022
\nFinancial assets
Financial liabilities
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(57.0)
\u2013
\nCommodity derivatives
135.0
\u2013
(3,393.5)
\u2013
\nForeign exchange derivatives
6.0
\u2013
(0.1)
\u2013
\nCarbon swaps
\u2013
\u2013
\u2013
\u2013
\nInterest rate derivatives
42.5
\u2013
\u2013
\u2013
\nTotal fair value
183.5
\u2013
(3,450.6)
\u2013
\nFinancial assets
Financial liabilities
\nAs at 31 December 2021 as restated
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(11.5)
\u2013
\nCommodity derivatives
2.8
\u2013
(3,508.8)
\u2013
\nForeign exchange derivatives
0.9
\u2013
(2.2)
\u2013
\nCarbon swaps
36.6
\u2013
(15.6)
\u2013
\nInterest rate derivatives
11.6
\u2013
\u2013
\u2013
\nTotal fair value
51.9
\u2013
(3,538.1)
\u2013
\n156
There were no transfers between fair value levels in the year. The movements in the year associated with \ufb01nancial assets and liabilities
\nmeasured in accordance with level 3 of the fair value hierarchy are shown below:
\nLevel 3
\nFinancial
\nassets
\nFinancial
\nliabilities
\n2022
\n$ million
\n2021
\n$ million
\n2022
\n$ million
\n2021
\n$ million
\nFair value as at 1 January
\u2013
9.7
\u2013
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
(10.2)
\u2013
(4.2)
\nGains and (losses) recognised in the income statement
\u2013
0.5
\u2013
4.2
\nFair value as at 31 December
\u2013
\u2013
\u2013
\u2013
\nFair value movements recognised in the income statement on \ufb01nancial instruments are shown below:
\n2022
\n$ million
\n2021
\n$ million
\nIncome included in the income statement
\nWarrants
\u2013
4.2
\nRemeasurement of royalty valuation
\u2013
0.5
\n\u2013
4.7
\nFair values of other \ufb01nancial instruments
\nThe following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
\n2022
2021
\nBook value
\n$ million
\nFair value
\n$ million
\nBook value
\n$ million
\nFair value
\n$ million
\nBond
(491.3)
(446.4)
(489.5)
(483.0)
\nThe 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
\nmarket yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
\nshort-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.
\nCash \ufb02ow hedge accounting
\nThe Group uses a combination of \ufb01xed price physical sales contracts and cash-settled \ufb01xed price commodity swaps and options to manage
\nthe price risk associated with its underlying oil and gas revenues. As at 31 December 2022, all of the Group\u2019s cash-settled \ufb01xed price
\ncommodity swap derivatives have been designated as cash \ufb02ow hedges of highly probable forecast sales of oil and gas.
\nThe following table indicates the volumes, average hedged price and timings associated with the Group\u2019s \ufb01nancial commodity derivatives.
\nVolumes hedged through \ufb01xed price contracts with customers for physical delivery are excluded.
\nPosition as at 31 December 2022
2023
2024
2025
2026
\nOil volume hedged (thousand bbls)
10,950
7,320
2,373
\u2013
\nWeighted average hedged price ($/bbl)
74.08
84.37
81.22
\u2013
\nGas volume hedged (million therms)
1,339
652
113
\u2013
\nWeighted average hedged price (p/therm)
41.46
68.85
75.22
\u2013
\nAs at 31 December 2022, the fair value of net \ufb01nancial commodity derivatives designated as cash \ufb02ow hedges, all executed under ISDA
\nagreements with no margining requirements, was a net payable of $3,516.7 million (2021: $3,868.2 million) and net unrealised pre-tax
\nlosses of $3,184.6 million (2021: $3,454.2 million) were deferred in other comprehensive income in respect of the effective portion of
\nthe hedge relationships.
\nAmounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur.
\nAs at 31 December 2022, net deferred pre-tax losses of $2,367.9 million (2021: $2,495.9 million) are expected to be released to the
\nincome statement within one year.
\n157
Notes to the consolidated \ufb01nancial statements
continued
\n22. Other \ufb01nancial assets and liabilities
continued
\nInterest Rate Benchmark Reform (IBOR)
\nFrom 1 January 2022, publication of most LIBOR settings ended (including Sterling LIBOR). All IBORs were replaced with alternative
\nreference rates with the exception of US LIBOR.
\nAfter 30 June 2023 US LIBOR will cease publication and will be replaced by SOFR (Secured overnight \ufb01nancing rate). The Group has
\nvariable rate RBL borrowings that currently reference US LIBOR, which are partially hedged by interest rate swaps that are also linked to
\nUS LIBOR. The RBL agreement has an automatic trigger to transition to SOFR after 30 June 2023, and a similar arrangement has been
\nagreed in principle with the interest rate swap counterparties to reduce any future impact on the \ufb01nancial statements after transition.
\nThe following table shows the \ufb01nancial instruments held by the Group as at 31 December 2022 which are referenced to US LIBOR that
\nwill transition to SOFR by 30 June 2023.
\nRBL borrowings \ufb01nancial liabilities
\nNominal value
\n$ million
\nUSD 1M LIBOR
475.0
\nUSD 6M LIBOR
300.0
\n775.0
\nDerivatives
\nInterest rate swaps USD 6M LIBOR
544.6
\nThe nominal values in the table above also represent the carrying values net of unamortised deferred fees of the RBL as at 31 December 2022.
\n23. Financial risk factors and risk management
\nThe Group\u2019s principal \ufb01nancial assets and liabilities comprise trade and other receivables, cash and short-term deposits accounts,
\ntrade payables, interest bearing loans and derivative \ufb01nancial instruments. The main purpose of these \ufb01nancial instruments is to manage
\nshort-term cash \ufb02ow, price exposures and raise \ufb01nance for the Group\u2019s expenditure programme. Further information on the Group\u2019s
\n\ufb01nancial instrument risk management objectives, policies and strategies are set out in the discussion of capital management policies
\nin the Strategic Report.
\nRisk exposures and responses
\nThe Group manages its exposure to key \ufb01nancial risks in accordance with its \ufb01nancial risk management policy. The objective of the policy
\nis to support the delivery of the Group\u2019s \ufb01nancial targets while protecting future \ufb01nancial security. The main risks that could adversely
\naffect the Group\u2019s \ufb01nancial assets, liabilities or future cash \ufb02ows are market risks comprising commodity price risk, interest rate risk and
\nforeign currency risk, liquidity risk, and credit risk. Management reviews and agrees policies for managing each of these risks which are
\nsummarised in this note.
\nThe Group\u2019s management oversees the management of \ufb01nancial risks. The Group\u2019s senior management ensures that \ufb01nancial risk-taking
\nactivities are governed by appropriate policies and procedures and that \ufb01nancial risks are identi\ufb01ed, measured and managed in
\naccordance with Group policies and risk objectives. All derivative activities for risk management purposes are carried out by specialist
\nteams that have the appropriate skills, experience and supervision. It is the Group\u2019s policy that no trading in derivatives for speculative
\npurposes shall be undertaken.
\nMarket risk
\nMarket risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market prices.
\nMarket risk comprises three types of risk: commodity price risk, interest rate risk and foreign currency risk. Financial instruments mainly
\naffected by market risk include loans and borrowings, deposits and derivative \ufb01nancial instruments.
\nThe sensitivity analyses in the following sections relate to the position as at 31 December 2022 and 31 December 2021.
\nThe sensitivity analyses have been prepared on the basis that the number of \ufb01nancial instruments are all constant. The sensitivity
\nanalyses are intended to illustrate the sensitivity to changes in market variables on the composition of the Group\u2019s \ufb01nancial instruments
\nat the balance sheet date and show the impact on pro\ufb01t or loss and shareholders\u2019 equity, where applicable.
\n158
The following assumptions have been made in calculating the sensitivity analyses:
\n\u00bc
The sensitivity of the relevant pro\ufb01t before tax item and/or equity is the effect of the assumed changes in respective market risks
\nfor the full year based on the \ufb01nancial assets and \ufb01nancial liabilities held at the balance sheet date.
\n\u00bc
The sensitivities indicate the effect of a reasonable increase in each market variable. Unless otherwise stated, the effect of a
\ncorresponding decrease in these variables is considered approximately equal and opposite.
\n\u00bc
Fair value changes from derivative instruments designated as cash \ufb02ow hedges are considered fully effective and recorded in
\nshareholders\u2019 equity, net of tax.
\n\u00bc
Fair value changes from derivatives and other \ufb01nancial instruments not designated as cash \ufb02ow hedges are presented as a sensitivity
\nto pro\ufb01t before tax only and not included in shareholders\u2019 equity.
\nCommodity price risk
\nThe Group is exposed to the risk of \ufb02uctuations in prevailing market commodity prices on the mix of oil and gas products. On a rolling
\nbasis, 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
\n(year 1), between 30 and 60 per cent of year 2 production, from year 3 up to 50 per cent of production and from year 4 up to 40 per
\ncent of production. The Group manages these risks through the use of \ufb01xed price contracts with customers for physical delivery and
\nderivative \ufb01nancial instruments including \ufb01xed price swaps and options.
\nCommodity price sensitivity
\nThe following table summarises the impact on the Group\u2019s pre-tax pro\ufb01t and equity from a reasonably foreseeable movement in
\ncommodity prices on the fair value of commodity based derivative instruments held by the Group at the balance sheet date.
\nAs at 31 December 2022
Market movement
\nE\ufb00ect on pro\ufb01t
\nbefore tax
\n$ million
\nE\ufb00ect
\non equity
\n$ million
\nBrent oil price
$10/bbl increase
\u2013
(48.8)
\nBrent oil price
$10/bbl decrease
\u2013
48.8
\nNBP gas price
\u00a30.1/therm increase
\u2013
(48.9)
\nNBP gas price
\u00a30.1/therm decrease
\u2013
48.9
\nAs at 31 December 2021
Market movement
\nEffect on pro\ufb01t
\nbefore tax
\n$ million
\nEffect
\non equity
\n$ million
\nBrent oil price
$10/bbl increase
\u2013
(156.6)
\nBrent oil price
$10/bbl decrease
\u2013
156.6
\nNBP gas price
\u00a30.1/therm increase
\u2013
(208.9)
\nNBP gas price
\u00a30.1/therm decrease
\u2013
208.9
\nInterest rate risk
\nInterest rate risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market
\ninterest rates. The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to the Group\u2019s long-term debt
\nobligation with \ufb02oating interest rates.
\nFloating rate borrowings comprise loans under the RBL facility which incurs interest \ufb01xed either one month, three months or six months
\nin advance at USD LIBOR plus a margin of 3.21 per cent. Fixed rate borrowings at 31 December 2022 comprise a bond which incurs
\ninterest at 5.5 per cent per annum. Floating rate \ufb01nancial assets comprise cash and cash equivalents which earn interest at the relevant
\nmarket rate. The Group monitors its exposure to \ufb02uctuations in interest rates and uses interest rate derivatives to manage the \ufb01xed and
\n\ufb02oating composition of its borrowings.
\nThe interest rate \ufb01nancial instruments in place at the balance sheet date are shown below:
\nDerivative
Currency
Period of hedge
Terms
\n31 December 2022
Interest rate swaps
$544.6 million
June 20 \u2013 June 25
Average 0.55%
\n31 December 2021
Interest rate swaps
$700.0 million
June 20 \u2013 June 25
Average 0.56%
\n159
Notes to the consolidated \ufb01nancial statements
continued
\n23. Financial risk factors and risk management
continued
\nThe interest rate and currency pro\ufb01le of the Group\u2019s interest-bearing \ufb01nancial assets and liabilities are shown below:
\nAs at 31 December 2022
\nCash at bank
\n$ million
\nFixed rate
\nborrowings
\n$ million
\nFloating rate
\nborrowings
\n$ million
\nTotal
\n$ million
\nUS dollar
480.5
(491.3)
(702.3)
(713.1)
\nPound sterling
8.0
\u2013
\u2013
8.0
\nNorwegian krone
6.2
\u2013
(10.5)
(4.3)
\nOther
5.0
\u2013
\u2013
5.0
\n499.7
(491.3)
(712.8)
(704.4)
\nAs at 31 December 2021
\nCash at bank
\n$ million
\nFixed rate
\nborrowings
\n$ million
\nFloating rate
\nborrowings
\n$ million
\nTotal
\n$ million
\nUS dollar
477.9
(489.5)
(2,351.9)
(2,363.5)
\nPound sterling
201.0
\u2013
\u2013
201.0
\nNorwegian krone
14.6
\u2013
(44.6)
(30.0)
\nOther
5.2
\u2013
\u2013
5.2
\n698.7
(489.5)
(2,396.5)
(2,187.3)
\nInterest rate sensitivity
\nThe following table demonstrates the indicative pre-tax effect on pro\ufb01t and equity of applying a reasonably foreseeable increase in
\ninterest rates to the Group\u2019s \ufb01nancial assets and liabilities at the balance sheet date.
\nMarket movement
\nEffect on pro\ufb01t
\nbefore tax
\n$ million
\nEffect on equity
\n$ million
\n31 December 2022
\nUS dollar interest rates
+100 basis points
7.9
\u2013
\n31 December 2021
\nUS dollar interest rates
+100 basis points
(1.6)
\u2013
\nForeign currency risk
\nForeign currency risk is the risk that the fair value or future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in
\nforeign exchange rates.
\nThe Group is exposed to foreign currency risk primarily arising from exchange rate movements in US dollar against pound sterling.
\nTo mitigate exposure to movements in exchange rates, wherever possible \ufb01nancial assets and liabilities are held in currencies that
\nmatch the functional currency of the relevant entity. The Group has subsidiaries with functional currencies of pound sterling, US dollar,
\nNorwegian krone, Mexican pesos and Brazilian reals. Exposures can also arise from sales or purchases denominated in currencies
\nother than the functional currency of the relevant entity; such exposures are monitored and hedged with agreement from the Board.
\nThe Group enters into forward contracts as a means of hedging its exposure to foreign exchange rate risks. As at 31 December 2022,
\nthe Group had \u00a342.0 million hedged at a forward rate of between $1.18331 and $1.24045:\u00a31 for the period to January 2023, and
\n$100.0 million hedged at forward rates of between $1.17543 and $1.18131:\u00a31 for the period to January 2023.
\nAs at 31 December 2021, the Group had \u00a320.0 million hedged at a forward rate of $1.39/\u00a31 for the period to January 2022
\nand EUR18.4 million hedged at forward rates of between \u20ac 1.19 and \u20ac 1.20/\u00a31 for the period January 2022 to December 2022.
\n160
Foreign currency sensitivity
\nThe following table demonstrates the sensitivity to a reasonably foreseeable change in US dollars against pound sterling with all
\nother variables held constant, of the Group\u2019s pro\ufb01t before tax (due to foreign exchange translation of monetary assets and liabilities).
\nThe impact of translating the net assets of foreign operations into US dollars is excluded from the sensitivity analysis.
\nMarket movement
\nEffect on pro\ufb01t
\nbefore tax
\n$ million
\nEffect on equity
\n$ million
\n31 December 2022
\nUS dollar/pound sterling
10% strengthening
291.1
\u2013
\nUS dollar/pound sterling
10% weakening
(291.1)
\u2013
\n31 December 2021
\nUS dollar/pound sterling
10% strengthening
284.5
\u2013
\nUS dollar/pound sterling
10% weakening
(284.5)
\u2013
\nCredit risk
\nCredit risk is the risk that a counterparty will not meet its obligations under a \ufb01nancial instrument or customer contract, leading to
\n\ufb01nancial loss. The Group trades only with recognised, creditworthy third parties. It is the Group\u2019s policy that all customers who wish to
\ntrade on credit terms are subject to credit veri\ufb01cation procedures, which include an assessment of credit rating, short-term liquidity, and
\n\ufb01nancial position. In addition, receivables balances are monitored on an ongoing basis, with the result that the Group\u2019s exposure to bad
\ndebts is not signi\ufb01cant.
\nThe Group is exposed to credit risk from its operating activities (primarily for trade receivables) and from its \ufb01nancing activities, including
\ndeposits with banks and derivative \ufb01nancial instruments.
\nThe Group has two ratings from two credit rating agencies: S&P Global at BB and Fitch at BB.
\nThe Group only sells hydrocarbons to recognised and creditworthy parties, typically the trading arm of large, international oil and gas
\ncompanies. An indication of the concentration of credit risk on trade receivables is shown in note 4, whereby the revenue from one
\ncustomer exceeds 84 per cent of the Group\u2019s consolidated revenue.
\nThe credit risk on liquid funds and derivative \ufb01nancial instruments is limited because the counterparties are internationally recognised
\nbanking institutions and are considered to represent minimal credit risk.
\nThere are no signi\ufb01cant concentrations of credit risk within the Group unless otherwise disclosed, and credit losses are expected to be
\nnear to zero. The maximum credit risk exposure relating to \ufb01nancial assets is represented by carrying value as at the balance sheet date.
\nLiquidity risk
\nLiquidity risk is the risk that the Group will encounter dif\ufb01culty in meeting obligations associated with \ufb01nancial liabilities that are settled by
\ndelivering cash or another \ufb01nancial asset. The Group monitors the amount of borrowings maturing within any speci\ufb01c period and expects
\nto meet its \ufb01nancing commitments from the operating cash \ufb02ows of the business and existing committed lines of credit.
\nThe table below summarises the maturity pro\ufb01le of the Group\u2019s \ufb01nancial liabilities based on contractual undiscounted payments:
\nAs at 31 December 2022
\nWithin 1 year
\n$ million
\n1 to 2 years
\n$ million
\n2 to 5 years
\n$ million
\nOver 5 years
\n$ million
\nTotal
\n$ million
\nNon-derivative \ufb01nancial liabilities
\nReserves-based lending facility
60.9
61.0
881.1
\u2013
1,003.0
\nBond
27.5
27.5
555.0
\u2013
610.0
\nExploration \ufb01nance facility
11.1
\u2013
\u2013
\u2013
11.1
\nOther loans
11.0
9.0
18.0
\u2013
38.0
\nTrade and other payables
1,318.4
18.8
\u2013
\u2013
1,337.2
\nLease obligations
208.1
180.0
386.2
60.9
835.2
\nTotal non-derivative \ufb01nancial liabilities
1,637.0
296.3
1,840.3
60.9
3,834.5
\nDerivative \ufb01nancial liabilities
\nNet-settled commodity derivatives
2,308.2
930.3
154.5
\u2013
3,393.0
\nNet-settled foreign exchange derivatives
0.1
\u2013
\u2013
\u2013
0.1
\n3,945.3
1,226.6
1,994.8
60.9
7,227.6
\n161
Notes to the consolidated \ufb01nancial statements
continued
\n23. Financial risk factors and risk management
continued
\nAs at 31 December 2021 as restated
\nWithin 1 year
\n$ million
\n1 to 2 years
\n$ million
\n2 to 5 years
\n$ million
\nOver 5 years
\n$ million
\nTotal
\n$ million
\nNon-derivative \ufb01nancial liabilities
\nReserves-based lending facility
85.8
758.4
1,569.5
305.8
2,719.5
\nBond
27.3
27.5
582.5
\u2013
637.3
\nExploration \ufb01nance facility
45.8
\u2013
\u2013
\u2013
45.8
\nOther loans
17.7
12.7
20.9
3.3
54.6
\nTrade and other payables
1,264.3
32.2
\u2013
\u2013
1,296.5
\nLease obligations
181.7
127.8
309.4
97.4
716.3
\nTotal non-derivative \ufb01nancial liabilities
1,622.6
958.6
2,482.3
406.5
5,470.0
\nDerivative \ufb01nancial liabilities
\nNet-settled commodity derivatives
2,146.2
1,090.6
283.1
\u2013
3,519.9
\nNet-settled foreign exchange derivatives
2.2
\u2013
\u2013
\u2013
2.2
\nNet-settled carbon derivatives
15.6
\u2013
\u2013
\u2013
15.6
\n3,786.6
2,049.2
2,765.4
406.5
9,007.7
\nThe 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
\nstatement against future production and revenue which are not recognised on the balance sheet as assets. Interest bearing loans and
\nborrowings and trade payables mainly originate from the \ufb01nancing of assets used in the Group\u2019s ongoing operations such as property,
\nplant and equipment and working capital such as inventories. These assets are considered part of the Group\u2019s overall liquidity risk.
\n24. Share capital
\nIssued and fully paid
Number
\n2022
\n$ million
Number
\n2021
\n$ million
\nOrdinary shares of 0.002p each
847,168,796
0
925,532,639
0
\nOrdinary non-voting deferred shares of 12.4999p each
925,532,809
171.1
925,532,809
171.1
\n171.1
171.1
\nThe rights and restrictions attached to the ordinary shares are as follows:
\n\u00bc
Dividend rights:
the rights of the holders of ordinary shares shall rank pari passu in all respects with each other in relation to dividends.
\n\u00bc
Winding up or reduction of capital:
on a return of capital on a winding up or otherwise (other than on conversion, redemption or
\npurchase of shares) the rights of the holders of ordinary shares to participate in the distribution of the assets of the company available
\nfor distribution shall rank pari passu in all respects with each other.
\n\u00bc
Voting rights:
the holders of ordinary shares shall be entitled to receive notice of, attend, vote and speak at any General Meeting of
\nthe company.
\nThe rights and restrictions attached to the non-voting deferred shares are as follows:
\n\u00bc
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
\namount paid up thereon only after holders of all ordinary shares have received, in aggregate, any amounts paid up on each ordinary
\nshare plus \u00a310 million on each ordinary share. The non-voting deferred shares will not give the holder the right to receive notice of, nor
\nattend, speak or vote at, any general meeting of the company.
\nIssue of ordinary shares
\nDuring the year, the company issued 1,024 ordinary shares at a nominal value of 0.002 pence per share in relation to the exercise of
\nequity warrants. All other outstanding warrants matured in May 2022.
\nPurchase and cancellation of own shares
\nDuring 2022, the company repurchased 78,364,867 ordinary shares for a total consideration, including transaction costs of $360.6 million,
\nas part of the share purchase programmes announced on 16 June 2022 and 3 November 2022. All shares purchased were cancelled.
\nAs of 15 February 2023, the buyback programme was completed with a further 11,093,925 million ordinary shares repurchased for
\ncancellation for a cost of $41.1 million. These shares were also cancelled.
\n162
Own shares
\n2022
\n$ million
\nAt 1 January
3.7
\nPurchase of ESOP trust shares
18.6
\nRelease of shares
(0.9)
\nAt 31 December
21.4
\nThe own shares represent the net cost of shares in Harbour Energy plc purchased in the market or issued by the company into the
\nHarbour Energy plc employee bene\ufb01t (ESOP) trust. This ESOP trust holds shares to satisfy awards under the Group\u2019s share incentive
\nplans. At 31 December 2022, the number of ordinary shares of 0.002 pence each held by the trust was 4,487,267 (2021: 775,523).
\nCapital reduction
\nThe capital reduction, comprising the share premium and the merger reserve, was approved by shareholders at the General Meeting held on
\n11 May 2022. In connection with the capitalisation of the merger reserve, the resolutions authorising the Directors to allot new B ordinary shares
\nand subsequently cancel them was also passed at the General Meeting. B ordinary shares totalling $4,806 million were issued on 25 July 2022.
\nOn 3 August 2022, Harbour announced that the capital reduction had become effective following the con\ufb01rmation by the Court of Session,
\nEdinburgh on 2 August 2022 and the registration of the Court order with the Registrar of Companies in Scotland on 3 August 2022. The share
\npremium account ($1,505 million), and the shares arising on the capitalisation of the merger reserve ($4,806 million), were cancelled.
\nThe capital reduction creates additional distributable reserves to the value of $6,311 million.
\n25. Share-based payments
\nThe company currently operates a Long Term Incentive Plan (LTIP) for certain employees, a Share Incentive Plan (SIP) and a Save As You
\nEarn (SAYE) scheme for UK-based and expatriate employees only.
\nFor the year ended 31 December 2022, the total cost recognised by the company for share-based payment transactions was
\n$36.9 million (2021: $13.4 million). A credit of $36.9 million (2021: $13.4 million) has been recorded in retained earnings for all
\nequity-settled payments of the company.
\nLike other elements of remuneration, this charge is processed through the time-writing system which allocates cost, based on time spent
\nby individuals, to various entities within the Group. Part of this cost is therefore recharged to the relevant subsidiary undertakings, part is
\ncapitalised as directly attributable to capital projects and part is charged to the income statement as operating costs, pre-licence
\nexploration costs or general and administration costs.
\nDetails of the various share incentive plans currently in operation are set out below:
\n2017 Long Term Incentive Plan (2017 LTIP)
\nDiscretionary share awards are granted to employees under the company\u2019s Long Term Incentive Plan (LTIP).
\nThe following types of award have been granted under the 2017 LTIP:
\n\u00bc
Performance share awards (PSA):
vesting is subject to a Performance Target, normally measured over a three-year period from
\n1 January based on Total Shareholder Return (TSR) relative to (i) FTSE 100 index, and (ii) a bespoke peer group of oil and gas companies
\nand aligns to longer-term strategic objectives.
\n\u00bc
Conditional share awards (CSAs):
vesting is only subject to continued employment.
\n\u00bc
Deferred bonus share plan (DBSP) awards:
certain employees are required to defer a portion of their annual bonus into shares which
\nvest over a three-year period subject to continued employment.
\n\u00bc
Restricted share awards (RSA):
legacy Premier Oil awards which were aligned to the primary objective of balance sheet recovery.
\nThe remainder of these lapsed in 2022.
\n\u00bc
Premier value share plan (PVSP) awards:
legacy Premier Oil awards which were made up of two awards, Base Awards and Multiplier
\nAwards. Under the PVSP, annual awards of time-vesting restricted shares (Base Awards) and three-year performance-vesting shares
\n(Performance Multiplier Awards) were made, with performance-vesting shares subject to achievements of Premier\u2019s delivery of long-term
\nshareholder return.
\nAll LTIP awards are granted in the form of nil-cost options or conditional share awards and therefore there is no exercise price payable
\non the exercise of these awards.
\nAll RSA awards lapsed during the year. The \ufb01nal outstanding PVSP Base Awards vested in the year, the remainder lapsed.
\n163
Notes to the consolidated \ufb01nancial statements
continued
\n25. Share-based payments
continued
\nFor further details of the LTIP awards, including the performance conditions of the PSAs granted in 2022, please refer to the Directors\u2019
\nremuneration report (pages 78-99).
\nThe following table shows the movement in the number of LTIP awards:
\n2022
\n(million shares)
\n2021
\n(million shares)
\nOutstanding at 1 January
20.5
\u2013
\nAdditions from business combinations and joint arrangements
\n1
\n\u2013
31.2
\nGranted pre-share consolidation
\u2013
23.1
\nVested pre-share consolidation
\u2013
(0.6)
\nForfeited pre-share consolidation
\u2013
(0.8)
\n20 to 1 share consolidation
\u2013
(50.3)
\nGranted (post-share consolidation)
\n2
\n10.3
18.0
\nVested (post-share consolidation)
\n2
\n(1.6)
\u2013
\nForfeited (post-share consolidation)
\n2
\n(1.4)
(0.1)
\nOutstanding at 31 December
\n3
\n27.8
20.5
\n1 Includes DBSP awards.
\n2
Post-share consolidation refers to movements in 2021 as a result of the merger.
\n3
This includes 1.6 million cash settled awards at 31 December 2022 (2021: 0.2 million), which are revalued using the year-end share price.
\nLTIP awards totalling 1.6 million shares were vested during the period. The weighted average remaining contractual life of the LTIP awards
\nat 31 December 2022 was 1.5 years (2021: 2.0 years).
\nKey assumptions used to calculate the fair value of awards
\nThe fair value of awards which are subject to TSR conditions, under the PSAs, is determined using a Monte Carlo simulation. The fair value of
\nall other awards is calculated using the share price at the date of grant, adjusted for dividends not received during the vesting period.
\nThe following table lists the inputs to the model used in respect of the PSA awards granted during the \ufb01nancial year:
\n2022
2021
\nShare price at date of grant
\u00a35.00 \u2013 \u00a35.19
\u00a33.60 \u2013 \u00a33.77
\nDividend yield
0%
0%
\nExpected term
3.0 years
1.5 years \u2013 3.0 years
\nRisk free rate
1.4% \u2013 1.6%
0.1% \u2013 0.5%
\nShare price volatility of the company
50.5% \u2013 51.3%
70%
\nThe weighted average fair value of the PSA awards granted in 2022 was $4.02 (2021: $1.57).
\nExpected volatility was determined by reference to both the historical volatility of the company and the historical volatility of a group
\nof comparable quoted companies over a period in line with the expected term assumption.
\nShare Incentive Plan (SIP)
\nUnder the Share Incentive Plan employees are invited to make contributions to buy partnership shares. If an employee agrees to buy
\npartnership shares the company currently matches the number of partnership shares bought with an award of shares (matching shares),
\non a one-for-one basis. 0.4 million matching shares were awarded to employees in 2022 (2021: 0.06 million). The SIP matching shares
\nare valued based on the quoted share price on the grant date.
\n164
Save As You Earn (SAYE) scheme
\nUnder the SAYE scheme, eligible employees with one month or more continuous service can join the scheme. Employees can save to a
\nmaximum of \u00a3500 per month through payroll deductions for a period of three years after which time they can acquire shares at up to a
\n20 per cent discount. 1.6 million SAYE options were granted in 2022 (2021: nil).
\nThe following table shows the movement in the number of SAYE options:
\n2022
2021
\nNumber
\n(million)
\nWeighted
\naverage
\nexercise price
\nNumber
\n(million)
\nWeighted
\naverage
\nexercise price
\nOutstanding at 1 January
0.4
\u00a35.78
\u2013
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
\u2013
10.3
\u00a35.82
\n20 to 1 share consolidation
\u2013
\u2013
(9.8)
\u2013
\nGranted during the year
1.6
\u00a34.12
\u2013
\u2013
\nLapsed during the year
(0.3)
\u00a35.36
(0.1)
\u00a36.01
\nExercised during the year
\u2013
\u2013
\u2013
\u2013
\nOutstanding as at 31 December
1.7
\u00a34.18
0.4
\u00a35.78
\nThe SAYE options outstanding at 31 December 2022 had exercise prices ranging from \u00a34.12 to \u00a35.53 (2021: \u00a35.53 to \u00a320.09) and a
\nweighted average remaining contractual life of 2.8 years (2021: 1.9 years).
\n26. Group pension schemes
\nBalance sheet
\n2022
\n$ million
\n2021
\n$ million
\nUK funded pension scheme
0.2
0.8
\nTotal surplus in balance sheet
0.2
0.8
\nUK unfunded pension scheme
0.5
0.7
\nTotal liability in balance sheet
0.5
0.7
\nUnfunded pensions
\nThe Group is paying an unfunded pension to a former director in the UK in regard to which annual increases and a reversionary spouse\u2019s
\npension apply on the same basis as pensions paid under the Scheme.
\nOn the same actuarial basis as used to assess the Scheme\u2019s pension costs, the present value as at 31 December 2022 of the future
\npayments projected to be made in respect of UK unfunded pensions is $0.5 million (2021: $0.7 million).
\nFunded pensions
\nThe Group operates a \ufb01nal salary de\ufb01ned bene\ufb01t pension plan in the UK (the Scheme). The Scheme is an HMRC registered pension plan
\nand is subject to standard UK pensions and tax law. Details on the bene\ufb01ts provided by the Scheme are set out in the Trust Deed and
\nRules dated 16 October 2008 (as amended).
\nThe disclosures in these accounts below are based on calculations carried out at the balance sheet date by a quali\ufb01ed independent actuary.
\nThe Scheme\u2019s assets are held in a separate trustee-administered fund to meet long-term pension liabilities to bene\ufb01ciaries. The Trustee of the
\nScheme is required to act in the best interest of the bene\ufb01ciaries. The appointment of trustee directors is determined by the trust documentation.
\nThe Trustee of the Scheme invests assets in line with the Statement on Investment Principles. The Statement on Investment Principles
\nhas been established taking into consideration the liabilities of the Scheme and the investment risk that the Trustee is willing to accept.
\nUnder the Scheme funding regime introduced by the Pension Act 2004, the Trustee is required to carry out regular actuarial valuations of the
\nScheme, establish a schedule of contributions and, when there is a shortfall, a recovery plan. Scheme funding valuations are carried out at
\nleast three years. Approximate funding updated are produced annually in years where a full scheme funding valuation is not completed.
\n165
Notes to the consolidated \ufb01nancial statements
continued
\n26. Group pension schemes
continued
\nAs at the balance sheet date, contributions are payable to the Scheme at the rates speci\ufb01ed in the schedule of contributions signed by
\nthe Trustee on 23 March 2021.
\nThe de\ufb01ned bene\ufb01t pension plan exposes the employer to actuarial risks, such as longevity risk, interest rate risk, salary risk, investment
\nmarket risk and currency risk.
\nPrincipal assumptions
\nAt 31 December
\n2022
\nAt 31 December
\n2021
\nDiscount rate
4.9% p.a.
1.8% p.a.
\nRPI in\ufb02ation
3.2% p.a.
3.4% p.a.
\nCPI in\ufb02ation
2.3% p.a.
2.4% p.a.
\nRate of increase in salaries
3.2% p.a.
3.4% p.a.
\nRate of increase in pensions in payment: LPI (max 5%)
3.1% p.a.
3.3% p.a.
\nMortality
S3PxA Light CMI_2021 with 0.5%
\np.a. IAMI and 1.25% p.a. long term
\nS3PxA Light CMI_2020 with 0.5%
\np.a IAMI and 1.25% p.a. long term
\nProportion married
80%
80%
\nWithdrawals
No allowance
No allowance
\nCash commutation
75% of maximum tax-free cash on
\nterms currently available
\n75% of maximum tax-free cash on
\nterms currently available
\nLife expectancy of male aged 65 now
23.6
23.6
\nLife expectancy of male aged 65 in 20 years
24.8
24.8
\nLife expectancy of female aged 65 now
25.2
25.1
\nLife expectancy of female aged 65 in 20 years
26.5
26.5
\nAsset breakdown
\nThe major categories of the Scheme assets as a percentage of total Scheme assets are:
\n2022
2021
\nEquities
12.0%
41.2%
\nGilts
51.7%
29.3%
\nCorporate bonds
13.1%
29.1%
\nCash
23.2%
0.4%
\nTotal
100.0%
100.0%
\nReconciliation of funded status and amount recognised in balance sheet
\n2022
\n$ million
\n2021
\n$ million
\nFair value of the Scheme assets
(36.6)
(55.4)
\nPresent value of de\ufb01ned bene\ufb01t obligation
23.5
39.4
\nSurplus
(13.1)
(16.0)
\nUnrecognised amount due to effect of IFRIC 14
\n1
\n12.9
15.2
\nDe\ufb01ned bene\ufb01t asset recognised in balance sheet
(0.2)
(0.8)
\n1
The trustees have certain rights to grant bene\ufb01t increases to members and accordingly it has been concluded the Group does not have an unconditional right to the surplus by way of a refund.
\nStatement of amount recognised in the income statement
\n2022
\n$ million
\n2021
\n$ million
\nCurrent service cost
0.1
0.1
\nNet interest on the net de\ufb01ned bene\ufb01t liability (asset)
\u2013
\u2013
\nTotal
0.1
0.1
\n166
Reconciliation of de\ufb01ned bene\ufb01t obligation
\n2022
\n$ million
\n2021
\n$ million
\nOpening present value of de\ufb01ned bene\ufb01t obligation
39.4
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
41.5
\nCurrent service cost
0.1
0.1
\nInterest cost
0.6
0.5
\nActuarial (gains)/losses from changes in demographic assumptions
0.4
\u2013
\nActuarial (gains)/losses from changes in \ufb01nancial assumptions
(13.3)
(1.7)
\nChanges due to experience adjustments
1.5
0.4
\nBene\ufb01ts paid
(1.2)
(1.1)
\nCurrency translation effects
(4.0)
(0.3)
\nClosing de\ufb01ned bene\ufb01t obligation
23.5
39.4
\nReconciliation of fair value of assets
\n2022
\n$ million
\n2021
\n$ million
\nOpening present value of Scheme assets
55.4
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
53.4
\nInterest income
0.9
0.6
\nReturn on assets less interest income
(12.9)
2.9
\nContributions by employer
\u2013
\u2013
\nBene\ufb01ts paid
(1.2)
(1.1)
\nCurrency translation effects
(5.6)
(0.4)
\nClosing fair value of Scheme assets
36.6
55.4
\nActual return on Scheme assets
(12.0)
3.5
\nStatement of amount recognised in comprehensive income
\n2022
\n$ million
\n2021
\n$ million
\n(Gain)/loss from changes in the \ufb01nancial assumptions for value of Scheme liabilities
(13.3)
(1.7)
\n(Gain)/loss from changes in the demographic assumptions for value of Scheme liabilities
0.4
\u2013
\nChanges due to experience adjustments
1.5
0.4
\nReturn on assets (excluding amounts included in net interest on the net de\ufb01ned bene\ufb01t liability (asset))
12.9
(2.9)
\nChange in the effect of the asset ceiling excluding amounts included in net interest on the net de\ufb01ned liability
(2.6)
4.2
\nCurrency translation effects
1.6
0.1
\nOther comprehensive income
0.5
0.1
\nStatement of amount recognised in pro\ufb01t and loss and other comprehensive income
\n2022
\n$ million
\n2021
\n$ million
\nAmount recognised in pro\ufb01t and loss
0.1
0.1
\nOther comprehensive income
0.5
0.1
\nTotal comprehensive loss
0.6
0.2
\nSensitivity of balance sheet at 31 December 2022
\nThe results of the calculations are sensitive to the assumptions used. The balance sheet position revealed by IAS 19 Employee Bene\ufb01ts
\ncalculations must be expected to be volatile, principally because the market value of assets (with signi\ufb01cant exposure to equities) is
\nbeing compared with a liability assessment derived from corporate bond yields.
\nThe table overleaf shows the sensitivity of the IAS 19 balance sheet position to small changes in some of the signi\ufb01cant assumptions,
\nas at 31 December 2022. The sensitivity analyses are based on a change in a signi\ufb01cant assumption, keeping all other assumptions
\nconstant. The sensitivity analyses may not be representative of an actual change in the de\ufb01ned bene\ufb01t obligation as it is unlikely that the
\nchanges in assumptions would occur in isolation from one another.
\n167
Notes to the consolidated \ufb01nancial statements
continued
\n26. Group pension schemes
continued
\nRevised (surplus)/de\ufb01cit
\n$ million
\nChange from disclosed
\n(surplus)/de\ufb01cit
\n$ million
\nDiscount rate less 0.1% p.a.
(12.8)
0.3
\nRPI in\ufb02ation and linked assumptions plus 0.1% p.a.
(12.8)
0.3
\nMembers living one year longer than assumed
(12.3)
0.8
\nProjected components of pension costs for period to 31 December 2023
\nBecause of the signi\ufb01cant volatility in investment markets, it is dif\ufb01cult to project forward the IAS 19 \ufb01gures for the next year with
\ncon\ufb01dence. The following projections should therefore be treated with caution.
\nAssumptions implicit in the following projections are:
\n\u00bc
The interest on the de\ufb01ned bene\ufb01t liability/(asset) from 31 December 2022 is 4.9 per cent p.a.
\n\u00bc
Contributions to the Scheme will continue throughout 2023 in accordance with the current Schedule of Contributions in place at the
\ndate of signing this report.
\n\u00bc
There will be no changes to the terms of the Scheme.
\nThe amounts recognised in the components of pension expense were nil for the year.
\nDe\ufb01ned contribution schemes
\nThe 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
\nmake 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
\nof $30.3 million (2021: $28.2 million) represents contributions payable to these schemes by the Group at rates speci\ufb01ed in the rules of the schemes.
\n27. Notes to the statement of cash \ufb02ows
\nNet cash \ufb02ows from operating activities consist of:
\n2022
\n$ million
\n2021
\n$ million
\nPro\ufb01t before taxation
2,461.8
314.5
\nAdjustments to reconcile pro\ufb01t before tax to net cash \ufb02ows:
\n\u2013 Finance cost, excluding foreign exchange
358.2
309.4
\n\u2013 Finance income, excluding foreign exchange
(77.1)
(48.8)
\n\u2013 Depreciation, depletion and amortisation
1,545.8
1,371.0
\n\u2013 Fair value movement in unrealised carbon swaps
2.6
\u2013
\n\u2013 Net impairment of property, plant and equipment
(169.6)
117.2
\n\u2013 Taxes paid
(551.5)
(279.8)
\n\u2013 Share-based payments
16.5
8.4
\n\u2013 Decommissioning payments
(217.0)
(244.8)
\n\u2013 Onerous contract provision
\u2013
(2.3)
\n\u2013 Exploration costs written-off
64.4
255.0
\n\u2013 Write-off of non-oil and gas assets
\u2013
4.7
\n\u2013 Pre-merger costs
\u2013
7.0
\n\u2013 Onerous contract payments
(2.3)
(9.2)
\n\u2013 Increase in royalty consideration receivable
\u2013
(0.5)
\n\u2013 (Gain)/loss on termination of IFRS 16 lease
(0.2)
0.3
\n\u2013 (Gain)/loss on disposal
(12.1)
0.1
\n\u2013 Movement in realised cash \ufb02ow hedges not yet settled
(104.3)
361.6
\n\u2013 Unrealised foreign exchange (gain)/loss
(237.9)
57.3
\nWorking capital adjustments:
\n\u2013 Decrease/(increase) in inventories
65.0
(13.0)
\n\u2013 Increase in trade and other receivables
(75.7)
(607.4)
\n\u2013 Increase in trade and other payables
63.2
13.5
\nNet cash in\ufb02ow from operating activities
3,129.8
1,614.2
\n168
Reconciliation of net cash \ufb02ow to movement in net borrowings
\n2022
\n$ million
\n2021
\n$ million
\nProceeds from drawdown of borrowing facilities
\u2013
(1,617.5)
\nProceeds from issue of bond
\u2013
(500.0)
\nShort-term debt arising on business combination
\u2013
2,219.3
\nRepayment of debt \u2013 equity allocation to borrowings
\u2013
(942.8)
\nRepayment of debt \u2013 cash allocation to borrowings
\u2013
(1,276.5)
\nConversion of D loan notes to equity
\u2013
134.7
\nProceeds from EFF loan
(11.5)
(45.9)
\nRepayment of RBL facility
1,662.5
697.5
\nRepayment of junior debt
\u2013
400.0
\nLoan notes redemption
\u2013
135.7
\nIFRS 9 modi\ufb01cation gain
\u2013
13.9
\nRepayment of EFF loan
38.6
14.7
\nRepayment of \ufb01nancing arrangement
15.4
9.3
\nArrangement fees and related costs capitalised
\u2013
88.5
\nFinancing arrangement interest payable
(9.5)
(11.6)
\nAmortisation of arrangement fees and related costs capitalised
(54.9)
(38.9)
\nCurrency translation adjustment on EFF loan
7.3
0.6
\nLoan notes interest capitalised
\u2013
(5.6)
\nMovement in total borrowings
1,647.9
(724.6)
\nMovement in cash and cash equivalents
(199.0)
253.3
\nDecrease/(increase) in net borrowings in the year
1,448.9
(471.3)
\nOpening net borrowings
(2,187.3)
(1,716.0)
\nClosing net borrowings
(738.4)
(2,187.3)
\nAnalysis of net borrowings
\n2022
\n$ million
\n2021
\n$ million
\nCash and cash equivalents
499.7
698.7
\nRBL facility
(702.3)
(2,312.0)
\nBond
(491.3)
(489.5)
\nEFF loan
(10.5)
(44.6)
\nNet debt
(704.4)
(2,147.4)
\nFinancing arrangement
(34.0)
(39.9)
\nClosing net borrowings
(738.4)
(2,187.3)
\n28. Related party disclosures
\nTransactions between the company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not
\ndisclosed in this note.
\nIn late 2021, the company agreed a secondment agreement with EIG to second two employees, familiar with Harbour\u2019s business and
\nassets, to provide additional support and expertise for Harbour for an initial period of six months from 1 December 2021. The
\nsecondment agreement provided that the secondees would work for Harbour on a substantially full-time basis which could be terminated
\nor extended with the agreement of the parties. In May 2022, the company and EIG agreed to terminate the agreement for one secondee
\nand to extend the second for a further period which was subsequently terminated before the end of the year.
\nHarbour Energy\u2019s Viking CCS (formerly V Net Zero), the CO
\n2
\ncapture, transport and storage network, entered into an arrangement with
\nWest Burton Energy, the independent power generation company based in Nottinghamshire which is a subsidiary of EIG, Harbour\u2019s
\nlargest shareholder. The intention is to capture, transport and permanently store CO
\n2
\nemissions from the West Burton B power station.
\nHarbour Energy and West Burton Energy have recently begun the necessary engineering design to connect West Burton B to the
\nhigh-capacity Viking CCS storage sites located deep beneath the Southern North Sea.
\n169
Notes to the consolidated \ufb01nancial statements
continued
\n28. Related party disclosures
continued
\nCompensation of key management personnel of the Group
\nThe remuneration of directors during the year is set out in the directors\u2019 remuneration report (pages 78 to 99).
\nRemuneration of key management personnel, including directors of the Group, is shown below:
\n2022
\n$ million
\n2021
\n1
\n$ million
\nSalaries and short-term employee bene\ufb01ts
14.6
18.6
\nPayments made in lieu of pension contributions
0.8
0.7
\nTermination bene\ufb01ts
0.4
\u2013
\nPension bene\ufb01ts
\u2013
\u2013
\n15.8
19.3
\n1
2021 data includes remuneration of key management personnel for the Chrysaor Holdings Group in the three months to 31 March 2021.
\n29. Distributions made and proposed
\nA \ufb01nal dividend of 11 cents per ordinary share in relation to the year ended 31 December 2021 was paid on 18 May 2022 pursuant
\nto shareholder approval received on 11 May 2022. Pursuant to shareholder approval received on 11 May 2022 an interim dividend of
\n11 cents per ordinary share in relation to the half year ended 30 June 2022 was paid on 19 October 2022.
\n2022
\n$ million
\n2021
\n$ million
\nCash dividends on ordinary shares declared and paid:
\nFinal dividend for 2021: 11 cents per share (2020: no dividend)
98.3
\u2013
\nInterim dividend for 2022: 11 cents per share
93.2
\u2013
\n191.5
\u2013
\nProposed dividends on ordinary shares:
\nFinal dividend for 2022: 12 cents per share (2021: 11 cents per share)
100.0
100.0
\nProposed dividends on ordinary shares are subject to approval at the Annual General Meeting and are not recognised as a liability as at 31 December.
\n30. Events after the reporting period
\nOn 14 February 2023, the Scheme\u2019s trustee effected a bulk annuity buy in policy with Just Retirement Limited. This policy secures the
\nbene\ufb01ts of all the Scheme\u2019s members and eliminates mortality and investment risk from the company\u2019s balance sheet. This decision was
\nmade principally in light of the substantial improvement to the Scheme\u2019s funded status over 2022 and the favourable market conditions
\nfor such transactions. The company was not required to pay any additional contributions to the Scheme in respect of the annuity purchase.
\n31. Investments
\nAt 31 December 2022, the subsidiary undertakings of the company which were all wholly owned were:
\nName of company
Area of operation
Country of incorporation
Main activity
\nChrysaor (U.K.) Alpha Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor (U.K.) Beta Limited
UK
UK
\n2
\nDecommissioning activities
\nChrysaor (U.K.) Delta Limited
UK
UK
\n2
\nNon-trading intermediate holding company
\nChrysaor (U.K.) Sigma Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor (U.K.) Theta Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor (U.K.) Zeta Limited
UK
UK
\n2
\nNon-trading intermediate holding company
\nChrysaor CNS Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Developments Limited
UK
UK
\n2
\nDecommissioning activities
\nChrysaor E&P Finance Limited
UK
UK
\n2
\nFinancing company
\nChrysaor E&P Limited
UK
UK
\n2
\nIntermediate holding company
\nHarbour Energy Services Limited
\n(formerly Chrysaor E&P Services Limited)
UK
UK
\n2
\nService company
\nChrysaor Holdings Limited
\n1
\nUK
Cayman Islands
\n13
\nIntermediate holding company
\n170
Name of company
Area of operation
Country of incorporation
Main activity
\nChrysaor Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Marketing Limited
UK
UK
\n2
\nGas trading
\nHarbour Energy Norge AS
\n(formerly Chrysaor Norge AS)
Norway
Norway
\n3
\nExploration, production, and development
\nChrysaor North Sea Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Petroleum Company U.K. Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Petroleum Limited
UK
UK
\n2
\nDecommissioning activities
\nChrysaor Production (U.K.) Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Production Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nChrysaor Production Limited
UK
UK
\n2
\nIntermediate holding company
\nChrysaor Resources (Irish Sea) Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Resources (UK) Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nEbury Gate Limited
Guernsey
Guernsey
\n11
\nRisk mitigation services
\nEnCore (NNS) Limited
UK
UK
\n2
\nIntermediate holding company
\nEnCore Oil Limited
UK
UK
\n2
\nIntermediate holding company
\nFP Mauritania A BV
Mauritania
Netherlands
\n7
\nDecommissioning activities
\nFP Mauritania B BV
Mauritania
Netherlands
\n7
\nDecommissioning activities
\nPremier Oil (EnCore Petroleum) Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil (Vietnam) Limited
Vietnam
British Virgin Islands
\n8
\nExploration, production, and development
\nPremier Oil Aberdeen Services Limited
UK
UK
\n2
\nService company
\nPremier Oil and Gas Services Limited
UK
UK
\n2
\nService company
\nPremier Oil Andaman I Limited
Indonesia
UK
\n2
\nExploration, production, and development
\nPremier Oil Andaman Limited
Indonesia
UK
\n2
\nExploration, production, and development
\nPremier Oil ANS Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil ANS Limited
Alaska
UK
\n2
\nExploration, production, and development
\nPremier Oil Barakuda Limited
Indonesia
UK
\n2
\nExploration, production and development
\nPremier Oil do Brasil Petroleo e Gas Ltda
Brazil
Brazil
\n9
\nExploration, production, and development
\nPremier Oil E&P Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil E&P UK Energy Trading Limited
UK
UK
\n2
\nGas trading
\nPremier Oil E&P UK EU Limited
UK
UK
\n2
\nExploration, production, and development
\nPremier Oil E&P UK Limited
UK
UK
\n2
\nExploration, production, and development
\nPremier Oil Exploration (Mauritania) Limited
Mauritania
Jersey
\n6
\nDecommissioning activities
\nPremier Oil Exploration and Production Mexico S.A.de C.V.
Mexico
Mexico
\n10
\nExploration, production, and development
\nPremier Oil Far East Limited
Singapore
UK
\n2
\nService company
\nPremier Oil Finance (Jersey) Limited
\n1
\nJersey
Jersey
\n6
\nInvestment management
\nPremier Oil Group Holdings Limited
\n1
\nUK
UK
\n2
\nIntermediate holding company
\nPremier Oil Group Limited
UK
UK
\n5
\nIntermediate holding company
\nPremier Oil Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil Mauritania B Limited
Mauritania
Jersey
\n6
\nDecommissioning activities
\nPremier Oil Mexico Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil Mexico Investments Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil Mexico Recursos S.A. de C.V.
Mexico
Mexico
\n10
\nExploration, production, and development
\nPremier Oil Natuna Sea BV
Indonesia
Netherlands
\n7
\nExploration, production, and development
\nPremier Oil Overseas BV
Netherlands
Netherlands
\n7
\nIntermediate holding company
\nPremier Oil South Andaman Limited
Indonesia
UK
\n2
\nExploration, production, and development
\nPremier Oil Tuna BV
Indonesia
Netherlands
\n7
\nExploration, production, and development
\nPremier Oil UK Limited
UK
UK
\n5
\nExploration, production, and development
\nPremier Oil Vietnam 121 Limited
Vietnam
UK
\n2
\nExploration, production, and development
\nPremier Oil Vietnam Offshore BV
Vietnam
Netherlands
\n7
\nExploration, production, and development
\nChrysaor (U.K.) Britannia Limited
\u2013
UK
\n2
\nDormant company
\n171
Notes to the consolidated \ufb01nancial statements
continued
\n31. Investments
continued
\nName of company
Area of operation
Country of incorporation
Main activity
\nChrysaor (U.K.) Eta Limited
\u2013
UK
\n2
\nNon-trading
\nChrysaor (U.K.) Lambda Limited
\u2013
ROI
\n4
\nDormant company
\nChrysaor Energy Limited
\u2013
UK
\n2
\nNon-trading
\nChrysaor Investments Limited
\u2013
UK
\n2
\nDormant company
\nChrysaor Supply & Trading Limited
\u2013
UK
\n2
\nDormant company
\nEnCore (VOG) Limited
\u2013
UK
\n2
\nDormant company
\nEnCore CCS Limited
\u2013
UK
\n2
\nDormant company
\nEnCore Natural Resources Limited
\u2013
UK
\n2
\nDormant company
\nEnCore Oil and Gas Limited
\u2013
UK
\n2
\nDormant company
\nHarbour Energy Developments Limited
\u2013
UK
\n2
\nDormant company
\nHarbour Energy Production Limited
\u2013
UK
\n2
\nDormant company
\nHarbour Energy Secretaries Limited
\n(formerly Premier Oil Ebury Limited)
\u2013
UK
\n2
\nNon-trading
\nChrysaor Petroleum Chemicals U.K. Limited
\n(formerly Harbour Energy Services Limited)
\u2013
UK
\n2
\nDormant company
\nPremier Oil B Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil Belgravia Holdings Limited
\u2013
UK
\n2
\nNon-trading Intermediate holding company
\nPremier Oil Belgravia Limited
\u2013
UK
\n2
\nNon-trading
\nPremier Oil Bukit Barat Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil Buton BV
\u2013
Netherlands
\n7
\nNon-trading
\nPremier Oil CCS Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil Congo (Marine IX) Limited
\u2013
Jersey
\n6
\nDormant company
\nPremier Oil Exploration and Production (Iraq) Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil Exploration Limited
\u2013
UK
\n5
\nNon-trading
\nPremier Oil Exploration ONS Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil International Holding BV
\u2013
Netherlands
\n7
\nNon-trading
\nPremier Oil Investments Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil ONS Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil Paci\ufb01c Limited
\u2013
Hong Kong
\n12
\nDormant company
\nPremier Oil Pakistan Offshore BV
\u2013
Netherlands
\n7
\nDormant company
\nPremier Oil Philippines BV
\u2013
Netherlands
\n7
\nDormant company
\nPremier Oil Vietnam North BV
\u2013
Netherlands
\n7
\nNon-trading
\nPremier Overseas Holdings Limited
\u2013
UK
\n2
\nDormant company
\nXEO Exploration plc
\u2013
UK
\n2
\nDormant company
\nNotes:
\n1
Held directly by the company. All other companies are held through a subsidiary undertaking.
\n2
Registered of\ufb01ce \u2013 23 Lower Belgrave Street, London SW1W ONR, United Kingdom.
\n3
Registered of\ufb01ce \u2013 Haakon VII\u2019s gate 1, 4
\nth
\nFloor, 0161 Oslo, Norway.
\n4
Registered of\ufb01ce \u2013 Riverside One, Sir John Rogerson\u2019s Quay, Dublin 2, Ireland.
\n5
Registered of\ufb01ce \u2013 4
\nth
\nFloor, Saltire Court, 20 Castle Terrace, Edinburgh EH1 2EN, United Kingdom.
\n6
Registered of\ufb01ce \u2013 46/50 Kensington Place, 1
\nst
\nFloor, Kensington Chambers, St. Helier JE4 0ZE, Jersey.
\n7
Registered of\ufb01ce \u2013 Herikerbergweg 88, 1101 CM, Amsterdam, Netherlands.
\n8
Registered of\ufb01ce \u2013 Commerce House, Wickhams Cay 1, Road Town, Tortola VG1110, British Virgin Islands.
\n9
Registered of\ufb01ce \u2013 Rua Lauro Muller, 116 \u2013 Sala 3201, Botafogo, Rio de Janeiro, CEP: 22.290-160, Brazil.
\n10 Registered of\ufb01ce \u2013 Presidente Masaryk 111, Piso 1, Polanco V Seccion, Mexico City CP 11560, Mexico.
\n11 Registered of\ufb01ce \u2013 Level 5, Mill Court, La Charroterie, St Peter Port GY1 1EJ, Guernsey.
\n12 Registered of\ufb01ce \u2013 31/F, Tower Two, Time Square, 1 Matheson Street, Causeway Bay, Hong Kong.
\n13 Cricket Square, Hutchins Drive, PO Box 2681, Grand Cayman KY1-1111, Cayman Islands. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfNotesAndOtherExplanatoryInformationExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15931": {
"value": "Harbour Energy plc",
"dimensions": {
"concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15932": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15934": {
"value": "4 th
\nFloor, Saltire Court, 20 Castle Terrace, Edinburgh EH1 2EN, United Kingdom. ",
"dimensions": {
"concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15939": {
"value": "United Kingdom",
"dimensions": {
"concept": "ifrs-full:PrincipalPlaceOfBusiness",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15940": {
"value": "United Kingdom",
"dimensions": {
"concept": "ifrs-full:CountryOfIncorporation",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15941": {
"value": "United Kingdom",
"dimensions": {
"concept": "ifrs-full:DomicileOfEntity",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15943": {
"value": "Harbour Energy plc (the company)",
"dimensions": {
"concept": "ifrs-full:NameOfUltimateParentOfGroup",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15945": {
"value": "2022-12-31",
"dimensions": {
"concept": "ifrs-full:DateOfEndOfReportingPeriod2013",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15947": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15952": {
"value": "2. Signi\ufb01cant accounting policies Basis of preparation
\nThe consolidated \ufb01nancial statements have been prepared on a going concern basis in accordance with UK-adopted International
\nAccounting Standards (IAS) in conformity with the requirements of the Companies Act 2006. The analysis used by the Directors in
\nadopting the going concern basis considers the various plans and commitments of the Group as well as various sensitivity and reverse
\nstress test analyses. The results from the downside sensitivities with regard to production and commodity price assumptions, which in
\nmanagement\u2019s view re\ufb02ect two of the principal risks, indicate that material changes within one year that would impact the going concern
\nbasis of preparation are unlikely. Further details are within the Financial review on pages 44-49 and Viability statement on page 53.
\nThe presentation currency of the Group \ufb01nancial information is US dollars and all values in the Group \ufb01nancial information are presented
\nin millions ($ million) and all values are rounded to the nearest $0.1 million, except where otherwise stated.
\nThe \ufb01nancial statements have been prepared on the historical cost basis, except for certain \ufb01nancial assets and liabilities, including
\nderivative \ufb01nancial instruments, which have been measured at fair value.
\nIn October 2020, Harbour Energy Limited entered into an agreement with Premier Oil plc (Premier) regarding an all-share merger between
\nPremier and Harbour Energy Limited\u2019s subsidiary, Chrysaor Holdings Limited (Chrysaor). Under the terms of the merger, Premier legally
\nacquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the acquiror for accounting purposes, primarily as a
\nresult of its ability to appoint the Board of the enlarged group. The transaction completed on 31 March 2021, whereupon Premier, being
\nthe legal acquirer and accounting acquiree, changed its name from Premier Oil plc to Harbour Energy plc.
\nThe consolidated \ufb01nancial statements provide comparative period information with respect to the prior year but this only includes nine
\nmonths of Premier contribution compared to a full 12 months contribution for the year ended 31 December 2022.
\nThe accounting policies, which follow, set out those policies which apply in preparing the \ufb01nancial statements for the year ended
\n31 December 2022. All accounting policies are consistent with those adopted and disclosed in Harbour\u2019s 2021 Annual Report and
\nAccounts, other than where new policies have been adopted.
\nBasis of consolidation
\nThe consolidated \ufb01nancial statements comprise the \ufb01nancial statements of the company and its subsidiaries as at 31 December 2022.
\nSubsidiaries are those entities over which the Group has control. Control is achieved where the Group has the power over the subsidiary,
\nhas rights, or is exposed to variable returns from the subsidiary and has the ability to use its power to affect its returns. All subsidiaries
\nare 100 per cent owned by the Group and there are no non-controlling interests.
\nIf the Group loses control over a subsidiary, it derecognises the related assets (including goodwill), liabilities, non-controlling interest and
\nother components of equity, while any resultant gain or loss is recognised in pro\ufb01t or loss. Any investment retained is recognised at fair value.
\nThe results of subsidiaries acquired or disposed of during the year are included in the income statement from the effective date of
\nacquisition or up to the effective date of disposal, as appropriate. Where necessary, adjustments are made to the \ufb01nancial statements
\nof subsidiaries acquired to bring the accounting policies used into line with those used by other members of the Group.
\nAll intra-group transactions and balances have been eliminated on consolidation.
\n123
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nPrior year adjustment
\nOther \ufb01nancial liabilities \u2013 commodity derivatives within current liabilities as at 31 December 2021 \u2013 included a number of \ufb01nancial
\ninstruments which had matured on the last day of the \ufb01nancial year for which the related liability should have been classi\ufb01ed within trade
\nand other payables. The relevant amounts have therefore been reclassi\ufb01ed to trade and other payables which is also held within current
\nliabilities (see note 19, Trade and other payables \u2013 matured \ufb01nancial instruments). There was no impact on any of the other primary
\nstatements. Each of the affected \ufb01nancial statement line items has been restated and the impact is summarised in the following table.
\nBalance sheet at 31 December 2021
Note
\nAs previously
\nreported
\n$ million
\nAdjustments
\n$ million
\nAs restated
\n$ million
\nOther \ufb01nancial liabilities \u2013 commodity derivatives
22
(2,526.2)
361.7
(2,164.5)
\nTrade and other payables
19
(873.6)
(361.7)
(1,235.3)
\nImpact of climate change on the \ufb01nancial statements and related disclosures
\nJudgements and estimates made in assessing the impact of climate change and the energy transition
\nHarbour monitors global climate change and energy transition developments and plans accordingly. Management recognises there is a general
\nhigh level of uncertainty about the speed and scale of impacts which, together with limited historical information, provides signi\ufb01cant challenges
\nin the preparation of forecasts and plans with a range of possible future scenarios.
\nThe Group\u2019s strategic ambition is to achieve net zero by 2035 through several opportunities, including operational improvements, UK
\noffshore electri\ufb01cation, UK carbon capture and storage (CCS) and the eventual cessation of production of mature \ufb01elds. Where the Group
\ncannot reduce its Scope 1 and 2 emissions, it will invest in carbon credits to achieve the goal of net zero (refer to the ESG review on
\npages 30-41). All new economic investment decisions include the cost of carbon, and opportunities are assessed on their climate-impact
\npotential and alignment with Harbour Energy\u2019s net zero goal, taking into consideration both GHG volumes and intensity. The corporate
\nmodelling that supports the preparation of the \ufb01nancial statements (such as asset impairment assessment, going concern and viability,
\ndeferred tax recoverability) includes project costs related to carbon, capture and storage; and certain limited electri\ufb01cation and reduction
\nof Scope 1 and 2 GHG emissions initiatives. Emissions reduction incentives are part of staff remuneration and annual bonus schemes
\n(refer to the Remuneration Committee report on pages 78-80). Additionally, the cost of borrowing is tied to our gross operated CO
\n2
\nemissions performance, with GHG metrics being linked to our RBL interest expense, further incentivising our emissions reduction targets.
\nAs a result, climate change and the energy transition have the potential to signi\ufb01cantly impact the accounting estimates adopted by
\nmanagement and therefore the valuation of assets and liabilities reported on the balance sheet. On an ongoing basis management
\ncontinues to assess the potential impacts on the signi\ufb01cant judgements and estimates used in the \ufb01nancial statements. Estimates
\nadopted in the preparation of the \ufb01nancial statements re\ufb02ect management\u2019s best estimate of future market conditions where, in
\nparticular, commodity prices can be volatile. Notwithstanding the challenges around climate change and the energy transition, it is
\nmanagement\u2019s view that the \ufb01nancial statements are consistent with the disclosures in the Strategic Report.
\nThis note provides insight into how Harbour has considered the impact on valuations of key line items in the \ufb01nancial statements and how
\nthey could change based on the climate change scenarios and sensitivities considered. The scenarios presented show what the possible
\nimpact could be on the \ufb01nancial statements considering both high and low-price curve outlooks. Importantly, these climate change
\nscenarios do not form the basis of the preparation of the \ufb01nancial statements but rather indicate how the key assumptions that underpin
\nthe \ufb01nancial statements would be impacted by the climate change scenarios. It is recognised that the reality of the nature of progress of
\nenergy transition will bring greater levels of disruption and volatility than these external scenarios expect and do not represent
\nmanagement\u2019s current best estimate.
\nManagement\u2019s current best estimate, which was derived from consideration of a range of considered economic forecasts, has been
\nused on the same basis to prepare the \ufb01nancial statements and is represented by the Harbour Scenario oil price curve. Management
\ncontinues to review these estimates and assumptions to ensure they re\ufb02ect the latest economic environment conditions and market
\ninformation available.
\nImpairment of property, plant and equipment, and goodwill
\nThe energy transition has the potential to signi\ufb01cantly impact future commodity and carbon prices which would, in turn, affect the
\nrecoverable amount of property, plant and equipment and goodwill. In the current period, the Harbour Scenario real long-term commodity
\nprice assumptions, when testing for impairment, were $65/bbl (2021: $65/bbl) and 65p/therm (2021: 60p/therm) for Brent crude and
\nUK NBP gas, respectively. The real long-term price assumptions for the UK regulatory price of carbon are \u00a380/tonne, being $100/tonne
\nat $:\u00a31.25 foreign exchange rate (2021: \u00a355/$74/tonne) and voluntary offsets $25/tonne used, with sensitivities run at $100/tonne
\n(2021: $100/tonne). Sensitivity analysis using a carbon price of $100/tonne indicates that material impairments would not arise. Such
\nassumptions are inherently uncertain and may ultimately differ from the actual amounts.
\nSee key sources of estimation uncertainty: recoverability of oil and gas assets and goodwill for further information (page 136), including
\nsensitivity analysis in relation to reasonably possible changes in price assumptions.
\n124
During 2022 there was a net pre-tax impairment credit of $170 million comprising: impairment on a single CGU asset $163 million,
\nimpairment reversals on North Sea assets $250 million and decommissioning provision reductions $83 million. In 2021, certain
\nimpairments were recognised as a result of underlying reservoir performance.
\nSensitivities on the impairment of property, plant and equipment and goodwill have been prepared using various price scenarios to
\nshow the possible impact on net book carrying values. As noted, the Harbour Scenario is the basis for the preparation of the \ufb01nancial
\nstatements and impairment sensitivities have been prepared at an average -10 per cent and +10 per cent to the Harbour Scenario
\naverage crude and selected published climate change price curves. Sensitivity analysis on carbon price $100/tonne indicates that
\nimpairments would not have a material impact on the \ufb01nancial statements.
\nThe sensitivity scenarios described below are price curves only and the modelling assumes that all other factors remain unchanged from
\nthe Harbour Scenario used for the basis of preparation of the \ufb01nancial statements. These sensitivities are stated before any management
\nmitigation actions to manage downside risks if the scenarios were to occur.
\n\u00bc
Harbour Scenario: base price curve for crude oil used for impairment testing.
\n\u00bc
NGFS Current Policies: re\ufb02ects high physical risks and low transition risks.
\n\u00bc
NGFS Delayed Transition: re\ufb02ects low physical risks and high transition risks.
\n\u00bc
IEA Net Zero 2050: re\ufb02ects low physical risks and low transition risks.
\n0
\n20
\n40
\n60
\n80
\n100
\n120
\n140
\n160
\n2020
\n2021
\n2022
\n2023
\n2024
\n2025
\n2026
\n2027
\n2028
\n2029
\n2030
\n2031
\n2032
\n2033
\n2034
\n2035
\n2036
\n2037
\n2038
\n2039
\n2040
\n2041
\n2042
\n2043
\n2044
\n2045
\n2046
\n2047
\n2048
\n2049
\n2050
\nBrent Crude
Harbour Scenario
IEA Net Zero 2050
NGFS Delayed Transition
NGFS Current Policies
\nThe graph above shows the crude oil price curves for the period to 2050 for the Harbour Scenario, NGFS Current Policies, NGFS Delayed
\nTransition and IEA Net Zero 2050. There are no climate change price curves published by NGFS or the IEA for UK NBP gas. All the scenario
\nprice curves are dependent on factors covering supply, demand, economic and geopolitical events and therefore are inherently uncertain
\nand subject to signi\ufb01cant volatility and hence unlikely to re\ufb02ect the future outcome.
\nThe results of the sensitivities are as follows and show the impact on the balance sheet carrying values.
\n$ million
Carrying value
Crude oil
\n-10% to
\nHarbour Scenario
\n+10% to
\nHarbour Scenario
\nNGFS Current
\nPolicies
\nNGFS Delayed
\nTransition
\nIEA Net Zero
\n2050
\nProperty, plant and equipment
5,690
(57)
\u2013
\u2013
\u2013
(355)
\nGoodwill
1,327
\u2013
\u2013
\u2013
\u2013
\u2013
\nThe sensitivity results show that under the -10 per cent to Harbour Scenario (oil and gas commodity prices reduced from 1 January 2023)
\nan impairment of $57 million would arise on a single North Sea CGU. The +10 per cent to Harbour Scenario (oil and gas commodity prices
\nincreased from 1 January 2023), NGFS Current and Delayed scenarios show no incremental impairments as these scenarios are all
\nfavourable to the Harbour Scenario. Furthermore, under these three scenarios, no reversal of any historic impairment is triggered as there
\nhave been no prior crude oil-price related impairments. Under the IEA Net Zero 2050 scenario there would be an impairment in property,
\nplant and equipment of $355 million with goodwill not impacted given suf\ufb01cient value headroom.
\nProperty, plant and equipment \u2013 depreciation and expected useful lives
\nThe energy transition has the potential to reduce the expected useful lives of assets and consequently accelerate depreciation charges.
\nThere are no signi\ufb01cant judgements and/or critical estimation uncertainty related to climate factors.
\nSee accounting policy: property, plant and equipment for further information (page 128).
\n125
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nIntangible assets \u2013 exploration and evaluation assets
\nThe energy transition has the potential to affect the future development or viability of exploration and evaluation prospects. A signi\ufb01cant
\nportion of the Group\u2019s exploration and evaluation assets relate to prospects that could be tied back to existing infrastructure and hence
\nrequire less capital investment as these assets are less exposed to the impacts of the energy transition compared to large frontier
\ndevelopments. At each balance sheet date, all exploration and evaluation prospects are reviewed against the Group\u2019s \ufb01nancial framework
\nto ensure that the continuation of activities is planned and expected. There are no signi\ufb01cant judgements and/or critical estimation
\nuncertainty related to climate factors.
\nSee judgements: exploration and evaluation expenditure (page 136) and note 11 for further information.
\nDecommissioning cost and provisions
\nThe energy transition may accelerate the decommissioning of assets which would result in an increase in the carrying value of associated
\ndecommissioning provisions. Whilst the Group currently expects to incur decommissioning costs over the next 40 years, we anticipate the
\nmajority of costs will be incurred between the next 10 to 20 years which will reduce the exposure to the impact of the energy transition.
\nDecommissioning cost estimates are based on the known regulatory and external environment. These cost estimates and recoverability
\nof associated deferred tax may change in the future, including as a result of the energy transition.
\nOn 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
\nreduction in the applied discount rates used to assess the \ufb01nal decommissioning obligation, would result in increases to the decommissioning
\nprovision of approximately $417 million and $162 million, respectively. This change would be principally offset by a change to the value of the
\nassociated asset unless the asset is fully depreciated, in which case the change in estimate is recognised directly within the income statement.
\nThe energy transition may accelerate the decommissioning of producing assets and therefore increase the carrying value of provisions.
\nThe Group currently expects to incur decommissioning costs over the next 40 years, the majority of which are anticipated to be incurred
\nbetween the next 10 to 20 years. Currently, the timing of decommissioning expenditures have not been materially brought forward and
\nmanagement do not consider that any reasonable change in the timing of decommissioning expenditure will have a material impact on
\nthe decommissioning provisions.
\nSee key sources of estimation uncertainty: decommissioning costs for further information (page 136).
\nSegment reporting
\nThe Group\u2019s activities consist of one class of business being the acquisition, exploration, development and production of oil and gas
\nreserves and related activities, and are split geographically and managed in two business units: namely North Sea and International.
\nJoint arrangements
\nA joint arrangement is one in which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an
\narrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
\nExploration and production operations are usually conducted through joint arrangements with other parties. The Group reviews all joint
\narrangements and classi\ufb01es them as either joint operations or joint ventures depending on the rights and obligations of each party to
\nthe arrangement and whether the arrangement is structured through a separate vehicle. The Group\u2019s interest in joint operations, such
\nas exploration and production arrangements, are accounted for by recognising its:
\n\u00bc
Assets, including its share of any assets held jointly.
\n\u00bc
Liabilities, including its share of any liabilities incurred jointly.
\n\u00bc
Revenue from the sale of its share of the output arising from the joint operation.
\n\u00bc
Expenses, including its share of any expenses incurred jointly.
\nA joint venture, which normally involves the establishment of a separate legal entity, is a contractual arrangement whereby the parties
\nthat have joint control of the arrangement have the rights to the arrangement\u2019s net assets. The results, assets and liabilities of a joint
\nventure are incorporated in the consolidated \ufb01nancial statements using the equity method of accounting. During 2022, the Group did not
\nhave any interests in joint ventures.
\nWhere the Group transacts with its joint operations, unrealised pro\ufb01ts and losses are eliminated to the extent of the Group\u2019s interest in
\nthe joint operation.
\n126
Foreign currency translation
\nEach entity in the Group determines its own functional currency, being the currency of the primary economic environment in which the
\nentity operates, and items included in the \ufb01nancial statements of each entity are measured using that functional currency.
\nThe consolidated \ufb01nancial statements are presented in US dollars, which is also the parent company\u2019s functional currency.
\nTransactions recorded in foreign currencies are initially recorded in the entity\u2019s functional currency by applying an average rate of
\nexchange. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency rate of exchange
\nruling at the reporting date. All differences are taken to the income statement.
\nNon-monetary assets and liabilities denominated in foreign currencies are measured at historic cost based on exchange rates at the date
\nof the initial transaction and subsequently not retranslated.
\nOn consolidation, the assets and liabilities of the Group\u2019s operations are translated at exchange rates prevailing on the balance sheet
\ndate. Income and expense items are translated at the average monthly exchange rates for the year. Equity is held at historic cost and is
\nnot retranslated. The resulting exchange differences are recognised as other comprehensive income and are transferred to the Group\u2019s
\ncurrency translation reserve.
\nWhen an overseas operation is disposed of, such translation differences relating to it are recognised as income or expense.
\nCurrent versus non-current classi\ufb01cation
\nThe Group presents assets and liabilities in the statement of \ufb01nancial position based on current or non-current classi\ufb01cation.
\nAn asset is current when it is:
\na. expected to be realised or intended to be sold or consumed in the normal operating cycle;
\nb. held primarily for the purpose of trading;
\nc. expected to be realised within 12 months after the reporting period; or
\nd.
cash or cash equivalent unless restricted from being exchanged or used to settle a liability for at least 12 months after the reporting period.
\nAll other assets are classi\ufb01ed as non-current.
\nA liability is current when:
\na. it is expected to be settled in the normal operating cycle;
\nb. it is held primarily for the purpose of trading;
\nc. it is due to be settled within 12 months after the reporting period, or;
\nd. there is no unconditional right to defer the settlement of the liability for at least 12 months after the reporting period.
\nThe terms of the liability that could, at the option of the counterparty, result in its settlement by the issue of equity instruments do
\nnot affect its classi\ufb01cation. The Group classi\ufb01es all other liabilities as non-current. Deferred tax assets and liabilities are classi\ufb01ed
\nas non-current assets and liabilities.
\nBusiness combinations
\nBusiness combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the
\nassets transferred, equity instruments issued and liabilities incurred or assumed at the date of completion of the acquisition. Acquisition
\ncosts incurred are expensed and included in administrative expenses. Where applicable, the consideration for the acquisition includes
\nany asset or liability resulting from a contingent consideration arrangement, measured at its fair value at acquisition.
\nThe identi\ufb01able assets, liabilities and contingent liabilities acquired that meet the conditions for recognition under IFRS 3 are recognised
\nat their fair value at the acquisition date, except that:
\n\u00bc
Deferred tax assets or liabilities and liabilities or assets related to employee bene\ufb01t arrangements are recognised and measured in
\naccordance with IAS 12 Income Taxes and IAS 19 Employee Bene\ufb01ts, respectively.
\n\u00bc
Lease arrangements that represent leases as de\ufb01ned by IFRS 16 Leases are recognised and measured in accordance with IFRS 16 Leases.
\n\u00bc
Liabilities or equity instruments related to the replacement by the Group of an acquirer\u2019s share-based payment awards are measured
\nin accordance with IFRS 2 Share-Based Payment.
\n127
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nIf the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the
\nGroup reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted during the
\nmeasurement period, or additional assets or liabilities are recognised to re\ufb02ect new information obtained about facts and circumstances
\nthat existed as of the acquisition date that, if known, would have affected the amounts recognised as of that date. The measurement period
\nis the period from the date of acquisition to the date the Group obtains complete information about facts and circumstances that existed as
\nof the acquisition date, subject to a maximum of one year.
\nGoodwill
\nIn 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
\nIFRS 3 Business Combinations, the acquisition method of accounting is applied. Goodwill represents the difference between the aggregate of
\nthe fair value of purchase consideration transferred at the acquisition date and the fair value of the identi\ufb01able assets, liabilities and contingent
\nliabilities acquired. If however, the fair value of the purchase consideration transferred is lower than the fair value of the identi\ufb01able assets and
\nliabilities acquired, the difference is recognised in the income statement as negative goodwill. Goodwill is initially measured at cost. Following
\ninitial recognition, goodwill is measured at cost less any accumulated impairment. For the purpose of impairment testing, goodwill acquired in a
\nbusiness combination is, from the acquisition date, allocated to each of the Group\u2019s cash-generating units (CGUs), or groups of CGUs, that are
\nexpected to bene\ufb01t from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Goodwill
\nis 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
\nrate of exchange at each reporting date.
\nGoodwill, as disclosed in note 10, is not amortised but is reviewed for impairment at least annually by assessing the recoverable amount of
\nthe CGUs to which the goodwill relates. Where the carrying amount of the CGU and related goodwill is higher than the recoverable amount
\nof the CGU, an impairment loss is recognised in the income statement. The recoverable amounts of the CGUs have been determined on a
\nfair value less costs to sell basis. Impairment losses relating to goodwill cannot be reversed in future periods. Goodwill acquired through
\nbusiness combinations has been allocated to two CGUs, being North Sea and International.
\nOil and gas assets
\nIntangibles
\nPre-licence costs
\nPre-licence costs are expensed in the period in which they are incurred.
\nLicence and property acquisition costs
\nLicence and property acquisition costs paid in connection with a right to explore in an existing exploration area are capitalised as exploration
\nand evaluation costs within intangible assets.
\nLicence and property acquisition costs are reviewed at each reporting date to con\ufb01rm that there is no indication that the carrying amount
\nexceeds the recoverable amount. If no future activity is planned or the related licence has been relinquished or has expired, the carrying
\nvalue of the property acquisition costs is written off through the income statement. Upon recognition of proved reserves and internal
\napproval for development, the relevant expenditure is transferred to oil and gas properties within development and production assets.
\nExploration and evaluation costs
\nOnce the legal right to explore has been acquired, costs directly associated with the exploration are capitalised as exploration and evaluation
\n(E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential commercial
\nresources are discovered, the exploration asset is written off.
\nAll such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment at
\nleast annually. This is to con\ufb01rm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the
\ncase, the costs are written off through the income statement.
\nWhen proved reserves of oil or natural gas are identi\ufb01ed and development is sanctioned by management, the relevant capitalised
\nexpenditure is \ufb01rst assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is transferred to
\noil and gas properties within development and production assets. No amortisation is charged during the exploration and evaluation phase.
\nFarm-outs \u2013 in the exploration and evaluation phase
\nThe 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
\nand evaluation farm-out arrangements but re-designates any costs previously capitalised in relation to the whole interest
\nas relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously
\ncapitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.
\nProperty, plant and equipment \u2013 oil and gas assets
\nOil and gas development and production assets are accumulated generally on a \ufb01eld-by-\ufb01eld basis. This represents expenditure on the
\nconstruction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells,
\nincluding E&E expenditures incurred in \ufb01nding commercial reserves transferred from intangible E&E assets, as outlined in the intangible
\nasset policy above, which is capitalised as oil and gas properties within development and production assets.
\n128
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into
\noperation, the initial estimate of the decommissioning obligation and, for qualifying assets, where relevant, borrowing costs. The purchase
\nprice or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
\nAn item of development and production expenditure and any signi\ufb01cant part initially recognised is derecognised upon disposal or when
\nno future economic bene\ufb01ts are expected. Any gain or loss arising on derecognition of the asset (calculated as the difference between
\nthe net disposal proceeds and the carrying amount of the asset) is included in the income statement.
\nExpenditure on major maintenance includes re\ufb01ts, inspections or repairs comprising the cost of replacement assets or parts of assets,
\ninspection costs and overhaul costs. Where an asset, or part of an asset, that was separately depreciated and is now written off is
\nreplaced and it is probable that future economic bene\ufb01ts associated with the item will \ufb02ow to the Group, the expenditure is capitalised.
\nAll other day-to-day repairs and maintenance costs are expensed as incurred.
\nDepreciation, depletion and amortisation (DD&A) of oil and gas assets
\nAll costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is provided
\ngenerally 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
\ncommercial proven and probable reserves of the \ufb01eld, considering future development expenditures necessary to bring those reserves
\ninto production.
\nWhen there is a change in the estimated total recoverable proven and probable reserves of a \ufb01eld, that change is accounted for in the
\ndepreciation charge over the revised remaining proven and probable reserves.
\nAcquisitions, asset purchases and disposals
\nAcquisitions of oil and gas properties are accounted for using the acquisition method when the assets acquired, and liabilities assumed
\nconstitute a business.
\nTransactions involving the purchase of an individual \ufb01eld interest, or a group of \ufb01eld interests, that do not constitute a business, are
\ntreated as asset purchases irrespective of whether the speci\ufb01c transactions involve the transfer of the \ufb01eld interests directly or the
\ntransfer of an incorporated entity. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to
\nthe assets and liabilities purchased on an appropriate basis.
\nProceeds on disposal are applied to the carrying amount of the speci\ufb01c intangible asset or oil and gas property disposed of and any
\nsurplus is recorded as a gain on disposal in the income statement.
\nDecommissioning
\nA provision for decommissioning is recognised in full when the related facilities are installed. The amount recognised is the present value
\nof the estimated future expenditure. A corresponding amount equivalent to the provision is also recognised as part of the cost of the
\nrelated oil and gas property. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the
\npresent value of the estimated expenditure is dealt with from the start of the \ufb01nancial year as an adjustment to the opening provision
\nand the oil and gas property. The unwinding of the discount is included as a \ufb01nance cost.
\nNon-oil and gas assets
\nProperty, plant and equipment \u2013 \ufb01xtures and \ufb01ttings and o\ufb03ce equipment
\nFixtures and \ufb01ttings and of\ufb01ce equipment is stated at cost less accumulated depreciation and impairment. Depreciation is provided for
\non 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
\nlives. The depreciation periods for the principal categories of assets are as follows:
\n\u00bc
Fixtures and \ufb01ttings: Up to 10 years.
\n\u00bc
Of\ufb01ce furniture and equipment: Up to 5 years.
\nIntangible assets
\nIntangible assets, which principally comprise IT software/licences, are carried at cost less any accumulated amortisation. These assets
\nare amortised on a straight-line basis over their useful economic lives of between three and ten years.
\nImpairment of non-current assets (excluding goodwill)
\nIn accordance with IAS 36 Impairment of Assets, impairment tests are carried out on items of property, plant and equipment and
\nintangible assets where there is an indicator of impairment, or an indicator identi\ufb01ed that a prior year impairment may have reversed
\nor decreased. Such indications may be based on events or changes in the market environment, or on internal sources of information.
\nImpairment and reversal indicators
\nProperty, plant and equipment and intangible assets with \ufb01nite useful lives are only tested for impairment when there is an indication
\nthat they may be impaired. This is generally the result of signi\ufb01cant changes to the environment in which the assets are operated or when
\nasset performance is signi\ufb01cantly lower than expected.
\n129
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nThe main impairment indicators used by the Group are described below:
\n\u00bc
External sources of information:
\n\u2013
Signi\ufb01cant changes in the economic, technological, political or market environment in which the entity operates or to which an asset
\nis dedicated.
\n\u2013
Fall in demand.
\n\u2013
Changes in commodity prices and exchange rates.
\n\u00bc
Internal sources of information:
\n\u2013
Evidence of obsolescence or physical damage.
\n\u2013
Signi\ufb01cantly lower than expected production or cost performance.
\n\u2013
Reduction in reserves and resources, including as a result of unsuccessful results of drilling operations.
\n\u2013
Pending expiry of licence or other rights.
\n\u2013
In respect of capitalised exploration and evaluation costs, lack of planned future activity on the prospect or licence.
\n\u2013
For reversals, plausible downside sensitivity scenarios are run to test the robustness of the asset carrying values typically against
\nchanges in production and commodity prices.
\nMeasurement of recoverable amount
\nThe cash-generating unit (CGU) applied for impairment test purposes is generally the \ufb01eld, except that a number of \ufb01eld interests may
\nbe grouped as a single CGU where the cash in\ufb02ows of each \ufb01eld are interdependent. The carrying value of each CGU is compared against
\nthe expected recoverable amount of the asset, which is primarily determined based on the fair value less cost of disposal (FVLCD)
\nmethod, where the fair value is determined from the estimated present value of the future net cash \ufb02ows expected to be derived from
\nproduction of commercial reserves. Standard valuation techniques are used based on the discount rates that re\ufb02ect the speci\ufb01c
\ncharacteristics of the operating entities concerned; discount rates are determined on a post-tax basis and applied to post-tax cash \ufb02ows.
\nAny impairment loss is recorded in the income statement under Impairment of property, plant and equipment. Impairment losses
\nrecorded in relation to property, plant and equipment may be subsequently reversed if the recoverable amount of the assets
\nsubsequently increases above carrying value. The increased carrying amount of an item of property, plant or equipment attributable to a
\nreversal of an impairment loss may not exceed the carrying amount that would have been determined (net of depreciation/amortisation)
\nhad no impairment loss been recognised in prior periods.
\nFinancial instruments
\nFinancial assets
\nFinancial instruments are recognised and measured in accordance with IFRS 9 Financial Instruments.
\nThe Group uses two criteria to determine the classi\ufb01cation of \ufb01nancial assets: the Group\u2019s business model and contractual cash \ufb02ow
\ncharacteristics of the \ufb01nancial assets. Where appropriate the Group identi\ufb01es three categories of \ufb01nancial assets: amortised cost,
\nfair value through pro\ufb01t or loss (FVTPL), and fair value through other comprehensive income (FVOCI).
\nFinancial assets held at amortised cost
\nFinancial assets held at amortised cost are initially measured at fair value except for trade debtors which are initially measured at cost.
\nBoth are subsequently carried at amortised cost using the effective interest rate (EIR) method, less impairment. The EIR amortisation is
\npresented within \ufb01nance income in the income statement.
\nCash and cash equivalents
\nCash and cash equivalents comprise cash at bank and other short-term highly liquid investments that are readily convertible to a known
\namount of cash and are subject to an insigni\ufb01cant risk of changes in value.
\nImpairment of \ufb01nancial assets
\nThe Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through pro\ufb01t or loss.
\nECLs are based on the difference between the contractual cash \ufb02ows due in accordance with the contract and all the cash \ufb02ows that the
\nGroup expects to receive, discounted at an approximation of the original effective interest rate.
\nECLs are recognised in two stages. For credit exposures for which there has not been a signi\ufb01cant increase in credit risk since initial recognition,
\nECLs are provided for credit losses that result from default events that are possible within the next 12 months (a 12-month ECL).
\n130
Default events could include:
\n\u00bc
Payment default, i.e. the failure to pay principal or interest when it falls due for payment.
\n\u00bc
Prospective default, when payment is not yet due, but it is clear that it will not be capable of being paid when it does fall due.
\n\u00bc
Covenant default, when the borrower fails to keep a promise (a covenant) that it has made in the contract.
\nFor those credit exposures for which there has been a signi\ufb01cant increase in credit risk since initial recognition, a loss allowance is
\nrequired for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default (a lifetime ECL).
\nFor trade receivables and contract assets, the Group applies a simpli\ufb01ed approach in calculating ECLs as allowed under IFRS 9.
\nProvision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as
\nadjusted for forward-looking factors speci\ufb01c to the debtors, the economic environment and the Group\u2019s historical credit loss experience.
\nCredit impaired \ufb01nancial assets
\nAt each reporting date, the Group assesses whether \ufb01nancial assets carried at amortised cost and debt \ufb01nancial assets carried at FVOCI
\nare credit impaired. A \ufb01nancial asset is credit impaired when one or more events that have a detrimental impact on the estimated future
\ncash \ufb02ows of the \ufb01nancial asset have occurred.
\nEvidence that a \ufb01nancial asset is credit impaired includes the following observable data:
\n\u00bc
Signi\ufb01cant \ufb01nancial dif\ufb01culty of the borrower or issuer.
\n\u00bc
A breach of contract such as default or past due event.
\n\u00bc
The restructuring of a loan or advance by the Group on terms that the Group would otherwise not consider.
\n\u00bc
It is becoming probable that the borrower will enter bankruptcy or other \ufb01nancial reorganisation.
\n\u00bc
The disappearance of an active market for a security because of \ufb01nancial dif\ufb01culties.
\nFinancial liabilities
\nFinancial liabilities are classi\ufb01ed, at initial recognition, as \ufb01nancial liabilities at fair value through pro\ufb01t or loss, loans and borrowings,
\npayables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. All \ufb01nancial liabilities are recognised
\ninitially at fair value and, in the case of loans, borrowings and payables, net of directly attributable transaction costs.
\nBorrowings and loans
\nInterest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including
\npremiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement
\nusing the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the
\nyear in which they arise.
\n Derecognition
\nA \ufb01nancial liability is derecognised when the obligation under the liability is discharged, cancelled, or expires. When an existing \ufb01nancial
\nliability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially
\nmodi\ufb01ed, such an exchange or modi\ufb01cation is treated as the derecognition of the original liability and the recognition of a new liability.
\nThe difference in the respective carrying amounts is recognised in the income statement.
\nDerivative \ufb01nancial instruments
\nThe Group uses derivative \ufb01nancial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and
\ncommodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative
\n\ufb01nancial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative \ufb01nancial instruments are
\ndesignated as cash \ufb02ow hedges in line with the Group\u2019s risk management policies. When derivatives do not qualify for hedge accounting
\nor are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.
\nCash \ufb02ow hedges
\nThe effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
\nhedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
\ntransaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
\nrecognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
\nAny gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
\nineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
\ncredit-worthiness of the counterparty is signi\ufb01cant and may dominate the transaction and lead to losses.
\n131
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nFair values
\nFair 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
\nmarket participants at the measurement date. It is determined by reference to quoted market prices adjusted for estimated transaction
\ncosts that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models
\nand estimated discounted values of cash \ufb02ows.
\nFor \ufb01nancial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques.
\nUnder IFRS 9, embedded derivatives are not separated from a host \ufb01nancial asset, and are classi\ufb01ed based on their contractual terms
\nand the Group\u2019s business model.
\nEquity
\nShare capital
\nShare capital includes the total net proceeds, both nominal and share premium, on the issue of ordinary and preference shares
\nof the company.
\nCapital redemption reserve
\nThe capital redemption reserve represents the nominal value of shares transferred following the company\u2019s purchase of them.
\nMerger reserve
\nOn 31 March 2021, Harbour Energy plc (formerly Premier Oil plc) acquired Chrysaor Holdings Limited as part of a reverse acquisition.
\nUnder the terms of the merger, Premier legally acquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the
\nacquirer for accounting purposes, primarily as a result of its ability to appoint the Board of the enlarged group. The merger reserve
\nprimarily represents Premier\u2019s opening balance on the legal reserve plus the fair value of the assets and liabilities acquired by Chrysaor.
\nCash \ufb02ow hedge reserve
\nThe cash \ufb02ow hedge and cost of hedging reserves represent gains and losses on derivatives classi\ufb01ed as effective cash \ufb02ow hedges.
\nUpon the designation of option instruments as hedging instruments, the intrinsic and time value components are separated, with only
\nthe intrinsic component being designated as the hedging instrument and the time value component is deferred in other comprehensive
\nincome as a cost of hedging.
\nCurrency translation reserve
\nThis reserve comprises exchange differences arising on consolidation of the Group\u2019s operations with a functional currency other than
\nthe US dollar.
\nShare-based payments
\nThe Group has applied the requirements of IFRS 2 Share-Based Payment. The Group has share-based awards that are equity and cash
\nsettled 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
\nfor the effect of any market-based conditions. The fair value determined at the grant date of the equity-settled share-based payments is
\nexpensed on a straight-line basis over the vesting period, based on the Group\u2019s estimate of shares that will eventually vest and adjusted
\nfor the effect of non-market based vesting conditions. For cash-settled awards, a liability is recognised for the goods or service acquired.
\nThis is measured initially at the fair value of the liability. The fair value of the liability is subsequently remeasured at each balance sheet
\ndate until the liability is settled, and at the date of settlement, with any changes in fair value recognised in the income statement.
\nInventories
\nAll inventories, except for petroleum products, are stated at the lower of cost and net realisable value. The cost of materials is the
\npurchase cost, determined on a \ufb01rst-in, \ufb01rst-out basis. Petroleum products and underlift and overlift positions are measured at net
\nrealisable value using an observable year-end oil or gas market price, and are included in other debtors or creditors, respectively.
\nLeases
\nLeases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use
\nby the Group. The \ufb01nance cost is charged to the income statement over the lease period so as to produce a constant periodic rate of
\ninterest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of lease term
\nand useful life. The Group recognises right-of-use assets and lease liabilities on a gross basis and the recovery of lease costs from
\njoint operations\u2019 partners is recorded as other income.
\n132
Right-of-use assets and lease liabilities arising from a lease are initially measured on a present value basis re\ufb02ecting the net present
\nvalue of the \ufb01xed lease payments and amounts expected to be payable by the Group assuming leases run to full term. The Group has
\napplied judgement to determine the lease term for some lease contracts in which it is a lessee that include renewal options. The
\nassessment of whether the Group is reasonably certain to exercise such options impacts the lease term, which signi\ufb01cantly impacts
\nthe amount of lease liabilities and right-of-use assets recognised.
\nThe lease payments are discounted using the Group\u2019s incremental borrowing rates of between 1.9 per cent and 6.8 per cent, being
\nthe rate that the Group would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic
\nenvironment with similar terms and conditions.
\nTo determine the incremental borrowing rate, the Group where possible:
\n\u00bc
Uses recent third party \ufb01nancing received by the individual lessee as a starting point, adjusted to re\ufb02ect changes in \ufb01nancing conditions
\nsince third party \ufb01nancing was received.
\n\u00bc
Makes adjustments speci\ufb01c to the lease, for example term, country, currency and security.
\nThe Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in
\nthe lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability
\nis reassessed and adjusted against the right-of-use asset.
\nLease payments are allocated between principal and \ufb01nance cost. The \ufb01nance cost is charged to the income statement over the lease
\nperiod so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.
\nRight-of-use assets are measured at cost comprising the following:
\n\u00bc
The amount of the initial measurement of lease liability.
\n\u00bc
Any lease payments made at or before the commencement date less any lease incentives received.
\n\u00bc
Any initial direct costs and restoration costs.
\nRight-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.
\nPayments associated with short-term leases and leases of low value assets are recognised on a straight-line basis as an expense in the
\nincome statement. Short-term leases are leases with a lease term of 12 months or less.
\nFor lease arrangements where all partners of a joint operation are considered to share the primary responsibility for lease payments
\nunder a lease contract, the Group recognises its share of the respective right-of-use asset and lease liability. This situation is most
\ncommon where the parties of a joint operation co-sign the lease contract.
\nThe Group recognises a gross lease liability for leases entered into on behalf of a joint operation where it has primary responsibility
\nfor making the lease payments. In such instances, if the arrangement between the Group and the joint operation represents a \ufb01nance
\nsublease, the Group recognises a net investment in sublease for amounts recoverable from non-operators whilst derecognising the
\nrespective portion of the gross right-of-use asset. The gross lease liability is retained on the balance sheet.
\nThe net investment in sublease is classi\ufb01ed as either trade and other receivables or long-term receivables on the balance sheet
\naccording to whether or not the amounts will be recovered within 12 months of the balance sheet date. Finance income is recognised
\nin respect of net investment in subleases.
\nProvisions for liabilities
\nA 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
\nembodying economic bene\ufb01ts will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
\nThe expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money
\nis material, provisions are discounted using a current pre-tax rate that re\ufb02ects, where appropriate, the risk speci\ufb01c to the liability. Where
\ndiscounting is used, the increase in the provision due to the passage of time is recognised as part of \ufb01nance costs in the income statement.
\nThe estimated cost of dismantling and restoring the production and related facilities at the end of the economic life of each \ufb01eld is
\nrecognised in full when the related facilities are installed. The amount provided is the present value of the estimated future restoration
\ncost. A non-current asset is also recognised. Any changes to estimated costs or discount rates are dealt with prospectively.
\nThe Group recognises provision for the estimated CO
\n2
\nemissions costs when actual emissions exceed the emission rights granted and
\nstill held. When actual emissions exceed the amount of emission rights granted, provision is recognised for the exceeding emission rights
\nbased on the purchase price of allowance concluded in forward contracts or market quotations at the reporting date.
\n133
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nGroup retirement bene\ufb01ts
\nPayments to de\ufb01ned contribution retirement bene\ufb01t plans are charged as an expense as they fall due. Payments made to state-managed
\nretirement bene\ufb01t schemes are dealt with as payments to de\ufb01ned contribution plans where the Group\u2019s obligations under the schemes
\nare equivalent to those arising in a de\ufb01ned contribution retirement bene\ufb01t plan.
\nThe Group operates a de\ufb01ned bene\ufb01t pension scheme, which requires contributions to be made to a separately administered fund.
\nThe cost of providing bene\ufb01ts is determined using the projected unit credit method, with actuarial valuations being carried out at each
\nbalance sheet date. Actuarial gains and losses are recognised immediately in the statement of comprehensive income.
\nThe retirement bene\ufb01t obligation recognised in the balance sheet represents the present value of the de\ufb01ned bene\ufb01t obligation as
\nreduced by the fair value of plan assets. Any asset resulting from this calculation is limited to the present value of available refunds
\nand reductions in future contributions to the plan.
\nTrade payables
\nInitial recognition of trade payables is at fair value. Subsequently they are stated at amortised cost.
\nTaxes
\nCurrent tax
\nCurrent tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to
\nthe taxation authorities. The tax rates and laws used to compute the amount are those that are enacted or substantively enacted at the
\nreporting date in the countries where the Group operates and generates taxable income.
\nCurrent income tax related to items recognised directly in other comprehensive income or equity is recognised in other comprehensive
\nincome or directly in equity, not in the income statement.
\nDeferred tax
\nDeferred taxation is recognised in respect of all timing differences arising between the tax bases of the assets and liabilities and their
\ncarrying amounts in the \ufb01nancial statements with the following exceptions:
\n\u00bc
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
\ndeductible temporary difference, carried forward tax credits or tax losses can be utilised.
\n\u00bc
Deferred income tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply when
\nthe related asset is realised or liability is settled, based on tax rates and laws enacted or substantively enacted at the reporting date.
\nThe carrying amount of the deferred income tax asset is reviewed at each balance sheet date and reduced to the extent that it is no
\nlonger probable that suf\ufb01cient taxable pro\ufb01ts will be available to allow all or part of the asset to be recovered. The Group reassesses
\nany unrecognised deferred tax assets each year taking into account changes in oil and gas prices, the Group\u2019s proven and probable
\nreserves and resources pro\ufb01le and forecast capital and operating expenditures.
\n\u00bc
Deferred income tax assets and liabilities are offset only if a legally enforceable right exists to offset current assets against current tax liabilities,
\nthe deferred income tax relates to the same tax authority and that same tax authority permits the Group to make a single net payment.
\nDeferred tax is charged or credited in the income statement, except when it relates to items charged or credited in other comprehensive
\nincome, in which case the deferred tax is also dealt with in other comprehensive income.
\nRevenue from contracts with customers
\nRevenue from contracts with customers is recognised when the Group satis\ufb01es a performance obligation by transferring a good or
\nservice to a customer. A good or service is transferred when the customer obtains control of that good or service. Revenue associated
\nwith the sale of crude oil, natural gas, and natural gas liquids (NGLs) is measured based on the consideration speci\ufb01ed in contracts with
\ncustomers with reference to quoted market prices in active markets, adjusted according to speci\ufb01c terms and conditions as applicable
\naccording to the sales contracts. The transfer of control of oil, natural gas, natural gas liquids and other items sold by the Group occurs
\nwhen title passes at the point the customer takes physical delivery. The Group principally satis\ufb01es its performance obligations at a point
\nin time and the amounts of revenue recognised relating to performance obligations satis\ufb01ed over time are not signi\ufb01cant.
\n134
Over/underlift
\nDifferences between the production sold and the Group\u2019s share of production result in an overlift or an underlift. Overlift and underlift
\nare valued at net realisable value using an observable year-end oil or gas market price and included within payables or receivables,
\nrespectively. Movements during the accounting period are recognised within cost of sales.
\nInterest income
\nInterest income is recognised on an accruals basis, by reference to the principal outstanding and at the effective interest rate applicable.
\nBorrowing costs
\nBorrowing costs directly attributable to the acquisition, construction or production of an asset that necessarily takes a substantial period
\nof 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
\nthe funds used to \ufb01nance a project form part of general borrowings, the amount capitalised is calculated using a weighted average of
\nrates applicable to relevant general borrowings of the Group during the period. All other borrowing costs are recognised in the income
\nstatement in the period in which they are incurred.
\nNew accounting standards and interpretations
\nThe Group adopted new and revised accounting standards and interpretations relevant to its business and effective for accounting
\nperiods beginning on or after 1 January 2022, including:
\nAmendments to IFRS 3 \u2013 Reference to the Conceptual Framework
\nThe IASB issued amendments to IFRS 3 to update the reference to the 2018 Conceptual Framework. The amendments add an exception
\nto the recognition principle for liabilities and contingent liabilities within the scope of IAS 37 or IFRIC 21 and clarify existing guidance for
\ncontingent assets. The requirements are effective for annual reporting periods beginning on or after 1 January 2022 and apply prospectively.
\nIFRS 9 Financial Instruments \u2013 Fees in the 10 per cent test for derecognition of \ufb01nancial liabilities
\nAs part of its 2018-2020 annual improvements to IFRS standards process, the IASB issued an amendment to IFRS 9. The amendment
\nclari\ufb01es the fees that an entity includes when assessing whether the terms of a new or modi\ufb01ed \ufb01nancial liability are substantially different
\nfrom the terms of the original \ufb01nancial liability. These fees include only those paid or received between the borrower and the lender, including
\nfees paid or received by either the borrower or lender on the other\u2019s behalf. An entity applies the amendment to \ufb01nancial liabilities that are
\nmodi\ufb01ed or exchanged on or after the beginning of the annual reporting period in which the entity \ufb01rst applies the amendment.
\nThe amendment is effective for annual reporting periods beginning on or after 1 January 2022 with earlier adoption permitted. The
\nGroup has applied the amendments to \ufb01nancial liabilities that are modi\ufb01ed or exchanged on or after the beginning of the annual reporting
\nperiod in which the entity \ufb01rst applies the amendment.
\nAccounting standards issued but not yet effective
\nThe new and amended standards and interpretations that are issued, but not yet effective, up to the date of issuance of the Group\u2019s
\n\ufb01nancial statements are disclosed below. The Group intends to adopt these new and amended standards and interpretations, if
\napplicable, when they become effective.
\nAmendments to IAS 1, Presentation of Financial Statements \u2013 classi\ufb01cation of liabilities as current or non-current
\nOn 23 January 2020, the IASB issued a narrow-scope amendment to IAS 1 to clarify that liabilities are classi\ufb01ed as either current or
\nnon-current depending on the rights that exist at the end of the reporting period. Liabilities are classi\ufb01ed as non-current if the entity
\nhas a substantive right to defer settlement for at least 12 months at the end of the reporting period. The Group does not consider this
\namendment to have signi\ufb01cant impact on the classi\ufb01cation of its liabilities as either current or non-current when the standard becomes
\neffective on 1 January 2023.
\nAmendments to IAS 8 \u2013 De\ufb01nition of Accounting Estimates
\nIn February 2021, the International Accounting Standards Board issued De\ufb01nition of Accounting Estimates, which amended IAS 8
\nAccounting Policies, Changes in Accounting Estimates and Errors.
\nThe amendments introduced the de\ufb01nition of accounting estimates and included other amendments to IAS 8 to help entities distinguish
\nchanges in accounting estimates from changes in accounting policies, with the distinction important because changes in accounting
\nestimates are applied prospectively only to future transactions and other future events, but changes in accounting policies are generally
\nalso applied retrospectively to past transactions and other past events. The amendments are effective for annual periods beginning on
\nor after 1 January 2023.
\n135
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nAmendments to IAS 1 and IFRS Practice Statement 2 \u2013 Disclosure of Accounting Policies
\nIn February 2021, the International Accounting Standards Board issued amendments to IAS 1 Presentation of Financial Statements
\nand IFRS Practice Statement 2 Making Materiality Judgements. The amendments to IAS 1 require companies to disclose their material
\naccounting policy information rather than their signi\ufb01cant accounting policies. The amendments to IFRS Practice Statement 2 provides
\nguidance on how to apply the concept of materiality to accounting policy disclosures. The amendments are effective for annual periods
\nbeginning on or after 1 January 2023.
\nAmendments to IAS 12 \u2013 Deferred Tax related to Assets and Liabilities arising from a Single Transaction
\nOn 7 May 2021, the IASB issued amendments to IAS 12 Income Taxes. The amendments require companies to recognise deferred tax
\non transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences. According to the
\namended guidance, a temporary difference that arises on initial recognition of an asset or liability is not subject to the initial recognition
\nexemption if that transaction gave rise to equal amounts of taxable and deductible temporary differences. The proposed amendments
\nwill typically apply to transactions such as leases for the lessee and decommissioning obligations. The amendments are effective for
\nannual reporting periods beginning on or after 1 January 2023.
\nThe amendments listed above are not expected to have a material impact on the Group.
\nSigni\ufb01cant accounting judgements and estimates
\nThe preparation of the Group\u2019s \ufb01nancial statements in conformity with IFRS requires management to make judgements, estimates
\nand assumptions at the date of the \ufb01nancial statements. Estimates and assumptions are continuously evaluated and are based on
\nmanagement experience and other factors, including expectations of future events that are believed to be reasonable under the
\ncircumstances. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to
\nthe carrying amount of the assets or liabilities affected in future periods. In particular, the Group has identi\ufb01ed the following areas
\nwhere signi\ufb01cant judgement, estimates and assumptions are required.
\nJudgements
\nThe signi\ufb01cant accounting judgements for the Group are considered to be:
\n\u00bc
the application of the going concern basis of accounting (see Basis of preparation section above);
\n\u00bc
the carrying value of intangible exploration and evaluation assets, in relation to whether commercial determination of an exploration
\nprospect had been reached;
\n\u00bc
the carrying value of property, plant and equipment regarding assessing assets for indicators of impairment;
\n\u00bc
decommissioning costs in relation to the timing of when decommissioning would occur; and
\n\u00bc
tax and recognition of deferred tax assets, relating to the extent to which future taxable pro\ufb01ts are included in the assessment
\nof recoverability, including the Energy Pro\ufb01ts Levy (EPL).
\nKey sources of estimation uncertainty
\nDetails of the Group\u2019s critical accounting estimates are set out in these \ufb01nancial statements and are considered to be:
\n\u00bc
the carrying value of property, plant and equipment and goodwill, where the key assumptions relate to oil and gas prices expected to be
\nrealised, and 2P production pro\ufb01les;
\n\u00bc
decommissioning costs where the key assumptions relate to the discount and in\ufb02ation rates applied, applicable rig rates and expected
\ntiming of cessation of production (COP) on each \ufb01eld; and
\n\u00bc
tax and recognition of deferred tax assets, where key assumptions relate to oil and gas prices expected to be realised, and production pro\ufb01les.
\nThe results from downside sensitivities prepared with regard to production and commodity price assumptions, which in management\u2019s
\nview re\ufb02ect the principal risks, indicate that material changes that would impact the carrying amounts of assets and liabilities within the
\nnext \ufb01nancial year are unlikely.
\nFurther information is provided in the Audit and Risk Committee report on pages 68 to 71.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSummaryOfSignificantAccountingPoliciesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15955": {
"value": "Basis of preparation The consolidated \ufb01nancial statements have been prepared on a going concern basis in accordance with UK-adopted International
\nAccounting Standards (IAS) in conformity with the requirements of the Companies Act 2006. The analysis used by the Directors in
\nadopting the going concern basis considers the various plans and commitments of the Group as well as various sensitivity and reverse
\nstress test analyses. The results from the downside sensitivities with regard to production and commodity price assumptions, which in
\nmanagement\u2019s view re\ufb02ect two of the principal risks, indicate that material changes within one year that would impact the going concern
\nbasis of preparation are unlikely. Further details are within the Financial review on pages 44-49 and Viability statement on page 53.
\nThe presentation currency of the Group \ufb01nancial information is US dollars and all values in the Group \ufb01nancial information are presented
\nin millions ($ million) and all values are rounded to the nearest $0.1 million, except where otherwise stated.
\nThe \ufb01nancial statements have been prepared on the historical cost basis, except for certain \ufb01nancial assets and liabilities, including
\nderivative \ufb01nancial instruments, which have been measured at fair value.
\nIn October 2020, Harbour Energy Limited entered into an agreement with Premier Oil plc (Premier) regarding an all-share merger between
\nPremier and Harbour Energy Limited\u2019s subsidiary, Chrysaor Holdings Limited (Chrysaor). Under the terms of the merger, Premier legally
\nacquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the acquiror for accounting purposes, primarily as a
\nresult of its ability to appoint the Board of the enlarged group. The transaction completed on 31 March 2021, whereupon Premier, being
\nthe legal acquirer and accounting acquiree, changed its name from Premier Oil plc to Harbour Energy plc.
\nThe consolidated \ufb01nancial statements provide comparative period information with respect to the prior year but this only includes nine
\nmonths of Premier contribution compared to a full 12 months contribution for the year ended 31 December 2022.
\nThe accounting policies, which follow, set out those policies which apply in preparing the \ufb01nancial statements for the year ended
\n31 December 2022. All accounting policies are consistent with those adopted and disclosed in Harbour\u2019s 2021 Annual Report and
\nAccounts, other than where new policies have been adopted.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15956": {
"value": "Basis of preparation The consolidated \ufb01nancial statements have been prepared on a going concern basis in accordance with UK-adopted International
\nAccounting Standards (IAS) in conformity with the requirements of the Companies Act 2006. The analysis used by the Directors in
\nadopting the going concern basis considers the various plans and commitments of the Group as well as various sensitivity and reverse
\nstress test analyses. The results from the downside sensitivities with regard to production and commodity price assumptions, which in
\nmanagement\u2019s view re\ufb02ect two of the principal risks, indicate that material changes within one year that would impact the going concern
\nbasis of preparation are unlikely. Further details are within the Financial review on pages 44-49 and Viability statement on page 53.
\nThe presentation currency of the Group \ufb01nancial information is US dollars and all values in the Group \ufb01nancial information are presented
\nin millions ($ million) and all values are rounded to the nearest $0.1 million, except where otherwise stated.
\nThe \ufb01nancial statements have been prepared on the historical cost basis, except for certain \ufb01nancial assets and liabilities, including
\nderivative \ufb01nancial instruments, which have been measured at fair value.
\nIn October 2020, Harbour Energy Limited entered into an agreement with Premier Oil plc (Premier) regarding an all-share merger between
\nPremier and Harbour Energy Limited\u2019s subsidiary, Chrysaor Holdings Limited (Chrysaor). Under the terms of the merger, Premier legally
\nacquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the acquiror for accounting purposes, primarily as a
\nresult of its ability to appoint the Board of the enlarged group. The transaction completed on 31 March 2021, whereupon Premier, being
\nthe legal acquirer and accounting acquiree, changed its name from Premier Oil plc to Harbour Energy plc.
\nThe consolidated \ufb01nancial statements provide comparative period information with respect to the prior year but this only includes nine
\nmonths of Premier contribution compared to a full 12 months contribution for the year ended 31 December 2022.
\nThe accounting policies, which follow, set out those policies which apply in preparing the \ufb01nancial statements for the year ended
\n31 December 2022. All accounting policies are consistent with those adopted and disclosed in Harbour\u2019s 2021 Annual Report and
\nAccounts, other than where new policies have been adopted.",
"dimensions": {
"concept": "ifrs-full:StatementOfIFRSCompliance",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15960": {
"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
\nadopting the going concern basis considers the various plans and commitments of the Group as well as various sensitivity and reverse
\nstress test analyses. The results from the downside sensitivities with regard to production and commodity price assumptions, which in
\nmanagement\u2019s view re\ufb02ect two of the principal risks, indicate that material changes within one year that would impact the going concern
\nbasis of preparation are unlikely. Further details are within the Financial review on pages 44-49 and Viability statement on page 53.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGoingConcernExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15973": {
"value": "In October 2020, Harbour Energy Limited entered into an agreement with Premier Oil plc (Premier) regarding an all-share merger between Premier and Harbour Energy Limited\u2019s subsidiary, Chrysaor Holdings Limited (Chrysaor). Under the terms of the merger, Premier legally
\nacquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the acquiror for accounting purposes, primarily as a
\nresult of its ability to appoint the Board of the enlarged group. The transaction completed on 31 March 2021, whereupon Premier, being
\nthe legal acquirer and accounting acquiree, changed its name from Premier Oil plc to Harbour Energy plc.",
"dimensions": {
"concept": "ifrs-full:ExplanationOfChangeInNameOfReportingEntityOrOtherMeansOfIdentificationFromEndOfPrecedingReportingPeriod",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15981": {
"value": "The consolidated \ufb01nancial statements provide comparative period information with respect to the prior year but this only includes nine months of Premier contribution compared to a full 12 months contribution for the year ended 31 December 2022.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfReasonWhyFinancialStatementsAreNotEntirelyComparable",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f15990": {
"value": "Basis of consolidation The consolidated \ufb01nancial statements comprise the \ufb01nancial statements of the company and its subsidiaries as at 31 December 2022.
\nSubsidiaries are those entities over which the Group has control. Control is achieved where the Group has the power over the subsidiary,
\nhas rights, or is exposed to variable returns from the subsidiary and has the ability to use its power to affect its returns. All subsidiaries
\nare 100 per cent owned by the Group and there are no non-controlling interests.
\nIf the Group loses control over a subsidiary, it derecognises the related assets (including goodwill), liabilities, non-controlling interest and
\nother components of equity, while any resultant gain or loss is recognised in pro\ufb01t or loss. Any investment retained is recognised at fair value.
\nThe results of subsidiaries acquired or disposed of during the year are included in the income statement from the effective date of
\nacquisition or up to the effective date of disposal, as appropriate. Where necessary, adjustments are made to the \ufb01nancial statements
\nof subsidiaries acquired to bring the accounting policies used into line with those used by other members of the Group.
\nAll intra-group transactions and balances have been eliminated on consolidation.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16020": {
"value": "Prior year adjustment Other \ufb01nancial liabilities \u2013 commodity derivatives within current liabilities as at 31 December 2021 \u2013 included a number of \ufb01nancial
\ninstruments which had matured on the last day of the \ufb01nancial year for which the related liability should have been classi\ufb01ed within trade
\nand other payables. The relevant amounts have therefore been reclassi\ufb01ed to trade and other payables which is also held within current
\nliabilities (see note 19, Trade and other payables \u2013 matured \ufb01nancial instruments). There was no impact on any of the other primary
\nstatements. Each of the affected \ufb01nancial statement line items has been restated and the impact is summarised in the following table.
\nBalance sheet at 31 December 2021
Note
\nAs previously
\nreported
\n$ million
\nAdjustments
\n$ million
\nAs restated
\n$ million
\nOther \ufb01nancial liabilities \u2013 commodity derivatives
22
(2,526.2)
361.7
(2,164.5)
\nTrade and other payables
19
(873.6)
(361.7)
(1,235.3)",
"dimensions": {
"concept": "ifrs-full:DisclosureOfReclassificationsOrChangesInPresentationExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16249": {
"value": "Segment reporting The Group\u2019s activities consist of one class of business being the acquisition, exploration, development and production of oil and gas
\nreserves and related activities, and are split geographically and managed in two business units: namely North Sea and International.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForSegmentReportingExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16255": {
"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
\narrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
\nExploration and production operations are usually conducted through joint arrangements with other parties. The Group reviews all joint
\narrangements and classi\ufb01es them as either joint operations or joint ventures depending on the rights and obligations of each party to
\nthe arrangement and whether the arrangement is structured through a separate vehicle. The Group\u2019s interest in joint operations, such
\nas exploration and production arrangements, are accounted for by recognising its:
\n\u00bc
Assets, including its share of any assets held jointly.
\n\u00bc
Liabilities, including its share of any liabilities incurred jointly.
\n\u00bc
Revenue from the sale of its share of the output arising from the joint operation.
\n\u00bc
Expenses, including its share of any expenses incurred jointly.
\nA joint venture, which normally involves the establishment of a separate legal entity, is a contractual arrangement whereby the parties
\nthat have joint control of the arrangement have the rights to the arrangement\u2019s net assets. The results, assets and liabilities of a joint
\nventure are incorporated in the consolidated \ufb01nancial statements using the equity method of accounting. During 2022, the Group did not
\nhave any interests in joint ventures.
\nWhere the Group transacts with its joint operations, unrealised pro\ufb01ts and losses are eliminated to the extent of the Group\u2019s interest in
\nthe joint operation.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16291": {
"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
\nentity operates, and items included in the \ufb01nancial statements of each entity are measured using that functional currency.
\nThe consolidated \ufb01nancial statements are presented in US dollars, which is also the parent company\u2019s functional currency.
\nTransactions recorded in foreign currencies are initially recorded in the entity\u2019s functional currency by applying an average rate of
\nexchange. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency rate of exchange
\nruling at the reporting date. All differences are taken to the income statement.
\nNon-monetary assets and liabilities denominated in foreign currencies are measured at historic cost based on exchange rates at the date
\nof the initial transaction and subsequently not retranslated.
\nOn consolidation, the assets and liabilities of the Group\u2019s operations are translated at exchange rates prevailing on the balance sheet
\ndate. Income and expense items are translated at the average monthly exchange rates for the year. Equity is held at historic cost and is
\nnot retranslated. The resulting exchange differences are recognised as other comprehensive income and are transferred to the Group\u2019s
\ncurrency translation reserve.
\nWhen 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16294": {
"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.
\nThe consolidated \ufb01nancial statements are presented in US dollars, which is also the parent company\u2019s functional currency.
\nTransactions recorded in foreign currencies are initially recorded in the entity\u2019s functional currency by applying an average rate of
\nexchange. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency rate of exchange
\nruling at the reporting date. All differences are taken to the income statement.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16311": {
"value": "Current versus non-current classi\ufb01cation The Group presents assets and liabilities in the statement of \ufb01nancial position based on current or non-current classi\ufb01cation.
\nAn asset is current when it is:
\na. expected to be realised or intended to be sold or consumed in the normal operating cycle;
\nb. held primarily for the purpose of trading;
\nc. expected to be realised within 12 months after the reporting period; or
\nd.
cash or cash equivalent unless restricted from being exchanged or used to settle a liability for at least 12 months after the reporting period.
\nAll other assets are classi\ufb01ed as non-current.
\nA liability is current when:
\na. it is expected to be settled in the normal operating cycle;
\nb. it is held primarily for the purpose of trading;
\nc. it is due to be settled within 12 months after the reporting period, or;
\nd. there is no unconditional right to defer the settlement of the liability for at least 12 months after the reporting period.
\nThe terms of the liability that could, at the option of the counterparty, result in its settlement by the issue of equity instruments do
\nnot affect its classi\ufb01cation. The Group classi\ufb01es all other liabilities as non-current. Deferred tax assets and liabilities are classi\ufb01ed
\nas non-current assets and liabilities.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForReclassificationOfFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16331": {
"value": "Business combinations Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the
\nassets transferred, equity instruments issued and liabilities incurred or assumed at the date of completion of the acquisition. Acquisition
\ncosts incurred are expensed and included in administrative expenses. Where applicable, the consideration for the acquisition includes
\nany asset or liability resulting from a contingent consideration arrangement, measured at its fair value at acquisition.
\nThe identi\ufb01able assets, liabilities and contingent liabilities acquired that meet the conditions for recognition under IFRS 3 are recognised
\nat their fair value at the acquisition date, except that:
\n\u00bc
Deferred tax assets or liabilities and liabilities or assets related to employee bene\ufb01t arrangements are recognised and measured in
\naccordance with IAS 12 Income Taxes and IAS 19 Employee Bene\ufb01ts, respectively.
\n\u00bc
Lease arrangements that represent leases as de\ufb01ned by IFRS 16 Leases are recognised and measured in accordance with IFRS 16 Leases.
\n\u00bc
Liabilities or equity instruments related to the replacement by the Group of an acquirer\u2019s share-based payment awards are measured
\nin accordance with IFRS 2 Share-Based Payment.
\n127
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nIf the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the
\nGroup reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted during the
\nmeasurement period, or additional assets or liabilities are recognised to re\ufb02ect new information obtained about facts and circumstances
\nthat existed as of the acquisition date that, if known, would have affected the amounts recognised as of that date. The measurement period
\nis the period from the date of acquisition to the date the Group obtains complete information about facts and circumstances that existed as
\nof the acquisition date, subject to a maximum of one year.
\nGoodwill
\nIn 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
\nIFRS 3 Business Combinations, the acquisition method of accounting is applied. Goodwill represents the difference between the aggregate of
\nthe fair value of purchase consideration transferred at the acquisition date and the fair value of the identi\ufb01able assets, liabilities and contingent
\nliabilities acquired. If however, the fair value of the purchase consideration transferred is lower than the fair value of the identi\ufb01able assets and
\nliabilities acquired, the difference is recognised in the income statement as negative goodwill. Goodwill is initially measured at cost. Following
\ninitial recognition, goodwill is measured at cost less any accumulated impairment. For the purpose of impairment testing, goodwill acquired in a
\nbusiness combination is, from the acquisition date, allocated to each of the Group\u2019s cash-generating units (CGUs), or groups of CGUs, that are
\nexpected to bene\ufb01t from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Goodwill
\nis 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
\nrate of exchange at each reporting date.
\nGoodwill, as disclosed in note 10, is not amortised but is reviewed for impairment at least annually by assessing the recoverable amount of
\nthe CGUs to which the goodwill relates. Where the carrying amount of the CGU and related goodwill is higher than the recoverable amount
\nof the CGU, an impairment loss is recognised in the income statement. The recoverable amounts of the CGUs have been determined on a
\nfair value less costs to sell basis. Impairment losses relating to goodwill cannot be reversed in future periods. Goodwill acquired through
\nbusiness combinations has been allocated to two CGUs, being North Sea and International.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsAndGoodwillExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16332": {
"value": "Business combinations Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the
\nassets transferred, equity instruments issued and liabilities incurred or assumed at the date of completion of the acquisition. Acquisition
\ncosts incurred are expensed and included in administrative expenses. Where applicable, the consideration for the acquisition includes
\nany asset or liability resulting from a contingent consideration arrangement, measured at its fair value at acquisition.
\nThe identi\ufb01able assets, liabilities and contingent liabilities acquired that meet the conditions for recognition under IFRS 3 are recognised
\nat their fair value at the acquisition date, except that:
\n\u00bc
Deferred tax assets or liabilities and liabilities or assets related to employee bene\ufb01t arrangements are recognised and measured in
\naccordance with IAS 12 Income Taxes and IAS 19 Employee Bene\ufb01ts, respectively.
\n\u00bc
Lease arrangements that represent leases as de\ufb01ned by IFRS 16 Leases are recognised and measured in accordance with IFRS 16 Leases.
\n\u00bc
Liabilities or equity instruments related to the replacement by the Group of an acquirer\u2019s share-based payment awards are measured
\nin accordance with IFRS 2 Share-Based Payment.
\n127
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nIf the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the
\nGroup reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted during the
\nmeasurement period, or additional assets or liabilities are recognised to re\ufb02ect new information obtained about facts and circumstances
\nthat existed as of the acquisition date that, if known, would have affected the amounts recognised as of that date. The measurement period
\nis the period from the date of acquisition to the date the Group obtains complete information about facts and circumstances that existed as
\nof the acquisition date, subject to a maximum of one year.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16377": {
"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
\nIFRS 3 Business Combinations, the acquisition method of accounting is applied. Goodwill represents the difference between the aggregate of
\nthe fair value of purchase consideration transferred at the acquisition date and the fair value of the identi\ufb01able assets, liabilities and contingent
\nliabilities acquired. If however, the fair value of the purchase consideration transferred is lower than the fair value of the identi\ufb01able assets and
\nliabilities acquired, the difference is recognised in the income statement as negative goodwill. Goodwill is initially measured at cost. Following
\ninitial recognition, goodwill is measured at cost less any accumulated impairment. For the purpose of impairment testing, goodwill acquired in a
\nbusiness combination is, from the acquisition date, allocated to each of the Group\u2019s cash-generating units (CGUs), or groups of CGUs, that are
\nexpected to bene\ufb01t from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Goodwill
\nis 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
\nrate of exchange at each reporting date.
\nGoodwill, as disclosed in note 10, is not amortised but is reviewed for impairment at least annually by assessing the recoverable amount of
\nthe CGUs to which the goodwill relates. Where the carrying amount of the CGU and related goodwill is higher than the recoverable amount
\nof the CGU, an impairment loss is recognised in the income statement. The recoverable amounts of the CGUs have been determined on a
\nfair value less costs to sell basis. Impairment losses relating to goodwill cannot be reversed in future periods. Goodwill acquired through
\nbusiness combinations has been allocated to two CGUs, being North Sea and International.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16378": {
"value": "GoodwillIn 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
\nIFRS 3 Business Combinations, the acquisition method of accounting is applied. Goodwill represents the difference between the aggregate of
\nthe fair value of purchase consideration transferred at the acquisition date and the fair value of the identi\ufb01able assets, liabilities and contingent
\nliabilities acquired. If however, the fair value of the purchase consideration transferred is lower than the fair value of the identi\ufb01able assets and
\nliabilities acquired, the difference is recognised in the income statement as negative goodwill. Goodwill is initially measured at cost. Following
\ninitial recognition, goodwill is measured at cost less any accumulated impairment. For the purpose of impairment testing, goodwill acquired in a
\nbusiness combination is, from the acquisition date, allocated to each of the Group\u2019s cash-generating units (CGUs), or groups of CGUs, that are
\nexpected to bene\ufb01t from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Goodwill
\nis 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
\nrate of exchange at each reporting date.
\nGoodwill, as disclosed in note 10, is not amortised but is reviewed for impairment at least annually by assessing the recoverable amount of
\nthe CGUs to which the goodwill relates. Where the carrying amount of the CGU and related goodwill is higher than the recoverable amount
\nof the CGU, an impairment loss is recognised in the income statement. The recoverable amounts of the CGUs have been determined on a
\nfair value less costs to sell basis. Impairment losses relating to goodwill cannot be reversed in future periods. Goodwill acquired through
\nbusiness combinations has been allocated to two CGUs, being North Sea and International.
Intangibles
\nPre-licence costs
\nPre-licence costs are expensed in the period in which they are incurred.
\nLicence and property acquisition costs
\nLicence and property acquisition costs paid in connection with a right to explore in an existing exploration area are capitalised as exploration
\nand evaluation costs within intangible assets.
\nLicence and property acquisition costs are reviewed at each reporting date to con\ufb01rm that there is no indication that the carrying amount
\nexceeds the recoverable amount. If no future activity is planned or the related licence has been relinquished or has expired, the carrying
\nvalue of the property acquisition costs is written off through the income statement. Upon recognition of proved reserves and internal
\napproval for development, the relevant expenditure is transferred to oil and gas properties within development and production assets.
\nExploration and evaluation costs
\nOnce the legal right to explore has been acquired, costs directly associated with the exploration are capitalised as exploration and evaluation
\n(E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential commercial
\nresources are discovered, the exploration asset is written off.
\nAll such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment at
\nleast annually. This is to con\ufb01rm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the
\ncase, the costs are written off through the income statement.
\nWhen proved reserves of oil or natural gas are identi\ufb01ed and development is sanctioned by management, the relevant capitalised
\nexpenditure is \ufb01rst assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is transferred to
\noil and gas properties within development and production assets. No amortisation is charged during the exploration and evaluation phase.
\nFarm-outs \u2013 in the exploration and evaluation phase
\nThe 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
\nand evaluation farm-out arrangements but re-designates any costs previously capitalised in relation to the whole interest
\nas relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously
\ncapitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.
Intangible assets
\nIntangible assets, which principally comprise IT software/licences, are carried at cost less any accumulated amortisation. These assets
\nare amortised on a straight-line basis over their useful economic lives of between three and ten years.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsAndGoodwillExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16400": {
"value": "Oil and gas assets Intangibles
\nPre-licence costs
\nPre-licence costs are expensed in the period in which they are incurred.
\nLicence and property acquisition costs
\nLicence and property acquisition costs paid in connection with a right to explore in an existing exploration area are capitalised as exploration
\nand evaluation costs within intangible assets.
\nLicence and property acquisition costs are reviewed at each reporting date to con\ufb01rm that there is no indication that the carrying amount
\nexceeds the recoverable amount. If no future activity is planned or the related licence has been relinquished or has expired, the carrying
\nvalue of the property acquisition costs is written off through the income statement. Upon recognition of proved reserves and internal
\napproval for development, the relevant expenditure is transferred to oil and gas properties within development and production assets.
\nExploration and evaluation costs
\nOnce the legal right to explore has been acquired, costs directly associated with the exploration are capitalised as exploration and evaluation
\n(E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential commercial
\nresources are discovered, the exploration asset is written off.
\nAll such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment at
\nleast annually. This is to con\ufb01rm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the
\ncase, the costs are written off through the income statement.
\nWhen proved reserves of oil or natural gas are identi\ufb01ed and development is sanctioned by management, the relevant capitalised
\nexpenditure is \ufb01rst assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is transferred to
\noil and gas properties within development and production assets. No amortisation is charged during the exploration and evaluation phase.
\nFarm-outs \u2013 in the exploration and evaluation phase
\nThe 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
\nand evaluation farm-out arrangements but re-designates any costs previously capitalised in relation to the whole interest
\nas relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously
\ncapitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.
\nProperty, plant and equipment \u2013 oil and gas assets
\nOil and gas development and production assets are accumulated generally on a \ufb01eld-by-\ufb01eld basis. This represents expenditure on the
\nconstruction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells,
\nincluding E&E expenditures incurred in \ufb01nding commercial reserves transferred from intangible E&E assets, as outlined in the intangible
\nasset policy above, which is capitalised as oil and gas properties within development and production assets.
\n128
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into
\noperation, the initial estimate of the decommissioning obligation and, for qualifying assets, where relevant, borrowing costs. The purchase
\nprice or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
\nAn item of development and production expenditure and any signi\ufb01cant part initially recognised is derecognised upon disposal or when
\nno future economic bene\ufb01ts are expected. Any gain or loss arising on derecognition of the asset (calculated as the difference between
\nthe net disposal proceeds and the carrying amount of the asset) is included in the income statement.
\nExpenditure on major maintenance includes re\ufb01ts, inspections or repairs comprising the cost of replacement assets or parts of assets,
\ninspection costs and overhaul costs. Where an asset, or part of an asset, that was separately depreciated and is now written off is
\nreplaced and it is probable that future economic bene\ufb01ts associated with the item will \ufb02ow to the Group, the expenditure is capitalised.
\nAll other day-to-day repairs and maintenance costs are expensed as incurred.
\nDepreciation, depletion and amortisation (DD&A) of oil and gas assets
\nAll costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is provided
\ngenerally 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
\ncommercial proven and probable reserves of the \ufb01eld, considering future development expenditures necessary to bring those reserves
\ninto production.
\nWhen there is a change in the estimated total recoverable proven and probable reserves of a \ufb01eld, that change is accounted for in the
\ndepreciation charge over the revised remaining proven and probable reserves.
\nAcquisitions, asset purchases and disposals
\nAcquisitions of oil and gas properties are accounted for using the acquisition method when the assets acquired, and liabilities assumed
\nconstitute a business.
\nTransactions involving the purchase of an individual \ufb01eld interest, or a group of \ufb01eld interests, that do not constitute a business, are
\ntreated as asset purchases irrespective of whether the speci\ufb01c transactions involve the transfer of the \ufb01eld interests directly or the
\ntransfer of an incorporated entity. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to
\nthe assets and liabilities purchased on an appropriate basis.
\nProceeds on disposal are applied to the carrying amount of the speci\ufb01c intangible asset or oil and gas property disposed of and any
\nsurplus is recorded as a gain on disposal in the income statement.
\nDecommissioning
\nA provision for decommissioning is recognised in full when the related facilities are installed. The amount recognised is the present value
\nof the estimated future expenditure. A corresponding amount equivalent to the provision is also recognised as part of the cost of the
\nrelated oil and gas property. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the
\npresent value of the estimated expenditure is dealt with from the start of the \ufb01nancial year as an adjustment to the opening provision
\nand 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16403": {
"value": "Intangibles
\nPre-licence costs
\nPre-licence costs are expensed in the period in which they are incurred.
\nLicence and property acquisition costs
\nLicence and property acquisition costs paid in connection with a right to explore in an existing exploration area are capitalised as exploration
\nand evaluation costs within intangible assets.
\nLicence and property acquisition costs are reviewed at each reporting date to con\ufb01rm that there is no indication that the carrying amount
\nexceeds the recoverable amount. If no future activity is planned or the related licence has been relinquished or has expired, the carrying
\nvalue of the property acquisition costs is written off through the income statement. Upon recognition of proved reserves and internal
\napproval for development, the relevant expenditure is transferred to oil and gas properties within development and production assets.
\nExploration and evaluation costs
\nOnce the legal right to explore has been acquired, costs directly associated with the exploration are capitalised as exploration and evaluation
\n(E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential commercial
\nresources are discovered, the exploration asset is written off.
\nAll such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment at
\nleast annually. This is to con\ufb01rm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the
\ncase, the costs are written off through the income statement.
\nWhen proved reserves of oil or natural gas are identi\ufb01ed and development is sanctioned by management, the relevant capitalised
\nexpenditure is \ufb01rst assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is transferred to
\noil and gas properties within development and production assets. No amortisation is charged during the exploration and evaluation phase.
\nFarm-outs \u2013 in the exploration and evaluation phase
\nThe 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
\nand evaluation farm-out arrangements but re-designates any costs previously capitalised in relation to the whole interest
\nas relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously
\ncapitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.
Intangible assets
\nIntangible assets, which principally comprise IT software/licences, are carried at cost less any accumulated amortisation. These assets
\nare amortised on a straight-line basis over their useful economic lives of between three and ten years.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsOtherThanGoodwillExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16415": {
"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
\n(E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential commercial
\nresources are discovered, the exploration asset is written off.
\nAll such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment at
\nleast annually. This is to con\ufb01rm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the
\ncase, the costs are written off through the income statement.
\nWhen proved reserves of oil or natural gas are identi\ufb01ed and development is sanctioned by management, the relevant capitalised
\nexpenditure is \ufb01rst assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is transferred to
\noil 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16433": {
"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
\nconstruction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells,
\nincluding E&E expenditures incurred in \ufb01nding commercial reserves transferred from intangible E&E assets, as outlined in the intangible
\nasset policy above, which is capitalised as oil and gas properties within development and production assets.
\n128
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into
\noperation, the initial estimate of the decommissioning obligation and, for qualifying assets, where relevant, borrowing costs. The purchase
\nprice or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
\nAn item of development and production expenditure and any signi\ufb01cant part initially recognised is derecognised upon disposal or when
\nno future economic bene\ufb01ts are expected. Any gain or loss arising on derecognition of the asset (calculated as the difference between
\nthe net disposal proceeds and the carrying amount of the asset) is included in the income statement.
\nExpenditure on major maintenance includes re\ufb01ts, inspections or repairs comprising the cost of replacement assets or parts of assets,
\ninspection costs and overhaul costs. Where an asset, or part of an asset, that was separately depreciated and is now written off is
\nreplaced and it is probable that future economic bene\ufb01ts associated with the item will \ufb02ow to the Group, the expenditure is capitalised.
\nAll other day-to-day repairs and maintenance costs are expensed as incurred.
\nDepreciation, depletion and amortisation (DD&A) of oil and gas assets
\nAll costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is provided
\ngenerally 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
\ncommercial proven and probable reserves of the \ufb01eld, considering future development expenditures necessary to bring those reserves
\ninto production.
\nWhen there is a change in the estimated total recoverable proven and probable reserves of a \ufb01eld, that change is accounted for in the
\ndepreciation charge over the revised remaining proven and probable reserves.
\nAcquisitions, asset purchases and disposals
\nAcquisitions of oil and gas properties are accounted for using the acquisition method when the assets acquired, and liabilities assumed
\nconstitute a business.
\nTransactions involving the purchase of an individual \ufb01eld interest, or a group of \ufb01eld interests, that do not constitute a business, are
\ntreated as asset purchases irrespective of whether the speci\ufb01c transactions involve the transfer of the \ufb01eld interests directly or the
\ntransfer of an incorporated entity. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to
\nthe assets and liabilities purchased on an appropriate basis.
\nProceeds on disposal are applied to the carrying amount of the speci\ufb01c intangible asset or oil and gas property disposed of and any
\nsurplus is recorded as a gain on disposal in the income statement.
\nDecommissioning
\nA provision for decommissioning is recognised in full when the related facilities are installed. The amount recognised is the present value
\nof the estimated future expenditure. A corresponding amount equivalent to the provision is also recognised as part of the cost of the
\nrelated oil and gas property. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the
\npresent value of the estimated expenditure is dealt with from the start of the \ufb01nancial year as an adjustment to the opening provision
\nand the oil and gas property. The unwinding of the discount is included as a \ufb01nance cost.
\nNon-oil and gas assets
\nProperty, plant and equipment \u2013 \ufb01xtures and \ufb01ttings and o\ufb03ce equipment
\nFixtures and \ufb01ttings and of\ufb01ce equipment is stated at cost less accumulated depreciation and impairment. Depreciation is provided for
\non 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
\nlives. The depreciation periods for the principal categories of assets are as follows:
\n\u00bc
Fixtures and \ufb01ttings: Up to 10 years.
\n\u00bc
Of\ufb01ce furniture and equipment: Up to 5 years.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16465": {
"value": "Depreciation, depletion and amortisation (DD&A) of oil and gas assets
\nAll costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is provided
\ngenerally 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
\ncommercial proven and probable reserves of the \ufb01eld, considering future development expenditures necessary to bring those reserves
\ninto production.
\nWhen there is a change in the estimated total recoverable proven and probable reserves of a \ufb01eld, that change is accounted for in the
\ndepreciation 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
\non 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
\nlives. The depreciation periods for the principal categories of assets are as follows:
\n\u00bc
Fixtures and \ufb01ttings: Up to 10 years.
\n\u00bc
Of\ufb01ce furniture and equipment: Up to 5 years.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16483": {
"value": "Decommissioning A provision for decommissioning is recognised in full when the related facilities are installed. The amount recognised is the present value
\nof the estimated future expenditure. A corresponding amount equivalent to the provision is also recognised as part of the cost of the
\nrelated oil and gas property. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the
\npresent 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16510": {
"value": "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
\nintangible assets where there is an indicator of impairment, or an indicator identi\ufb01ed that a prior year impairment may have reversed
\nor decreased. Such indications may be based on events or changes in the market environment, or on internal sources of information.
\nImpairment and reversal indicators
\nProperty, plant and equipment and intangible assets with \ufb01nite useful lives are only tested for impairment when there is an indication
\nthat they may be impaired. This is generally the result of signi\ufb01cant changes to the environment in which the assets are operated or when
\nasset performance is signi\ufb01cantly lower than expected.
\n129
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nThe main impairment indicators used by the Group are described below:
\n\u00bc
External sources of information:
\n\u2013
Signi\ufb01cant changes in the economic, technological, political or market environment in which the entity operates or to which an asset
\nis dedicated.
\n\u2013
Fall in demand.
\n\u2013
Changes in commodity prices and exchange rates.
\n\u00bc
Internal sources of information:
\n\u2013
Evidence of obsolescence or physical damage.
\n\u2013
Signi\ufb01cantly lower than expected production or cost performance.
\n\u2013
Reduction in reserves and resources, including as a result of unsuccessful results of drilling operations.
\n\u2013
Pending expiry of licence or other rights.
\n\u2013
In respect of capitalised exploration and evaluation costs, lack of planned future activity on the prospect or licence.
\n\u2013
For reversals, plausible downside sensitivity scenarios are run to test the robustness of the asset carrying values typically against
\nchanges in production and commodity prices.
\nMeasurement of recoverable amount
\nThe cash-generating unit (CGU) applied for impairment test purposes is generally the \ufb01eld, except that a number of \ufb01eld interests may
\nbe grouped as a single CGU where the cash in\ufb02ows of each \ufb01eld are interdependent. The carrying value of each CGU is compared against
\nthe expected recoverable amount of the asset, which is primarily determined based on the fair value less cost of disposal (FVLCD)
\nmethod, where the fair value is determined from the estimated present value of the future net cash \ufb02ows expected to be derived from
\nproduction of commercial reserves. Standard valuation techniques are used based on the discount rates that re\ufb02ect the speci\ufb01c
\ncharacteristics of the operating entities concerned; discount rates are determined on a post-tax basis and applied to post-tax cash \ufb02ows.
\nAny impairment loss is recorded in the income statement under Impairment of property, plant and equipment. Impairment losses
\nrecorded in relation to property, plant and equipment may be subsequently reversed if the recoverable amount of the assets
\nsubsequently increases above carrying value. The increased carrying amount of an item of property, plant or equipment attributable to a
\nreversal of an impairment loss may not exceed the carrying amount that would have been determined (net of depreciation/amortisation)
\nhad no impairment loss been recognised in prior periods.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfNonfinancialAssetsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16511": {
"value": "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
\nintangible assets where there is an indicator of impairment, or an indicator identi\ufb01ed that a prior year impairment may have reversed
\nor decreased. Such indications may be based on events or changes in the market environment, or on internal sources of information.
\nImpairment and reversal indicators
\nProperty, plant and equipment and intangible assets with \ufb01nite useful lives are only tested for impairment when there is an indication
\nthat they may be impaired. This is generally the result of signi\ufb01cant changes to the environment in which the assets are operated or when
\nasset performance is signi\ufb01cantly lower than expected.
\n129
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nThe main impairment indicators used by the Group are described below:
\n\u00bc
External sources of information:
\n\u2013
Signi\ufb01cant changes in the economic, technological, political or market environment in which the entity operates or to which an asset
\nis dedicated.
\n\u2013
Fall in demand.
\n\u2013
Changes in commodity prices and exchange rates.
\n\u00bc
Internal sources of information:
\n\u2013
Evidence of obsolescence or physical damage.
\n\u2013
Signi\ufb01cantly lower than expected production or cost performance.
\n\u2013
Reduction in reserves and resources, including as a result of unsuccessful results of drilling operations.
\n\u2013
Pending expiry of licence or other rights.
\n\u2013
In respect of capitalised exploration and evaluation costs, lack of planned future activity on the prospect or licence.
\n\u2013
For reversals, plausible downside sensitivity scenarios are run to test the robustness of the asset carrying values typically against
\nchanges in production and commodity prices.
\nMeasurement of recoverable amount
\nThe cash-generating unit (CGU) applied for impairment test purposes is generally the \ufb01eld, except that a number of \ufb01eld interests may
\nbe grouped as a single CGU where the cash in\ufb02ows of each \ufb01eld are interdependent. The carrying value of each CGU is compared against
\nthe expected recoverable amount of the asset, which is primarily determined based on the fair value less cost of disposal (FVLCD)
\nmethod, where the fair value is determined from the estimated present value of the future net cash \ufb02ows expected to be derived from
\nproduction of commercial reserves. Standard valuation techniques are used based on the discount rates that re\ufb02ect the speci\ufb01c
\ncharacteristics of the operating entities concerned; discount rates are determined on a post-tax basis and applied to post-tax cash \ufb02ows.
\nAny impairment loss is recorded in the income statement under Impairment of property, plant and equipment. Impairment losses
\nrecorded in relation to property, plant and equipment may be subsequently reversed if the recoverable amount of the assets
\nsubsequently increases above carrying value. The increased carrying amount of an item of property, plant or equipment attributable to a
\nreversal of an impairment loss may not exceed the carrying amount that would have been determined (net of depreciation/amortisation)
\nhad no impairment loss been recognised in prior periods.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16581": {
"value": "Financial instruments Financial assets
\nFinancial instruments are recognised and measured in accordance with IFRS 9 Financial Instruments.
\nThe Group uses two criteria to determine the classi\ufb01cation of \ufb01nancial assets: the Group\u2019s business model and contractual cash \ufb02ow
\ncharacteristics of the \ufb01nancial assets. Where appropriate the Group identi\ufb01es three categories of \ufb01nancial assets: amortised cost,
\nfair value through pro\ufb01t or loss (FVTPL), and fair value through other comprehensive income (FVOCI).
\nFinancial assets held at amortised cost
\nFinancial assets held at amortised cost are initially measured at fair value except for trade debtors which are initially measured at cost.
\nBoth are subsequently carried at amortised cost using the effective interest rate (EIR) method, less impairment. The EIR amortisation is
\npresented within \ufb01nance income in the income statement.
\nCash and cash equivalents
\nCash and cash equivalents comprise cash at bank and other short-term highly liquid investments that are readily convertible to a known
\namount of cash and are subject to an insigni\ufb01cant risk of changes in value.
\nImpairment of \ufb01nancial assets
\nThe Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through pro\ufb01t or loss.
\nECLs are based on the difference between the contractual cash \ufb02ows due in accordance with the contract and all the cash \ufb02ows that the
\nGroup expects to receive, discounted at an approximation of the original effective interest rate.
\nECLs are recognised in two stages. For credit exposures for which there has not been a signi\ufb01cant increase in credit risk since initial recognition,
\nECLs are provided for credit losses that result from default events that are possible within the next 12 months (a 12-month ECL).
\n130
Default events could include:
\n\u00bc
Payment default, i.e. the failure to pay principal or interest when it falls due for payment.
\n\u00bc
Prospective default, when payment is not yet due, but it is clear that it will not be capable of being paid when it does fall due.
\n\u00bc
Covenant default, when the borrower fails to keep a promise (a covenant) that it has made in the contract.
\nFor those credit exposures for which there has been a signi\ufb01cant increase in credit risk since initial recognition, a loss allowance is
\nrequired for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default (a lifetime ECL).
\nFor trade receivables and contract assets, the Group applies a simpli\ufb01ed approach in calculating ECLs as allowed under IFRS 9.
\nProvision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as
\nadjusted for forward-looking factors speci\ufb01c to the debtors, the economic environment and the Group\u2019s historical credit loss experience.
\nCredit impaired \ufb01nancial assets
\nAt each reporting date, the Group assesses whether \ufb01nancial assets carried at amortised cost and debt \ufb01nancial assets carried at FVOCI
\nare credit impaired. A \ufb01nancial asset is credit impaired when one or more events that have a detrimental impact on the estimated future
\ncash \ufb02ows of the \ufb01nancial asset have occurred.
\nEvidence that a \ufb01nancial asset is credit impaired includes the following observable data:
\n\u00bc
Signi\ufb01cant \ufb01nancial dif\ufb01culty of the borrower or issuer.
\n\u00bc
A breach of contract such as default or past due event.
\n\u00bc
The restructuring of a loan or advance by the Group on terms that the Group would otherwise not consider.
\n\u00bc
It is becoming probable that the borrower will enter bankruptcy or other \ufb01nancial reorganisation.
\n\u00bc
The disappearance of an active market for a security because of \ufb01nancial dif\ufb01culties.
\nFinancial liabilities
\nFinancial liabilities are classi\ufb01ed, at initial recognition, as \ufb01nancial liabilities at fair value through pro\ufb01t or loss, loans and borrowings,
\npayables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. All \ufb01nancial liabilities are recognised
\ninitially at fair value and, in the case of loans, borrowings and payables, net of directly attributable transaction costs.
\nBorrowings and loans
\nInterest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including
\npremiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement
\nusing the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the
\nyear in which they arise.
\n Derecognition
\nA \ufb01nancial liability is derecognised when the obligation under the liability is discharged, cancelled, or expires. When an existing \ufb01nancial
\nliability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially
\nmodi\ufb01ed, such an exchange or modi\ufb01cation is treated as the derecognition of the original liability and the recognition of a new liability.
\nThe difference in the respective carrying amounts is recognised in the income statement.
\nDerivative \ufb01nancial instruments
\nThe Group uses derivative \ufb01nancial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and
\ncommodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative
\n\ufb01nancial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative \ufb01nancial instruments are
\ndesignated as cash \ufb02ow hedges in line with the Group\u2019s risk management policies. When derivatives do not qualify for hedge accounting
\nor are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.
\nCash \ufb02ow hedges
\nThe effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
\nhedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
\ntransaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
\nrecognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
\nAny gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
\nineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
\ncredit-worthiness of the counterparty is signi\ufb01cant and may dominate the transaction and lead to losses.
\n131
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nFair values
\nFair 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
\nmarket participants at the measurement date. It is determined by reference to quoted market prices adjusted for estimated transaction
\ncosts that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models
\nand estimated discounted values of cash \ufb02ows.
\nFor \ufb01nancial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques.
\nUnder IFRS 9, embedded derivatives are not separated from a host \ufb01nancial asset, and are classi\ufb01ed based on their contractual terms
\nand the Group\u2019s business model.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16582": {
"value": "Financial instruments Financial assets
\nFinancial instruments are recognised and measured in accordance with IFRS 9 Financial Instruments.
\nThe Group uses two criteria to determine the classi\ufb01cation of \ufb01nancial assets: the Group\u2019s business model and contractual cash \ufb02ow
\ncharacteristics of the \ufb01nancial assets. Where appropriate the Group identi\ufb01es three categories of \ufb01nancial assets: amortised cost,
\nfair value through pro\ufb01t or loss (FVTPL), and fair value through other comprehensive income (FVOCI).
\nFinancial assets held at amortised cost
\nFinancial assets held at amortised cost are initially measured at fair value except for trade debtors which are initially measured at cost.
\nBoth are subsequently carried at amortised cost using the effective interest rate (EIR) method, less impairment. The EIR amortisation is
\npresented within \ufb01nance income in the income statement.
\nCash and cash equivalents
\nCash and cash equivalents comprise cash at bank and other short-term highly liquid investments that are readily convertible to a known
\namount of cash and are subject to an insigni\ufb01cant risk of changes in value.
\nImpairment of \ufb01nancial assets
\nThe Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through pro\ufb01t or loss.
\nECLs are based on the difference between the contractual cash \ufb02ows due in accordance with the contract and all the cash \ufb02ows that the
\nGroup expects to receive, discounted at an approximation of the original effective interest rate.
\nECLs are recognised in two stages. For credit exposures for which there has not been a signi\ufb01cant increase in credit risk since initial recognition,
\nECLs are provided for credit losses that result from default events that are possible within the next 12 months (a 12-month ECL).
\n130
Default events could include:
\n\u00bc
Payment default, i.e. the failure to pay principal or interest when it falls due for payment.
\n\u00bc
Prospective default, when payment is not yet due, but it is clear that it will not be capable of being paid when it does fall due.
\n\u00bc
Covenant default, when the borrower fails to keep a promise (a covenant) that it has made in the contract.
\nFor those credit exposures for which there has been a signi\ufb01cant increase in credit risk since initial recognition, a loss allowance is
\nrequired for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default (a lifetime ECL).
\nFor trade receivables and contract assets, the Group applies a simpli\ufb01ed approach in calculating ECLs as allowed under IFRS 9.
\nProvision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as
\nadjusted for forward-looking factors speci\ufb01c to the debtors, the economic environment and the Group\u2019s historical credit loss experience.
\nCredit impaired \ufb01nancial assets
\nAt each reporting date, the Group assesses whether \ufb01nancial assets carried at amortised cost and debt \ufb01nancial assets carried at FVOCI
\nare credit impaired. A \ufb01nancial asset is credit impaired when one or more events that have a detrimental impact on the estimated future
\ncash \ufb02ows of the \ufb01nancial asset have occurred.
\nEvidence that a \ufb01nancial asset is credit impaired includes the following observable data:
\n\u00bc
Signi\ufb01cant \ufb01nancial dif\ufb01culty of the borrower or issuer.
\n\u00bc
A breach of contract such as default or past due event.
\n\u00bc
The restructuring of a loan or advance by the Group on terms that the Group would otherwise not consider.
\n\u00bc
It is becoming probable that the borrower will enter bankruptcy or other \ufb01nancial reorganisation.
\n\u00bc
The disappearance of an active market for a security because of \ufb01nancial dif\ufb01culties.
\nFinancial liabilities
\nFinancial liabilities are classi\ufb01ed, at initial recognition, as \ufb01nancial liabilities at fair value through pro\ufb01t or loss, loans and borrowings,
\npayables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. All \ufb01nancial liabilities are recognised
\ninitially at fair value and, in the case of loans, borrowings and payables, net of directly attributable transaction costs.
\nBorrowings and loans
\nInterest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including
\npremiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement
\nusing the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the
\nyear in which they arise.
\n Derecognition
\nA \ufb01nancial liability is derecognised when the obligation under the liability is discharged, cancelled, or expires. When an existing \ufb01nancial
\nliability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially
\nmodi\ufb01ed, such an exchange or modi\ufb01cation is treated as the derecognition of the original liability and the recognition of a new liability.
\nThe difference in the respective carrying amounts is recognised in the income statement.
\nDerivative \ufb01nancial instruments
\nThe Group uses derivative \ufb01nancial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and
\ncommodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative
\n\ufb01nancial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative \ufb01nancial instruments are
\ndesignated as cash \ufb02ow hedges in line with the Group\u2019s risk management policies. When derivatives do not qualify for hedge accounting
\nor are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.
\nCash \ufb02ow hedges
\nThe effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
\nhedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
\ntransaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
\nrecognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
\nAny gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
\nineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
\ncredit-worthiness of the counterparty is signi\ufb01cant and may dominate the transaction and lead to losses.
\n131
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nFair values
\nFair 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
\nmarket participants at the measurement date. It is determined by reference to quoted market prices adjusted for estimated transaction
\ncosts that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models
\nand estimated discounted values of cash \ufb02ows.
\nFor \ufb01nancial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques.
\nUnder IFRS 9, embedded derivatives are not separated from a host \ufb01nancial asset, and are classi\ufb01ed based on their contractual terms
\nand the Group\u2019s business model.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16586": {
"value": "Financial assets Financial instruments are recognised and measured in accordance with IFRS 9 Financial Instruments.
\nThe Group uses two criteria to determine the classi\ufb01cation of \ufb01nancial assets: the Group\u2019s business model and contractual cash \ufb02ow
\ncharacteristics of the \ufb01nancial assets. Where appropriate the Group identi\ufb01es three categories of \ufb01nancial assets: amortised cost,
\nfair value through pro\ufb01t or loss (FVTPL), and fair value through other comprehensive income (FVOCI).
\nFinancial assets held at amortised cost
\nFinancial assets held at amortised cost are initially measured at fair value except for trade debtors which are initially measured at cost.
\nBoth are subsequently carried at amortised cost using the effective interest rate (EIR) method, less impairment. The EIR amortisation is
\npresented within \ufb01nance income in the income statement.
\nCash and cash equivalents
\nCash and cash equivalents comprise cash at bank and other short-term highly liquid investments that are readily convertible to a known
\namount of cash and are subject to an insigni\ufb01cant risk of changes in value.
\nImpairment of \ufb01nancial assets
\nThe Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through pro\ufb01t or loss.
\nECLs are based on the difference between the contractual cash \ufb02ows due in accordance with the contract and all the cash \ufb02ows that the
\nGroup expects to receive, discounted at an approximation of the original effective interest rate.
\nECLs are recognised in two stages. For credit exposures for which there has not been a signi\ufb01cant increase in credit risk since initial recognition,
\nECLs are provided for credit losses that result from default events that are possible within the next 12 months (a 12-month ECL).
\n130
Default events could include:
\n\u00bc
Payment default, i.e. the failure to pay principal or interest when it falls due for payment.
\n\u00bc
Prospective default, when payment is not yet due, but it is clear that it will not be capable of being paid when it does fall due.
\n\u00bc
Covenant default, when the borrower fails to keep a promise (a covenant) that it has made in the contract.
\nFor those credit exposures for which there has been a signi\ufb01cant increase in credit risk since initial recognition, a loss allowance is
\nrequired for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default (a lifetime ECL).
\nFor trade receivables and contract assets, the Group applies a simpli\ufb01ed approach in calculating ECLs as allowed under IFRS 9.
\nProvision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as
\nadjusted for forward-looking factors speci\ufb01c to the debtors, the economic environment and the Group\u2019s historical credit loss experience.
\nCredit impaired \ufb01nancial assets
\nAt each reporting date, the Group assesses whether \ufb01nancial assets carried at amortised cost and debt \ufb01nancial assets carried at FVOCI
\nare credit impaired. A \ufb01nancial asset is credit impaired when one or more events that have a detrimental impact on the estimated future
\ncash \ufb02ows of the \ufb01nancial asset have occurred.
\nEvidence that a \ufb01nancial asset is credit impaired includes the following observable data:
\n\u00bc
Signi\ufb01cant \ufb01nancial dif\ufb01culty of the borrower or issuer.
\n\u00bc
A breach of contract such as default or past due event.
\n\u00bc
The restructuring of a loan or advance by the Group on terms that the Group would otherwise not consider.
\n\u00bc
It is becoming probable that the borrower will enter bankruptcy or other \ufb01nancial reorganisation.
\n\u00bc
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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16597": {
"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
\namount of cash and are subject to an insigni\ufb01cant risk of changes in value.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForRestrictedCashAndCashEquivalentsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16598": {
"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
\namount 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16606": {
"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.
\nECLs are based on the difference between the contractual cash \ufb02ows due in accordance with the contract and all the cash \ufb02ows that the
\nGroup expects to receive, discounted at an approximation of the original effective interest rate.
\nECLs are recognised in two stages. For credit exposures for which there has not been a signi\ufb01cant increase in credit risk since initial recognition,
\nECLs are provided for credit losses that result from default events that are possible within the next 12 months (a 12-month ECL).
\n130
Default events could include:
\n\u00bc
Payment default, i.e. the failure to pay principal or interest when it falls due for payment.
\n\u00bc
Prospective default, when payment is not yet due, but it is clear that it will not be capable of being paid when it does fall due.
\n\u00bc
Covenant default, when the borrower fails to keep a promise (a covenant) that it has made in the contract.
\nFor those credit exposures for which there has been a signi\ufb01cant increase in credit risk since initial recognition, a loss allowance is
\nrequired for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default (a lifetime ECL).
\nFor trade receivables and contract assets, the Group applies a simpli\ufb01ed approach in calculating ECLs as allowed under IFRS 9.
\nProvision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as
\nadjusted for forward-looking factors speci\ufb01c to the debtors, the economic environment and the Group\u2019s historical credit loss experience.
\nCredit impaired \ufb01nancial assets
\nAt each reporting date, the Group assesses whether \ufb01nancial assets carried at amortised cost and debt \ufb01nancial assets carried at FVOCI
\nare credit impaired. A \ufb01nancial asset is credit impaired when one or more events that have a detrimental impact on the estimated future
\ncash \ufb02ows of the \ufb01nancial asset have occurred.
\nEvidence that a \ufb01nancial asset is credit impaired includes the following observable data:
\n\u00bc
Signi\ufb01cant \ufb01nancial dif\ufb01culty of the borrower or issuer.
\n\u00bc
A breach of contract such as default or past due event.
\n\u00bc
The restructuring of a loan or advance by the Group on terms that the Group would otherwise not consider.
\n\u00bc
It is becoming probable that the borrower will enter bankruptcy or other \ufb01nancial reorganisation.
\n\u00bc
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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16663": {
"value": "Financial liabilities Financial liabilities are classi\ufb01ed, at initial recognition, as \ufb01nancial liabilities at fair value through pro\ufb01t or loss, loans and borrowings,
\npayables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. All \ufb01nancial liabilities are recognised
\ninitially at fair value and, in the case of loans, borrowings and payables, net of directly attributable transaction costs.
\nBorrowings and loans
\nInterest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including
\npremiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement
\nusing the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the
\nyear in which they arise.
\n Derecognition
\nA \ufb01nancial liability is derecognised when the obligation under the liability is discharged, cancelled, or expires. When an existing \ufb01nancial
\nliability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially
\nmodi\ufb01ed, such an exchange or modi\ufb01cation is treated as the derecognition of the original liability and the recognition of a new liability.
\nThe difference in the respective carrying amounts is recognised in the income statement. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16669": {
"value": "Borrowings and loans Interest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including
\npremiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement
\nusing the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the
\nyear in which they arise.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16670": {
"value": "Borrowings and loans Interest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including
\npremiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement
\nusing the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the
\nyear in which they arise.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForLoansAndReceivablesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16680": {
"value": "DerecognitionA \ufb01nancial liability is derecognised when the obligation under the liability is discharged, cancelled, or expires. When an existing \ufb01nancial
\nliability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially
\nmodi\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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16689": {
"value": "Derivative \ufb01nancial instruments The Group uses derivative \ufb01nancial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and
\ncommodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative
\n\ufb01nancial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative \ufb01nancial instruments are
\ndesignated as cash \ufb02ow hedges in line with the Group\u2019s risk management policies. When derivatives do not qualify for hedge accounting
\nor are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.
\nCash \ufb02ow hedges
\nThe effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
\nhedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
\ntransaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
\nrecognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
\nAny gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
\nineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
\ncredit-worthiness 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16690": {
"value": "Derivative \ufb01nancial instruments The Group uses derivative \ufb01nancial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and
\ncommodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative
\n\ufb01nancial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative \ufb01nancial instruments are
\ndesignated as cash \ufb02ow hedges in line with the Group\u2019s risk management policies. When derivatives do not qualify for hedge accounting
\nor are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.
\nCash \ufb02ow hedges
\nThe effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
\nhedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
\ntransaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
\nrecognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
\nAny gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
\nineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
\ncredit-worthiness 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16699": {
"value": "Cash \ufb02ow hedges The effective portion of gains and losses arising from the remeasurement of derivative \ufb01nancial instruments designated as cash \ufb02ow
\nhedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged
\ntransaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously
\nrecognised in other comprehensive income remains deferred until the hedged item affects pro\ufb01t or loss or is no longer expected to occur.
\nAny gain or loss relating to the ineffective portion of a cash \ufb02ow hedge is immediately recognised in the income statement. Hedge
\nineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the
credit-worthiness 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16732": {
"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
\nmarket participants at the measurement date. It is determined by reference to quoted market prices adjusted for estimated transaction
\ncosts that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models
\nand estimated discounted values of cash \ufb02ows.
\nFor \ufb01nancial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques.
\nUnder 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16733": {
"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
\nmarket participants at the measurement date. It is determined by reference to quoted market prices adjusted for estimated transaction
\ncosts that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models
\nand estimated discounted values of cash \ufb02ows.
\nFor \ufb01nancial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques.
\nUnder 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:DescriptionOfAccountingPolicyForRecognisingDifferenceBetweenFairValueAtInitialRecognitionAndAmountDeterminedUsingValuationTechniqueExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16749": {
"value": "Share capital Share capital includes the total net proceeds, both nominal and share premium, on the issue of ordinary and preference shares
\nof the company. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIssuedCapitalExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16755": {
"value": "Capital redemption reserve The capital redemption reserve represents the nominal value of shares transferred following the company\u2019s purchase of them.
\nMerger reserve
\nOn 31 March 2021, Harbour Energy plc (formerly Premier Oil plc) acquired Chrysaor Holdings Limited as part of a reverse acquisition.
\nUnder the terms of the merger, Premier legally acquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the
\nacquirer for accounting purposes, primarily as a result of its ability to appoint the Board of the enlarged group. The merger reserve
\nprimarily represents Premier\u2019s opening balance on the legal reserve plus the fair value of the assets and liabilities acquired by Chrysaor.
\nCash \ufb02ow hedge reserve
\nThe cash \ufb02ow hedge and cost of hedging reserves represent gains and losses on derivatives classi\ufb01ed as effective cash \ufb02ow hedges.
\nUpon the designation of option instruments as hedging instruments, the intrinsic and time value components are separated, with only
\nthe intrinsic component being designated as the hedging instrument and the time value component is deferred in other comprehensive
\nincome as a cost of hedging.
\nCurrency translation reserve
\nThis reserve comprises exchange differences arising on consolidation of the Group\u2019s operations with a functional currency other than
\nthe US dollar.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16773": {
"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
\nsettled 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
\nfor the effect of any market-based conditions. The fair value determined at the grant date of the equity-settled share-based payments is
\nexpensed on a straight-line basis over the vesting period, based on the Group\u2019s estimate of shares that will eventually vest and adjusted
\nfor the effect of non-market based vesting conditions. For cash-settled awards, a liability is recognised for the goods or service acquired.
\nThis is measured initially at the fair value of the liability. The fair value of the liability is subsequently remeasured at each balance sheet
\ndate 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16784": {
"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
\npurchase cost, determined on a \ufb01rst-in, \ufb01rst-out basis. Petroleum products and underlift and overlift positions are measured at net
\nrealisable 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16791": {
"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
\nby the Group. The \ufb01nance cost is charged to the income statement over the lease period so as to produce a constant periodic rate of
\ninterest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of lease term
\nand useful life. The Group recognises right-of-use assets and lease liabilities on a gross basis and the recovery of lease costs from
\njoint operations\u2019 partners is recorded as other income.
\n132
Right-of-use assets and lease liabilities arising from a lease are initially measured on a present value basis re\ufb02ecting the net present
\nvalue of the \ufb01xed lease payments and amounts expected to be payable by the Group assuming leases run to full term. The Group has
\napplied judgement to determine the lease term for some lease contracts in which it is a lessee that include renewal options. The
\nassessment of whether the Group is reasonably certain to exercise such options impacts the lease term, which signi\ufb01cantly impacts
\nthe amount of lease liabilities and right-of-use assets recognised.
\nThe lease payments are discounted using the Group\u2019s incremental borrowing rates of between 1.9 per cent and 6.8 per cent, being
\nthe rate that the Group would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic
\nenvironment with similar terms and conditions.
\nTo determine the incremental borrowing rate, the Group where possible:
\n\u00bc
Uses recent third party \ufb01nancing received by the individual lessee as a starting point, adjusted to re\ufb02ect changes in \ufb01nancing conditions
\nsince third party \ufb01nancing was received.
\n\u00bc
Makes adjustments speci\ufb01c to the lease, for example term, country, currency and security.
\nThe Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in
\nthe lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability
\nis reassessed and adjusted against the right-of-use asset.
\nLease payments are allocated between principal and \ufb01nance cost. The \ufb01nance cost is charged to the income statement over the lease
\nperiod so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.
\nRight-of-use assets are measured at cost comprising the following:
\n\u00bc
The amount of the initial measurement of lease liability.
\n\u00bc
Any lease payments made at or before the commencement date less any lease incentives received.
\n\u00bc
Any initial direct costs and restoration costs.
\nRight-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.
\nPayments associated with short-term leases and leases of low value assets are recognised on a straight-line basis as an expense in the
\nincome statement. Short-term leases are leases with a lease term of 12 months or less.
\nFor lease arrangements where all partners of a joint operation are considered to share the primary responsibility for lease payments
\nunder a lease contract, the Group recognises its share of the respective right-of-use asset and lease liability. This situation is most
\ncommon where the parties of a joint operation co-sign the lease contract.
\nThe Group recognises a gross lease liability for leases entered into on behalf of a joint operation where it has primary responsibility
\nfor making the lease payments. In such instances, if the arrangement between the Group and the joint operation represents a \ufb01nance
\nsublease, the Group recognises a net investment in sublease for amounts recoverable from non-operators whilst derecognising the
\nrespective portion of the gross right-of-use asset. The gross lease liability is retained on the balance sheet.
\nThe net investment in sublease is classi\ufb01ed as either trade and other receivables or long-term receivables on the balance sheet
\naccording to whether or not the amounts will be recovered within 12 months of the balance sheet date. Finance income is recognised
\nin respect of net investment in subleases.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16853": {
"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
\nembodying economic bene\ufb01ts will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
\nThe expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money
\nis material, provisions are discounted using a current pre-tax rate that re\ufb02ects, where appropriate, the risk speci\ufb01c to the liability. Where
\ndiscounting is used, the increase in the provision due to the passage of time is recognised as part of \ufb01nance costs in the income statement.
\nThe estimated cost of dismantling and restoring the production and related facilities at the end of the economic life of each \ufb01eld is
\nrecognised in full when the related facilities are installed. The amount provided is the present value of the estimated future restoration
\ncost. A non-current asset is also recognised. Any changes to estimated costs or discount rates are dealt with prospectively.
\nThe Group recognises provision for the estimated CO
\n2
\nemissions costs when actual emissions exceed the emission rights granted and
\nstill held. When actual emissions exceed the amount of emission rights granted, provision is recognised for the exceeding emission rights
\nbased 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16886": {
"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
\nretirement bene\ufb01t schemes are dealt with as payments to de\ufb01ned contribution plans where the Group\u2019s obligations under the schemes
\nare equivalent to those arising in a de\ufb01ned contribution retirement bene\ufb01t plan.
\nThe Group operates a de\ufb01ned bene\ufb01t pension scheme, which requires contributions to be made to a separately administered fund.
\nThe cost of providing bene\ufb01ts is determined using the projected unit credit method, with actuarial valuations being carried out at each
\nbalance sheet date. Actuarial gains and losses are recognised immediately in the statement of comprehensive income.
\nThe retirement bene\ufb01t obligation recognised in the balance sheet represents the present value of the de\ufb01ned bene\ufb01t obligation as
\nreduced by the fair value of plan assets. Any asset resulting from this calculation is limited to the present value of available refunds
\nand reductions in future contributions to the plan.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16899": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16903": {
"value": "Taxes Current tax
\nCurrent tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to
\nthe taxation authorities. The tax rates and laws used to compute the amount are those that are enacted or substantively enacted at the
\nreporting date in the countries where the Group operates and generates taxable income.
\nCurrent income tax related to items recognised directly in other comprehensive income or equity is recognised in other comprehensive
\nincome or directly in equity, not in the income statement.
\nDeferred tax
\nDeferred taxation is recognised in respect of all timing differences arising between the tax bases of the assets and liabilities and their
\ncarrying amounts in the \ufb01nancial statements with the following exceptions:
\n\u00bc
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
\ndeductible temporary difference, carried forward tax credits or tax losses can be utilised.
\n\u00bc
Deferred income tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply when
\nthe related asset is realised or liability is settled, based on tax rates and laws enacted or substantively enacted at the reporting date.
\nThe carrying amount of the deferred income tax asset is reviewed at each balance sheet date and reduced to the extent that it is no
\nlonger probable that suf\ufb01cient taxable pro\ufb01ts will be available to allow all or part of the asset to be recovered. The Group reassesses
\nany unrecognised deferred tax assets each year taking into account changes in oil and gas prices, the Group\u2019s proven and probable
\nreserves and resources pro\ufb01le and forecast capital and operating expenditures.
\n\u00bc
Deferred income tax assets and liabilities are offset only if a legally enforceable right exists to offset current assets against current tax liabilities,
\nthe deferred income tax relates to the same tax authority and that same tax authority permits the Group to make a single net payment.
\nDeferred tax is charged or credited in the income statement, except when it relates to items charged or credited in other comprehensive
\nincome, 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16912": {
"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
\ncarrying amounts in the \ufb01nancial statements with the following exceptions:
\n\u00bc
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
\ndeductible temporary difference, carried forward tax credits or tax losses can be utilised.
\n\u00bc
Deferred income tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply when
\nthe related asset is realised or liability is settled, based on tax rates and laws enacted or substantively enacted at the reporting date.
\nThe carrying amount of the deferred income tax asset is reviewed at each balance sheet date and reduced to the extent that it is no
\nlonger probable that suf\ufb01cient taxable pro\ufb01ts will be available to allow all or part of the asset to be recovered. The Group reassesses
\nany unrecognised deferred tax assets each year taking into account changes in oil and gas prices, the Group\u2019s proven and probable
\nreserves and resources pro\ufb01le and forecast capital and operating expenditures.
\n\u00bc
Deferred income tax assets and liabilities are offset only if a legally enforceable right exists to offset current assets against current tax liabilities,
\nthe deferred income tax relates to the same tax authority and that same tax authority permits the Group to make a single net payment.
\nDeferred 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16934": {
"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
\nservice to a customer. A good or service is transferred when the customer obtains control of that good or service. Revenue associated
\nwith the sale of crude oil, natural gas, and natural gas liquids (NGLs) is measured based on the consideration speci\ufb01ed in contracts with
\ncustomers with reference to quoted market prices in active markets, adjusted according to speci\ufb01c terms and conditions as applicable
\naccording to the sales contracts. The transfer of control of oil, natural gas, natural gas liquids and other items sold by the Group occurs
\nwhen title passes at the point the customer takes physical delivery. The Group principally satis\ufb01es its performance obligations at a point
\nin time and the amounts of revenue recognised relating to performance obligations satis\ufb01ed over time are not signi\ufb01cant.
\n134
Over/underlift
\nDifferences between the production sold and the Group\u2019s share of production result in an overlift or an underlift. Overlift and underlift
\nare valued at net realisable value using an observable year-end oil or gas market price and included within payables or receivables,
\nrespectively. Movements during the accounting period are recognised within cost of sales.
\nInterest income
\nInterest 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16962": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16967": {
"value": "Borrowing costs Borrowing costs directly attributable to the acquisition, construction or production of an asset that necessarily takes a substantial period
\nof 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
\nthe funds used to \ufb01nance a project form part of general borrowings, the amount capitalised is calculated using a weighted average of
\nrates applicable to relevant general borrowings of the Group during the period. All other borrowing costs are recognised in the income
\nstatement in the period in which they are incurred.",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingCostsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f16976": {
"value": "New accounting standards and interpretations The Group adopted new and revised accounting standards and interpretations relevant to its business and effective for accounting
\nperiods beginning on or after 1 January 2022, including:
\nAmendments to IFRS 3 \u2013 Reference to the Conceptual Framework
\nThe IASB issued amendments to IFRS 3 to update the reference to the 2018 Conceptual Framework. The amendments add an exception
\nto the recognition principle for liabilities and contingent liabilities within the scope of IAS 37 or IFRIC 21 and clarify existing guidance for
\ncontingent assets. The requirements are effective for annual reporting periods beginning on or after 1 January 2022 and apply prospectively.
\nIFRS 9 Financial Instruments \u2013 Fees in the 10 per cent test for derecognition of \ufb01nancial liabilities
\nAs part of its 2018-2020 annual improvements to IFRS standards process, the IASB issued an amendment to IFRS 9. The amendment
\nclari\ufb01es the fees that an entity includes when assessing whether the terms of a new or modi\ufb01ed \ufb01nancial liability are substantially different
\nfrom the terms of the original \ufb01nancial liability. These fees include only those paid or received between the borrower and the lender, including
\nfees paid or received by either the borrower or lender on the other\u2019s behalf. An entity applies the amendment to \ufb01nancial liabilities that are
\nmodi\ufb01ed or exchanged on or after the beginning of the annual reporting period in which the entity \ufb01rst applies the amendment.
\nThe amendment is effective for annual reporting periods beginning on or after 1 January 2022 with earlier adoption permitted. The
\nGroup has applied the amendments to \ufb01nancial liabilities that are modi\ufb01ed or exchanged on or after the beginning of the annual reporting
\nperiod in which the entity \ufb01rst applies the amendment.
\nAccounting standards issued but not yet effective
\nThe new and amended standards and interpretations that are issued, but not yet effective, up to the date of issuance of the Group\u2019s
\n\ufb01nancial statements are disclosed below. The Group intends to adopt these new and amended standards and interpretations, if
\napplicable, when they become effective.
\nAmendments to IAS 1, Presentation of Financial Statements \u2013 classi\ufb01cation of liabilities as current or non-current
\nOn 23 January 2020, the IASB issued a narrow-scope amendment to IAS 1 to clarify that liabilities are classi\ufb01ed as either current or
\nnon-current depending on the rights that exist at the end of the reporting period. Liabilities are classi\ufb01ed as non-current if the entity
\nhas a substantive right to defer settlement for at least 12 months at the end of the reporting period. The Group does not consider this
\namendment to have signi\ufb01cant impact on the classi\ufb01cation of its liabilities as either current or non-current when the standard becomes
\neffective on 1 January 2023.
\nAmendments to IAS 8 \u2013 De\ufb01nition of Accounting Estimates
\nIn February 2021, the International Accounting Standards Board issued De\ufb01nition of Accounting Estimates, which amended IAS 8
\nAccounting Policies, Changes in Accounting Estimates and Errors.
\nThe amendments introduced the de\ufb01nition of accounting estimates and included other amendments to IAS 8 to help entities distinguish
\nchanges in accounting estimates from changes in accounting policies, with the distinction important because changes in accounting
\nestimates are applied prospectively only to future transactions and other future events, but changes in accounting policies are generally
\nalso applied retrospectively to past transactions and other past events. The amendments are effective for annual periods beginning on
\nor after 1 January 2023.
\n135
Notes to the consolidated \ufb01nancial statements
continued
\n2. Signi\ufb01cant accounting policies
continued
\nAmendments to IAS 1 and IFRS Practice Statement 2 \u2013 Disclosure of Accounting Policies
\nIn February 2021, the International Accounting Standards Board issued amendments to IAS 1 Presentation of Financial Statements
\nand IFRS Practice Statement 2 Making Materiality Judgements. The amendments to IAS 1 require companies to disclose their material
\naccounting policy information rather than their signi\ufb01cant accounting policies. The amendments to IFRS Practice Statement 2 provides
\nguidance on how to apply the concept of materiality to accounting policy disclosures. The amendments are effective for annual periods
\nbeginning on or after 1 January 2023.
\nAmendments to IAS 12 \u2013 Deferred Tax related to Assets and Liabilities arising from a Single Transaction
\nOn 7 May 2021, the IASB issued amendments to IAS 12 Income Taxes. The amendments require companies to recognise deferred tax
\non transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences. According to the
\namended guidance, a temporary difference that arises on initial recognition of an asset or liability is not subject to the initial recognition
\nexemption if that transaction gave rise to equal amounts of taxable and deductible temporary differences. The proposed amendments
\nwill typically apply to transactions such as leases for the lessee and decommissioning obligations. The amendments are effective for
\nannual reporting periods beginning on or after 1 January 2023.
\nThe amendments listed above are not expected to have a material impact on the Group.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17045": {
"value": "Signi\ufb01cant accounting judgements and estimates The preparation of the Group\u2019s \ufb01nancial statements in conformity with IFRS requires management to make judgements, estimates
\nand assumptions at the date of the \ufb01nancial statements. Estimates and assumptions are continuously evaluated and are based on
\nmanagement experience and other factors, including expectations of future events that are believed to be reasonable under the
\ncircumstances. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to
\nthe carrying amount of the assets or liabilities affected in future periods. In particular, the Group has identi\ufb01ed the following areas
\nwhere signi\ufb01cant judgement, estimates and assumptions are required.
\nJudgements
\nThe signi\ufb01cant accounting judgements for the Group are considered to be:
\n\u00bc
the application of the going concern basis of accounting (see Basis of preparation section above);
\n\u00bc
the carrying value of intangible exploration and evaluation assets, in relation to whether commercial determination of an exploration
\nprospect had been reached;
\n\u00bc
the carrying value of property, plant and equipment regarding assessing assets for indicators of impairment;
\n\u00bc
decommissioning costs in relation to the timing of when decommissioning would occur; and
\n\u00bc
tax and recognition of deferred tax assets, relating to the extent to which future taxable pro\ufb01ts are included in the assessment
\nof recoverability, including the Energy Pro\ufb01ts Levy (EPL).
\nKey sources of estimation uncertainty
\nDetails of the Group\u2019s critical accounting estimates are set out in these \ufb01nancial statements and are considered to be:
\n\u00bc
the carrying value of property, plant and equipment and goodwill, where the key assumptions relate to oil and gas prices expected to be
\nrealised, and 2P production pro\ufb01les;
\n\u00bc
decommissioning costs where the key assumptions relate to the discount and in\ufb02ation rates applied, applicable rig rates and expected
\ntiming of cessation of production (COP) on each \ufb01eld; and
\n\u00bc
tax and recognition of deferred tax assets, where key assumptions relate to oil and gas prices expected to be realised, and production pro\ufb01les.
\nThe results from downside sensitivities prepared with regard to production and commodity price assumptions, which in management\u2019s
\nview re\ufb02ect the principal risks, indicate that material changes that would impact the carrying amounts of assets and liabilities within the
\nnext \ufb01nancial year are unlikely.
Further information is provided in the Audit and Risk Committee report on pages 68 to 71.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17094": {
"value": "3. Segment information The chief operating decision maker, who is responsible for allocating resources and assessing performance of the Group\u2019s business
\nsegments, has been identi\ufb01ed as the Chief Executive Of\ufb01cer.
\nThe Group\u2019s activities consist of one class of business being the acquisition, exploration, development and production of oil and gas reserves
\nand related activities, and are split geographically and managed in two regions, namely North Sea and International. The North Sea segment
\nincludes the UK and Norwegian continental shelves, and the International segment includes Indonesia, Vietnam and Mexico.
\nInformation on major customers can be found in note 4.
\nIncome statement
\n2022
\n$ million
\n2021
\n$ million
\nRevenue
\nNorth Sea
5,082.1
3,268.2
\nInternational
307.9
210.6
\nTotal Group sales revenue
5,390.0
3,478.8
\nOther income
\nNorth Sea
40.9
139.0
\nInternational
0.3
0.2
\nTotal Group revenue and other income
5,431.2
3,618.0
\nOperating pro\ufb01t
\nNorth Sea
2,388.4
699.3
\nInternational
152.5
(59.0)
\nGroup operating pro\ufb01t
2,540.9
640.3
\nFinance income
279.1
48.8
\nFinance expenses
(358.2)
(374.6)
\nPro\ufb01t before income tax
2,461.8
314.5
\nIncome tax expense
(2,453.6)
(213.4)
\nPro\ufb01t for the \ufb01nancial year
8.2
101.1
\nBalance sheet
\n2022
\n$ million
\n2021
\n$ million
\nSegment assets
\nNorth Sea
11,346.2
13,325.8
\nInternational
1,219.6
1,178.8
\nTotal assets
12,565.8
14,504.6
\nSegment liabilities
\nNorth Sea
(10,937.3)
(13,379.6)
\nInternational
(607.2)
(651.5)
\nTotal liabilities
(11,544.5)
(14,031.1)
\n137
Notes to the consolidated \ufb01nancial statements
continued
\n3. Segment information
continued
\nOther information
\n2022
\n$ million
\n2021
\n$ million
\nCapital additions
\nNorth Sea
576.2
640.7
\nInternational
108.6
68.4
\nTotal capital additions
684.8
709.1
\nDepreciation, depletion and amortisation
\nNorth Sea
1,470.4
1,299.8
\nInternational
75.4
71.2
\nTotal depreciation, depletion and amortisation
1,545.8
1,371.0
\nExploration and evaluation expenses and new ventures
\nNorth Sea
33.5
45.4
\nInternational
8.0
4.4
\nTotal exploration and evaluation expenses and new ventures
41.5
49.8
\nExploration costs written-o\ufb00
\nNorth Sea
71.6
121.1
\nInternational
(7.2)
133.9
\nTotal exploration costs written-o\ufb00
64.4
255.0
\nExploration costs written-off of $64.4 million is net of a $5.7 million credit related to a decrease in the decommissioning provisions in the North
\nSea (note 20) and includes a $7.0 million credit related to a change to the decommissioning estimate in the Falkland Islands business unit
\n(2021: $6.3 million relating to the effect of changes in decommissioning provisions on oil and gas intangible assets previously written-off).",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17243": {
"value": "4. Revenue from contracts with customers and other income 2022
\n$ million
\n2021
\n$ million
\nType of goods
\nCrude oil sales
2,791.9
2,023.4
\nGas sales
2,321.5
1,264.0
\nCondensate sales
238.3
163.6
\nTotal revenue from contracts with customers
\n1
\n5,351.7
3,451.0
\nTariff income
30.0
27.2
\nOther revenue
8.3
0.6
\nTotal revenue from production activities
5,390.0
3,478.8
\nOther income
\n2
\n41.2
139.2
\nTotal revenue and other income
5,431.2
3,618.0
\n1
Revenues from contracts with customers of $8,536.5 million (2021: $4,968.2 million) include crude oil sales of $3,544.7 million (2021: $2,278.1 million) and gas sales of $4,753.5 million
\n(2021: $2,526.5 million). This was prior to realised hedging losses in the period of $752.8 million (2021: $254.7 million) on crude oil and $2,432.0 million (2021: $1,262.5 million) on gas sales.
\n2
Other income mainly represents $20.3 million partner recoveries related to lease obligations (2021: $26.0 million), mark to market losses on EUA emissions hedges of $2.6 million
\n(2021: gain of $51.0 million) and $16.7 million in respect of research and development expenditure credits (RDEC) (2021: $17.5 million). Other income in 2021 included a receipt from
\nConocoPhillips in relation to an adjustment to consideration relating to Chrysaor\u2019s purchase of the ConocoPhillips UK business in 2019 (2021: $40.0 million).
\nApproximately 84 per cent (2021: 84 per cent) of the revenues were attributable to sales to energy trading companies of the Shell group.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17244": {
"value": "4. Revenue from contracts with customers and other income 2022
\n$ million
\n2021
\n$ million
\nType of goods
\nCrude oil sales
2,791.9
2,023.4
\nGas sales
2,321.5
1,264.0
\nCondensate sales
238.3
163.6
\nTotal revenue from contracts with customers
\n1
\n5,351.7
3,451.0
\nTariff income
30.0
27.2
\nOther revenue
8.3
0.6
\nTotal revenue from production activities
5,390.0
3,478.8
\nOther income
\n2
\n41.2
139.2
\nTotal revenue and other income
5,431.2
3,618.0
\n1
Revenues from contracts with customers of $8,536.5 million (2021: $4,968.2 million) include crude oil sales of $3,544.7 million (2021: $2,278.1 million) and gas sales of $4,753.5 million
\n(2021: $2,526.5 million). This was prior to realised hedging losses in the period of $752.8 million (2021: $254.7 million) on crude oil and $2,432.0 million (2021: $1,262.5 million) on gas sales.
\n2
Other income mainly represents $20.3 million partner recoveries related to lease obligations (2021: $26.0 million), mark to market losses on EUA emissions hedges of $2.6 million
\n(2021: gain of $51.0 million) and $16.7 million in respect of research and development expenditure credits (RDEC) (2021: $17.5 million). Other income in 2021 included a receipt from
\nConocoPhillips in relation to an adjustment to consideration relating to Chrysaor\u2019s purchase of the ConocoPhillips UK business in 2019 (2021: $40.0 million).
\nApproximately 84 per cent (2021: 84 per cent) of the revenues were attributable to sales to energy trading companies of the Shell group.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17245": {
"value": "4. Revenue from contracts with customers and other income 2022
\n$ million
\n2021
\n$ million
\nType of goods
\nCrude oil sales
2,791.9
2,023.4
\nGas sales
2,321.5
1,264.0
\nCondensate sales
238.3
163.6
\nTotal revenue from contracts with customers
\n1
\n5,351.7
3,451.0
\nTariff income
30.0
27.2
\nOther revenue
8.3
0.6
\nTotal revenue from production activities
5,390.0
3,478.8
\nOther income
\n2
\n41.2
139.2
\nTotal revenue and other income
5,431.2
3,618.0
\n1
Revenues from contracts with customers of $8,536.5 million (2021: $4,968.2 million) include crude oil sales of $3,544.7 million (2021: $2,278.1 million) and gas sales of $4,753.5 million
\n(2021: $2,526.5 million). This was prior to realised hedging losses in the period of $752.8 million (2021: $254.7 million) on crude oil and $2,432.0 million (2021: $1,262.5 million) on gas sales.
\n2
Other income mainly represents $20.3 million partner recoveries related to lease obligations (2021: $26.0 million), mark to market losses on EUA emissions hedges of $2.6 million
\n(2021: gain of $51.0 million) and $16.7 million in respect of research and development expenditure credits (RDEC) (2021: $17.5 million). Other income in 2021 included a receipt from
\nConocoPhillips in relation to an adjustment to consideration relating to Chrysaor\u2019s purchase of the ConocoPhillips UK business in 2019 (2021: $40.0 million).
\nApproximately 84 per cent (2021: 84 per cent) of the revenues were attributable to sales to energy trading companies of the Shell group.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRevenueExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17305": {
"value": "5. Operating pro\ufb01t Note
\n2022
\n$ million
\n2021
\n$ million
\nCost of operations
\nProduction, insurance and transportation costs
1,114.2
1,085.5
\nGas purchases
36.6
28.4
\nRoyalties
5.0
3.8
\nDepreciation of oil and gas assets
12
1,318.4
1,204.1
\nDepreciation of right-of-use oil and gas assets
13
218.6
153.9
\nCapitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(29.9)
(30.7)
\nOther cost of operations
\u2013
(0.5)
\nOnerous contract provision
20
\u2013
(2.3)
\nAmortisation of capacity rights
11
1.0
1.6
\nRemeasurement of royalty valuation
\u2013
(0.5)
\nRemeasurement \u2013 loss on termination of lease
\u2013
0.3
\nMovement in over/underlift balances and hydrocarbon inventories
180.9
9.6
\nTotal cost of operations
2,844.8
2,453.2
\nImpairment (reversal)/expense of property, plant and equipment
12
(87.3)
108.7
\nImpairment (gain)/loss due to (decrease)/increase in decommissioning
\nprovisions on oil and gas tangible assets
20
(82.3)
8.5
\nExploration costs written-off
\n1
\n11
64.4
255.0
\nExploration and evaluation expenditure and new ventures
\n2
\n41.5
49.8
\n(Gain)/loss on disposal
\n3
\n(12.1)
0.1
\nGeneral and administrative expenses
\nDepreciation of right-of-use non-oil and gas assets
13
11.2
10.5
\nDepreciation of non-oil and gas assets
12
5.4
5.5
\nAmortisation of non-oil and gas intangible assets
11
21.1
26.1
\nOther administrative costs
83.6
60.4
\nTotal general and administrative expenses
\n4
\n121.3
102.5
\nAuditor\u2019s remuneration
\nAudit fees
\nFees payable to the company\u2019s auditor for the company\u2019s Annual Report
2.6
2.3
\nAudit of the company\u2019s subsidiaries pursuant to legislation
0.6
0.5
\nNon-audit fees
\n5
\nOther services pursuant to legislation \u2013 interim review
0.2
0.3
\nOther services
\n6
\n0.8
0.4
\n1
Exploration costs written-off of $64.4 million includes a credit of $7.0 million related to a change to the decommissioning estimate in the Falkland Islands business unit.
\n2
Exploration and evaluation expenditure and new ventures of $41.5 million (2021: $49.8 million) includes $28.4 million (2021: $14.4 million) of early project costs on new ventures
\nincurred in respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $13.1 million (2021 $35.4 million) of ongoing pre-licence costs.
\n3
The gain on disposal of $12.1 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the period
\nfor tax claims to be submitted.
\n4
Expenses related to both short-term and low value lease arrangements are considered to be immaterial for reporting purposes.
\n5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the Group\u2019s website.
\nThe use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
\ncon\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
\n6
Other services in 2022 primarily relate to reporting accountant services provided by EY. In 2021 this also included services in respect of the merger and other corporate transactions.
\nThe Audit and Risk Committee concluded that shareholder value was best served by appointing our auditors for this work.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17306": {
"value": "5. Operating pro\ufb01t Note
\n2022
\n$ million
\n2021
\n$ million
\nCost of operations
\nProduction, insurance and transportation costs
1,114.2
1,085.5
\nGas purchases
36.6
28.4
\nRoyalties
5.0
3.8
\nDepreciation of oil and gas assets
12
1,318.4
1,204.1
\nDepreciation of right-of-use oil and gas assets
13
218.6
153.9
\nCapitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(29.9)
(30.7)
\nOther cost of operations
\u2013
(0.5)
\nOnerous contract provision
20
\u2013
(2.3)
\nAmortisation of capacity rights
11
1.0
1.6
\nRemeasurement of royalty valuation
\u2013
(0.5)
\nRemeasurement \u2013 loss on termination of lease
\u2013
0.3
\nMovement in over/underlift balances and hydrocarbon inventories
180.9
9.6
\nTotal cost of operations
2,844.8
2,453.2
\nImpairment (reversal)/expense of property, plant and equipment
12
(87.3)
108.7
\nImpairment (gain)/loss due to (decrease)/increase in decommissioning
\nprovisions on oil and gas tangible assets
20
(82.3)
8.5
\nExploration costs written-off
\n1
\n11
64.4
255.0
\nExploration and evaluation expenditure and new ventures
\n2
\n41.5
49.8
\n(Gain)/loss on disposal
\n3
\n(12.1)
0.1
\nGeneral and administrative expenses
\nDepreciation of right-of-use non-oil and gas assets
13
11.2
10.5
\nDepreciation of non-oil and gas assets
12
5.4
5.5
\nAmortisation of non-oil and gas intangible assets
11
21.1
26.1
\nOther administrative costs
83.6
60.4
\nTotal general and administrative expenses
\n4
\n121.3
102.5
\nAuditor\u2019s remuneration
\nAudit fees
\nFees payable to the company\u2019s auditor for the company\u2019s Annual Report
2.6
2.3
\nAudit of the company\u2019s subsidiaries pursuant to legislation
0.6
0.5
\nNon-audit fees
\n5
\nOther services pursuant to legislation \u2013 interim review
0.2
0.3
\nOther services
\n6
\n0.8
0.4
\n1
Exploration costs written-off of $64.4 million includes a credit of $7.0 million related to a change to the decommissioning estimate in the Falkland Islands business unit.
\n2
Exploration and evaluation expenditure and new ventures of $41.5 million (2021: $49.8 million) includes $28.4 million (2021: $14.4 million) of early project costs on new ventures
\nincurred in respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $13.1 million (2021 $35.4 million) of ongoing pre-licence costs.
\n3
The gain on disposal of $12.1 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the period
\nfor tax claims to be submitted.
\n4
Expenses related to both short-term and low value lease arrangements are considered to be immaterial for reporting purposes.
\n5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the Group\u2019s website.
\nThe use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
\ncon\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
\n6
Other services in 2022 primarily relate to reporting accountant services provided by EY. In 2021 this also included services in respect of the merger and other corporate transactions.
\nThe Audit and Risk Committee concluded that shareholder value was best served by appointing our auditors for this work.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGeneralAndAdministrativeExpenseExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17307": {
"value": "5. Operating pro\ufb01t Note
\n2022
\n$ million
\n2021
\n$ million
\nCost of operations
\nProduction, insurance and transportation costs
1,114.2
1,085.5
\nGas purchases
36.6
28.4
\nRoyalties
5.0
3.8
\nDepreciation of oil and gas assets
12
1,318.4
1,204.1
\nDepreciation of right-of-use oil and gas assets
13
218.6
153.9
\nCapitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(29.9)
(30.7)
\nOther cost of operations
\u2013
(0.5)
\nOnerous contract provision
20
\u2013
(2.3)
\nAmortisation of capacity rights
11
1.0
1.6
\nRemeasurement of royalty valuation
\u2013
(0.5)
\nRemeasurement \u2013 loss on termination of lease
\u2013
0.3
\nMovement in over/underlift balances and hydrocarbon inventories
180.9
9.6
\nTotal cost of operations
2,844.8
2,453.2
\nImpairment (reversal)/expense of property, plant and equipment
12
(87.3)
108.7
\nImpairment (gain)/loss due to (decrease)/increase in decommissioning
\nprovisions on oil and gas tangible assets
20
(82.3)
8.5
\nExploration costs written-off
\n1
\n11
64.4
255.0
\nExploration and evaluation expenditure and new ventures
\n2
\n41.5
49.8
\n(Gain)/loss on disposal
\n3
\n(12.1)
0.1
\nGeneral and administrative expenses
\nDepreciation of right-of-use non-oil and gas assets
13
11.2
10.5
\nDepreciation of non-oil and gas assets
12
5.4
5.5
\nAmortisation of non-oil and gas intangible assets
11
21.1
26.1
\nOther administrative costs
83.6
60.4
\nTotal general and administrative expenses
\n4
\n121.3
102.5
\nAuditor\u2019s remuneration
\nAudit fees
\nFees payable to the company\u2019s auditor for the company\u2019s Annual Report
2.6
2.3
\nAudit of the company\u2019s subsidiaries pursuant to legislation
0.6
0.5
\nNon-audit fees
\n5
\nOther services pursuant to legislation \u2013 interim review
0.2
0.3
\nOther services
\n6
\n0.8
0.4
\n1
Exploration costs written-off of $64.4 million includes a credit of $7.0 million related to a change to the decommissioning estimate in the Falkland Islands business unit.
\n2
Exploration and evaluation expenditure and new ventures of $41.5 million (2021: $49.8 million) includes $28.4 million (2021: $14.4 million) of early project costs on new ventures
\nincurred in respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $13.1 million (2021 $35.4 million) of ongoing pre-licence costs.
\n3
The gain on disposal of $12.1 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the period
\nfor tax claims to be submitted.
\n4
Expenses related to both short-term and low value lease arrangements are considered to be immaterial for reporting purposes.
\n5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the Group\u2019s website.
\nThe use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
\ncon\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
\n6
Other services in 2022 primarily relate to reporting accountant services provided by EY. In 2021 this also included services in respect of the merger and other corporate transactions.
\nThe Audit and Risk Committee concluded that shareholder value was best served by appointing our auditors for this work.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfProfitLossFromOperatingActivitiesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17308": {
"value": "5. Operating pro\ufb01t Note
\n2022
\n$ million
\n2021
\n$ million
\nCost of operations
\nProduction, insurance and transportation costs
1,114.2
1,085.5
\nGas purchases
36.6
28.4
\nRoyalties
5.0
3.8
\nDepreciation of oil and gas assets
12
1,318.4
1,204.1
\nDepreciation of right-of-use oil and gas assets
13
218.6
153.9
\nCapitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(29.9)
(30.7)
\nOther cost of operations
\u2013
(0.5)
\nOnerous contract provision
20
\u2013
(2.3)
\nAmortisation of capacity rights
11
1.0
1.6
\nRemeasurement of royalty valuation
\u2013
(0.5)
\nRemeasurement \u2013 loss on termination of lease
\u2013
0.3
\nMovement in over/underlift balances and hydrocarbon inventories
180.9
9.6
\nTotal cost of operations
2,844.8
2,453.2
\nImpairment (reversal)/expense of property, plant and equipment
12
(87.3)
108.7
\nImpairment (gain)/loss due to (decrease)/increase in decommissioning
\nprovisions on oil and gas tangible assets
20
(82.3)
8.5
\nExploration costs written-off
\n1
\n11
64.4
255.0
\nExploration and evaluation expenditure and new ventures
\n2
\n41.5
49.8
\n(Gain)/loss on disposal
\n3
\n(12.1)
0.1
\nGeneral and administrative expenses
\nDepreciation of right-of-use non-oil and gas assets
13
11.2
10.5
\nDepreciation of non-oil and gas assets
12
5.4
5.5
\nAmortisation of non-oil and gas intangible assets
11
21.1
26.1
\nOther administrative costs
83.6
60.4
\nTotal general and administrative expenses
\n4
\n121.3
102.5
\nAuditor\u2019s remuneration
\nAudit fees
\nFees payable to the company\u2019s auditor for the company\u2019s Annual Report
2.6
2.3
\nAudit of the company\u2019s subsidiaries pursuant to legislation
0.6
0.5
\nNon-audit fees
\n5
\nOther services pursuant to legislation \u2013 interim review
0.2
0.3
\nOther services
\n6
\n0.8
0.4
\n1
Exploration costs written-off of $64.4 million includes a credit of $7.0 million related to a change to the decommissioning estimate in the Falkland Islands business unit.
\n2
Exploration and evaluation expenditure and new ventures of $41.5 million (2021: $49.8 million) includes $28.4 million (2021: $14.4 million) of early project costs on new ventures
\nincurred in respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $13.1 million (2021 $35.4 million) of ongoing pre-licence costs.
\n3
The gain on disposal of $12.1 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the period
\nfor tax claims to be submitted.
\n4
Expenses related to both short-term and low value lease arrangements are considered to be immaterial for reporting purposes.
\n5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the Group\u2019s website.
\nThe use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
\ncon\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
\n6
Other services in 2022 primarily relate to reporting accountant services provided by EY. In 2021 this also included services in respect of the merger and other corporate transactions.
\nThe Audit and Risk Committee concluded that shareholder value was best served by appointing our auditors for this work.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCostOfSalesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17309": {
"value": "5. Operating pro\ufb01t Note
\n2022
\n$ million
\n2021
\n$ million
\nCost of operations
\nProduction, insurance and transportation costs
1,114.2
1,085.5
\nGas purchases
36.6
28.4
\nRoyalties
5.0
3.8
\nDepreciation of oil and gas assets
12
1,318.4
1,204.1
\nDepreciation of right-of-use oil and gas assets
13
218.6
153.9
\nCapitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(29.9)
(30.7)
\nOther cost of operations
\u2013
(0.5)
\nOnerous contract provision
20
\u2013
(2.3)
\nAmortisation of capacity rights
11
1.0
1.6
\nRemeasurement of royalty valuation
\u2013
(0.5)
\nRemeasurement \u2013 loss on termination of lease
\u2013
0.3
\nMovement in over/underlift balances and hydrocarbon inventories
180.9
9.6
\nTotal cost of operations
2,844.8
2,453.2
\nImpairment (reversal)/expense of property, plant and equipment
12
(87.3)
108.7
\nImpairment (gain)/loss due to (decrease)/increase in decommissioning
\nprovisions on oil and gas tangible assets
20
(82.3)
8.5
\nExploration costs written-off
\n1
\n11
64.4
255.0
\nExploration and evaluation expenditure and new ventures
\n2
\n41.5
49.8
\n(Gain)/loss on disposal
\n3
\n(12.1)
0.1
\nGeneral and administrative expenses
\nDepreciation of right-of-use non-oil and gas assets
13
11.2
10.5
\nDepreciation of non-oil and gas assets
12
5.4
5.5
\nAmortisation of non-oil and gas intangible assets
11
21.1
26.1
\nOther administrative costs
83.6
60.4
\nTotal general and administrative expenses
\n4
\n121.3
102.5
\nAuditor\u2019s remuneration
\nAudit fees
\nFees payable to the company\u2019s auditor for the company\u2019s Annual Report
2.6
2.3
\nAudit of the company\u2019s subsidiaries pursuant to legislation
0.6
0.5
\nNon-audit fees
\n5
\nOther services pursuant to legislation \u2013 interim review
0.2
0.3
\nOther services
\n6
\n0.8
0.4
\n1
Exploration costs written-off of $64.4 million includes a credit of $7.0 million related to a change to the decommissioning estimate in the Falkland Islands business unit.
\n2
Exploration and evaluation expenditure and new ventures of $41.5 million (2021: $49.8 million) includes $28.4 million (2021: $14.4 million) of early project costs on new ventures
\nincurred in respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $13.1 million (2021 $35.4 million) of ongoing pre-licence costs.
\n3
The gain on disposal of $12.1 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the period
\nfor tax claims to be submitted.
\n4
Expenses related to both short-term and low value lease arrangements are considered to be immaterial for reporting purposes.
\n5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the Group\u2019s website.
\nThe use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
\ncon\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
\n6
Other services in 2022 primarily relate to reporting accountant services provided by EY. In 2021 this also included services in respect of the merger and other corporate transactions.
\nThe Audit and Risk Committee concluded that shareholder value was best served by appointing our auditors for this work.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfExpensesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17310": {
"value": "5. Operating pro\ufb01t Note
\n2022
\n$ million
\n2021
\n$ million
\nCost of operations
\nProduction, insurance and transportation costs
1,114.2
1,085.5
\nGas purchases
36.6
28.4
\nRoyalties
5.0
3.8
\nDepreciation of oil and gas assets
12
1,318.4
1,204.1
\nDepreciation of right-of-use oil and gas assets
13
218.6
153.9
\nCapitalisation of IFRS 16 lease depreciation on oil and gas assets
13
(29.9)
(30.7)
\nOther cost of operations
\u2013
(0.5)
\nOnerous contract provision
20
\u2013
(2.3)
\nAmortisation of capacity rights
11
1.0
1.6
\nRemeasurement of royalty valuation
\u2013
(0.5)
\nRemeasurement \u2013 loss on termination of lease
\u2013
0.3
\nMovement in over/underlift balances and hydrocarbon inventories
180.9
9.6
\nTotal cost of operations
2,844.8
2,453.2
\nImpairment (reversal)/expense of property, plant and equipment
12
(87.3)
108.7
\nImpairment (gain)/loss due to (decrease)/increase in decommissioning
\nprovisions on oil and gas tangible assets
20
(82.3)
8.5
\nExploration costs written-off
\n1
\n11
64.4
255.0
\nExploration and evaluation expenditure and new ventures
\n2
\n41.5
49.8
\n(Gain)/loss on disposal
\n3
\n(12.1)
0.1
\nGeneral and administrative expenses
\nDepreciation of right-of-use non-oil and gas assets
13
11.2
10.5
\nDepreciation of non-oil and gas assets
12
5.4
5.5
\nAmortisation of non-oil and gas intangible assets
11
21.1
26.1
\nOther administrative costs
83.6
60.4
\nTotal general and administrative expenses
\n4
\n121.3
102.5
\nAuditor\u2019s remuneration
\nAudit fees
\nFees payable to the company\u2019s auditor for the company\u2019s Annual Report
2.6
2.3
\nAudit of the company\u2019s subsidiaries pursuant to legislation
0.6
0.5
\nNon-audit fees
\n5
\nOther services pursuant to legislation \u2013 interim review
0.2
0.3
\nOther services
\n6
\n0.8
0.4
\n1
Exploration costs written-off of $64.4 million includes a credit of $7.0 million related to a change to the decommissioning estimate in the Falkland Islands business unit.
\n2
Exploration and evaluation expenditure and new ventures of $41.5 million (2021: $49.8 million) includes $28.4 million (2021: $14.4 million) of early project costs on new ventures
\nincurred in respect of the Group\u2019s interest in CCS and electri\ufb01cation projects in the UK, plus $13.1 million (2021 $35.4 million) of ongoing pre-licence costs.
\n3
The gain on disposal of $12.1 million relates to the release of a provision associated with Premier\u2019s sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the period
\nfor tax claims to be submitted.
\n4
Expenses related to both short-term and low value lease arrangements are considered to be immaterial for reporting purposes.
\n5
The company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the Group\u2019s website.
\nThe use of the external auditor for services relating to accounting systems or \ufb01nancial statement preparations is not permitted, as are various other services that could give rise to
\ncon\ufb02icts of interest or other threats to the auditor\u2019s objectivity that cannot be reduced to an acceptable level by applying safeguards.
\n6
Other services in 2022 primarily relate to reporting accountant services provided by EY. In 2021 this also included services in respect of the merger and other corporate transactions.
\nThe Audit and Risk Committee concluded that shareholder value was best served by appointing our auditors for this work.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17462": {
"value": "6. Staff costs 2022
\n$ million
\n2021
\n$ million
\nWages and salaries and other staff costs
306.1
261.0
\nSocial security costs
30.1
27.9
\nPension costs
30.3
28.2
\nTotal sta\ufb00 costs
366.5
317.1
\nAverage annual number of employees employed by the Group worldwide was:
\n2022
\nNumber
\n2021
\nNumber
\nOffshore based
559
589
\nOf\ufb01ce and administration
1,273
1,218
\nTotal sta\ufb00
1,832
1,807
\nStaff costs above are recharged to joint venture partners where applicable, or are capitalised to the extent that they are directly attributable
\nto capital or decommissioning projects. The above costs include share-based payments as disclosed in note 25.
\nAll employees were engaged in the acquisition, exploration, development and production of oil and gas reserves, and energy transition activities.
\nThe Group operates two de\ufb01ned contribution schemes 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17500": {
"value": "7. Finance income and \ufb01nance expenses Note
\n2022
\n$ million
\n2021
\n$ million
\nFinance income
\nBank interest
10.2
0.9
\nOther interest and \ufb01nance gains
\n1
\n20.0
3.2
\nIFRS 9 modi\ufb01cation impact
\u2013
13.9
\nLease \ufb01nance income
1.7
3.2
\nFinance income on deferred revenue
19
\u2013
1.2
\nRealised gains on interest rate swaps
6.5
\u2013
\nRealised gains on foreign exchange forward contracts
0.5
10.0
\nGains on derivatives
\n2
\n38.2
14.5
\nForeign exchange gains
\n3
\n202.0
1.9
\nTotal \ufb01nance income
279.1
48.8
\nFinance expenses
\nInterest payable on reserves-based lending
71.1
101.6
\nInterest payable on bond
27.3
5.7
\nInterest payable on loan notes
\u2013
5.6
\nOther interest and \ufb01nance expenses
\n4
\n11.7
16.6
\nLease interest
13
25.1
22.3
\nRealised losses on interest rate swaps
\u2013
2.4
\nLosses on derivatives
\n5
\n48.0
14.6
\nFinance expense on deferred revenue
19
19.9
\u2013
\nForeign exchange losses
\u2013
65.2
\nBank and \ufb01nancing fees
\n6
\n91.0
63.4
\nUnwinding of discount on decommissioning and other provisions
20
65.1
78.0
\n359.2
375.4
\nFinance costs capitalised during the year
\n7
\n(1.0)
(0.8)
\nTotal \ufb01nance expense
358.2
374.6
\n1
Other interest and \ufb01nance gains includes $16.0 million (2021: $1.9 million) related to an update to the amount recognised under the decommissioning liability agreement as detailed in note 16.
\n2
Gains on derivatives mainly relates to mark to market gains on interest rate and foreign currency derivatives.
\n3
Signi\ufb01cant unrealised foreign exchange gains consist mainly of unrealised gains arising from revaluation of open gas hedges denominated in pound sterling.
\n4
Other interest includes a $9.5 million charge (2021: $11.6 million) which represents interest under a \ufb01nancing arrangement (note 21).
\n5
Losses on derivatives relate to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2021: $14.6 million).
\n6
Bank and \ufb01nancing fees include an amount of $54.9 million (2021: $38.9 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s
\nlong-term borrowings (note 21).
\n7
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 4.4 per cent to the
\nexpenditures on the qualifying assets (2021: 3.7 per cent). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17501": {
"value": "7. Finance income and \ufb01nance expenses Note
\n2022
\n$ million
\n2021
\n$ million
\nFinance income
\nBank interest
10.2
0.9
\nOther interest and \ufb01nance gains
\n1
\n20.0
3.2
\nIFRS 9 modi\ufb01cation impact
\u2013
13.9
\nLease \ufb01nance income
1.7
3.2
\nFinance income on deferred revenue
19
\u2013
1.2
\nRealised gains on interest rate swaps
6.5
\u2013
\nRealised gains on foreign exchange forward contracts
0.5
10.0
\nGains on derivatives
\n2
\n38.2
14.5
\nForeign exchange gains
\n3
\n202.0
1.9
\nTotal \ufb01nance income
279.1
48.8
\nFinance expenses
\nInterest payable on reserves-based lending
71.1
101.6
\nInterest payable on bond
27.3
5.7
\nInterest payable on loan notes
\u2013
5.6
\nOther interest and \ufb01nance expenses
\n4
\n11.7
16.6
\nLease interest
13
25.1
22.3
\nRealised losses on interest rate swaps
\u2013
2.4
\nLosses on derivatives
\n5
\n48.0
14.6
\nFinance expense on deferred revenue
19
19.9
\u2013
\nForeign exchange losses
\u2013
65.2
\nBank and \ufb01nancing fees
\n6
\n91.0
63.4
\nUnwinding of discount on decommissioning and other provisions
20
65.1
78.0
\n359.2
375.4
\nFinance costs capitalised during the year
\n7
\n(1.0)
(0.8)
\nTotal \ufb01nance expense
358.2
374.6
\n1
Other interest and \ufb01nance gains includes $16.0 million (2021: $1.9 million) related to an update to the amount recognised under the decommissioning liability agreement as detailed in note 16.
\n2
Gains on derivatives mainly relates to mark to market gains on interest rate and foreign currency derivatives.
\n3
Signi\ufb01cant unrealised foreign exchange gains consist mainly of unrealised gains arising from revaluation of open gas hedges denominated in pound sterling.
\n4
Other interest includes a $9.5 million charge (2021: $11.6 million) which represents interest under a \ufb01nancing arrangement (note 21).
\n5
Losses on derivatives relate to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2021: $14.6 million).
\n6
Bank and \ufb01nancing fees include an amount of $54.9 million (2021: $38.9 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s
\nlong-term borrowings (note 21).
\n7
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 4.4 per cent to the
\nexpenditures on the qualifying assets (2021: 3.7 per cent). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17502": {
"value": "7. Finance income and \ufb01nance expenses Note
\n2022
\n$ million
\n2021
\n$ million
\nFinance income
\nBank interest
10.2
0.9
\nOther interest and \ufb01nance gains
\n1
\n20.0
3.2
\nIFRS 9 modi\ufb01cation impact
\u2013
13.9
\nLease \ufb01nance income
1.7
3.2
\nFinance income on deferred revenue
19
\u2013
1.2
\nRealised gains on interest rate swaps
6.5
\u2013
\nRealised gains on foreign exchange forward contracts
0.5
10.0
\nGains on derivatives
\n2
\n38.2
14.5
\nForeign exchange gains
\n3
\n202.0
1.9
\nTotal \ufb01nance income
279.1
48.8
\nFinance expenses
\nInterest payable on reserves-based lending
71.1
101.6
\nInterest payable on bond
27.3
5.7
\nInterest payable on loan notes
\u2013
5.6
\nOther interest and \ufb01nance expenses
\n4
\n11.7
16.6
\nLease interest
13
25.1
22.3
\nRealised losses on interest rate swaps
\u2013
2.4
\nLosses on derivatives
\n5
\n48.0
14.6
\nFinance expense on deferred revenue
19
19.9
\u2013
\nForeign exchange losses
\u2013
65.2
\nBank and \ufb01nancing fees
\n6
\n91.0
63.4
\nUnwinding of discount on decommissioning and other provisions
20
65.1
78.0
\n359.2
375.4
\nFinance costs capitalised during the year
\n7
\n(1.0)
(0.8)
\nTotal \ufb01nance expense
358.2
374.6
\n1
Other interest and \ufb01nance gains includes $16.0 million (2021: $1.9 million) related to an update to the amount recognised under the decommissioning liability agreement as detailed in note 16.
\n2
Gains on derivatives mainly relates to mark to market gains on interest rate and foreign currency derivatives.
\n3
Signi\ufb01cant unrealised foreign exchange gains consist mainly of unrealised gains arising from revaluation of open gas hedges denominated in pound sterling.
\n4
Other interest includes a $9.5 million charge (2021: $11.6 million) which represents interest under a \ufb01nancing arrangement (note 21).
\n5
Losses on derivatives relate to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2021: $14.6 million).
\n6
Bank and \ufb01nancing fees include an amount of $54.9 million (2021: $38.9 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s
\nlong-term borrowings (note 21).
\n7
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 4.4 per cent to the
\nexpenditures on the qualifying assets (2021: 3.7 per cent). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17503": {
"value": "7. Finance income and \ufb01nance expenses Note
\n2022
\n$ million
\n2021
\n$ million
\nFinance income
\nBank interest
10.2
0.9
\nOther interest and \ufb01nance gains
\n1
\n20.0
3.2
\nIFRS 9 modi\ufb01cation impact
\u2013
13.9
\nLease \ufb01nance income
1.7
3.2
\nFinance income on deferred revenue
19
\u2013
1.2
\nRealised gains on interest rate swaps
6.5
\u2013
\nRealised gains on foreign exchange forward contracts
0.5
10.0
\nGains on derivatives
\n2
\n38.2
14.5
\nForeign exchange gains
\n3
\n202.0
1.9
\nTotal \ufb01nance income
279.1
48.8
\nFinance expenses
\nInterest payable on reserves-based lending
71.1
101.6
\nInterest payable on bond
27.3
5.7
\nInterest payable on loan notes
\u2013
5.6
\nOther interest and \ufb01nance expenses
\n4
\n11.7
16.6
\nLease interest
13
25.1
22.3
\nRealised losses on interest rate swaps
\u2013
2.4
\nLosses on derivatives
\n5
\n48.0
14.6
\nFinance expense on deferred revenue
19
19.9
\u2013
\nForeign exchange losses
\u2013
65.2
\nBank and \ufb01nancing fees
\n6
\n91.0
63.4
\nUnwinding of discount on decommissioning and other provisions
20
65.1
78.0
\n359.2
375.4
\nFinance costs capitalised during the year
\n7
\n(1.0)
(0.8)
\nTotal \ufb01nance expense
358.2
374.6
\n1
Other interest and \ufb01nance gains includes $16.0 million (2021: $1.9 million) related to an update to the amount recognised under the decommissioning liability agreement as detailed in note 16.
\n2
Gains on derivatives mainly relates to mark to market gains on interest rate and foreign currency derivatives.
\n3
Signi\ufb01cant unrealised foreign exchange gains consist mainly of unrealised gains arising from revaluation of open gas hedges denominated in pound sterling.
\n4
Other interest includes a $9.5 million charge (2021: $11.6 million) which represents interest under a \ufb01nancing arrangement (note 21).
\n5
Losses on derivatives relate to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2021: $14.6 million).
\n6
Bank and \ufb01nancing fees include an amount of $54.9 million (2021: $38.9 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s
\nlong-term borrowings (note 21).
\n7
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 4.4 per cent to the
\nexpenditures on the qualifying assets (2021: 3.7 per cent). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17504": {
"value": "7. Finance income and \ufb01nance expenses Note
\n2022
\n$ million
\n2021
\n$ million
\nFinance income
\nBank interest
10.2
0.9
\nOther interest and \ufb01nance gains
\n1
\n20.0
3.2
\nIFRS 9 modi\ufb01cation impact
\u2013
13.9
\nLease \ufb01nance income
1.7
3.2
\nFinance income on deferred revenue
19
\u2013
1.2
\nRealised gains on interest rate swaps
6.5
\u2013
\nRealised gains on foreign exchange forward contracts
0.5
10.0
\nGains on derivatives
\n2
\n38.2
14.5
\nForeign exchange gains
\n3
\n202.0
1.9
\nTotal \ufb01nance income
279.1
48.8
\nFinance expenses
\nInterest payable on reserves-based lending
71.1
101.6
\nInterest payable on bond
27.3
5.7
\nInterest payable on loan notes
\u2013
5.6
\nOther interest and \ufb01nance expenses
\n4
\n11.7
16.6
\nLease interest
13
25.1
22.3
\nRealised losses on interest rate swaps
\u2013
2.4
\nLosses on derivatives
\n5
\n48.0
14.6
\nFinance expense on deferred revenue
19
19.9
\u2013
\nForeign exchange losses
\u2013
65.2
\nBank and \ufb01nancing fees
\n6
\n91.0
63.4
\nUnwinding of discount on decommissioning and other provisions
20
65.1
78.0
\n359.2
375.4
\nFinance costs capitalised during the year
\n7
\n(1.0)
(0.8)
\nTotal \ufb01nance expense
358.2
374.6
\n1
Other interest and \ufb01nance gains includes $16.0 million (2021: $1.9 million) related to an update to the amount recognised under the decommissioning liability agreement as detailed in note 16.
\n2
Gains on derivatives mainly relates to mark to market gains on interest rate and foreign currency derivatives.
\n3
Signi\ufb01cant unrealised foreign exchange gains consist mainly of unrealised gains arising from revaluation of open gas hedges denominated in pound sterling.
\n4
Other interest includes a $9.5 million charge (2021: $11.6 million) which represents interest under a \ufb01nancing arrangement (note 21).
\n5
Losses on derivatives relate to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2021: $14.6 million).
\n6
Bank and \ufb01nancing fees include an amount of $54.9 million (2021: $38.9 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s
\nlong-term borrowings (note 21).
\n7
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 4.4 per cent to the
\nexpenditures on the qualifying assets (2021: 3.7 per cent). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceCostExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17505": {
"value": "7. Finance income and \ufb01nance expenses Note
\n2022
\n$ million
\n2021
\n$ million
\nFinance income
\nBank interest
10.2
0.9
\nOther interest and \ufb01nance gains
\n1
\n20.0
3.2
\nIFRS 9 modi\ufb01cation impact
\u2013
13.9
\nLease \ufb01nance income
1.7
3.2
\nFinance income on deferred revenue
19
\u2013
1.2
\nRealised gains on interest rate swaps
6.5
\u2013
\nRealised gains on foreign exchange forward contracts
0.5
10.0
\nGains on derivatives
\n2
\n38.2
14.5
\nForeign exchange gains
\n3
\n202.0
1.9
\nTotal \ufb01nance income
279.1
48.8
\nFinance expenses
\nInterest payable on reserves-based lending
71.1
101.6
\nInterest payable on bond
27.3
5.7
\nInterest payable on loan notes
\u2013
5.6
\nOther interest and \ufb01nance expenses
\n4
\n11.7
16.6
\nLease interest
13
25.1
22.3
\nRealised losses on interest rate swaps
\u2013
2.4
\nLosses on derivatives
\n5
\n48.0
14.6
\nFinance expense on deferred revenue
19
19.9
\u2013
\nForeign exchange losses
\u2013
65.2
\nBank and \ufb01nancing fees
\n6
\n91.0
63.4
\nUnwinding of discount on decommissioning and other provisions
20
65.1
78.0
\n359.2
375.4
\nFinance costs capitalised during the year
\n7
\n(1.0)
(0.8)
\nTotal \ufb01nance expense
358.2
374.6
\n1
Other interest and \ufb01nance gains includes $16.0 million (2021: $1.9 million) related to an update to the amount recognised under the decommissioning liability agreement as detailed in note 16.
\n2
Gains on derivatives mainly relates to mark to market gains on interest rate and foreign currency derivatives.
\n3
Signi\ufb01cant unrealised foreign exchange gains consist mainly of unrealised gains arising from revaluation of open gas hedges denominated in pound sterling.
\n4
Other interest includes a $9.5 million charge (2021: $11.6 million) which represents interest under a \ufb01nancing arrangement (note 21).
\n5
Losses on derivatives relate to changes in the fair value of an embedded derivative within one of the Group\u2019s gas contracts (2021: $14.6 million).
\n6
Bank and \ufb01nancing fees include an amount of $54.9 million (2021: $38.9 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group\u2019s
\nlong-term borrowings (note 21).
\n7
The amount of \ufb01nance costs capitalised was determined by applying the weighted average rate of \ufb01nance costs applicable to the borrowings of the Group of 4.4 per cent to the
\nexpenditures on the qualifying assets (2021: 3.7 per cent). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17634": {
"value": "8. Income tax The major components of income tax expense for the years ended 31 December 2022 and 2021 are:
\n2022
\n$ million
\n2021
\n$ million
\nCurrent income tax expense
\nUK corporation tax
671.7
202.2
\nOverseas tax
53.5
(5.2)
\nAdjustments in respect of prior years
(19.4)
(4.9)
\nTotal current income tax expense
705.8
192.1
\nDeferred tax expense
\nUK corporation tax
302.1
7.7
\nUK Energy Pro\ufb01ts Levy
1,469.5
\u2013
\nOverseas tax
(7.5)
(10.3)
\nAdjustments in respect of prior years
(16.3)
23.9
\nTotal deferred tax expense
1,747.8
21.3
\nTotal tax expense reported in the income statement
2,453.6
213.4
\nThe tax credit in the statement of comprehensive income is as follows:
\nTax credit on cash \ufb02ow hedges
(1,005.6)
(1,433.2)
\nReconciliation of tax expense and the accounting pro\ufb01t before taxation multiplied by the statutory rate of corporation tax and supplementary
\ncharge applying to UK oil and gas production operations for the years ended 31 December 2022 and 2021 is as follows:
\n2022
\n$ million
\n2021
\n$ million
\nPro\ufb01t before income tax
2,461.8
314.5
\nAt the Group\u2019s statutory income tax rate of 55.0% (2021: 40.0%)
1,354.0
125.8
\nEffects of:
\n\u2013 Expenses/(income) not deductible/(taxable) for tax purposes
(11.7)
56.8
\n\u2013 Interest not deductible for supplementary charge and Energy Pro\ufb01ts Levy
53.1
13.1
\n\u2013 Adjustments in respect of prior years
(35.8)
19.0
\n\u2013 Movement in unrecognised deferred tax assets
(72.2)
27.4
\n\u2013 Deferred Energy Pro\ufb01ts Levy
1,469.2
\u2013
\n\u2013 Impact of different tax rates
(190.3)
4.0
\n\u2013 Expenses not deductible for Energy Pro\ufb01ts Levy
8.0
\u2013
\n\u2013 Energy Pro\ufb01ts Levy investment allowance
(81.4)
\u2013
\n\u2013 Investment allowance
(39.3)
(32.7)
\nTotal tax expense reported in the consolidated income statement at the e\ufb00ective tax rate of 100% (2021: 68%)
2,453.6
213.4
\nThe effective tax rate for the year was 100 per cent, compared to 68 per cent for 2021.
\nThe tax expense/(credit) reconciliation has been prepared based on the statutory rate of taxation applying to UK oil and gas production
\nbecause 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
\ncent (2021: 30 per cent), a supplementary charge of 10 per cent (2021: 10 per cent), and with effect from 26 May 2022, the Energy
\nPro\ufb01ts Levy (EPL) of 25 per cent to give an overall tax rate of 65 per cent (2021: 40 per cent). As the EPL was introduced part way
\nthrough the \ufb01nancial year a blended average rate of 55 per cent has been applied.
\nThe 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
\nproduction operations is expected to remain a primary in\ufb02uence on the effective tax rate. The EPL will increase to a rate of 35 per cent
\nfrom 25 per cent with effect from 1 January 2023 and consequently the headline rate will increase next year to 75 per cent. The Energy
\nPro\ufb01ts Levy at the 35 per cent rate will be in place until 31 March 2028.
\n141
Notes to the consolidated \ufb01nancial statements
continued
\n8. Income tax
continued
\nDeferred tax
\nThe principal components of deferred tax are set out in the following tables:
\n2022
\n$ million
\n2021
\n$ million
\nDeferred tax assets
1,406.5
1,938.4
\nDeferred tax liabilities
(397.2)
(187.1)
\nTotal deferred tax
1,009.3
1,751.3
\nThe origination of and reversal of temporary differences are, as shown in the next table, related primarily to movements in the carrying amounts
\nand tax base values of expenditure and the timing of when these items are charged and/or credited against accounting and taxable pro\ufb01t.
\nNote
\nAccelerated
\ncapital
\nallowances
\n$ million
\nDecommissioning
\n$ million
\nLosses
\n$ million
\nFair value of
\nderivatives
\n$ million
\nOther
\n$ million
\nOverseas
\n$ million
\nTotal
\n$ million
\nAs at 1 January 2021
(2,650.5)
1,640.7
\u2013
(57.1)
51.5
(16.0)
(1,031.4)
\nDeferred tax expense
385.9
(178.2)
(216.1)
3.6
(26.8)
10.3
(21.3)
\nComprehensive income
\u2013
\u2013
\u2013
1,433.2
\u2013
\u2013
1,433.2
\nForeign exchange
13.5
(13.6)
\u2013
4.0
(1.1)
1.9
4.7
\nAdditions from business
\ncombinations and joint
\narrangements
14
(569.0)
564.0
1,530.6
8.4
15.2
(183.1)
1,366.1
\nAs at 31 December 2021
(2,820.1)
2,012.9
1,314.5
1,392.1
38.8
(186.9)
1,751.3
\nDeferred tax expense
(657.7)
(361.7)
(745.2)
49.0
(39.7)
7.5
(1,747.8)
\nComprehensive income
\u2013
\u2013
\u2013
1,005.6
\u2013
\u2013
1,005.6
\nForeign exchange
82.2
(85.9)
(0.2)
5.0
(1.8)
0.9
0.2
\nAs at 31 December 2022
(3,395.6)
1,565.3
569.1
2,451.7
(2.7)
(178.5)
1,009.3
\nThe Group\u2019s deferred tax assets as at 31 December 2022 are recognised to the extent that taxable pro\ufb01ts are expected to arise against
\nwhich the tax assets can be utilised. The Group assessed the recoverability of its UK ring fenced losses and allowances using corporate
\nassumptions which are consistent with the Group\u2019s impairment assessment. Based on those assumptions, the Group expects to fully
\nutilise its recognised UK tax losses and allowances. The recovery of the Group\u2019s UK decommissioning deferred tax asset is additionally
\nsupported by the ability to carry back decommissioning tax losses and set these against ring fence taxable pro\ufb01ts of prior periods.
\nThe EPL will increase to a rate of 35 per cent from 25 per cent with effect from 1 January 2023. The increase in rate was substantively
\nenacted on 30\u00a0November 2022. The EPL will be in place until 31 March 2028. Any temporary differences subject to the EPL expected to
\nreverse in this period have consequently been remeasured to the higher rate. This has resulted in a one-off deferred tax charge to the
\nincome statement of $1,469.2 million and a one-off deferred tax credit arising on unrealised derivative balances in other comprehensive
\nincome of $1,005.6 million. The net impact on the deferred tax asset at the end of the period as a result of the EPL is a decrease in the
\ndeferred tax asset of $463.7 million.
\nIn line with other sensitivity analysis undertaken, we have assessed the impact on the recoverability of deferred tax assets based on an
\naverage -10 per cent to the Harbour Scenario average crude price curves. The sensitivity analysis indicates that there would no material
\nimpact to the recoverability of deferred tax assets.
\nThe Group has unrecognised UK tax losses and allowances as at 31 December 2022 of approximately $201.7 million (2021: $343.1 million)
\nin respect of ring fence losses, $111.1 million (2021: $104.4 million) in respect of ring fence investment allowance and $807.2 million (2021:
\n$741.5 million) in respect of non-ring fence losses.
\nThe Group also has unrecognised tax losses of approximately $156.9 million (2021: $212.8 million) in respect of its international operations.
\nThese losses include amounts of $30.3 million which will expire, primarily within \ufb01ve years and $13.8 million expiring within 10 years.
\nThe overseas deferred tax relates mainly to temporary differences associated with \ufb01xed asset balances.
\n142
No deferred tax liabilities have been provided on unremitted earnings of overseas subsidiaries, because due to the application of
\nwithholding reliefs under international double taxation treaties and dividend exemptions under UK and Netherlands legislation no
\nadditional taxation is expected to arise on future distribution.
\nLegislation was introduced in UK Finance Act 2021 to increase the main rate of UK corporation tax for non-ring fence pro\ufb01ts from 19 per
\ncent to 25 per cent from 1 April 2023. This change does not have a material impact on the Group as the UK pro\ufb01ts are primarily subject
\nto the UK ring fence tax rate. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17747": {
"value": "Deferred tax The principal components of deferred tax are set out in the following tables:
\n2022
\n$ million
\n2021
\n$ million
\nDeferred tax assets
1,406.5
1,938.4
\nDeferred tax liabilities
(397.2)
(187.1)
\nTotal deferred tax
1,009.3
1,751.3
\nThe origination of and reversal of temporary differences are, as shown in the next table, related primarily to movements in the carrying amounts
\nand tax base values of expenditure and the timing of when these items are charged and/or credited against accounting and taxable pro\ufb01t.
\nNote
\nAccelerated
\ncapital
\nallowances
\n$ million
\nDecommissioning
\n$ million
\nLosses
\n$ million
\nFair value of
\nderivatives
\n$ million
\nOther
\n$ million
\nOverseas
\n$ million
\nTotal
\n$ million
\nAs at 1 January 2021
(2,650.5)
1,640.7
\u2013
(57.1)
51.5
(16.0)
(1,031.4)
\nDeferred tax expense
385.9
(178.2)
(216.1)
3.6
(26.8)
10.3
(21.3)
\nComprehensive income
\u2013
\u2013
\u2013
1,433.2
\u2013
\u2013
1,433.2
\nForeign exchange
13.5
(13.6)
\u2013
4.0
(1.1)
1.9
4.7
\nAdditions from business
\ncombinations and joint
\narrangements
14
(569.0)
564.0
1,530.6
8.4
15.2
(183.1)
1,366.1
\nAs at 31 December 2021
(2,820.1)
2,012.9
1,314.5
1,392.1
38.8
(186.9)
1,751.3
\nDeferred tax expense
(657.7)
(361.7)
(745.2)
49.0
(39.7)
7.5
(1,747.8)
\nComprehensive income
\u2013
\u2013
\u2013
1,005.6
\u2013
\u2013
1,005.6
\nForeign exchange
82.2
(85.9)
(0.2)
5.0
(1.8)
0.9
0.2
\nAs at 31 December 2022
(3,395.6)
1,565.3
569.1
2,451.7
(2.7)
(178.5)
1,009.3
\nThe Group\u2019s deferred tax assets as at 31 December 2022 are recognised to the extent that taxable pro\ufb01ts are expected to arise against
\nwhich the tax assets can be utilised. The Group assessed the recoverability of its UK ring fenced losses and allowances using corporate
\nassumptions which are consistent with the Group\u2019s impairment assessment. Based on those assumptions, the Group expects to fully
\nutilise its recognised UK tax losses and allowances. The recovery of the Group\u2019s UK decommissioning deferred tax asset is additionally
\nsupported by the ability to carry back decommissioning tax losses and set these against ring fence taxable pro\ufb01ts of prior periods.
\nThe EPL will increase to a rate of 35 per cent from 25 per cent with effect from 1 January 2023. The increase in rate was substantively
\nenacted on 30\u00a0November 2022. The EPL will be in place until 31 March 2028. Any temporary differences subject to the EPL expected to
\nreverse in this period have consequently been remeasured to the higher rate. This has resulted in a one-off deferred tax charge to the
\nincome statement of $1,469.2 million and a one-off deferred tax credit arising on unrealised derivative balances in other comprehensive
\nincome of $1,005.6 million. The net impact on the deferred tax asset at the end of the period as a result of the EPL is a decrease in the
\ndeferred tax asset of $463.7 million.
\nIn line with other sensitivity analysis undertaken, we have assessed the impact on the recoverability of deferred tax assets based on an
\naverage -10 per cent to the Harbour Scenario average crude price curves. The sensitivity analysis indicates that there would no material
\nimpact to the recoverability of deferred tax assets.
\nThe Group has unrecognised UK tax losses and allowances as at 31 December 2022 of approximately $201.7 million (2021: $343.1 million)
\nin respect of ring fence losses, $111.1 million (2021: $104.4 million) in respect of ring fence investment allowance and $807.2 million (2021:
\n$741.5 million) in respect of non-ring fence losses.
\nThe Group also has unrecognised tax losses of approximately $156.9 million (2021: $212.8 million) in respect of its international operations.
\nThese losses include amounts of $30.3 million which will expire, primarily within \ufb01ve years and $13.8 million expiring within 10 years.
\nThe overseas deferred tax relates mainly to temporary differences associated with \ufb01xed asset balances.
\n142
No deferred tax liabilities have been provided on unremitted earnings of overseas subsidiaries, because due to the application of
\nwithholding reliefs under international double taxation treaties and dividend exemptions under UK and Netherlands legislation no
\nadditional taxation is expected to arise on future distribution.
\nLegislation was introduced in UK Finance Act 2021 to increase the main rate of UK corporation tax for non-ring fence pro\ufb01ts from 19 per
\ncent to 25 per cent from 1 April 2023. This change does not have a material impact on the Group as the UK pro\ufb01ts are primarily subject
\nto the UK ring fence tax rate. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17909": {
"value": "9. Earnings per share (EPS) Basic EPS is calculated by dividing the pro\ufb01t after tax attributable to ordinary shareholders of the Group by the weighted average number
\nof ordinary shares in issue during the year.
\nDiluted EPS is calculated by dividing the pro\ufb01t after tax attributable to ordinary shareholders by the weighted average number of ordinary
\nshares in issue during the year plus the weighted average number of ordinary shares that would be issued on conversion of all the
\ndilutive potential ordinary shares into ordinary shares.
\nThe following table re\ufb02ects the income and share data used in the basic and diluted EPS calculations:
\n2022
2021
\nEarnings for the year ($ millions)
\nEarnings for the purpose of basic earnings per share
8.2
101.1
\nEffect of dilutive potential ordinary shares
\u2013
\u2013
\nEarnings for the purpose of diluted earnings per share
8.2
101.1
\nNumber of ordinary shares (millions)
\nWeighted average number of ordinary shares for the purpose of basic earnings per share
\n1
\n899.8
871.2
\nDilutive potential ordinary shares
\n2
\n12.3
1.3
\nWeighted average number of ordinary shares for the purpose of diluted earnings per share
912.1
872.5
\nEarnings per share ($ cents)
\nBasic
0.9
11.6
\nDiluted
0.9
11.6
\n1
During the current period 78.4 million ordinary shares were repurchased as part of the share buyback programme.
\n2
Excludes certain share options outstanding at 31 December 2022 as their option price was greater than market price. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f17954": {
"value": "10. Goodwill Goodwill represents the difference between the aggregate of the fair value of purchase consideration transferred at the acquisition date
\nand the fair value of the identi\ufb01able assets.
\nNote
\n2022
\n$ million
\n2021
\n$ million
\nCost and net book value
\nAt 1 January
1,327.1
990.0
\nAdditions
14
\u2013
339.3
\nCurrency translation adjustment
\u2013
(2.2)
\nAt 31 December
1,327.1
1,327.1
\nThe goodwill balance consists of balances arising from the completion of the all-share merger between Premier Oil plc and Chrysaor Holdings
\nLimited in March 2021, on Chrysaor Holdings Limited\u2019s acquisition of the ConocoPhillips UK business, and of the UK North Sea assets from
\nShell, which completed on 30 September 2019 and 1 November 2017, respectively.
\nGoodwill acquired through business combinations has been allocated to two groups of cash-generating units (CGUs), being the North Sea,
\nof $1,278.1 million (2021: $1,278.1 million), and International, of $49.0 million (2021: $49.0 million), and these are therefore the lowest
\nlevels at which goodwill is reviewed.
\n143
Notes to the consolidated \ufb01nancial statements
continued
\n10. Goodwill
continued
\nImpairment testing of goodwill
\nIn accordance with IAS 36 Impairment of Assets, goodwill is reviewed for impairment at the year-end or more frequently if there are
\nindications that goodwill might be impaired. In assessing whether goodwill has been impaired, the carrying amount of the CGU for
\ngoodwill is compared with its recoverable amount. At the year-end, the Group tested for impairment in accordance with accounting policy
\nand no impairment was identi\ufb01ed (2021: $nil).
\nDetermining recoverable amount
\nThe recoverable amounts of the CGU and \ufb01elds have been determined on a fair value less costs to sell basis. The key assumptions
\nused in determining the fair value are often subjective, such as the future long-term oil and gas price assumption, or the operational
\nperformance of the assets. Discounted cash \ufb02ow models comprising asset-by-asset life of \ufb01eld projections using Level 3 inputs (based
\non the IFRS 13 fair value hierarchy) have been used to determine the recoverable amounts.
\nThe 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
\n2026, and discounted at the Group\u2019s post-tax discount rate of between 8.5 and 11.0 per cent (pre-tax 12.1 per cent \u2013 14.1 per cent)
\n(2021: 8.0 \u2013 10.5 per cent post-tax; pre-tax 11.4 per cent \u2013 12.8 per cent). Risks speci\ufb01c to assets within the CGU are re\ufb02ected within
\nthe cash \ufb02ow forecasts.
\nKey assumptions used in calculations
\nAssumptions involved in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas
\nprices, discount rates and the level and timing of expenditures, all of which are inherently uncertain.
\nCommodity and carbon prices
\nManagement\u2019s commodity price curve assumptions are benchmarked against a range of external forward price curves on a regular
\nbasis. The \ufb01rst three years re\ufb02ect the market forward prices curves transitioning to a long-term price thereafter. The long-term commodity
\nprices used were $65/bbl for crude and 65p/therm for gas, which are in\ufb02ated at 2.5 per cent per annum from 1 January 2026. The
\nlong-term carbon price used was \u00a380/tonne, being $100/tonne at $:\u00a31.25 foreign exchange rate, in\ufb02ated at 2.5 per cent per annum
\nfrom 1 January 2026.
\nProduction volumes
\nBased 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
\ngas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates its reserves using standard recognised
\nevaluation techniques and they are assessed at least annually by management and by an independent consultant. Proven and probable
\nreserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices.
\nCosts
\nOperating expenditure, capital expenditure and decommissioning costs, which have been in\ufb02ated at 2.5 per cent per annum from
\n1 January 2026, are derived from the Group\u2019s business plan.
\nDiscount rates
\nRepresent management\u2019s estimate of the Group\u2019s country-based weighted average cost of capital (WACC), considering both debt and
\nequity. 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
\nits interest-bearing borrowings. Segment-speci\ufb01c risk is incorporated by applying a beta factor based on publicly available market data.
\nThe discount rate is based on an assessment of a relevant peer group\u2019s post-tax WACC.
\nForeign exchange rates
\nBased on management\u2019s long-term rate assumptions, with reference to a range of underlying economic indicators.
\nSensitivity to changes in assumptions used in calculations
\nThe Group has run sensitivities on its long-term commodity price assumptions, which have been based on long-range forecasts from external
\n\ufb01nancial analysts, using alternate long-term price assumptions, and discount rates. These are considered to be reasonably possible changes
\nfor the purposes of sensitivity analysis. No impairment arose on the Group\u2019s goodwill under any of the sensitivity scenarios. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGoodwillExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18053": {
"value": "11. Other intangible assets Note
\nOil and
\ngas assets
\n$ million
\nNon-oil and
\ngas assets
\n3
\n$ million
\nCapacity
\nrights
\n4
\n$ million
\nTotal
\n$ million
\nCost
\nAt 1 January 2021
391.3
94.9
10.3
496.5
\nAdditions during the year
210.0
30.2
\u2013
240.2
\nAdditions from business combinations and joint arrangements
14
596.7
0.4
\u2013
597.1
\nTransfers to property, plant and equipment
(139.5)
\u2013
\u2013
(139.5)
\nIncrease in decommissioning asset
20
10.4
\u2013
\u2013
10.4
\nPrior capitalised costs expensed
\u2013
(4.7)
\u2013
(4.7)
\nUnsuccessful exploration written-off
(255.0)
\u2013
\u2013
(255.0)
\nCurrency translation adjustment
(0.5)
(1.4)
(0.1)
(2.0)
\nAt 31 December 2021
813.4
119.4
10.2
943.0
\nAdditions during the year
111.0
30.7
\u2013
141.7
\nTransfers to property, plant and equipment
(29.0)
\u2013
\u2013
(29.0)
\nDecrease in decommissioning asset
\n1
\n20
(11.8)
\u2013
\u2013
(11.8)
\nUnsuccessful exploration written-off
\n2
\n(64.4)
\u2013
\u2013
(64.4)
\nCurrency translation adjustment
(2.5)
(12.5)
(1.4)
(16.4)
\nAt 31 December 2022
816.7
137.6
8.8
963.1
\nAmortisation
\nAt 1 January 2021
\u2013
34.8
7.6
42.4
\nCharge for the year
\u2013
26.1
1.6
27.7
\nCurrency translation adjustment
\u2013
(0.7)
(0.1)
(0.8)
\nAt 31 December 2021
\u2013
60.2
9.1
69.3
\nCharge for the year
\u2013
21.1
1.0
22.1
\nCurrency translation adjustment
\u2013
(7.0)
(1.3)
(8.3)
\nAt 31 December 2022
\u2013
74.3
8.8
83.1
\nNet book value
\nAt 31 December 2021
813.4
59.2
1.1
873.7
\nAt 31 December 2022
816.7
63.3
\u2013
880.0
\n1
A decrease to decommissioning assets of $11.8 million (2021: increase of $10.4 million) was made during the year as a result of an update to decommissioning estimates (note 20).
\n2
The exploration write-off of $64.4 million (2021: $255.0 million), which relates to costs associated with licence relinquishments and uncommercial well evaluations, is net of a
\n$5.7 million credit related to a decrease in decommissioning provisions in the North Sea (note 20) and a $7.0 million credit related to a change to the decommissioning estimate
\nin the Falkland Islands business unit (2021: $6.3 million relating to the effect of changes in decommissioning provisions on oil and gas intangible assets previously written-off).
\n3
Non-oil and gas assets relate primarily to Group IT software.
\n4
The capacity rights represent National Transmission System (NTS) entry capacity at Bacton and Teesside acquired as part of the business combination completed in 2017. These rights,
\nwhich have been amortised on a contracted volume basis, are now fully amortised. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18054": {
"value": "11. Other intangible assets Note
\nOil and
\ngas assets
\n$ million
\nNon-oil and
\ngas assets
\n3
\n$ million
\nCapacity
\nrights
\n4
\n$ million
\nTotal
\n$ million
\nCost
\nAt 1 January 2021
391.3
94.9
10.3
496.5
\nAdditions during the year
210.0
30.2
\u2013
240.2
\nAdditions from business combinations and joint arrangements
14
596.7
0.4
\u2013
597.1
\nTransfers to property, plant and equipment
(139.5)
\u2013
\u2013
(139.5)
\nIncrease in decommissioning asset
20
10.4
\u2013
\u2013
10.4
\nPrior capitalised costs expensed
\u2013
(4.7)
\u2013
(4.7)
\nUnsuccessful exploration written-off
(255.0)
\u2013
\u2013
(255.0)
\nCurrency translation adjustment
(0.5)
(1.4)
(0.1)
(2.0)
\nAt 31 December 2021
813.4
119.4
10.2
943.0
\nAdditions during the year
111.0
30.7
\u2013
141.7
\nTransfers to property, plant and equipment
(29.0)
\u2013
\u2013
(29.0)
\nDecrease in decommissioning asset
\n1
\n20
(11.8)
\u2013
\u2013
(11.8)
\nUnsuccessful exploration written-off
\n2
\n(64.4)
\u2013
\u2013
(64.4)
\nCurrency translation adjustment
(2.5)
(12.5)
(1.4)
(16.4)
\nAt 31 December 2022
816.7
137.6
8.8
963.1
\nAmortisation
\nAt 1 January 2021
\u2013
34.8
7.6
42.4
\nCharge for the year
\u2013
26.1
1.6
27.7
\nCurrency translation adjustment
\u2013
(0.7)
(0.1)
(0.8)
\nAt 31 December 2021
\u2013
60.2
9.1
69.3
\nCharge for the year
\u2013
21.1
1.0
22.1
\nCurrency translation adjustment
\u2013
(7.0)
(1.3)
(8.3)
\nAt 31 December 2022
\u2013
74.3
8.8
83.1
\nNet book value
\nAt 31 December 2021
813.4
59.2
1.1
873.7
\nAt 31 December 2022
816.7
63.3
\u2013
880.0
\n1
A decrease to decommissioning assets of $11.8 million (2021: increase of $10.4 million) was made during the year as a result of an update to decommissioning estimates (note 20).
\n2
The exploration write-off of $64.4 million (2021: $255.0 million), which relates to costs associated with licence relinquishments and uncommercial well evaluations, is net of a
\n$5.7 million credit related to a decrease in decommissioning provisions in the North Sea (note 20) and a $7.0 million credit related to a change to the decommissioning estimate
\nin the Falkland Islands business unit (2021: $6.3 million relating to the effect of changes in decommissioning provisions on oil and gas intangible assets previously written-off).
\n3
Non-oil and gas assets relate primarily to Group IT software.
\n4
The capacity rights represent National Transmission System (NTS) entry capacity at Bacton and Teesside acquired as part of the business combination completed in 2017. These rights,
\nwhich have been amortised on a contracted volume basis, are now fully amortised.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18057": {
"value": "Note
\nOil and
\ngas assets
\n$ million
\nNon-oil and
\ngas assets
\n3
\n$ million
\nCapacity
\nrights
\n4
\n$ million
\nTotal
\n$ million
\nCost
\nAt 1 January 2021
391.3
94.9
10.3
496.5
\nAdditions during the year
210.0
30.2
\u2013
240.2
\nAdditions from business combinations and joint arrangements
14
596.7
0.4
\u2013
597.1
\nTransfers to property, plant and equipment
(139.5)
\u2013
\u2013
(139.5)
\nIncrease in decommissioning asset
20
10.4
\u2013
\u2013
10.4
\nPrior capitalised costs expensed
\u2013
(4.7)
\u2013
(4.7)
\nUnsuccessful exploration written-off
(255.0)
\u2013
\u2013
(255.0)
\nCurrency translation adjustment
(0.5)
(1.4)
(0.1)
(2.0)
\nAt 31 December 2021
813.4
119.4
10.2
943.0
\nAdditions during the year
111.0
30.7
\u2013
141.7
\nTransfers to property, plant and equipment
(29.0)
\u2013
\u2013
(29.0)
\nDecrease in decommissioning asset
\n1
\n20
(11.8)
\u2013
\u2013
(11.8)
\nUnsuccessful exploration written-off
\n2
\n(64.4)
\u2013
\u2013
(64.4)
\nCurrency translation adjustment
(2.5)
(12.5)
(1.4)
(16.4)
\nAt 31 December 2022
816.7
137.6
8.8
963.1
\nAmortisation
\nAt 1 January 2021
\u2013
34.8
7.6
42.4
\nCharge for the year
\u2013
26.1
1.6
27.7
\nCurrency translation adjustment
\u2013
(0.7)
(0.1)
(0.8)
\nAt 31 December 2021
\u2013
60.2
9.1
69.3
\nCharge for the year
\u2013
21.1
1.0
22.1
\nCurrency translation adjustment
\u2013
(7.0)
(1.3)
(8.3)
\nAt 31 December 2022
\u2013
74.3
8.8
83.1
\nNet book value
\nAt 31 December 2021
813.4
59.2
1.1
873.7
\nAt 31 December 2022
816.7
63.3
\u2013
880.0
Note
\nOil and gas
\nassets
\n$ million
\nFixtures,
\n\ufb01ttings & of\ufb01ce
\nequipment
\n$ million
\nTotal
\n$ million
\nCost
\nAt 1 January 2021
9,996.0
22.8
10,018.8
\nAdditions during the year
464.5
4.4
468.9
\nAdditions from business combinations and joint arrangements
\n1
\n14
1,814.3
4.2
1,818.5
\nTransfers from intangible assets
139.5
\u2013
139.5
\nDisposals
\u2013
(0.3)
(0.3)
\nDecrease in decommissioning asset
20
(357.8)
\u2013
(357.8)
\nCurrency translation adjustment
(34.5)
(0.3)
(34.8)
\nAt 31 December 2021
12,022.0
30.8
12,052.8
\nAdditions
\n2
\n532.4
10.7
543.1
\nTransfers from intangible assets
29.0
\u2013
29.0
\nDecrease in decommissioning asset
\n3
\n20
(778.8)
\u2013
(778.8)
\nCurrency translation adjustment
(369.0)
(3.2)
(372.2)
\nAt 31 December 2022
11,435.6
38.3
11,473.9
\nAccumulated depreciation
\nAt 1 January 2021
3,480.2
16.2
3,496.4
\nCharge for the year
1,204.1
5.5
1,209.6
\nImpairment
117.2
\u2013
117.2
\nDisposals
\u2013
(0.1)
(0.1)
\nCurrency translation adjustment
(16.6)
(0.4)
(17.0)
\nAt 31 December 2021
4,784.9
21.2
4,806.1
\nCharge for the year
1,318.4
5.4
1,323.8
\nNet impairment reversal
(169.6)
\u2013
(169.6)
\nCurrency translation adjustment
(174.4)
(2.2)
(176.6)
\nAt 31 December 2022
5,759.3
24.4
5,783.7
\nNet book value
\nAt 31 December 2021
7,237.1
9.6
7,246.7
\nAt 31 December 2022
5,676.3
13.9
5,690.2
Right-of-use assets
Note
\nLand and
\nbuildings
\n$ million
\nDrilling rigs
\n$ million
\nFPSO
\n$ million
\nOffshore
\nfacilities
\n$ million
\nEquipment
\n$ million
\nTotal
\n$ million
\nCost
\nAt 1 January 2021
66.0
129.9
\u2013
\u2013
3.2
199.1
\nAdditions during the year
\u2013
29.0
\u2013
\u2013
15.6
44.6
\nAdditions from business combinations
\nand joint arrangements
14
41.1
\u2013
525.6
\u2013
1.2
567.9
\nCost revisions/remeasurements
\u2013
(3.7)
(15.7)
\u2013
(1.3)
(20.7)
\nDisposals
(5.4)
\u2013
\u2013
\u2013
\u2013
(5.4)
\nCurrency translation adjustment
(1.4)
(2.5)
\u2013
\u2013
(0.5)
(4.4)
\nAt 31 December 2021
100.3
152.7
509.9
\u2013
18.2
781.1
\nAdditions during the year
\n1
\n\u2013
\u2013
\u2013
338.0
\u2013
338.0
\nCost revisions/remeasurements
3.3
33.6
52.7
(3.8)
3.4
89.2
\nDisposals
(6.6)
\u2013
\u2013
\u2013
\u2013
(6.6)
\nCurrency translation adjustment
(9.6)
(17.4)
\u2013
\u2013
(1.6)
(28.6)
\nAt 31 December 2022
87.4
168.9
562.6
334.2
20.0
1,173.1
\nAccumulated depreciation
\nAt 1 January 2021
11.0
54.3
\u2013
\u2013
1.6
66.9
\nCharge for the year
11.6
44.8
102.1
\u2013
5.9
164.4
\nCurrency translation adjustment
(0.3)
(1.3)
\u2013
\u2013
(0.1)
(1.7)
\nAt 31 December 2021
22.3
97.8
102.1
\u2013
7.4
229.6
\nCharge for the year
11.8
42.5
107.4
61.1
7.0
229.8
\nDisposals
(6.4)
\u2013
\u2013
\u2013
\u2013
(6.4)
\nCurrency translation adjustment
(1.8)
(11.8)
\u2013
\u2013
(1.0)
(14.6)
\nAt 31 December 2022
25.9
128.5
209.5
61.1
13.4
438.4
\nNet book value
\nAt 31 December 2021
78.0
54.9
407.8
\u2013
10.8
551.5
\nAt 31 December 2022
61.5
40.4
353.1
273.1
6.6
734.7
Depreciation charge of right-of-use assets
Note
\n2022
\n$ million
\n2021
\n$ million
\nLand and buildings \u2013 non-oil and gas assets
10.8
10.5
\nLand and buildings \u2013 oil and gas assets
1.0
1.1
\nDrilling rigs
42.5
44.8
\nOffshore facilities
61.1
\u2013
\nFPSO
107.4
102.1
\nEquipment \u2013 non-oil and gas assets
0.4
\u2013
\nEquipment \u2013 oil and gas assets
6.6
5.9
\n229.8
164.4
\nCapitalisation of IFRS 16 lease depreciation
\n1
\nDrilling rigs
(25.9)
(27.2)
\nEquipment
(4.0)
(3.5)
\nTotal depreciation charge
199.9
133.7
\nLease interest
7
25.1
22.3
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18226": {
"value": "12. Property, plant and equipment Note
\nOil and gas
\nassets
\n$ million
\nFixtures,
\n\ufb01ttings & of\ufb01ce
\nequipment
\n$ million
\nTotal
\n$ million
\nCost
\nAt 1 January 2021
9,996.0
22.8
10,018.8
\nAdditions during the year
464.5
4.4
468.9
\nAdditions from business combinations and joint arrangements
\n1
\n14
1,814.3
4.2
1,818.5
\nTransfers from intangible assets
139.5
\u2013
139.5
\nDisposals
\u2013
(0.3)
(0.3)
\nDecrease in decommissioning asset
20
(357.8)
\u2013
(357.8)
\nCurrency translation adjustment
(34.5)
(0.3)
(34.8)
\nAt 31 December 2021
12,022.0
30.8
12,052.8
\nAdditions
\n2
\n532.4
10.7
543.1
\nTransfers from intangible assets
29.0
\u2013
29.0
\nDecrease in decommissioning asset
\n3
\n20
(778.8)
\u2013
(778.8)
\nCurrency translation adjustment
(369.0)
(3.2)
(372.2)
\nAt 31 December 2022
11,435.6
38.3
11,473.9
\nAccumulated depreciation
\nAt 1 January 2021
3,480.2
16.2
3,496.4
\nCharge for the year
1,204.1
5.5
1,209.6
\nImpairment
117.2
\u2013
117.2
\nDisposals
\u2013
(0.1)
(0.1)
\nCurrency translation adjustment
(16.6)
(0.4)
(17.0)
\nAt 31 December 2021
4,784.9
21.2
4,806.1
\nCharge for the year
1,318.4
5.4
1,323.8
\nNet impairment reversal
(169.6)
\u2013
(169.6)
\nCurrency translation adjustment
(174.4)
(2.2)
(176.6)
\nAt 31 December 2022
5,759.3
24.4
5,783.7
\nNet book value
\nAt 31 December 2021
7,237.1
9.6
7,246.7
\nAt 31 December 2022
5,676.3
13.9
5,690.2
\n1
Further information on additions from business combinations and joint arrangements can be found in note 14.
\n2
Included within property, plant and equipment additions of $543.1 million (2021: $468.9 million) are associated cash \ufb02ows of $476.5 million (2021: $437.4 million) and non-cash \ufb02ow
\nmovements of $66.6 million (2021: ($31.5 million)), represented by a $44.2 million increase in capital accruals (2021: $9.0 million increase) and $22.4 million of capitalised lease
\ndepreciation (2021: $22.5 million).
\n3
A decrease in the decommissioning assets of $778.8 million (2021: $357.8 million) was made during the year as a result of both new obligations and an update to the decommissioning
\nestimates (note 20).
\nDuring the year, the Group recognised a net pre-tax impairment credit of $169.6 million (post-tax $49.8 million) (2021: impairment
\ncharge of $117.2 million; post-tax $70.3 million) comprising a pre-tax impairment reversal of $250.5 million (2021: $nil) and a pre-tax
\nimpairment credit of $82.3 million (2021: $8.5 million charge) in respect of revisions to decommissioning estimates on the Group\u2019s
\nnon-producing assets with no remaining net book value (see note 20). This is net of a pre-tax impairment charge representing a
\nwrite-down of property, plant and equipment assets of $163.2 million (2021: $108.7 million).
\nThe impairment reversal was driven by a higher forward curve and long-term price assumption for gas resulting in reversals of
\n$250.5 million covering two cash-generating groups in the North Sea business unit.
\nThe impairment to property, plant and equipment of $163.2 million arises primarily from a single CGU in the UK North Sea, driven
\nprimarily due to the contracted price realised for crude sales being negatively impacted by the pricing differential between Urals and
\nBrent crude, which is currently subject to dispute with the buyer, and also a revised operating cost pro\ufb01le for the \ufb01eld. Impairments
\non property, plant and equipment are reversible in the future.
\n146
Key assumptions used in calculations
\nAssumptions used in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas
\nprices, discount rates and the level and timing of expenditures, all of which are inherently uncertain.
\nCommodity and carbon prices
\nThe Group uses the fair value less cost of disposal method (FVLCD) to calculate the recoverable amount of the cash-generating
\nunits (CGU) consistent with a level 3 fair value measurement (see note 22). In determining the recoverable value, appropriate discounted-
\ncash-\ufb02ow valuation models were used, incorporating market-based assumptions. Management\u2019s commodity price curve assumptions
\nare benchmarked against a range of external forward price curves on a regular basis. Individual \ufb01eld price differentials are then applied.
\nThe \ufb01rst three years re\ufb02ect the market forward price curves transitioning to a long-term price from 2026, thereafter in\ufb02ated at 2.5 per
\ncent per annum. The long-term commodity prices used were $65 per barrel for crude and 65p per therm for gas.
\nProduction volumes
\nProduction volumes are based on life of \ufb01eld production pro\ufb01les for each asset within the CGU. Proven and probable reserves are
\nestimates of the amount of oil and gas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates its
\nreserves using standard recognised evaluation techniques, assessed at least annually by management. Proven and probable reserves
\nare determined using estimates of oil and gas in place, recovery factors and future commodity prices.
\nCosts
\nOperating expenditure, capital expenditure and decommissioning costs are derived from the Group\u2019s business plan. The discount rate
\nre\ufb02ects management\u2019s estimate of the Group\u2019s Weighted Average Cost of Capital (WACC), see note 10 for further details. Foreign
\nexchange rates are based on management\u2019s long-term rate assumptions, with reference to a range of underlying economic indicators.
\nSensitivity to changes in assumptions used in calculations
\nReductions or increases in the long-term oil and gas prices of 10 per cent are considered to be reasonably possible changes for the
\npurpose of sensitivity analysis. Decreases to the long-term oil and gas prices from 1 January 2026 speci\ufb01ed above would result in a
\nfurther post-tax impairment of $44.9 million. A 10 per cent increase in the long-term oil and gas price deck would reduce the post-tax
\nimpairment charge by $44.9 million. Considering the discount rates, the Group believes a one per cent increase in the post-tax discount
\nrate is considered to be a reasonable possibility for the purpose of sensitivity analysis. A one per cent increase in the post-tax discount
\nrate would lead to a further post-tax impairment of $17.6 million, and a one per cent decrease in the post-tax discount rate would reduce
\nthe post-tax impairment charge by $19.1 million.
\nSensitivity analyses indicate that reductions or increases in the long-term oil and gas prices of 10 per cent or a one per cent increase
\nor decrease in the post-tax discount rate would not have resulted in a different impairment reversal.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18423": {
"value": "13. Leases This note provides information for leases where the Group is a lessee.
\nBalance sheet
\nRight-of-use assets
Note
\nLand and
\nbuildings
\n$ million
\nDrilling rigs
\n$ million
\nFPSO
\n$ million
\nOffshore
\nfacilities
\n$ million
\nEquipment
\n$ million
\nTotal
\n$ million
\nCost
\nAt 1 January 2021
66.0
129.9
\u2013
\u2013
3.2
199.1
\nAdditions during the year
\u2013
29.0
\u2013
\u2013
15.6
44.6
\nAdditions from business combinations
\nand joint arrangements
14
41.1
\u2013
525.6
\u2013
1.2
567.9
\nCost revisions/remeasurements
\u2013
(3.7)
(15.7)
\u2013
(1.3)
(20.7)
\nDisposals
(5.4)
\u2013
\u2013
\u2013
\u2013
(5.4)
\nCurrency translation adjustment
(1.4)
(2.5)
\u2013
\u2013
(0.5)
(4.4)
\nAt 31 December 2021
100.3
152.7
509.9
\u2013
18.2
781.1
\nAdditions during the year
\n1
\n\u2013
\u2013
\u2013
338.0
\u2013
338.0
\nCost revisions/remeasurements
3.3
33.6
52.7
(3.8)
3.4
89.2
\nDisposals
(6.6)
\u2013
\u2013
\u2013
\u2013
(6.6)
\nCurrency translation adjustment
(9.6)
(17.4)
\u2013
\u2013
(1.6)
(28.6)
\nAt 31 December 2022
87.4
168.9
562.6
334.2
20.0
1,173.1
\nAccumulated depreciation
\nAt 1 January 2021
11.0
54.3
\u2013
\u2013
1.6
66.9
\nCharge for the year
11.6
44.8
102.1
\u2013
5.9
164.4
\nCurrency translation adjustment
(0.3)
(1.3)
\u2013
\u2013
(0.1)
(1.7)
\nAt 31 December 2021
22.3
97.8
102.1
\u2013
7.4
229.6
\nCharge for the year
11.8
42.5
107.4
61.1
7.0
229.8
\nDisposals
(6.4)
\u2013
\u2013
\u2013
\u2013
(6.4)
\nCurrency translation adjustment
(1.8)
(11.8)
\u2013
\u2013
(1.0)
(14.6)
\nAt 31 December 2022
25.9
128.5
209.5
61.1
13.4
438.4
\nNet book value
\nAt 31 December 2021
78.0
54.9
407.8
\u2013
10.8
551.5
\nAt 31 December 2022
61.5
40.4
353.1
273.1
6.6
734.7
\n1
Additions of $338.0 million related to the Tolmount offshore facilities were made to the right-of-use assets during the year (2021: total additions of $612.5 million arose primarily from
\nbusiness combinations of $567.9 million \u2013 see note 14) and $42.7 million from a new drilling rig contract.
\nRight-of-use liabilities
Note
\n2022
\n$ million
\n2021
\n$ million
\nAt 1 January
654.3
140.9
\nAdditions
338.0
42.7
\nAdditions from business combinations and joint arrangements
14
\u2013
637.8
\nRemeasurement
88.9
(5.0)
\nFinance costs charged to income statement
7
25.1
22.3
\nFinance costs charged to decommissioning provision
20
0.6
0.7
\nDisposals
(0.4)
(5.1)
\nLease payments
(254.0)
(160.4)
\nCurrency translation adjustment
(27.9)
(19.6)
\nAt 31 December
824.6
654.3
\nClassi\ufb01ed as
\nCurrent
220.8
165.1
\nNon-current
603.8
489.2
\nTotal lease liabilities
824.6
654.3
\n148
The signi\ufb01cant portion of the Group\u2019s lease liabilities represent lease arrangements for FPSO vessels on the Catcher and Chim S\u00e1o
\nassets, and offshore facilities on the Tolmount asset.
\nThe lease liabilities and associated right-of-use-assets have been calculated by reference to in-substance \ufb01xed lease payments in the
\nunderlying agreements incurred throughout the non-cancellable period of the lease along with periods covered by options to extend the
\nlease where the Group is reasonably certain that such options will be exercised. When assessing whether extension options were likely
\nto be exercised, assumptions are consistent with those applied when testing for impairment.
\nIncome statement
\nDepreciation charge of right-of-use assets
Note
\n2022
\n$ million
\n2021
\n$ million
\nLand and buildings \u2013 non-oil and gas assets
10.8
10.5
\nLand and buildings \u2013 oil and gas assets
1.0
1.1
\nDrilling rigs
42.5
44.8
\nOffshore facilities
61.1
\u2013
\nFPSO
107.4
102.1
\nEquipment \u2013 non-oil and gas assets
0.4
\u2013
\nEquipment \u2013 oil and gas assets
6.6
5.9
\n229.8
164.4
\nCapitalisation of IFRS 16 lease depreciation
\n1
\nDrilling rigs
(25.9)
(27.2)
\nEquipment
(4.0)
(3.5)
\nTotal depreciation charge
199.9
133.7
\nLease interest
7
25.1
22.3
\n1
Of the $29.9 million (2021: $30.7 million) capitalised IFRS 16 lease depreciation, $22.4 million (2021: $22.5 million) has been capitalised within property, plant and equipment and
\n$7.5 million (2021: $8.2 million) within provisions (note 20).
\nThe total cash out\ufb02ow for leases in 2022 was $254.0 million (2021: $160.4 million).",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLeasesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18726": {
"value": "14. Business combinations and acquisition of interests in joint arrangements Business combinations during the year ended 31 December 2021
\nIn October 2020, Harbour Energy Limited entered into an agreement with Premier Oil plc (Premier) regarding an all-share merger between
\nPremier and Harbour Energy Limited\u2019s subsidiary, Chrysaor Holdings Limited (Chrysaor). Under the terms of the merger, Premier legally
\nacquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the acquirer for accounting purposes, primarily as a
\nresult of its ability to appoint the Board of the enlarged group. The transaction completed on 31 March 2021, whereupon Premier, being
\nthe legal acquirer and accounting acquiree, changed its name from Premier Oil plc to Harbour Energy plc (Harbour).
\nThe merger constituted a reverse takeover of Premier by Chrysaor and has therefore been accounted for as a reverse acquisition in
\naccordance with IFRS 3 Business Combinations. As a result, Premier is fully consolidated in the \ufb01nancial statements with effect from
\n31\u00a0March 2021, and all results prior to this date represent those of Chrysaor only.
\nPremier was an upstream exploration and production company with its primary assets located in the UK North Sea, Vietnam and
\nIndonesia. The merger brought together two complementary businesses and created the largest independent oil and gas company
\nlisted on the London Stock Exchange with a strong balance sheet and signi\ufb01cant international growth opportunities.
\nA purchase price allocation (PPA) exercise has been performed under which the identi\ufb01able assets and liabilities of Premier were
\nrecognised at fair value.
\n149
Notes to the consolidated \ufb01nancial statements
continued
\n14. Business combinations and acquisition of interests in joint arrangements
continued
\nThe fair values of the net identi\ufb01able assets as at the date of acquisition are as follows:
\nFair value
\n$ million
\nAssets
\nExploration, evaluation and other intangible assets
597.1
\nProperty, plant and equipment \u2013 oil and gas assets
1,814.3
\nProperty, plant and equipment \u2013 non-oil and gas assets
4.2
\nProperty, plant and equipment \u2013 right-of-use assets
567.9
\nLong-term receivables
258.8
\nDeferred tax
1,549.2
\nInventories
15.2
\nTrade and other receivables
291.0
\nDerivative \ufb01nancial instruments
9.2
\nCash and cash equivalents
97.4
\n5,204.3
\nLiabilities
\nTrade and other payables
(317.5)
\nIFRS 16 lease liabilities
(637.8)
\nDeferred tax
(183.1)
\nProvision for decommissioning
(1,683.0)
\nDerivative \ufb01nancial instruments
(153.7)
\nShort-term debt
(2,219.3)
\nDeferred income
(33.6)
\nOther provisions
(34.5)
\n(5,262.5)
\nFair value of identi\ufb01able net liabilities acquired
(58.2)
\nFair value of shares acquired
285.7
\nTransaction cost adjustments
(4.6)
\nCost of acquisition
281.1
\nGoodwill recognised
339.3
\nThe fair values of the oil and gas assets and intangible assets acquired were determined using valuation techniques based on
\ndiscounted cash \ufb02ows using forward curve commodity prices and estimates of long-term prices, a discount rate based on market
\nobservable data and cost and production pro\ufb01les generally consistent with the 2P reserves acquired with each asset. Where applicable
\nother observable market information was also used. The decommissioning provisions recognised were estimated based on Harbour\u2019s
\ninternal estimates with reference to observable market data, including rig rates.
\nThe fair value of debt facilities was determined based on the total fair value of cash paid and new shares issued to creditors to satisfy
\nPremier\u2019s historical debt arrangements.
\nThe consideration was measured using the closing market price of Premier\u2019s ordinary share capital and the number of shares in issue
\nimmediately before the acquisition date. The transaction cost adjustments relate to share-based payment charges accruing prior to
\n31 March 2021 and certain transaction costs settled by Premier on behalf of Chrysaor which have been recognised as an expense
\nwithin general and administrative expenses.
\nGoodwill of $339.3 million was recognised on the acquisition, representing the excess of the total consideration transferred over the fair
\nvalue of the net assets acquired. The goodwill arose principally because of the following factors:
\n1.
The ability to deliver cost synergies as a result of combining the two businesses.
\n2.
The avoidance of costs that would otherwise have been incurred by Chrysaor as a result of an initial stock exchange listing.
\n3.
The expertise and experience of the acquired business, particularly with respect to ful\ufb01lling the obligations of a UK listed entity.
\n4.
The requirement to recognise deferred tax liabilities for the difference between the assigned fair values and the tax bases of assets acquired.
\n150
None of the goodwill is deductible for corporation tax.
\nAcquisition related costs of $26.5 million were incurred by the Group and recognised as an expense within general and administrative
\nexpenses within 2021.
\nFrom the date of acquisition to 31 December 2021, the acquired business contributed $815.6 million of revenue and a loss of $89.0 million
\nto the pro\ufb01t before tax from continuing operations of the Group. Had the acquisition completed at 1 January 2021, the business would have
\ncontributed revenue of $1,078.5 million in the year to 31 December 2021, and a loss of $93.9 million towards the pro\ufb01t before tax. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18852": {
"value": "15. Inventories 2022
\n$ million
\n2021
\n$ million
\nHydrocarbons
21.5
65.4
\nConsumables and subsea supplies
121.4
146.0
\nTotal inventories
142.9
211.4
\nInventories of consumables and subsea supplies include a provision of $24.6 million (2021: $8.5 million) where it is considered that the
\nnet realisable value is lower than the original cost.
\nInventories recognised as an expense during the year ended 31 December 2022 amounted to $22.4 million (2021: $3.3 million).
\nThese expenses are included within production costs. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInventoriesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18873": {
"value": "16. Trade and other receivables 2022
\n$ million
\n2021
\n$ million
\nTrade receivables
392.4
364.0
\nUnderlift position
69.3
147.5
\nOther debtors
97.2
74.1
\nPrepayments and accrued income
784.6
677.4
\nCorporation tax receivable
59.7
79.2
\nTotal trade and other receivables
1,403.2
1,342.2
\nTrade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2022, there were no trade
\nreceivables that were past due (2021: nil).
\nPrepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas. Other debtors mainly
\nrelate to amounts due from joint venture partners.
\nThe carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
\nOther long-term receivables
\n2022
\n$ million
\n2021
\n$ million
\nNet investment in sublease
44.0
52.9
\nDecommissioning funding asset
\n1
\n62.5
67.1
\nLong-term employee bene\ufb01t plan surplus
0.2
0.8
\nOther receivables
\n2
\n163.7
140.8
\nPrepayments and accrued income
27.6
1.4
\nTotal other long-term receivables
298.0
263.0
\n1
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
\nJohnston 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
\nbased 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 2022, a long-term
\ndecommissioning funding asset of $62.5 million (2021: $67.1 million) has been recognised utilising the year-end US dollar/pound sterling exchange rate and underlying assumptions
\nconsistent with those used for the corresponding decommissioning provision.
\n2
Other receivables includes $123.4 million in cash held in escrow accounts for expected future decommissioning expenditure in Indonesia and Vietnam (2021: $120.7 million), and
\n$22.6 million (2021: $23.9 million) held as security for the Mexican letters of credit. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18874": {
"value": "16. Trade and other receivables 2022
\n$ million
\n2021
\n$ million
\nTrade receivables
392.4
364.0
\nUnderlift position
69.3
147.5
\nOther debtors
97.2
74.1
\nPrepayments and accrued income
784.6
677.4
\nCorporation tax receivable
59.7
79.2
\nTotal trade and other receivables
1,403.2
1,342.2
\nTrade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2022, there were no trade
\nreceivables that were past due (2021: nil).
\nPrepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas. Other debtors mainly
\nrelate to amounts due from joint venture partners.
\nThe carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
\nOther long-term receivables
\n2022
\n$ million
\n2021
\n$ million
\nNet investment in sublease
44.0
52.9
\nDecommissioning funding asset
\n1
\n62.5
67.1
\nLong-term employee bene\ufb01t plan surplus
0.2
0.8
\nOther receivables
\n2
\n163.7
140.8
\nPrepayments and accrued income
27.6
1.4
\nTotal other long-term receivables
298.0
263.0
\n1
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
\nJohnston 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
\nbased 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 2022, a long-term
\ndecommissioning funding asset of $62.5 million (2021: $67.1 million) has been recognised utilising the year-end US dollar/pound sterling exchange rate and underlying assumptions
\nconsistent with those used for the corresponding decommissioning provision.
\n2
Other receivables includes $123.4 million in cash held in escrow accounts for expected future decommissioning expenditure in Indonesia and Vietnam (2021: $120.7 million), and
\n$22.6 million (2021: $23.9 million) held as security for the Mexican letters of credit.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherCurrentAssetsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18875": {
"value": "16. Trade and other receivables 2022
\n$ million
\n2021
\n$ million
\nTrade receivables
392.4
364.0
\nUnderlift position
69.3
147.5
\nOther debtors
97.2
74.1
\nPrepayments and accrued income
784.6
677.4
\nCorporation tax receivable
59.7
79.2
\nTotal trade and other receivables
1,403.2
1,342.2
\nTrade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2022, there were no trade
\nreceivables that were past due (2021: nil).
\nPrepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas. Other debtors mainly
\nrelate to amounts due from joint venture partners.
\nThe carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
\nOther long-term receivables
\n2022
\n$ million
\n2021
\n$ million
\nNet investment in sublease
44.0
52.9
\nDecommissioning funding asset
\n1
\n62.5
67.1
\nLong-term employee bene\ufb01t plan surplus
0.2
0.8
\nOther receivables
\n2
\n163.7
140.8
\nPrepayments and accrued income
27.6
1.4
\nTotal other long-term receivables
298.0
263.0
\n1
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
\nJohnston 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
\nbased 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 2022, a long-term
\ndecommissioning funding asset of $62.5 million (2021: $67.1 million) has been recognised utilising the year-end US dollar/pound sterling exchange rate and underlying assumptions
\nconsistent with those used for the corresponding decommissioning provision.
\n2
Other receivables includes $123.4 million in cash held in escrow accounts for expected future decommissioning expenditure in Indonesia and Vietnam (2021: $120.7 million), and
\n$22.6 million (2021: $23.9 million) held as security for the Mexican letters of credit. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherNoncurrentAssetsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18876": {
"value": "16. Trade and other receivables 2022
\n$ million
\n2021
\n$ million
\nTrade receivables
392.4
364.0
\nUnderlift position
69.3
147.5
\nOther debtors
97.2
74.1
\nPrepayments and accrued income
784.6
677.4
\nCorporation tax receivable
59.7
79.2
\nTotal trade and other receivables
1,403.2
1,342.2
\nTrade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2022, there were no trade
\nreceivables that were past due (2021: nil).
\nPrepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas. Other debtors mainly
\nrelate to amounts due from joint venture partners.
\nThe carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
\nOther long-term receivables
\n2022
\n$ million
\n2021
\n$ million
\nNet investment in sublease
44.0
52.9
\nDecommissioning funding asset
\n1
\n62.5
67.1
\nLong-term employee bene\ufb01t plan surplus
0.2
0.8
\nOther receivables
\n2
\n163.7
140.8
\nPrepayments and accrued income
27.6
1.4
\nTotal other long-term receivables
298.0
263.0
\n1
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
\nJohnston 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
\nbased 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 2022, a long-term
\ndecommissioning funding asset of $62.5 million (2021: $67.1 million) has been recognised utilising the year-end US dollar/pound sterling exchange rate and underlying assumptions
\nconsistent with those used for the corresponding decommissioning provision.
\n2
Other receivables includes $123.4 million in cash held in escrow accounts for expected future decommissioning expenditure in Indonesia and Vietnam (2021: $120.7 million), and
\n$22.6 million (2021: $23.9 million) held as security for the Mexican letters of credit.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTaxReceivablesAndPayablesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18882": {
"value": "2022 $ million
\n2021
\n$ million
\nTrade receivables
392.4
364.0
\nUnderlift position
69.3
147.5
\nOther debtors
97.2
74.1
\nPrepayments and accrued income
784.6
677.4
\nCorporation tax receivable
59.7
79.2
\nTotal trade and other receivables
1,403.2
1,342.2
\nTrade receivables are non-interest bearing and are generally on 20-to-30-day terms. As at 31 December 2022, there were no trade
\nreceivables that were past due (2021: nil).
\nPrepayments and accrued income mainly comprise amounts due, but not yet invoiced, for the sale of oil and gas. Other debtors mainly
\nrelate to amounts due from joint venture partners.
\nThe carrying value of the trade and other receivables are equal to their fair value as at the balance sheet date.
\nOther long-term receivables
\n2022
\n$ million
\n2021
\n$ million
\nNet investment in sublease
44.0
52.9
\nDecommissioning funding asset
\n1
\n62.5
67.1
\nLong-term employee bene\ufb01t plan surplus
0.2
0.8
\nOther receivables
\n2
\n163.7
140.8
\nPrepayments and accrued income
27.6
1.4
\nTotal other long-term receivables
298.0
263.0",
"dimensions": {
"concept": "ifrs-full:DisclosureOfPrepaymentsAndOtherAssetsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18962": {
"value": "17. Cash and cash equivalents 2022
\n$ million
\n2021
\n$ million
\nCash at bank and in hand
499.7
698.7
\nCash at bank earns interest at \ufb02oating rates based on daily bank deposit rates. The Group only deposits cash with major banks of
\nhigh-quality credit standing.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDepositsFromBanksExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18963": {
"value": "17. Cash and cash equivalents 2022
\n$ million
\n2021
\n$ million
\nCash at bank and in hand
499.7
698.7
\nCash at bank earns interest at \ufb02oating rates based on daily bank deposit rates. The Group only deposits cash with major banks of
\nhigh-quality credit standing.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18978": {
"value": "18. Commitments Capital commitments
\nAs at 31 December 2022, the Group had commitments for future capital expenditure amounting to $408.7 million (2021: $451.1 million).
\nWhere the commitment relates to a joint arrangement, the amount represents the Group\u2019s net share of the commitment. Where the Group
\nis not the operator of the joint arrangement then the amounts are based on the Group\u2019s net share of committed future work programmes.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCommitmentsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18986": {
"value": "19. Trade and other payables 2022
\n$ million
\n2021
\nrestated
\n$ million
\nCurrent
\nTrade payables
47.2
120.9
\nOverlift position
131.5
76.7
\nOther payables
\n1
\n117.5
148.6
\nMatured \ufb01nancial instruments
258.2
361.7
\nAccruals
682.3
482.4
\nDeferred income
\n2
\n14.5
45.0
\n1,251.2
1,235.3
\nNon-current
\nOther payables
10.8
27.6
\nDeferred income
\n2
\n8.0
4.7
\n18.8
32.3
\n1
Other payables, within current liabilities at 31 December 2021, included $24.1 million of additional completion payments payable to ConocoPhillips as part of the acquisition of the
\nConocoPhillips UK business in 2019. This amount was settled in October 2022 and no further liabilities remain payable to ConocoPhillips.
\n2
Deferred income includes $22.5 million (2021: $20.8 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100.0 million from
\nFlowStream 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.
\nThis 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
\nunobservable inputs and is level 3 in the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has increased by $1.7 million in the year re\ufb02ecting the impact
\nof barrels delivered to FlowStream resulting in a debit to the income statement within \ufb01nance expense. Deferred income of $14.5 million (2021: $16.1 million) is expected to be delivered
\nto FlowStream within the next 12 months and has been classi\ufb01ed as a current liability, with the balance of $8.0 million classi\ufb01ed as non-current liabilities.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18987": {
"value": "19. Trade and other payables 2022
\n$ million
\n2021
\nrestated
\n$ million
\nCurrent
\nTrade payables
47.2
120.9
\nOverlift position
131.5
76.7
\nOther payables
\n1
\n117.5
148.6
\nMatured \ufb01nancial instruments
258.2
361.7
\nAccruals
682.3
482.4
\nDeferred income
\n2
\n14.5
45.0
\n1,251.2
1,235.3
\nNon-current
\nOther payables
10.8
27.6
\nDeferred income
\n2
\n8.0
4.7
\n18.8
32.3
\n1
Other payables, within current liabilities at 31 December 2021, included $24.1 million of additional completion payments payable to ConocoPhillips as part of the acquisition of the
\nConocoPhillips UK business in 2019. This amount was settled in October 2022 and no further liabilities remain payable to ConocoPhillips.
\n2
Deferred income includes $22.5 million (2021: $20.8 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100.0 million from
\nFlowStream 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.
\nThis 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
\nunobservable inputs and is level 3 in the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has increased by $1.7 million in the year re\ufb02ecting the impact
\nof barrels delivered to FlowStream resulting in a debit to the income statement within \ufb01nance expense. Deferred income of $14.5 million (2021: $16.1 million) is expected to be delivered
\nto FlowStream within the next 12 months and has been classi\ufb01ed as a current liability, with the balance of $8.0 million classi\ufb01ed as non-current liabilities.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherCurrentLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18988": {
"value": "19. Trade and other payables 2022
\n$ million
\n2021
\nrestated
\n$ million
\nCurrent
\nTrade payables
47.2
120.9
\nOverlift position
131.5
76.7
\nOther payables
\n1
\n117.5
148.6
\nMatured \ufb01nancial instruments
258.2
361.7
\nAccruals
682.3
482.4
\nDeferred income
\n2
\n14.5
45.0
\n1,251.2
1,235.3
\nNon-current
\nOther payables
10.8
27.6
\nDeferred income
\n2
\n8.0
4.7
\n18.8
32.3
\n1
Other payables, within current liabilities at 31 December 2021, included $24.1 million of additional completion payments payable to ConocoPhillips as part of the acquisition of the
\nConocoPhillips UK business in 2019. This amount was settled in October 2022 and no further liabilities remain payable to ConocoPhillips.
\n2
Deferred income includes $22.5 million (2021: $20.8 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100.0 million from
\nFlowStream 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.
\nThis 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
\nunobservable inputs and is level 3 in the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has increased by $1.7 million in the year re\ufb02ecting the impact
\nof barrels delivered to FlowStream resulting in a debit to the income statement within \ufb01nance expense. Deferred income of $14.5 million (2021: $16.1 million) is expected to be delivered
\nto FlowStream within the next 12 months and has been classi\ufb01ed as a current liability, with the balance of $8.0 million classi\ufb01ed as non-current liabilities.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18989": {
"value": "19. Trade and other payables 2022
\n$ million
\n2021
\nrestated
\n$ million
\nCurrent
\nTrade payables
47.2
120.9
\nOverlift position
131.5
76.7
\nOther payables
\n1
\n117.5
148.6
\nMatured \ufb01nancial instruments
258.2
361.7
\nAccruals
682.3
482.4
\nDeferred income
\n2
\n14.5
45.0
\n1,251.2
1,235.3
\nNon-current
\nOther payables
10.8
27.6
\nDeferred income
\n2
\n8.0
4.7
\n18.8
32.3
\n1
Other payables, within current liabilities at 31 December 2021, included $24.1 million of additional completion payments payable to ConocoPhillips as part of the acquisition of the
\nConocoPhillips UK business in 2019. This amount was settled in October 2022 and no further liabilities remain payable to ConocoPhillips.
\n2
Deferred income includes $22.5 million (2021: $20.8 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100.0 million from
\nFlowStream 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.
\nThis 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
\nunobservable inputs and is level 3 in the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has increased by $1.7 million in the year re\ufb02ecting the impact
\nof barrels delivered to FlowStream resulting in a debit to the income statement within \ufb01nance expense. Deferred income of $14.5 million (2021: $16.1 million) is expected to be delivered
\nto FlowStream within the next 12 months and has been classi\ufb01ed as a current liability, with the balance of $8.0 million classi\ufb01ed as non-current liabilities.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherNoncurrentLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18995": {
"value": "2022 $ million
\n2021
\nrestated
\n$ million
\nCurrent
\nTrade payables
47.2
120.9
\nOverlift position
131.5
76.7
\nOther payables
\n1
\n117.5
148.6
\nMatured \ufb01nancial instruments
258.2
361.7
\nAccruals
682.3
482.4
\nDeferred income
\n2
\n14.5
45.0
\n1,251.2
1,235.3
\nNon-current
\nOther payables
10.8
27.6
\nDeferred income
\n2
\n8.0
4.7
\n18.8
32.3
\n1
Other payables, within current liabilities at 31 December 2021, included $24.1 million of additional completion payments payable to ConocoPhillips as part of the acquisition of the
\nConocoPhillips UK business in 2019. This amount was settled in October 2022 and no further liabilities remain payable to ConocoPhillips.
\n2
Deferred income includes $22.5 million (2021: $20.8 million) in relation to the closing year-end fair value payable to FlowStream. In June 2015, Premier received $100.0 million from
\nFlowStream 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.
\nThis 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
\nunobservable inputs and is level 3 in the IFRS 13 hierarchy and is held at fair value through pro\ufb01t and loss. The balance has increased by $1.7 million in the year re\ufb02ecting the impact
\nof barrels delivered to FlowStream resulting in a debit to the income statement within \ufb01nance expense. Deferred income of $14.5 million (2021: $16.1 million) is expected to be delivered
to FlowStream within the next 12 months and has been classi\ufb01ed as a current liability, with the balance of $8.0 million classi\ufb01ed as non-current liabilities.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDeferredIncomeExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f18996": {
"value": "2022 $ million
\n2021
\nrestated
\n$ million
\nCurrent
\nTrade payables
47.2
120.9
\nOverlift position
131.5
76.7
\nOther payables
\n1
\n117.5
148.6
\nMatured \ufb01nancial instruments
258.2
361.7
\nAccruals
682.3
482.4
\nDeferred income
\n2
\n14.5
45.0
\n1,251.2
1,235.3
\nNon-current
\nOther payables
10.8
27.6
\nDeferred income
\n2
\n8.0
4.7
\n18.8
32.3",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19063": {
"value": "20. Provisions Note
\nDecommissioning
\nprovision
\n$ million
\nOther
\n$ million
\nTotal
\n$ million
\nAt 1 January 2021
4,197.1
13.9
4,211.0
\nAdditions
17.1
1.0
18.1
\nAdditions from business combinations and joint arrangements
1,683.0
34.5
1,717.5
\nChanges in estimates \u2013 decrease to oil and gas tangible decommissioning assets
(381.0)
\u2013
(381.0)
\nChanges in estimates \u2013 increase to oil and gas intangible decommissioning assets
14.3
\u2013
14.3
\nChanges in estimates \u2013 credit to income statement
\u2013
(2.3)
(2.3)
\nChanges in estimates on oil and gas tangible assets \u2013 debit to income statement
8.5
\u2013
8.5
\nChanges in estimates on oil and gas intangible assets \u2013 credit to income statement
(6.3)
\u2013
(6.3)
\nAmounts used
(225.9)
(9.2)
(235.1)
\nInterest on decommissioning lease
(0.7)
\u2013
(0.7)
\nDepreciation, depletion & amortisation on decommissioning right-of-use leased asset
(8.2)
\u2013
(8.2)
\nRelease of royalty provision
22
\u2013
(10.2)
(10.2)
\nUnwinding of discount
78.0
\u2013
78.0
\nCurrency translation adjustment
(22.2)
(0.2)
(22.4)
\nAt 31 December 2021
5,353.7
27.5
5,381.2
\nAdditions
24.4
\u2013
24.4
\nChanges in estimates \u2013 decrease to oil and gas tangible decommissioning assets
(720.9)
\u2013
(720.9)
\nChanges in estimates \u2013 decrease to oil and gas intangible decommissioning assets
(6.1)
\u2013
(6.1)
\nChanges in estimates \u2013 credit to income statement
\u2013
(1.2)
(1.2)
\nChanges in estimates on oil and gas tangible assets \u2013 credit to income statement
(82.3)
\u2013
(82.3)
\nChanges in estimates on oil and gas intangible assets \u2013 credit to income statement
(5.7)
\u2013
(5.7)
\nAmounts used
(222.6)
(2.3)
(224.9)
\nDisposal
(9.0)
\u2013
(9.0)
\nInterest on decommissioning lease
(0.6)
\u2013
(0.6)
\nDepreciation, depletion & amortisation on decommissioning right-of-use leased asset
(7.5)
\u2013
(7.5)
\nUnwinding of discount
65.1
\u2013
65.1
\nCurrency translation adjustment
(247.2)
\u2013
(247.2)
\nAt 31 December 2022
4,141.3
24.0
4,165.3
\nClassi\ufb01ed within
\nNon-current
\nliabilities
\n$ million
\nCurrent
\nliabilities
\n$ million
\nTotal
\n$ million
\nAt 31 December 2021
5,022.6
358.6
5,381.2
\nAt 31 December 2022
3,933.7
231.6
4,165.3
\nDecommissioning provision
\nAll of the $24.4 million decommissioning provision additions relate to oil and gas tangible assets (2021: $14.7 million related to oil and
\ngas tangible assets, and $2.4 million related to oil and gas intangible assets).
\nThe Group provides for the estimated future decommissioning costs on its oil and gas assets at the balance sheet date. The payment
\ndates of expected decommissioning costs are uncertain and are based on economic assumptions of the \ufb01elds concerned. The Group
\ncurrently expects to incur decommissioning costs within the next 40 years, the majority of which are anticipated to be incurred between
\nthe 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
\ncent per annum (2021: 2.0 per cent per annum) and discounted at a risk-free rate of between 3.5 per cent and 3.7 per cent (2021:
\n0.9 per cent and 1.8 per cent) re\ufb02ecting a six-month (2021: 24-month) rolling average of market rates over the varying lives of the assets
\nto calculate the present value of the decommissioning liabilities. The unwinding of the discount is presented within \ufb01nance costs.
\nThese provisions have been created based on internal and third-party estimates. Assumptions based on the current economic
\nenvironment have been made, which management believe are a reasonable basis upon which to estimate the future liability. These
\nestimates are reviewed regularly to consider any material changes to the assumptions. However, actual decommissioning costs will
\nultimately depend upon market prices for the necessary decommissioning work required, which will re\ufb02ect market conditions at the
\nrelevant time. In addition, the timing of decommissioning liabilities will depend upon the dates when the \ufb01elds become economically
\nunviable, which in itself will depend on future commodity prices and climate change, which are inherently uncertain.
\n153
Notes to the consolidated \ufb01nancial statements
continued
\n20. Provisions
continued
\nOther provisions
\nOther provisions relate to termination bene\ufb01t provision in Indonesia of $23.5 million (2021: $25.3 million), where the Group operates a service,
\nseverance and compensation pay scheme under a collective labour agreement with the local workforce. Other provisions at 31 December 2021
\nalso included a $2.3 million onerous contract provision in respect of the termination cost of the rig which had been operating on the Schiehallion
\n\ufb01eld, which has now been fully settled. The onerous contract had no impact on the income statement in the year.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfProvisionsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19236": {
"value": "Other provisions Other provisions relate to termination bene\ufb01t provision in Indonesia of $23.5 million (2021: $25.3 million), where the Group operates a service,
\nseverance and compensation pay scheme under a collective labour agreement with the local workforce. Other provisions at 31 December 2021
\nalso included a $2.3 million onerous contract provision in respect of the termination cost of the rig which had been operating on the Schiehallion
\ufb01eld, which has now been fully settled. The onerous contract had no impact on the income statement in the year.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherProvisionsContingentLiabilitiesAndContingentAssetsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19245": {
"value": "21. Borrowings and facilities The Group\u2019s borrowings are carried at amortised cost:
\n2022
\n$ million
\n2021
\n$ million
\nReserves-based lending (RBL) facility
702.3
2,312.0
\nBond
491.3
489.5
\nExploration \ufb01nance facility (EFF)
10.5
44.6
\nOther loans
34.0
39.9
\nTotal borrowings
1,238.1
2,886.0
\nClassi\ufb01ed within
\nNon-current liabilities
1,216.6
2,823.7
\nCurrent liabilities
21.5
62.3
\nTotal borrowings
1,238.1
2,886.0
\nInterest of $6.2 million (2021: $17.4 million) on the RBL, bond and EFF had accrued by the balance sheet date and has been classi\ufb01ed
\nwithin accruals.
\nThe key terms of the RBL facility are:
\n\u00bc
Term matures 23 November 2027.
\n\u00bc
Facility size of $4.1 billion (with $0.75 billion accordion option).
\n\u00bc
Debt availability currently at $2.75 billion.
\n\u00bc
Debt availability to be redetermined on an annual basis.
\n\u00bc
Interest at USD LIBOR plus a margin of 3.25 per cent, rising to a margin of 3.5 per cent from November 2025.
\n\u00bc
A margin adjustment linked to carbon-emission reductions.
\n\u00bc
Liquidity and leverage covenant tests.
\n\u00bc
A syndication group of 19 banks.
\nCertain fees are also payable, including fees on available commitments at 40 per cent of the applicable margin and commission on
\nletters of credit issued at 50 per cent of the applicable margin.
\nIn October 2021, the Group issued a $500 million bond under Rule 144A and has a tenor of \ufb01ve years to maturity. The coupon was set
\nat 5.50 per cent and interest is payable semi-annually.
\nSince 2019, the Group has been operating within an exploration \ufb01nance facility, currently for NOK 1 billion, in relation to part-\ufb01nancing
\nthe exploration activities of Harbour Energy Norge AS. At the balance sheet date, the amount drawn down on the facility was NOK 104
\nmillion/$10.5 million (2021: NOK 396 million/$44.9 million).
\nDuring the year $54.9 million (2021: $38.9 million) of arrangement fees and related costs have been amortised and are included
\nwithin \ufb01nancing costs. 2021 also included a $13.9 million modi\ufb01cation gain following a maturity extension of the RBL debt prior to
\nthe completion of the merger in March 2021.
\nAt 31 December 2022, $81.5 million of arrangement fees and related costs remain capitalised (2021: $136.4 million), of which
\n$20.2 million are due to be amortised within the next 12 months (2021: $43.6 million).
\nAt the balance sheet date, the outstanding RBL balance excluding incremental arrangement fees and related costs was $775.0 million (2021:
\n$2,437.5 million). As at 31 December 2022, $1,972.0 million remained available for drawdown under the RBL facility (2021: $884 million).
\n154
The Group has facilities to issue up to $1.5 billion of letters of credit, of which $966 million was in issue as at 31 December (2021:
\n$796 million), mainly in respect of future abandonment liabilities.
\nOther loans represent a commercial \ufb01nancing arrangement with Baker Hughes (formerly BHGE), that covered a three-year work programme
\nfor drilling, completion and subsea tie-in of development wells on Harbour\u2019s operated assets. The loan will be repaid based on production
\nperformance, subject to a cap, in addition to three annual instalments of $9.0 million commencing on 1 December 2024, if required.
\nThe table below details the change in the carrying amount of the Group\u2019s borrowings arising from \ufb01nancing cash \ufb02ow.
\n$ million
\nTotal borrowings as at 1 January 2021
2,161.4
\nRepayment of RBL
(697.5)
\nRepayment of junior debt
(400.0)
\nShort-term debt arising on business combination
(2,219.3)
\nRepayment of debt \u2013 equity allocation to borrowings
942.8
\nRepayment of debt \u2013 cash allocation to borrowings
1,276.5
\nConversion of D loan notes to equity
(134.7)
\nIFRS 9 modi\ufb01cation gain
(13.9)
\nRepayment of \ufb01nancing arrangement
(9.3)
\nRepayment of EFF loan
(14.7)
\nProceeds from drawdown of borrowing facilities
1,617.5
\nProceeds from EFF loan
45.9
\nProceeds from issue of bond
500.0
\nLoan notes redemption
(135.7)
\nArrangement fees and related costs on RBL paid and capitalised
(77.2)
\nArrangement fees and related costs on bond capitalised
(10.9)
\nArrangement fees and related costs on EFF loan capitalised
(0.4)
\nCurrency translation adjustment on EFF loan
(0.6)
\nLoan notes interest capitalised
5.6
\nFinancing arrangement interest payable
11.6
\nAmortisation of arrangement fees and related costs
38.9
\nTotal borrowings as at 31 December 2021
2,886.0
\nRepayment of RBL
(1,662.5)
\nRepayment of \ufb01nancing arrangement
(15.4)
\nRepayment of EFF loan
(38.6)
\nProceeds from EFF loan
11.5
\nCurrency translation adjustment on EFF loan
(7.3)
\nFinancing arrangement interest payable
9.5
\nAmortisation of arrangement fees and related costs
54.9
\nTotal borrowings as at 31 December 2022
1,238.1 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBorrowingsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19403": {
"value": "22. Other \ufb01nancial assets and liabilities The Group held the following \ufb01nancial instruments at fair value at 31 December 2022. The fair values of all derivative \ufb01nancial instruments
\nare based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation, which includes
\nestimates based on unobservable inputs and is level 3 in the IFRS 13 hierarchy.
\nCurrent
\n31 December 2022
31 December 2021 restated
\nAssets
\n$ million
\nLiabilities
\n$ million
\nAssets
\n$ million
\nLiabilities
\n$ million
\nMeasured at fair value through pro\ufb01t and loss
\nForeign exchange derivatives
6.0
(0.1)
0.9
(2.2)
\nInterest rate derivatives
24.3
\u2013
3.3
\u2013
\nFair value of embedded derivative within gas contract
\u2013
(57.0)
\u2013
(11.5)
\nCarbon swaps
\u2013
\u2013
36.6
(15.6)
\n30.3
(57.1)
40.8
(29.3)
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
50.5
(2,114.4)
1.0
(2,135.2)
\n50.5
(2,114.4)
1.0
(2,135.2)
\nTotal current
80.8
(2,171.5)
41.8
(2,164.5)
\nNon-current
\nMeasured at fair value through pro\ufb01t and loss
\nInterest rate derivatives
18.2
\u2013
8.3
\u2013
\n18.2
\u2013
8.3
\u2013
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
84.5
(1,279.1)
1.8
(1,373.6)
\n84.5
(1,279.1)
1.8
(1,373.6)
\nTotal non-current
102.7
(1,279.1)
10.1
(1,373.6)
\nTotal current and non-current
183.5
(3,450.6)
51.9
(3,538.1)
\nFair value measurements
\nAll \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with the
\nhierarchy described in IFRS 13 Fair Value Measurement. The hierarchy groups fair value measurements into the following levels based on
\nthe degree to which the fair value is observable.
\n\u00bc
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities.
\n\u00bc
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or indirectly.
\n\u00bc
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data.
\nAs at 31 December 2022
\nFinancial assets
Financial liabilities
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(57.0)
\u2013
\nCommodity derivatives
135.0
\u2013
(3,393.5)
\u2013
\nForeign exchange derivatives
6.0
\u2013
(0.1)
\u2013
\nCarbon swaps
\u2013
\u2013
\u2013
\u2013
\nInterest rate derivatives
42.5
\u2013
\u2013
\u2013
\nTotal fair value
183.5
\u2013
(3,450.6)
\u2013
\nFinancial assets
Financial liabilities
\nAs at 31 December 2021 as restated
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(11.5)
\u2013
\nCommodity derivatives
2.8
\u2013
(3,508.8)
\u2013
\nForeign exchange derivatives
0.9
\u2013
(2.2)
\u2013
\nCarbon swaps
36.6
\u2013
(15.6)
\u2013
\nInterest rate derivatives
11.6
\u2013
\u2013
\u2013
\nTotal fair value
51.9
\u2013
(3,538.1)
\u2013
\n156
There were no transfers between fair value levels in the year. The movements in the year associated with \ufb01nancial assets and liabilities
\nmeasured in accordance with level 3 of the fair value hierarchy are shown below:
\nLevel 3
\nFinancial
\nassets
\nFinancial
\nliabilities
\n2022
\n$ million
\n2021
\n$ million
\n2022
\n$ million
\n2021
\n$ million
\nFair value as at 1 January
\u2013
9.7
\u2013
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
(10.2)
\u2013
(4.2)
\nGains and (losses) recognised in the income statement
\u2013
0.5
\u2013
4.2
\nFair value as at 31 December
\u2013
\u2013
\u2013
\u2013
\nFair value movements recognised in the income statement on \ufb01nancial instruments are shown below:
\n2022
\n$ million
\n2021
\n$ million
\nIncome included in the income statement
\nWarrants
\u2013
4.2
\nRemeasurement of royalty valuation
\u2013
0.5
\n\u2013
4.7
\nFair values of other \ufb01nancial instruments
\nThe following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
\n2022
2021
\nBook value
\n$ million
\nFair value
\n$ million
\nBook value
\n$ million
\nFair value
\n$ million
\nBond
(491.3)
(446.4)
(489.5)
(483.0)
\nThe 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
\nmarket yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
\nshort-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.
\nCash \ufb02ow hedge accounting
\nThe Group uses a combination of \ufb01xed price physical sales contracts and cash-settled \ufb01xed price commodity swaps and options to manage
\nthe price risk associated with its underlying oil and gas revenues. As at 31 December 2022, all of the Group\u2019s cash-settled \ufb01xed price
\ncommodity swap derivatives have been designated as cash \ufb02ow hedges of highly probable forecast sales of oil and gas.
\nThe following table indicates the volumes, average hedged price and timings associated with the Group\u2019s \ufb01nancial commodity derivatives.
\nVolumes hedged through \ufb01xed price contracts with customers for physical delivery are excluded.
\nPosition as at 31 December 2022
2023
2024
2025
2026
\nOil volume hedged (thousand bbls)
10,950
7,320
2,373
\u2013
\nWeighted average hedged price ($/bbl)
74.08
84.37
81.22
\u2013
\nGas volume hedged (million therms)
1,339
652
113
\u2013
\nWeighted average hedged price (p/therm)
41.46
68.85
75.22
\u2013
\nAs at 31 December 2022, the fair value of net \ufb01nancial commodity derivatives designated as cash \ufb02ow hedges, all executed under ISDA
\nagreements with no margining requirements, was a net payable of $3,516.7 million (2021: $3,868.2 million) and net unrealised pre-tax
\nlosses of $3,184.6 million (2021: $3,454.2 million) were deferred in other comprehensive income in respect of the effective portion of
\nthe hedge relationships.
\nAmounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur.
\nAs at 31 December 2022, net deferred pre-tax losses of $2,367.9 million (2021: $2,495.9 million) are expected to be released to the
\nincome statement within one year.
\n157
Notes to the consolidated \ufb01nancial statements
continued
\n22. Other \ufb01nancial assets and liabilities
continued
\nInterest Rate Benchmark Reform (IBOR)
\nFrom 1 January 2022, publication of most LIBOR settings ended (including Sterling LIBOR). All IBORs were replaced with alternative
\nreference rates with the exception of US LIBOR.
\nAfter 30 June 2023 US LIBOR will cease publication and will be replaced by SOFR (Secured overnight \ufb01nancing rate). The Group has
\nvariable rate RBL borrowings that currently reference US LIBOR, which are partially hedged by interest rate swaps that are also linked to
\nUS LIBOR. The RBL agreement has an automatic trigger to transition to SOFR after 30 June 2023, and a similar arrangement has been
\nagreed in principle with the interest rate swap counterparties to reduce any future impact on the \ufb01nancial statements after transition.
\nThe following table shows the \ufb01nancial instruments held by the Group as at 31 December 2022 which are referenced to US LIBOR that
\nwill transition to SOFR by 30 June 2023.
\nRBL borrowings \ufb01nancial liabilities
\nNominal value
\n$ million
\nUSD 1M LIBOR
475.0
\nUSD 6M LIBOR
300.0
\n775.0
\nDerivatives
\nInterest rate swaps USD 6M LIBOR
544.6
\nThe nominal values in the table above also represent the carrying values net of unamortised deferred fees of the RBL as at 31 December 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialLiabilitiesHeldForTradingExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19404": {
"value": "22. Other \ufb01nancial assets and liabilities The Group held the following \ufb01nancial instruments at fair value at 31 December 2022. The fair values of all derivative \ufb01nancial instruments
\nare based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation, which includes
\nestimates based on unobservable inputs and is level 3 in the IFRS 13 hierarchy.
\nCurrent
\n31 December 2022
31 December 2021 restated
\nAssets
\n$ million
\nLiabilities
\n$ million
\nAssets
\n$ million
\nLiabilities
\n$ million
\nMeasured at fair value through pro\ufb01t and loss
\nForeign exchange derivatives
6.0
(0.1)
0.9
(2.2)
\nInterest rate derivatives
24.3
\u2013
3.3
\u2013
\nFair value of embedded derivative within gas contract
\u2013
(57.0)
\u2013
(11.5)
\nCarbon swaps
\u2013
\u2013
36.6
(15.6)
\n30.3
(57.1)
40.8
(29.3)
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
50.5
(2,114.4)
1.0
(2,135.2)
\n50.5
(2,114.4)
1.0
(2,135.2)
\nTotal current
80.8
(2,171.5)
41.8
(2,164.5)
\nNon-current
\nMeasured at fair value through pro\ufb01t and loss
\nInterest rate derivatives
18.2
\u2013
8.3
\u2013
\n18.2
\u2013
8.3
\u2013
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
84.5
(1,279.1)
1.8
(1,373.6)
\n84.5
(1,279.1)
1.8
(1,373.6)
\nTotal non-current
102.7
(1,279.1)
10.1
(1,373.6)
\nTotal current and non-current
183.5
(3,450.6)
51.9
(3,538.1)
\nFair value measurements
\nAll \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with the
\nhierarchy described in IFRS 13 Fair Value Measurement. The hierarchy groups fair value measurements into the following levels based on
\nthe degree to which the fair value is observable.
\n\u00bc
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities.
\n\u00bc
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or indirectly.
\n\u00bc
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data.
\nAs at 31 December 2022
\nFinancial assets
Financial liabilities
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(57.0)
\u2013
\nCommodity derivatives
135.0
\u2013
(3,393.5)
\u2013
\nForeign exchange derivatives
6.0
\u2013
(0.1)
\u2013
\nCarbon swaps
\u2013
\u2013
\u2013
\u2013
\nInterest rate derivatives
42.5
\u2013
\u2013
\u2013
\nTotal fair value
183.5
\u2013
(3,450.6)
\u2013
\nFinancial assets
Financial liabilities
\nAs at 31 December 2021 as restated
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(11.5)
\u2013
\nCommodity derivatives
2.8
\u2013
(3,508.8)
\u2013
\nForeign exchange derivatives
0.9
\u2013
(2.2)
\u2013
\nCarbon swaps
36.6
\u2013
(15.6)
\u2013
\nInterest rate derivatives
11.6
\u2013
\u2013
\u2013
\nTotal fair value
51.9
\u2013
(3,538.1)
\u2013
\n156
There were no transfers between fair value levels in the year. The movements in the year associated with \ufb01nancial assets and liabilities
\nmeasured in accordance with level 3 of the fair value hierarchy are shown below:
\nLevel 3
\nFinancial
\nassets
\nFinancial
\nliabilities
\n2022
\n$ million
\n2021
\n$ million
\n2022
\n$ million
\n2021
\n$ million
\nFair value as at 1 January
\u2013
9.7
\u2013
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
(10.2)
\u2013
(4.2)
\nGains and (losses) recognised in the income statement
\u2013
0.5
\u2013
4.2
\nFair value as at 31 December
\u2013
\u2013
\u2013
\u2013
\nFair value movements recognised in the income statement on \ufb01nancial instruments are shown below:
\n2022
\n$ million
\n2021
\n$ million
\nIncome included in the income statement
\nWarrants
\u2013
4.2
\nRemeasurement of royalty valuation
\u2013
0.5
\n\u2013
4.7
\nFair values of other \ufb01nancial instruments
\nThe following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
\n2022
2021
\nBook value
\n$ million
\nFair value
\n$ million
\nBook value
\n$ million
\nFair value
\n$ million
\nBond
(491.3)
(446.4)
(489.5)
(483.0)
\nThe 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
\nmarket yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
\nshort-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.
\nCash \ufb02ow hedge accounting
\nThe Group uses a combination of \ufb01xed price physical sales contracts and cash-settled \ufb01xed price commodity swaps and options to manage
\nthe price risk associated with its underlying oil and gas revenues. As at 31 December 2022, all of the Group\u2019s cash-settled \ufb01xed price
\ncommodity swap derivatives have been designated as cash \ufb02ow hedges of highly probable forecast sales of oil and gas.
\nThe following table indicates the volumes, average hedged price and timings associated with the Group\u2019s \ufb01nancial commodity derivatives.
\nVolumes hedged through \ufb01xed price contracts with customers for physical delivery are excluded.
\nPosition as at 31 December 2022
2023
2024
2025
2026
\nOil volume hedged (thousand bbls)
10,950
7,320
2,373
\u2013
\nWeighted average hedged price ($/bbl)
74.08
84.37
81.22
\u2013
\nGas volume hedged (million therms)
1,339
652
113
\u2013
\nWeighted average hedged price (p/therm)
41.46
68.85
75.22
\u2013
\nAs at 31 December 2022, the fair value of net \ufb01nancial commodity derivatives designated as cash \ufb02ow hedges, all executed under ISDA
\nagreements with no margining requirements, was a net payable of $3,516.7 million (2021: $3,868.2 million) and net unrealised pre-tax
\nlosses of $3,184.6 million (2021: $3,454.2 million) were deferred in other comprehensive income in respect of the effective portion of
\nthe hedge relationships.
\nAmounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur.
\nAs at 31 December 2022, net deferred pre-tax losses of $2,367.9 million (2021: $2,495.9 million) are expected to be released to the
\nincome statement within one year.
\n157
Notes to the consolidated \ufb01nancial statements
continued
\n22. Other \ufb01nancial assets and liabilities
continued
\nInterest Rate Benchmark Reform (IBOR)
\nFrom 1 January 2022, publication of most LIBOR settings ended (including Sterling LIBOR). All IBORs were replaced with alternative
\nreference rates with the exception of US LIBOR.
\nAfter 30 June 2023 US LIBOR will cease publication and will be replaced by SOFR (Secured overnight \ufb01nancing rate). The Group has
\nvariable rate RBL borrowings that currently reference US LIBOR, which are partially hedged by interest rate swaps that are also linked to
\nUS LIBOR. The RBL agreement has an automatic trigger to transition to SOFR after 30 June 2023, and a similar arrangement has been
\nagreed in principle with the interest rate swap counterparties to reduce any future impact on the \ufb01nancial statements after transition.
\nThe following table shows the \ufb01nancial instruments held by the Group as at 31 December 2022 which are referenced to US LIBOR that
\nwill transition to SOFR by 30 June 2023.
\nRBL borrowings \ufb01nancial liabilities
\nNominal value
\n$ million
\nUSD 1M LIBOR
475.0
\nUSD 6M LIBOR
300.0
\n775.0
\nDerivatives
\nInterest rate swaps USD 6M LIBOR
544.6
\nThe nominal values in the table above also represent the carrying values net of unamortised deferred fees of the RBL as at 31 December 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialAssetsHeldForTradingExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19405": {
"value": "22. Other \ufb01nancial assets and liabilities The Group held the following \ufb01nancial instruments at fair value at 31 December 2022. The fair values of all derivative \ufb01nancial instruments
\nare based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation, which includes
\nestimates based on unobservable inputs and is level 3 in the IFRS 13 hierarchy.
\nCurrent
\n31 December 2022
31 December 2021 restated
\nAssets
\n$ million
\nLiabilities
\n$ million
\nAssets
\n$ million
\nLiabilities
\n$ million
\nMeasured at fair value through pro\ufb01t and loss
\nForeign exchange derivatives
6.0
(0.1)
0.9
(2.2)
\nInterest rate derivatives
24.3
\u2013
3.3
\u2013
\nFair value of embedded derivative within gas contract
\u2013
(57.0)
\u2013
(11.5)
\nCarbon swaps
\u2013
\u2013
36.6
(15.6)
\n30.3
(57.1)
40.8
(29.3)
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
50.5
(2,114.4)
1.0
(2,135.2)
\n50.5
(2,114.4)
1.0
(2,135.2)
\nTotal current
80.8
(2,171.5)
41.8
(2,164.5)
\nNon-current
\nMeasured at fair value through pro\ufb01t and loss
\nInterest rate derivatives
18.2
\u2013
8.3
\u2013
\n18.2
\u2013
8.3
\u2013
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
84.5
(1,279.1)
1.8
(1,373.6)
\n84.5
(1,279.1)
1.8
(1,373.6)
\nTotal non-current
102.7
(1,279.1)
10.1
(1,373.6)
\nTotal current and non-current
183.5
(3,450.6)
51.9
(3,538.1)
\nFair value measurements
\nAll \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with the
\nhierarchy described in IFRS 13 Fair Value Measurement. The hierarchy groups fair value measurements into the following levels based on
\nthe degree to which the fair value is observable.
\n\u00bc
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities.
\n\u00bc
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or indirectly.
\n\u00bc
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data.
\nAs at 31 December 2022
\nFinancial assets
Financial liabilities
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(57.0)
\u2013
\nCommodity derivatives
135.0
\u2013
(3,393.5)
\u2013
\nForeign exchange derivatives
6.0
\u2013
(0.1)
\u2013
\nCarbon swaps
\u2013
\u2013
\u2013
\u2013
\nInterest rate derivatives
42.5
\u2013
\u2013
\u2013
\nTotal fair value
183.5
\u2013
(3,450.6)
\u2013
\nFinancial assets
Financial liabilities
\nAs at 31 December 2021 as restated
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(11.5)
\u2013
\nCommodity derivatives
2.8
\u2013
(3,508.8)
\u2013
\nForeign exchange derivatives
0.9
\u2013
(2.2)
\u2013
\nCarbon swaps
36.6
\u2013
(15.6)
\u2013
\nInterest rate derivatives
11.6
\u2013
\u2013
\u2013
\nTotal fair value
51.9
\u2013
(3,538.1)
\u2013
\n156
There were no transfers between fair value levels in the year. The movements in the year associated with \ufb01nancial assets and liabilities
\nmeasured in accordance with level 3 of the fair value hierarchy are shown below:
\nLevel 3
\nFinancial
\nassets
\nFinancial
\nliabilities
\n2022
\n$ million
\n2021
\n$ million
\n2022
\n$ million
\n2021
\n$ million
\nFair value as at 1 January
\u2013
9.7
\u2013
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
(10.2)
\u2013
(4.2)
\nGains and (losses) recognised in the income statement
\u2013
0.5
\u2013
4.2
\nFair value as at 31 December
\u2013
\u2013
\u2013
\u2013
\nFair value movements recognised in the income statement on \ufb01nancial instruments are shown below:
\n2022
\n$ million
\n2021
\n$ million
\nIncome included in the income statement
\nWarrants
\u2013
4.2
\nRemeasurement of royalty valuation
\u2013
0.5
\n\u2013
4.7
\nFair values of other \ufb01nancial instruments
\nThe following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
\n2022
2021
\nBook value
\n$ million
\nFair value
\n$ million
\nBook value
\n$ million
\nFair value
\n$ million
\nBond
(491.3)
(446.4)
(489.5)
(483.0)
\nThe 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
\nmarket yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
\nshort-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.
\nCash \ufb02ow hedge accounting
\nThe Group uses a combination of \ufb01xed price physical sales contracts and cash-settled \ufb01xed price commodity swaps and options to manage
\nthe price risk associated with its underlying oil and gas revenues. As at 31 December 2022, all of the Group\u2019s cash-settled \ufb01xed price
\ncommodity swap derivatives have been designated as cash \ufb02ow hedges of highly probable forecast sales of oil and gas.
\nThe following table indicates the volumes, average hedged price and timings associated with the Group\u2019s \ufb01nancial commodity derivatives.
\nVolumes hedged through \ufb01xed price contracts with customers for physical delivery are excluded.
\nPosition as at 31 December 2022
2023
2024
2025
2026
\nOil volume hedged (thousand bbls)
10,950
7,320
2,373
\u2013
\nWeighted average hedged price ($/bbl)
74.08
84.37
81.22
\u2013
\nGas volume hedged (million therms)
1,339
652
113
\u2013
\nWeighted average hedged price (p/therm)
41.46
68.85
75.22
\u2013
\nAs at 31 December 2022, the fair value of net \ufb01nancial commodity derivatives designated as cash \ufb02ow hedges, all executed under ISDA
\nagreements with no margining requirements, was a net payable of $3,516.7 million (2021: $3,868.2 million) and net unrealised pre-tax
\nlosses of $3,184.6 million (2021: $3,454.2 million) were deferred in other comprehensive income in respect of the effective portion of
\nthe hedge relationships.
\nAmounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur.
\nAs at 31 December 2022, net deferred pre-tax losses of $2,367.9 million (2021: $2,495.9 million) are expected to be released to the
\nincome statement within one year.
\n157
Notes to the consolidated \ufb01nancial statements
continued
\n22. Other \ufb01nancial assets and liabilities
continued
\nInterest Rate Benchmark Reform (IBOR)
\nFrom 1 January 2022, publication of most LIBOR settings ended (including Sterling LIBOR). All IBORs were replaced with alternative
\nreference rates with the exception of US LIBOR.
\nAfter 30 June 2023 US LIBOR will cease publication and will be replaced by SOFR (Secured overnight \ufb01nancing rate). The Group has
\nvariable rate RBL borrowings that currently reference US LIBOR, which are partially hedged by interest rate swaps that are also linked to
\nUS LIBOR. The RBL agreement has an automatic trigger to transition to SOFR after 30 June 2023, and a similar arrangement has been
\nagreed in principle with the interest rate swap counterparties to reduce any future impact on the \ufb01nancial statements after transition.
\nThe following table shows the \ufb01nancial instruments held by the Group as at 31 December 2022 which are referenced to US LIBOR that
\nwill transition to SOFR by 30 June 2023.
\nRBL borrowings \ufb01nancial liabilities
\nNominal value
\n$ million
\nUSD 1M LIBOR
475.0
\nUSD 6M LIBOR
300.0
\n775.0
\nDerivatives
\nInterest rate swaps USD 6M LIBOR
544.6
\nThe nominal values in the table above also represent the carrying values net of unamortised deferred fees of the RBL as at 31 December 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDerivativeFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19406": {
"value": "22. Other \ufb01nancial assets and liabilities The Group held the following \ufb01nancial instruments at fair value at 31 December 2022. The fair values of all derivative \ufb01nancial instruments
\nare based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation, which includes
\nestimates based on unobservable inputs and is level 3 in the IFRS 13 hierarchy.
\nCurrent
\n31 December 2022
31 December 2021 restated
\nAssets
\n$ million
\nLiabilities
\n$ million
\nAssets
\n$ million
\nLiabilities
\n$ million
\nMeasured at fair value through pro\ufb01t and loss
\nForeign exchange derivatives
6.0
(0.1)
0.9
(2.2)
\nInterest rate derivatives
24.3
\u2013
3.3
\u2013
\nFair value of embedded derivative within gas contract
\u2013
(57.0)
\u2013
(11.5)
\nCarbon swaps
\u2013
\u2013
36.6
(15.6)
\n30.3
(57.1)
40.8
(29.3)
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
50.5
(2,114.4)
1.0
(2,135.2)
\n50.5
(2,114.4)
1.0
(2,135.2)
\nTotal current
80.8
(2,171.5)
41.8
(2,164.5)
\nNon-current
\nMeasured at fair value through pro\ufb01t and loss
\nInterest rate derivatives
18.2
\u2013
8.3
\u2013
\n18.2
\u2013
8.3
\u2013
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
84.5
(1,279.1)
1.8
(1,373.6)
\n84.5
(1,279.1)
1.8
(1,373.6)
\nTotal non-current
102.7
(1,279.1)
10.1
(1,373.6)
\nTotal current and non-current
183.5
(3,450.6)
51.9
(3,538.1)
\nFair value measurements
\nAll \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with the
\nhierarchy described in IFRS 13 Fair Value Measurement. The hierarchy groups fair value measurements into the following levels based on
\nthe degree to which the fair value is observable.
\n\u00bc
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities.
\n\u00bc
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or indirectly.
\n\u00bc
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data.
\nAs at 31 December 2022
\nFinancial assets
Financial liabilities
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(57.0)
\u2013
\nCommodity derivatives
135.0
\u2013
(3,393.5)
\u2013
\nForeign exchange derivatives
6.0
\u2013
(0.1)
\u2013
\nCarbon swaps
\u2013
\u2013
\u2013
\u2013
\nInterest rate derivatives
42.5
\u2013
\u2013
\u2013
\nTotal fair value
183.5
\u2013
(3,450.6)
\u2013
\nFinancial assets
Financial liabilities
\nAs at 31 December 2021 as restated
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(11.5)
\u2013
\nCommodity derivatives
2.8
\u2013
(3,508.8)
\u2013
\nForeign exchange derivatives
0.9
\u2013
(2.2)
\u2013
\nCarbon swaps
36.6
\u2013
(15.6)
\u2013
\nInterest rate derivatives
11.6
\u2013
\u2013
\u2013
\nTotal fair value
51.9
\u2013
(3,538.1)
\u2013
\n156
There were no transfers between fair value levels in the year. The movements in the year associated with \ufb01nancial assets and liabilities
\nmeasured in accordance with level 3 of the fair value hierarchy are shown below:
\nLevel 3
\nFinancial
\nassets
\nFinancial
\nliabilities
\n2022
\n$ million
\n2021
\n$ million
\n2022
\n$ million
\n2021
\n$ million
\nFair value as at 1 January
\u2013
9.7
\u2013
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
(10.2)
\u2013
(4.2)
\nGains and (losses) recognised in the income statement
\u2013
0.5
\u2013
4.2
\nFair value as at 31 December
\u2013
\u2013
\u2013
\u2013
\nFair value movements recognised in the income statement on \ufb01nancial instruments are shown below:
\n2022
\n$ million
\n2021
\n$ million
\nIncome included in the income statement
\nWarrants
\u2013
4.2
\nRemeasurement of royalty valuation
\u2013
0.5
\n\u2013
4.7
\nFair values of other \ufb01nancial instruments
\nThe following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
\n2022
2021
\nBook value
\n$ million
\nFair value
\n$ million
\nBook value
\n$ million
\nFair value
\n$ million
\nBond
(491.3)
(446.4)
(489.5)
(483.0)
\nThe 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
\nmarket yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
\nshort-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.
\nCash \ufb02ow hedge accounting
\nThe Group uses a combination of \ufb01xed price physical sales contracts and cash-settled \ufb01xed price commodity swaps and options to manage
\nthe price risk associated with its underlying oil and gas revenues. As at 31 December 2022, all of the Group\u2019s cash-settled \ufb01xed price
\ncommodity swap derivatives have been designated as cash \ufb02ow hedges of highly probable forecast sales of oil and gas.
\nThe following table indicates the volumes, average hedged price and timings associated with the Group\u2019s \ufb01nancial commodity derivatives.
\nVolumes hedged through \ufb01xed price contracts with customers for physical delivery are excluded.
\nPosition as at 31 December 2022
2023
2024
2025
2026
\nOil volume hedged (thousand bbls)
10,950
7,320
2,373
\u2013
\nWeighted average hedged price ($/bbl)
74.08
84.37
81.22
\u2013
\nGas volume hedged (million therms)
1,339
652
113
\u2013
\nWeighted average hedged price (p/therm)
41.46
68.85
75.22
\u2013
\nAs at 31 December 2022, the fair value of net \ufb01nancial commodity derivatives designated as cash \ufb02ow hedges, all executed under ISDA
\nagreements with no margining requirements, was a net payable of $3,516.7 million (2021: $3,868.2 million) and net unrealised pre-tax
\nlosses of $3,184.6 million (2021: $3,454.2 million) were deferred in other comprehensive income in respect of the effective portion of
\nthe hedge relationships.
\nAmounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur.
\nAs at 31 December 2022, net deferred pre-tax losses of $2,367.9 million (2021: $2,495.9 million) are expected to be released to the
\nincome statement within one year.
\n157
Notes to the consolidated \ufb01nancial statements
continued
\n22. Other \ufb01nancial assets and liabilities
continued
\nInterest Rate Benchmark Reform (IBOR)
\nFrom 1 January 2022, publication of most LIBOR settings ended (including Sterling LIBOR). All IBORs were replaced with alternative
\nreference rates with the exception of US LIBOR.
\nAfter 30 June 2023 US LIBOR will cease publication and will be replaced by SOFR (Secured overnight \ufb01nancing rate). The Group has
\nvariable rate RBL borrowings that currently reference US LIBOR, which are partially hedged by interest rate swaps that are also linked to
\nUS LIBOR. The RBL agreement has an automatic trigger to transition to SOFR after 30 June 2023, and a similar arrangement has been
\nagreed in principle with the interest rate swap counterparties to reduce any future impact on the \ufb01nancial statements after transition.
\nThe following table shows the \ufb01nancial instruments held by the Group as at 31 December 2022 which are referenced to US LIBOR that
\nwill transition to SOFR by 30 June 2023.
\nRBL borrowings \ufb01nancial liabilities
\nNominal value
\n$ million
\nUSD 1M LIBOR
475.0
\nUSD 6M LIBOR
300.0
\n775.0
\nDerivatives
\nInterest rate swaps USD 6M LIBOR
544.6
\nThe nominal values in the table above also represent the carrying values net of unamortised deferred fees of the RBL as at 31 December 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19407": {
"value": "22. Other \ufb01nancial assets and liabilities The Group held the following \ufb01nancial instruments at fair value at 31 December 2022. The fair values of all derivative \ufb01nancial instruments
\nare based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation, which includes
\nestimates based on unobservable inputs and is level 3 in the IFRS 13 hierarchy.
\nCurrent
\n31 December 2022
31 December 2021 restated
\nAssets
\n$ million
\nLiabilities
\n$ million
\nAssets
\n$ million
\nLiabilities
\n$ million
\nMeasured at fair value through pro\ufb01t and loss
\nForeign exchange derivatives
6.0
(0.1)
0.9
(2.2)
\nInterest rate derivatives
24.3
\u2013
3.3
\u2013
\nFair value of embedded derivative within gas contract
\u2013
(57.0)
\u2013
(11.5)
\nCarbon swaps
\u2013
\u2013
36.6
(15.6)
\n30.3
(57.1)
40.8
(29.3)
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
50.5
(2,114.4)
1.0
(2,135.2)
\n50.5
(2,114.4)
1.0
(2,135.2)
\nTotal current
80.8
(2,171.5)
41.8
(2,164.5)
\nNon-current
\nMeasured at fair value through pro\ufb01t and loss
\nInterest rate derivatives
18.2
\u2013
8.3
\u2013
\n18.2
\u2013
8.3
\u2013
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
84.5
(1,279.1)
1.8
(1,373.6)
\n84.5
(1,279.1)
1.8
(1,373.6)
\nTotal non-current
102.7
(1,279.1)
10.1
(1,373.6)
\nTotal current and non-current
183.5
(3,450.6)
51.9
(3,538.1)
\nFair value measurements
\nAll \ufb01nancial instruments that are initially recognised and subsequently remeasured at fair value have been classi\ufb01ed in accordance with the
\nhierarchy described in IFRS 13 Fair Value Measurement. The hierarchy groups fair value measurements into the following levels based on
\nthe degree to which the fair value is observable.
\n\u00bc
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities.
\n\u00bc
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or indirectly.
\n\u00bc
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data.
\nAs at 31 December 2022
\nFinancial assets
Financial liabilities
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(57.0)
\u2013
\nCommodity derivatives
135.0
\u2013
(3,393.5)
\u2013
\nForeign exchange derivatives
6.0
\u2013
(0.1)
\u2013
\nCarbon swaps
\u2013
\u2013
\u2013
\u2013
\nInterest rate derivatives
42.5
\u2013
\u2013
\u2013
\nTotal fair value
183.5
\u2013
(3,450.6)
\u2013
\nFinancial assets
Financial liabilities
\nAs at 31 December 2021 as restated
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(11.5)
\u2013
\nCommodity derivatives
2.8
\u2013
(3,508.8)
\u2013
\nForeign exchange derivatives
0.9
\u2013
(2.2)
\u2013
\nCarbon swaps
36.6
\u2013
(15.6)
\u2013
\nInterest rate derivatives
11.6
\u2013
\u2013
\u2013
\nTotal fair value
51.9
\u2013
(3,538.1)
\u2013
\n156
There were no transfers between fair value levels in the year. The movements in the year associated with \ufb01nancial assets and liabilities
\nmeasured in accordance with level 3 of the fair value hierarchy are shown below:
\nLevel 3
\nFinancial
\nassets
\nFinancial
\nliabilities
\n2022
\n$ million
\n2021
\n$ million
\n2022
\n$ million
\n2021
\n$ million
\nFair value as at 1 January
\u2013
9.7
\u2013
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
(10.2)
\u2013
(4.2)
\nGains and (losses) recognised in the income statement
\u2013
0.5
\u2013
4.2
\nFair value as at 31 December
\u2013
\u2013
\u2013
\u2013
\nFair value movements recognised in the income statement on \ufb01nancial instruments are shown below:
\n2022
\n$ million
\n2021
\n$ million
\nIncome included in the income statement
\nWarrants
\u2013
4.2
\nRemeasurement of royalty valuation
\u2013
0.5
\n\u2013
4.7
\nFair values of other \ufb01nancial instruments
\nThe following \ufb01nancial instruments are measured at amortised cost and are considered to have fair values different to their book values.
\n2022
2021
\nBook value
\n$ million
\nFair value
\n$ million
\nBook value
\n$ million
\nFair value
\n$ million
\nBond
(491.3)
(446.4)
(489.5)
(483.0)
\nThe 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
\nmarket yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
\nshort-term deposits, trade receivables, trade payables and \ufb02oating rate borrowings equate approximately to their carrying amounts.
\nCash \ufb02ow hedge accounting
\nThe Group uses a combination of \ufb01xed price physical sales contracts and cash-settled \ufb01xed price commodity swaps and options to manage
\nthe price risk associated with its underlying oil and gas revenues. As at 31 December 2022, all of the Group\u2019s cash-settled \ufb01xed price
\ncommodity swap derivatives have been designated as cash \ufb02ow hedges of highly probable forecast sales of oil and gas.
\nThe following table indicates the volumes, average hedged price and timings associated with the Group\u2019s \ufb01nancial commodity derivatives.
\nVolumes hedged through \ufb01xed price contracts with customers for physical delivery are excluded.
\nPosition as at 31 December 2022
2023
2024
2025
2026
\nOil volume hedged (thousand bbls)
10,950
7,320
2,373
\u2013
\nWeighted average hedged price ($/bbl)
74.08
84.37
81.22
\u2013
\nGas volume hedged (million therms)
1,339
652
113
\u2013
\nWeighted average hedged price (p/therm)
41.46
68.85
75.22
\u2013
\nAs at 31 December 2022, the fair value of net \ufb01nancial commodity derivatives designated as cash \ufb02ow hedges, all executed under ISDA
\nagreements with no margining requirements, was a net payable of $3,516.7 million (2021: $3,868.2 million) and net unrealised pre-tax
\nlosses of $3,184.6 million (2021: $3,454.2 million) were deferred in other comprehensive income in respect of the effective portion of
\nthe hedge relationships.
\nAmounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur.
\nAs at 31 December 2022, net deferred pre-tax losses of $2,367.9 million (2021: $2,495.9 million) are expected to be released to the
\nincome statement within one year.
\n157
Notes to the consolidated \ufb01nancial statements
continued
\n22. Other \ufb01nancial assets and liabilities
continued
\nInterest Rate Benchmark Reform (IBOR)
\nFrom 1 January 2022, publication of most LIBOR settings ended (including Sterling LIBOR). All IBORs were replaced with alternative
\nreference rates with the exception of US LIBOR.
\nAfter 30 June 2023 US LIBOR will cease publication and will be replaced by SOFR (Secured overnight \ufb01nancing rate). The Group has
\nvariable rate RBL borrowings that currently reference US LIBOR, which are partially hedged by interest rate swaps that are also linked to
\nUS LIBOR. The RBL agreement has an automatic trigger to transition to SOFR after 30 June 2023, and a similar arrangement has been
\nagreed in principle with the interest rate swap counterparties to reduce any future impact on the \ufb01nancial statements after transition.
\nThe following table shows the \ufb01nancial instruments held by the Group as at 31 December 2022 which are referenced to US LIBOR that
\nwill transition to SOFR by 30 June 2023.
\nRBL borrowings \ufb01nancial liabilities
\nNominal value
\n$ million
\nUSD 1M LIBOR
475.0
\nUSD 6M LIBOR
300.0
\n775.0
\nDerivatives
\nInterest rate swaps USD 6M LIBOR
544.6
\nThe nominal values in the table above also represent the carrying values net of unamortised deferred fees of the RBL as at 31 December 2022.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialInstrumentsHeldForTradingExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19417": {
"value": "Current 31 December 2022
31 December 2021 restated
\nAssets
\n$ million
\nLiabilities
\n$ million
\nAssets
\n$ million
\nLiabilities
\n$ million
\nMeasured at fair value through pro\ufb01t and loss
\nForeign exchange derivatives
6.0
(0.1)
0.9
(2.2)
\nInterest rate derivatives
24.3
\u2013
3.3
\u2013
\nFair value of embedded derivative within gas contract
\u2013
(57.0)
\u2013
(11.5)
\nCarbon swaps
\u2013
\u2013
36.6
(15.6)
\n30.3
(57.1)
40.8
(29.3)
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
50.5
(2,114.4)
1.0
(2,135.2)
\n50.5
(2,114.4)
1.0
(2,135.2)
\nTotal current
80.8
(2,171.5)
41.8
(2,164.5)
\nNon-current
\nMeasured at fair value through pro\ufb01t and loss
\nInterest rate derivatives
18.2
\u2013
8.3
\u2013
\n18.2
\u2013
8.3
\u2013
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
84.5
(1,279.1)
1.8
(1,373.6)
\n84.5
(1,279.1)
1.8
(1,373.6)
\nTotal non-current
102.7
(1,279.1)
10.1
(1,373.6)
\nTotal current and non-current
183.5
(3,450.6)
51.9
(3,538.1)",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19418": {
"value": "Current 31 December 2022
31 December 2021 restated
\nAssets
\n$ million
\nLiabilities
\n$ million
\nAssets
\n$ million
\nLiabilities
\n$ million
\nMeasured at fair value through pro\ufb01t and loss
\nForeign exchange derivatives
6.0
(0.1)
0.9
(2.2)
\nInterest rate derivatives
24.3
\u2013
3.3
\u2013
\nFair value of embedded derivative within gas contract
\u2013
(57.0)
\u2013
(11.5)
\nCarbon swaps
\u2013
\u2013
36.6
(15.6)
\n30.3
(57.1)
40.8
(29.3)
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
50.5
(2,114.4)
1.0
(2,135.2)
\n50.5
(2,114.4)
1.0
(2,135.2)
\nTotal current
80.8
(2,171.5)
41.8
(2,164.5)
\nNon-current
\nMeasured at fair value through pro\ufb01t and loss
\nInterest rate derivatives
18.2
\u2013
8.3
\u2013
\n18.2
\u2013
8.3
\u2013
\nMeasured at fair value through other comprehensive income
\nCommodity derivatives
84.5
(1,279.1)
1.8
(1,373.6)
\n84.5
(1,279.1)
1.8
(1,373.6)
\nTotal non-current
102.7
(1,279.1)
10.1
(1,373.6)
\nTotal current and non-current
183.5
(3,450.6)
51.9
(3,538.1)",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialInstrumentsDesignatedAtFairValueThroughProfitOrLossExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19505": {
"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
\nhierarchy described in IFRS 13 Fair Value Measurement. The hierarchy groups fair value measurements into the following levels based on
\nthe degree to which the fair value is observable.
\n\u00bc
Level 1:
fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities.
\n\u00bc
Level 2:
fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or indirectly.
\n\u00bc
Level 3:
fair value measurements are derived from valuation techniques that include signi\ufb01cant inputs not based on observable data.
\nAs at 31 December 2022
\nFinancial assets
Financial liabilities
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(57.0)
\u2013
\nCommodity derivatives
135.0
\u2013
(3,393.5)
\u2013
\nForeign exchange derivatives
6.0
\u2013
(0.1)
\u2013
\nCarbon swaps
\u2013
\u2013
\u2013
\u2013
\nInterest rate derivatives
42.5
\u2013
\u2013
\u2013
\nTotal fair value
183.5
\u2013
(3,450.6)
\u2013
\nFinancial assets
Financial liabilities
\nAs at 31 December 2021 as restated
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nLevel 2
\n$ million
\nLevel 3
\n$ million
\nFair value of embedded derivative within gas contract
\u2013
\u2013
(11.5)
\u2013
\nCommodity derivatives
2.8
\u2013
(3,508.8)
\u2013
\nForeign exchange derivatives
0.9
\u2013
(2.2)
\u2013
\nCarbon swaps
36.6
\u2013
(15.6)
\u2013
\nInterest rate derivatives
11.6
\u2013
\u2013
\u2013
\nTotal fair value
51.9
\u2013
(3,538.1)
\u2013
\n156
There were no transfers between fair value levels in the year. The movements in the year associated with \ufb01nancial assets and liabilities
\nmeasured in accordance with level 3 of the fair value hierarchy are shown below:
\nLevel 3
\nFinancial
\nassets
\nFinancial
\nliabilities
\n2022
\n$ million
\n2021
\n$ million
\n2022
\n$ million
\n2021
\n$ million
\nFair value as at 1 January
\u2013
9.7
\u2013
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
(10.2)
\u2013
(4.2)
\nGains and (losses) recognised in the income statement
\u2013
0.5
\u2013
4.2
\nFair value as at 31 December
\u2013
\u2013
\u2013
\u2013
\nFair value movements recognised in the income statement on \ufb01nancial instruments are shown below:
\n2022
\n$ million
\n2021
\n$ million
\nIncome included in the income statement
\nWarrants
\u2013
4.2
\nRemeasurement of royalty valuation
\u2013
0.5
\n\u2013
4.7",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19674": {
"value": "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.
\n2022
2021
\nBook value
\n$ million
\nFair value
\n$ million
\nBook value
\n$ million
\nFair value
\n$ million
\nBond
(491.3)
(446.4)
(489.5)
(483.0)
\nThe 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
\nmarket yield curve at the balance sheet date. The fair values of other \ufb01nancial instruments not measured at fair value including cash and
\nshort-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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19785": {
"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,
\ntrade payables, interest bearing loans and derivative \ufb01nancial instruments. The main purpose of these \ufb01nancial instruments is to manage
\nshort-term cash \ufb02ow, price exposures and raise \ufb01nance for the Group\u2019s expenditure programme. Further information on the Group\u2019s
\n\ufb01nancial instrument risk management objectives, policies and strategies are set out in the discussion of capital management policies
\nin the Strategic Report.
\nRisk exposures and responses
\nThe Group manages its exposure to key \ufb01nancial risks in accordance with its \ufb01nancial risk management policy. The objective of the policy
\nis to support the delivery of the Group\u2019s \ufb01nancial targets while protecting future \ufb01nancial security. The main risks that could adversely
\naffect the Group\u2019s \ufb01nancial assets, liabilities or future cash \ufb02ows are market risks comprising commodity price risk, interest rate risk and
\nforeign currency risk, liquidity risk, and credit risk. Management reviews and agrees policies for managing each of these risks which are
\nsummarised in this note.
\nThe Group\u2019s management oversees the management of \ufb01nancial risks. The Group\u2019s senior management ensures that \ufb01nancial risk-taking
\nactivities are governed by appropriate policies and procedures and that \ufb01nancial risks are identi\ufb01ed, measured and managed in
\naccordance with Group policies and risk objectives. All derivative activities for risk management purposes are carried out by specialist
\nteams that have the appropriate skills, experience and supervision. It is the Group\u2019s policy that no trading in derivatives for speculative
\npurposes shall be undertaken.
\nMarket risk
\nMarket risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market prices.
\nMarket risk comprises three types of risk: commodity price risk, interest rate risk and foreign currency risk. Financial instruments mainly
\naffected by market risk include loans and borrowings, deposits and derivative \ufb01nancial instruments.
\nThe sensitivity analyses in the following sections relate to the position as at 31 December 2022 and 31 December 2021.
\nThe sensitivity analyses have been prepared on the basis that the number of \ufb01nancial instruments are all constant. The sensitivity
\nanalyses are intended to illustrate the sensitivity to changes in market variables on the composition of the Group\u2019s \ufb01nancial instruments
\nat the balance sheet date and show the impact on pro\ufb01t or loss and shareholders\u2019 equity, where applicable.
\n158
The following assumptions have been made in calculating the sensitivity analyses:
\n\u00bc
The sensitivity of the relevant pro\ufb01t before tax item and/or equity is the effect of the assumed changes in respective market risks
\nfor the full year based on the \ufb01nancial assets and \ufb01nancial liabilities held at the balance sheet date.
\n\u00bc
The sensitivities indicate the effect of a reasonable increase in each market variable. Unless otherwise stated, the effect of a
\ncorresponding decrease in these variables is considered approximately equal and opposite.
\n\u00bc
Fair value changes from derivative instruments designated as cash \ufb02ow hedges are considered fully effective and recorded in
\nshareholders\u2019 equity, net of tax.
\n\u00bc
Fair value changes from derivatives and other \ufb01nancial instruments not designated as cash \ufb02ow hedges are presented as a sensitivity
\nto pro\ufb01t before tax only and not included in shareholders\u2019 equity.
\nCommodity price risk
\nThe Group is exposed to the risk of \ufb02uctuations in prevailing market commodity prices on the mix of oil and gas products. On a rolling
\nbasis, 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
\n(year 1), between 30 and 60 per cent of year 2 production, from year 3 up to 50 per cent of production and from year 4 up to 40 per
\ncent of production. The Group manages these risks through the use of \ufb01xed price contracts with customers for physical delivery and
\nderivative \ufb01nancial instruments including \ufb01xed price swaps and options.
\nCommodity price sensitivity
\nThe following table summarises the impact on the Group\u2019s pre-tax pro\ufb01t and equity from a reasonably foreseeable movement in
\ncommodity prices on the fair value of commodity based derivative instruments held by the Group at the balance sheet date.
\nAs at 31 December 2022
Market movement
\nE\ufb00ect on pro\ufb01t
\nbefore tax
\n$ million
\nE\ufb00ect
\non equity
\n$ million
\nBrent oil price
$10/bbl increase
\u2013
(48.8)
\nBrent oil price
$10/bbl decrease
\u2013
48.8
\nNBP gas price
\u00a30.1/therm increase
\u2013
(48.9)
\nNBP gas price
\u00a30.1/therm decrease
\u2013
48.9
\nAs at 31 December 2021
Market movement
\nEffect on pro\ufb01t
\nbefore tax
\n$ million
\nEffect
\non equity
\n$ million
\nBrent oil price
$10/bbl increase
\u2013
(156.6)
\nBrent oil price
$10/bbl decrease
\u2013
156.6
\nNBP gas price
\u00a30.1/therm increase
\u2013
(208.9)
\nNBP gas price
\u00a30.1/therm decrease
\u2013
208.9
\nInterest rate risk
\nInterest rate risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market
\ninterest rates. The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to the Group\u2019s long-term debt
\nobligation with \ufb02oating interest rates.
\nFloating rate borrowings comprise loans under the RBL facility which incurs interest \ufb01xed either one month, three months or six months
\nin advance at USD LIBOR plus a margin of 3.21 per cent. Fixed rate borrowings at 31 December 2022 comprise a bond which incurs
\ninterest at 5.5 per cent per annum. Floating rate \ufb01nancial assets comprise cash and cash equivalents which earn interest at the relevant
\nmarket rate. The Group monitors its exposure to \ufb02uctuations in interest rates and uses interest rate derivatives to manage the \ufb01xed and
\n\ufb02oating composition of its borrowings.
\nThe interest rate \ufb01nancial instruments in place at the balance sheet date are shown below:
\nDerivative
Currency
Period of hedge
Terms
\n31 December 2022
Interest rate swaps
$544.6 million
June 20 \u2013 June 25
Average 0.55%
\n31 December 2021
Interest rate swaps
$700.0 million
June 20 \u2013 June 25
Average 0.56%
\n159
Notes to the consolidated \ufb01nancial statements
continued
\n23. Financial risk factors and risk management
continued
\nThe interest rate and currency pro\ufb01le of the Group\u2019s interest-bearing \ufb01nancial assets and liabilities are shown below:
\nAs at 31 December 2022
\nCash at bank
\n$ million
\nFixed rate
\nborrowings
\n$ million
\nFloating rate
\nborrowings
\n$ million
\nTotal
\n$ million
\nUS dollar
480.5
(491.3)
(702.3)
(713.1)
\nPound sterling
8.0
\u2013
\u2013
8.0
\nNorwegian krone
6.2
\u2013
(10.5)
(4.3)
\nOther
5.0
\u2013
\u2013
5.0
\n499.7
(491.3)
(712.8)
(704.4)
\nAs at 31 December 2021
\nCash at bank
\n$ million
\nFixed rate
\nborrowings
\n$ million
\nFloating rate
\nborrowings
\n$ million
\nTotal
\n$ million
\nUS dollar
477.9
(489.5)
(2,351.9)
(2,363.5)
\nPound sterling
201.0
\u2013
\u2013
201.0
\nNorwegian krone
14.6
\u2013
(44.6)
(30.0)
\nOther
5.2
\u2013
\u2013
5.2
\n698.7
(489.5)
(2,396.5)
(2,187.3)
\nInterest rate sensitivity
\nThe following table demonstrates the indicative pre-tax effect on pro\ufb01t and equity of applying a reasonably foreseeable increase in
\ninterest rates to the Group\u2019s \ufb01nancial assets and liabilities at the balance sheet date.
\nMarket movement
\nEffect on pro\ufb01t
\nbefore tax
\n$ million
\nEffect on equity
\n$ million
\n31 December 2022
\nUS dollar interest rates
+100 basis points
7.9
\u2013
\n31 December 2021
\nUS dollar interest rates
+100 basis points
(1.6)
\u2013
\nForeign currency risk
\nForeign currency risk is the risk that the fair value or future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in
\nforeign exchange rates.
\nThe Group is exposed to foreign currency risk primarily arising from exchange rate movements in US dollar against pound sterling.
\nTo mitigate exposure to movements in exchange rates, wherever possible \ufb01nancial assets and liabilities are held in currencies that
\nmatch the functional currency of the relevant entity. The Group has subsidiaries with functional currencies of pound sterling, US dollar,
\nNorwegian krone, Mexican pesos and Brazilian reals. Exposures can also arise from sales or purchases denominated in currencies
\nother than the functional currency of the relevant entity; such exposures are monitored and hedged with agreement from the Board.
\nThe Group enters into forward contracts as a means of hedging its exposure to foreign exchange rate risks. As at 31 December 2022,
\nthe Group had \u00a342.0 million hedged at a forward rate of between $1.18331 and $1.24045:\u00a31 for the period to January 2023, and
\n$100.0 million hedged at forward rates of between $1.17543 and $1.18131:\u00a31 for the period to January 2023.
\nAs at 31 December 2021, the Group had \u00a320.0 million hedged at a forward rate of $1.39/\u00a31 for the period to January 2022
\nand EUR18.4 million hedged at forward rates of between \u20ac 1.19 and \u20ac 1.20/\u00a31 for the period January 2022 to December 2022.
\n160
Foreign currency sensitivity
\nThe following table demonstrates the sensitivity to a reasonably foreseeable change in US dollars against pound sterling with all
\nother variables held constant, of the Group\u2019s pro\ufb01t before tax (due to foreign exchange translation of monetary assets and liabilities).
\nThe impact of translating the net assets of foreign operations into US dollars is excluded from the sensitivity analysis.
\nMarket movement
\nEffect on pro\ufb01t
\nbefore tax
\n$ million
\nEffect on equity
\n$ million
\n31 December 2022
\nUS dollar/pound sterling
10% strengthening
291.1
\u2013
\nUS dollar/pound sterling
10% weakening
(291.1)
\u2013
\n31 December 2021
\nUS dollar/pound sterling
10% strengthening
284.5
\u2013
\nUS dollar/pound sterling
10% weakening
(284.5)
\u2013
\nCredit risk
\nCredit risk is the risk that a counterparty will not meet its obligations under a \ufb01nancial instrument or customer contract, leading to
\n\ufb01nancial loss. The Group trades only with recognised, creditworthy third parties. It is the Group\u2019s policy that all customers who wish to
\ntrade on credit terms are subject to credit veri\ufb01cation procedures, which include an assessment of credit rating, short-term liquidity, and
\n\ufb01nancial position. In addition, receivables balances are monitored on an ongoing basis, with the result that the Group\u2019s exposure to bad
\ndebts is not signi\ufb01cant.
\nThe Group is exposed to credit risk from its operating activities (primarily for trade receivables) and from its \ufb01nancing activities, including
\ndeposits with banks and derivative \ufb01nancial instruments.
\nThe Group has two ratings from two credit rating agencies: S&P Global at BB and Fitch at BB.
\nThe Group only sells hydrocarbons to recognised and creditworthy parties, typically the trading arm of large, international oil and gas
\ncompanies. An indication of the concentration of credit risk on trade receivables is shown in note 4, whereby the revenue from one
\ncustomer exceeds 84 per cent of the Group\u2019s consolidated revenue.
\nThe credit risk on liquid funds and derivative \ufb01nancial instruments is limited because the counterparties are internationally recognised
\nbanking institutions and are considered to represent minimal credit risk.
\nThere are no signi\ufb01cant concentrations of credit risk within the Group unless otherwise disclosed, and credit losses are expected to be
\nnear to zero. The maximum credit risk exposure relating to \ufb01nancial assets is represented by carrying value as at the balance sheet date.
\nLiquidity risk
\nLiquidity risk is the risk that the Group will encounter dif\ufb01culty in meeting obligations associated with \ufb01nancial liabilities that are settled by
\ndelivering cash or another \ufb01nancial asset. The Group monitors the amount of borrowings maturing within any speci\ufb01c period and expects
\nto meet its \ufb01nancing commitments from the operating cash \ufb02ows of the business and existing committed lines of credit.
\nThe table below summarises the maturity pro\ufb01le of the Group\u2019s \ufb01nancial liabilities based on contractual undiscounted payments:
\nAs at 31 December 2022
\nWithin 1 year
\n$ million
\n1 to 2 years
\n$ million
\n2 to 5 years
\n$ million
\nOver 5 years
\n$ million
\nTotal
\n$ million
\nNon-derivative \ufb01nancial liabilities
\nReserves-based lending facility
60.9
61.0
881.1
\u2013
1,003.0
\nBond
27.5
27.5
555.0
\u2013
610.0
\nExploration \ufb01nance facility
11.1
\u2013
\u2013
\u2013
11.1
\nOther loans
11.0
9.0
18.0
\u2013
38.0
\nTrade and other payables
1,318.4
18.8
\u2013
\u2013
1,337.2
\nLease obligations
208.1
180.0
386.2
60.9
835.2
\nTotal non-derivative \ufb01nancial liabilities
1,637.0
296.3
1,840.3
60.9
3,834.5
\nDerivative \ufb01nancial liabilities
\nNet-settled commodity derivatives
2,308.2
930.3
154.5
\u2013
3,393.0
\nNet-settled foreign exchange derivatives
0.1
\u2013
\u2013
\u2013
0.1
\n3,945.3
1,226.6
1,994.8
60.9
7,227.6
\n161
Notes to the consolidated \ufb01nancial statements
continued
\n23. Financial risk factors and risk management
continued
\nAs at 31 December 2021 as restated
\nWithin 1 year
\n$ million
\n1 to 2 years
\n$ million
\n2 to 5 years
\n$ million
\nOver 5 years
\n$ million
\nTotal
\n$ million
\nNon-derivative \ufb01nancial liabilities
\nReserves-based lending facility
85.8
758.4
1,569.5
305.8
2,719.5
\nBond
27.3
27.5
582.5
\u2013
637.3
\nExploration \ufb01nance facility
45.8
\u2013
\u2013
\u2013
45.8
\nOther loans
17.7
12.7
20.9
3.3
54.6
\nTrade and other payables
1,264.3
32.2
\u2013
\u2013
1,296.5
\nLease obligations
181.7
127.8
309.4
97.4
716.3
\nTotal non-derivative \ufb01nancial liabilities
1,622.6
958.6
2,482.3
406.5
5,470.0
\nDerivative \ufb01nancial liabilities
\nNet-settled commodity derivatives
2,146.2
1,090.6
283.1
\u2013
3,519.9
\nNet-settled foreign exchange derivatives
2.2
\u2013
\u2013
\u2013
2.2
\nNet-settled carbon derivatives
15.6
\u2013
\u2013
\u2013
15.6
\n3,786.6
2,049.2
2,765.4
406.5
9,007.7
\nThe 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
\nstatement against future production and revenue which are not recognised on the balance sheet as assets. Interest bearing loans and
\nborrowings and trade payables mainly originate from the \ufb01nancing of assets used in the Group\u2019s ongoing operations such as property,
\nplant 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f19804": {
"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.
\nMarket risk comprises three types of risk: commodity price risk, interest rate risk and foreign currency risk. Financial instruments mainly
\naffected by market risk include loans and borrowings, deposits and derivative \ufb01nancial instruments.
\nThe sensitivity analyses in the following sections relate to the position as at 31 December 2022 and 31 December 2021.
\nThe sensitivity analyses have been prepared on the basis that the number of \ufb01nancial instruments are all constant. The sensitivity
\nanalyses are intended to illustrate the sensitivity to changes in market variables on the composition of the Group\u2019s \ufb01nancial instruments
\nat the balance sheet date and show the impact on pro\ufb01t or loss and shareholders\u2019 equity, where applicable.
\n158
The following assumptions have been made in calculating the sensitivity analyses:
\n\u00bc
The sensitivity of the relevant pro\ufb01t before tax item and/or equity is the effect of the assumed changes in respective market risks
\nfor the full year based on the \ufb01nancial assets and \ufb01nancial liabilities held at the balance sheet date.
\n\u00bc
The sensitivities indicate the effect of a reasonable increase in each market variable. Unless otherwise stated, the effect of a
\ncorresponding decrease in these variables is considered approximately equal and opposite.
\n\u00bc
Fair value changes from derivative instruments designated as cash \ufb02ow hedges are considered fully effective and recorded in
\nshareholders\u2019 equity, net of tax.
\n\u00bc
Fair value changes from derivatives and other \ufb01nancial instruments not designated as cash \ufb02ow hedges are presented as a sensitivity
\nto pro\ufb01t before tax only and not included in shareholders\u2019 equity.
\nCommodity price risk
\nThe Group is exposed to the risk of \ufb02uctuations in prevailing market commodity prices on the mix of oil and gas products. On a rolling
\nbasis, 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
\n(year 1), between 30 and 60 per cent of year 2 production, from year 3 up to 50 per cent of production and from year 4 up to 40 per
\ncent of production. The Group manages these risks through the use of \ufb01xed price contracts with customers for physical delivery and
\nderivative \ufb01nancial instruments including \ufb01xed price swaps and options.
\nCommodity price sensitivity
\nThe following table summarises the impact on the Group\u2019s pre-tax pro\ufb01t and equity from a reasonably foreseeable movement in
\ncommodity prices on the fair value of commodity based derivative instruments held by the Group at the balance sheet date.
\nAs at 31 December 2022
Market movement
\nE\ufb00ect on pro\ufb01t
\nbefore tax
\n$ million
\nE\ufb00ect
\non equity
\n$ million
\nBrent oil price
$10/bbl increase
\u2013
(48.8)
\nBrent oil price
$10/bbl decrease
\u2013
48.8
\nNBP gas price
\u00a30.1/therm increase
\u2013
(48.9)
\nNBP gas price
\u00a30.1/therm decrease
\u2013
48.9
\nAs at 31 December 2021
Market movement
\nEffect on pro\ufb01t
\nbefore tax
\n$ million
\nEffect
\non equity
\n$ million
\nBrent oil price
$10/bbl increase
\u2013
(156.6)
\nBrent oil price
$10/bbl decrease
\u2013
156.6
\nNBP gas price
\u00a30.1/therm increase
\u2013
(208.9)
\nNBP gas price
\u00a30.1/therm decrease
\u2013
208.9
\nInterest rate risk
\nInterest rate risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market
\ninterest rates. The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to the Group\u2019s long-term debt
\nobligation with \ufb02oating interest rates.
\nFloating rate borrowings comprise loans under the RBL facility which incurs interest \ufb01xed either one month, three months or six months
\nin advance at USD LIBOR plus a margin of 3.21 per cent. Fixed rate borrowings at 31 December 2022 comprise a bond which incurs
\ninterest at 5.5 per cent per annum. Floating rate \ufb01nancial assets comprise cash and cash equivalents which earn interest at the relevant
\nmarket rate. The Group monitors its exposure to \ufb02uctuations in interest rates and uses interest rate derivatives to manage the \ufb01xed and
\n\ufb02oating composition of its borrowings.
\nThe interest rate \ufb01nancial instruments in place at the balance sheet date are shown below:
\nDerivative
Currency
Period of hedge
Terms
\n31 December 2022
Interest rate swaps
$544.6 million
June 20 \u2013 June 25
Average 0.55%
\n31 December 2021
Interest rate swaps
$700.0 million
June 20 \u2013 June 25
Average 0.56%
\n159
Notes to the consolidated \ufb01nancial statements
continued
\n23. Financial risk factors and risk management
continued
\nThe interest rate and currency pro\ufb01le of the Group\u2019s interest-bearing \ufb01nancial assets and liabilities are shown below:
\nAs at 31 December 2022
\nCash at bank
\n$ million
\nFixed rate
\nborrowings
\n$ million
\nFloating rate
\nborrowings
\n$ million
\nTotal
\n$ million
\nUS dollar
480.5
(491.3)
(702.3)
(713.1)
\nPound sterling
8.0
\u2013
\u2013
8.0
\nNorwegian krone
6.2
\u2013
(10.5)
(4.3)
\nOther
5.0
\u2013
\u2013
5.0
\n499.7
(491.3)
(712.8)
(704.4)
\nAs at 31 December 2021
\nCash at bank
\n$ million
\nFixed rate
\nborrowings
\n$ million
\nFloating rate
\nborrowings
\n$ million
\nTotal
\n$ million
\nUS dollar
477.9
(489.5)
(2,351.9)
(2,363.5)
\nPound sterling
201.0
\u2013
\u2013
201.0
\nNorwegian krone
14.6
\u2013
(44.6)
(30.0)
\nOther
5.2
\u2013
\u2013
5.2
\n698.7
(489.5)
(2,396.5)
(2,187.3)",
"dimensions": {
"concept": "ifrs-full:DisclosureOfMarketRiskExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f20031": {
"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
\nforeign exchange rates.
\nThe Group is exposed to foreign currency risk primarily arising from exchange rate movements in US dollar against pound sterling.
\nTo mitigate exposure to movements in exchange rates, wherever possible \ufb01nancial assets and liabilities are held in currencies that
\nmatch the functional currency of the relevant entity. The Group has subsidiaries with functional currencies of pound sterling, US dollar,
\nNorwegian krone, Mexican pesos and Brazilian reals. Exposures can also arise from sales or purchases denominated in currencies
\nother than the functional currency of the relevant entity; such exposures are monitored and hedged with agreement from the Board.
\nThe Group enters into forward contracts as a means of hedging its exposure to foreign exchange rate risks. As at 31 December 2022,
\nthe Group had \u00a342.0 million hedged at a forward rate of between $1.18331 and $1.24045:\u00a31 for the period to January 2023, and
\n$100.0 million hedged at forward rates of between $1.17543 and $1.18131:\u00a31 for the period to January 2023.
\nAs at 31 December 2021, the Group had \u00a320.0 million hedged at a forward rate of $1.39/\u00a31 for the period to January 2022
\nand EUR18.4 million hedged at forward rates of between \u20ac 1.19 and \u20ac 1.20/\u00a31 for the period January 2022 to December 2022.
\n160
Foreign currency sensitivity
\nThe following table demonstrates the sensitivity to a reasonably foreseeable change in US dollars against pound sterling with all
\nother variables held constant, of the Group\u2019s pro\ufb01t before tax (due to foreign exchange translation of monetary assets and liabilities).
\nThe impact of translating the net assets of foreign operations into US dollars is excluded from the sensitivity analysis.
\nMarket movement
\nEffect on pro\ufb01t
\nbefore tax
\n$ million
\nEffect on equity
\n$ million
\n31 December 2022
\nUS dollar/pound sterling
10% strengthening
291.1
\u2013
\nUS dollar/pound sterling
10% weakening
(291.1)
\u2013
\n31 December 2021
\nUS dollar/pound sterling
10% strengthening
284.5
\u2013
\nUS dollar/pound sterling
10% weakening
(284.5)
\u2013",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEffectOfChangesInForeignExchangeRatesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f20089": {
"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
\n\ufb01nancial loss. The Group trades only with recognised, creditworthy third parties. It is the Group\u2019s policy that all customers who wish to
\ntrade on credit terms are subject to credit veri\ufb01cation procedures, which include an assessment of credit rating, short-term liquidity, and
\n\ufb01nancial position. In addition, receivables balances are monitored on an ongoing basis, with the result that the Group\u2019s exposure to bad
\ndebts is not signi\ufb01cant.
\nThe Group is exposed to credit risk from its operating activities (primarily for trade receivables) and from its \ufb01nancing activities, including
\ndeposits with banks and derivative \ufb01nancial instruments.
\nThe Group has two ratings from two credit rating agencies: S&P Global at BB and Fitch at BB.
\nThe Group only sells hydrocarbons to recognised and creditworthy parties, typically the trading arm of large, international oil and gas
\ncompanies. An indication of the concentration of credit risk on trade receivables is shown in note 4, whereby the revenue from one
\ncustomer exceeds 84 per cent of the Group\u2019s consolidated revenue.
\nThe credit risk on liquid funds and derivative \ufb01nancial instruments is limited because the counterparties are internationally recognised
\nbanking institutions and are considered to represent minimal credit risk.
\nThere are no signi\ufb01cant concentrations of credit risk within the Group unless otherwise disclosed, and credit losses are expected to be
\nnear 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f20108": {
"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
\ndelivering cash or another \ufb01nancial asset. The Group monitors the amount of borrowings maturing within any speci\ufb01c period and expects
\nto meet its \ufb01nancing commitments from the operating cash \ufb02ows of the business and existing committed lines of credit.
\nThe table below summarises the maturity pro\ufb01le of the Group\u2019s \ufb01nancial liabilities based on contractual undiscounted payments:
\nAs at 31 December 2022
\nWithin 1 year
\n$ million
\n1 to 2 years
\n$ million
\n2 to 5 years
\n$ million
\nOver 5 years
\n$ million
\nTotal
\n$ million
\nNon-derivative \ufb01nancial liabilities
\nReserves-based lending facility
60.9
61.0
881.1
\u2013
1,003.0
\nBond
27.5
27.5
555.0
\u2013
610.0
\nExploration \ufb01nance facility
11.1
\u2013
\u2013
\u2013
11.1
\nOther loans
11.0
9.0
18.0
\u2013
38.0
\nTrade and other payables
1,318.4
18.8
\u2013
\u2013
1,337.2
\nLease obligations
208.1
180.0
386.2
60.9
835.2
\nTotal non-derivative \ufb01nancial liabilities
1,637.0
296.3
1,840.3
60.9
3,834.5
\nDerivative \ufb01nancial liabilities
\nNet-settled commodity derivatives
2,308.2
930.3
154.5
\u2013
3,393.0
\nNet-settled foreign exchange derivatives
0.1
\u2013
\u2013
\u2013
0.1
\n3,945.3
1,226.6
1,994.8
60.9
7,227.6
\n161
Notes to the consolidated \ufb01nancial statements
continued
\n23. Financial risk factors and risk management
continued
\nAs at 31 December 2021 as restated
\nWithin 1 year
\n$ million
\n1 to 2 years
\n$ million
\n2 to 5 years
\n$ million
\nOver 5 years
\n$ million
\nTotal
\n$ million
\nNon-derivative \ufb01nancial liabilities
\nReserves-based lending facility
85.8
758.4
1,569.5
305.8
2,719.5
\nBond
27.3
27.5
582.5
\u2013
637.3
\nExploration \ufb01nance facility
45.8
\u2013
\u2013
\u2013
45.8
\nOther loans
17.7
12.7
20.9
3.3
54.6
\nTrade and other payables
1,264.3
32.2
\u2013
\u2013
1,296.5
\nLease obligations
181.7
127.8
309.4
97.4
716.3
\nTotal non-derivative \ufb01nancial liabilities
1,622.6
958.6
2,482.3
406.5
5,470.0
\nDerivative \ufb01nancial liabilities
\nNet-settled commodity derivatives
2,146.2
1,090.6
283.1
\u2013
3,519.9
\nNet-settled foreign exchange derivatives
2.2
\u2013
\u2013
\u2013
2.2
\nNet-settled carbon derivatives
15.6
\u2013
\u2013
\u2013
15.6
\n3,786.6
2,049.2
2,765.4
406.5
9,007.7
\nThe 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
\nstatement against future production and revenue which are not recognised on the balance sheet as assets. Interest bearing loans and
\nborrowings and trade payables mainly originate from the \ufb01nancing of assets used in the Group\u2019s ongoing operations such as property,
\nplant 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f20289": {
"value": "24. Share capital Issued and fully paid
Number
\n2022
\n$ million
Number
\n2021
\n$ million
\nOrdinary shares of 0.002p each
847,168,796
0
925,532,639
0
\nOrdinary non-voting deferred shares of 12.4999p each
925,532,809
171.1
925,532,809
171.1
\n171.1
171.1
\nThe rights and restrictions attached to the ordinary shares are as follows:
\n\u00bc
Dividend rights:
the rights of the holders of ordinary shares shall rank pari passu in all respects with each other in relation to dividends.
\n\u00bc
Winding up or reduction of capital:
on a return of capital on a winding up or otherwise (other than on conversion, redemption or
\npurchase of shares) the rights of the holders of ordinary shares to participate in the distribution of the assets of the company available
\nfor distribution shall rank pari passu in all respects with each other.
\n\u00bc
Voting rights:
the holders of ordinary shares shall be entitled to receive notice of, attend, vote and speak at any General Meeting of
\nthe company.
\nThe rights and restrictions attached to the non-voting deferred shares are as follows:
\n\u00bc
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
\namount paid up thereon only after holders of all ordinary shares have received, in aggregate, any amounts paid up on each ordinary
\nshare plus \u00a310 million on each ordinary share. The non-voting deferred shares will not give the holder the right to receive notice of, nor
\nattend, speak or vote at, any general meeting of the company.
\nIssue of ordinary shares
\nDuring the year, the company issued 1,024 ordinary shares at a nominal value of 0.002 pence per share in relation to the exercise of
\nequity warrants. All other outstanding warrants matured in May 2022.
\nPurchase and cancellation of own shares
\nDuring 2022, the company repurchased 78,364,867 ordinary shares for a total consideration, including transaction costs of $360.6 million,
\nas part of the share purchase programmes announced on 16 June 2022 and 3 November 2022. All shares purchased were cancelled.
\nAs of 15 February 2023, the buyback programme was completed with a further 11,093,925 million ordinary shares repurchased for
\ncancellation for a cost of $41.1 million. These shares were also cancelled.
\n162
Own shares
\n2022
\n$ million
\nAt 1 January
3.7
\nPurchase of ESOP trust shares
18.6
\nRelease of shares
(0.9)
\nAt 31 December
21.4
\nThe own shares represent the net cost of shares in Harbour Energy plc purchased in the market or issued by the company into the
\nHarbour Energy plc employee bene\ufb01t (ESOP) trust. This ESOP trust holds shares to satisfy awards under the Group\u2019s share incentive
\nplans. At 31 December 2022, the number of ordinary shares of 0.002 pence each held by the trust was 4,487,267 (2021: 775,523).",
"dimensions": {
"concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f20290": {
"value": "24. Share capital Issued and fully paid
Number
\n2022
\n$ million
Number
\n2021
\n$ million
\nOrdinary shares of 0.002p each
847,168,796
0
925,532,639
0
\nOrdinary non-voting deferred shares of 12.4999p each
925,532,809
171.1
925,532,809
171.1
\n171.1
171.1
\nThe rights and restrictions attached to the ordinary shares are as follows:
\n\u00bc
Dividend rights:
the rights of the holders of ordinary shares shall rank pari passu in all respects with each other in relation to dividends.
\n\u00bc
Winding up or reduction of capital:
on a return of capital on a winding up or otherwise (other than on conversion, redemption or
\npurchase of shares) the rights of the holders of ordinary shares to participate in the distribution of the assets of the company available
\nfor distribution shall rank pari passu in all respects with each other.
\n\u00bc
Voting rights:
the holders of ordinary shares shall be entitled to receive notice of, attend, vote and speak at any General Meeting of
\nthe company.
\nThe rights and restrictions attached to the non-voting deferred shares are as follows:
\n\u00bc
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
\namount paid up thereon only after holders of all ordinary shares have received, in aggregate, any amounts paid up on each ordinary
\nshare plus \u00a310 million on each ordinary share. The non-voting deferred shares will not give the holder the right to receive notice of, nor
\nattend, speak or vote at, any general meeting of the company.
\nIssue of ordinary shares
\nDuring the year, the company issued 1,024 ordinary shares at a nominal value of 0.002 pence per share in relation to the exercise of
\nequity warrants. All other outstanding warrants matured in May 2022.
\nPurchase and cancellation of own shares
\nDuring 2022, the company repurchased 78,364,867 ordinary shares for a total consideration, including transaction costs of $360.6 million,
\nas part of the share purchase programmes announced on 16 June 2022 and 3 November 2022. All shares purchased were cancelled.
\nAs of 15 February 2023, the buyback programme was completed with a further 11,093,925 million ordinary shares repurchased for
\ncancellation for a cost of $41.1 million. These shares were also cancelled.
\n162
Own shares
\n2022
\n$ million
\nAt 1 January
3.7
\nPurchase of ESOP trust shares
18.6
\nRelease of shares
(0.9)
\nAt 31 December
21.4
\nThe own shares represent the net cost of shares in Harbour Energy plc purchased in the market or issued by the company into the
\nHarbour Energy plc employee bene\ufb01t (ESOP) trust. This ESOP trust holds shares to satisfy awards under the Group\u2019s share incentive
\nplans. At 31 December 2022, the number of ordinary shares of 0.002 pence each held by the trust was 4,487,267 (2021: 775,523).",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f20335": {
"value": "Purchase and cancellation of own shares During 2022, the company repurchased 78,364,867 ordinary shares for a total consideration, including transaction costs of $360.6 million,
\nas part of the share purchase programmes announced on 16 June 2022 and 3 November 2022. All shares purchased were cancelled.
\nAs of 15 February 2023, the buyback programme was completed with a further 11,093,925 million ordinary shares repurchased for
\ncancellation for a cost of $41.1 million. These shares were also cancelled.
\n162
Own shares
\n2022
\n$ million
\nAt 1 January
3.7
\nPurchase of ESOP trust shares
18.6
\nRelease of shares
(0.9)
\nAt 31 December
21.4
\nThe own shares represent the net cost of shares in Harbour Energy plc purchased in the market or issued by the company into the
\nHarbour Energy plc employee bene\ufb01t (ESOP) trust. This ESOP trust holds shares to satisfy awards under the Group\u2019s share incentive
\nplans. At 31 December 2022, the number of ordinary shares of 0.002 pence each held by the trust was 4,487,267 (2021: 775,523).",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f20383": {
"value": "25. Share-based payments The company currently operates a Long Term Incentive Plan (LTIP) for certain employees, a Share Incentive Plan (SIP) and a Save As You
\nEarn (SAYE) scheme for UK-based and expatriate employees only.
\nFor the year ended 31 December 2022, the total cost recognised by the company for share-based payment transactions was
\n$36.9 million (2021: $13.4 million). A credit of $36.9 million (2021: $13.4 million) has been recorded in retained earnings for all
\nequity-settled payments of the company.
\nLike other elements of remuneration, this charge is processed through the time-writing system which allocates cost, based on time spent
\nby individuals, to various entities within the Group. Part of this cost is therefore recharged to the relevant subsidiary undertakings, part is
\ncapitalised as directly attributable to capital projects and part is charged to the income statement as operating costs, pre-licence
\nexploration costs or general and administration costs.
\nDetails of the various share incentive plans currently in operation are set out below:
\n2017 Long Term Incentive Plan (2017 LTIP)
\nDiscretionary share awards are granted to employees under the company\u2019s Long Term Incentive Plan (LTIP).
\nThe following types of award have been granted under the 2017 LTIP:
\n\u00bc
Performance share awards (PSA):
vesting is subject to a Performance Target, normally measured over a three-year period from
\n1 January based on Total Shareholder Return (TSR) relative to (i) FTSE 100 index, and (ii) a bespoke peer group of oil and gas companies
\nand aligns to longer-term strategic objectives.
\n\u00bc
Conditional share awards (CSAs):
vesting is only subject to continued employment.
\n\u00bc
Deferred bonus share plan (DBSP) awards:
certain employees are required to defer a portion of their annual bonus into shares which
\nvest over a three-year period subject to continued employment.
\n\u00bc
Restricted share awards (RSA):
legacy Premier Oil awards which were aligned to the primary objective of balance sheet recovery.
\nThe remainder of these lapsed in 2022.
\n\u00bc
Premier value share plan (PVSP) awards:
legacy Premier Oil awards which were made up of two awards, Base Awards and Multiplier
\nAwards. Under the PVSP, annual awards of time-vesting restricted shares (Base Awards) and three-year performance-vesting shares
\n(Performance Multiplier Awards) were made, with performance-vesting shares subject to achievements of Premier\u2019s delivery of long-term
\nshareholder return.
\nAll LTIP awards are granted in the form of nil-cost options or conditional share awards and therefore there is no exercise price payable
\non the exercise of these awards.
\nAll RSA awards lapsed during the year. The \ufb01nal outstanding PVSP Base Awards vested in the year, the remainder lapsed.
\n163
Notes to the consolidated \ufb01nancial statements
continued
\n25. Share-based payments
continued
\nFor further details of the LTIP awards, including the performance conditions of the PSAs granted in 2022, please refer to the Directors\u2019
\nremuneration report (pages 78-99).
\nThe following table shows the movement in the number of LTIP awards:
\n2022
\n(million shares)
\n2021
\n(million shares)
\nOutstanding at 1 January
20.5
\u2013
\nAdditions from business combinations and joint arrangements
\n1
\n\u2013
31.2
\nGranted pre-share consolidation
\u2013
23.1
\nVested pre-share consolidation
\u2013
(0.6)
\nForfeited pre-share consolidation
\u2013
(0.8)
\n20 to 1 share consolidation
\u2013
(50.3)
\nGranted (post-share consolidation)
\n2
\n10.3
18.0
\nVested (post-share consolidation)
\n2
\n(1.6)
\u2013
\nForfeited (post-share consolidation)
\n2
\n(1.4)
(0.1)
\nOutstanding at 31 December
\n3
\n27.8
20.5
\n1 Includes DBSP awards.
\n2
Post-share consolidation refers to movements in 2021 as a result of the merger.
\n3
This includes 1.6 million cash settled awards at 31 December 2022 (2021: 0.2 million), which are revalued using the year-end share price.
\nLTIP awards totalling 1.6 million shares were vested during the period. The weighted average remaining contractual life of the LTIP awards
\nat 31 December 2022 was 1.5 years (2021: 2.0 years).
\nKey assumptions used to calculate the fair value of awards
\nThe fair value of awards which are subject to TSR conditions, under the PSAs, is determined using a Monte Carlo simulation. The fair value of
\nall other awards is calculated using the share price at the date of grant, adjusted for dividends not received during the vesting period.
\nThe following table lists the inputs to the model used in respect of the PSA awards granted during the \ufb01nancial year:
\n2022
2021
\nShare price at date of grant
\u00a35.00 \u2013 \u00a35.19
\u00a33.60 \u2013 \u00a33.77
\nDividend yield
0%
0%
\nExpected term
3.0 years
1.5 years \u2013 3.0 years
\nRisk free rate
1.4% \u2013 1.6%
0.1% \u2013 0.5%
\nShare price volatility of the company
50.5% \u2013 51.3%
70%
\nThe weighted average fair value of the PSA awards granted in 2022 was $4.02 (2021: $1.57).
\nExpected volatility was determined by reference to both the historical volatility of the company and the historical volatility of a group
\nof comparable quoted companies over a period in line with the expected term assumption.
\nShare Incentive Plan (SIP)
\nUnder the Share Incentive Plan employees are invited to make contributions to buy partnership shares. If an employee agrees to buy
\npartnership shares the company currently matches the number of partnership shares bought with an award of shares (matching shares),
\non a one-for-one basis. 0.4 million matching shares were awarded to employees in 2022 (2021: 0.06 million). The SIP matching shares
\nare valued based on the quoted share price on the grant date.
\n164
Save As You Earn (SAYE) scheme
\nUnder the SAYE scheme, eligible employees with one month or more continuous service can join the scheme. Employees can save to a
\nmaximum of \u00a3500 per month through payroll deductions for a period of three years after which time they can acquire shares at up to a
\n20 per cent discount. 1.6 million SAYE options were granted in 2022 (2021: nil).
\nThe following table shows the movement in the number of SAYE options:
\n2022
2021
\nNumber
\n(million)
\nWeighted
\naverage
\nexercise price
\nNumber
\n(million)
\nWeighted
\naverage
\nexercise price
\nOutstanding at 1 January
0.4
\u00a35.78
\u2013
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
\u2013
10.3
\u00a35.82
\n20 to 1 share consolidation
\u2013
\u2013
(9.8)
\u2013
\nGranted during the year
1.6
\u00a34.12
\u2013
\u2013
\nLapsed during the year
(0.3)
\u00a35.36
(0.1)
\u00a36.01
\nExercised during the year
\u2013
\u2013
\u2013
\u2013
\nOutstanding as at 31 December
1.7
\u00a34.18
0.4
\u00a35.78
\nThe SAYE options outstanding at 31 December 2022 had exercise prices ranging from \u00a34.12 to \u00a35.53 (2021: \u00a35.53 to \u00a320.09) and a
\nweighted average remaining contractual life of 2.8 years (2021: 1.9 years).",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f20585": {
"value": "26. Group pension schemes Balance sheet
\n2022
\n$ million
\n2021
\n$ million
\nUK funded pension scheme
0.2
0.8
\nTotal surplus in balance sheet
0.2
0.8
\nUK unfunded pension scheme
0.5
0.7
\nTotal liability in balance sheet
0.5
0.7
\nUnfunded pensions
\nThe Group is paying an unfunded pension to a former director in the UK in regard to which annual increases and a reversionary spouse\u2019s
\npension apply on the same basis as pensions paid under the Scheme.
\nOn the same actuarial basis as used to assess the Scheme\u2019s pension costs, the present value as at 31 December 2022 of the future
\npayments projected to be made in respect of UK unfunded pensions is $0.5 million (2021: $0.7 million).
\nFunded pensions
\nThe Group operates a \ufb01nal salary de\ufb01ned bene\ufb01t pension plan in the UK (the Scheme). The Scheme is an HMRC registered pension plan
\nand is subject to standard UK pensions and tax law. Details on the bene\ufb01ts provided by the Scheme are set out in the Trust Deed and
\nRules dated 16 October 2008 (as amended).
\nThe disclosures in these accounts below are based on calculations carried out at the balance sheet date by a quali\ufb01ed independent actuary.
\nThe Scheme\u2019s assets are held in a separate trustee-administered fund to meet long-term pension liabilities to bene\ufb01ciaries. The Trustee of the
\nScheme is required to act in the best interest of the bene\ufb01ciaries. The appointment of trustee directors is determined by the trust documentation.
\nThe Trustee of the Scheme invests assets in line with the Statement on Investment Principles. The Statement on Investment Principles
\nhas been established taking into consideration the liabilities of the Scheme and the investment risk that the Trustee is willing to accept.
\nUnder the Scheme funding regime introduced by the Pension Act 2004, the Trustee is required to carry out regular actuarial valuations of the
\nScheme, establish a schedule of contributions and, when there is a shortfall, a recovery plan. Scheme funding valuations are carried out at
\nleast three years. Approximate funding updated are produced annually in years where a full scheme funding valuation is not completed.
\n165
Notes to the consolidated \ufb01nancial statements
continued
\n26. Group pension schemes
continued
\nAs at the balance sheet date, contributions are payable to the Scheme at the rates speci\ufb01ed in the schedule of contributions signed by
\nthe Trustee on 23 March 2021.
\nThe de\ufb01ned bene\ufb01t pension plan exposes the employer to actuarial risks, such as longevity risk, interest rate risk, salary risk, investment
\nmarket risk and currency risk.
\nPrincipal assumptions
\nAt 31 December
\n2022
\nAt 31 December
\n2021
\nDiscount rate
4.9% p.a.
1.8% p.a.
\nRPI in\ufb02ation
3.2% p.a.
3.4% p.a.
\nCPI in\ufb02ation
2.3% p.a.
2.4% p.a.
\nRate of increase in salaries
3.2% p.a.
3.4% p.a.
\nRate of increase in pensions in payment: LPI (max 5%)
3.1% p.a.
3.3% p.a.
\nMortality
S3PxA Light CMI_2021 with 0.5%
\np.a. IAMI and 1.25% p.a. long term
\nS3PxA Light CMI_2020 with 0.5%
\np.a IAMI and 1.25% p.a. long term
\nProportion married
80%
80%
\nWithdrawals
No allowance
No allowance
\nCash commutation
75% of maximum tax-free cash on
\nterms currently available
\n75% of maximum tax-free cash on
\nterms currently available
\nLife expectancy of male aged 65 now
23.6
23.6
\nLife expectancy of male aged 65 in 20 years
24.8
24.8
\nLife expectancy of female aged 65 now
25.2
25.1
\nLife expectancy of female aged 65 in 20 years
26.5
26.5
\nAsset breakdown
\nThe major categories of the Scheme assets as a percentage of total Scheme assets are:
\n2022
2021
\nEquities
12.0%
41.2%
\nGilts
51.7%
29.3%
\nCorporate bonds
13.1%
29.1%
\nCash
23.2%
0.4%
\nTotal
100.0%
100.0%
\nReconciliation of funded status and amount recognised in balance sheet
\n2022
\n$ million
\n2021
\n$ million
\nFair value of the Scheme assets
(36.6)
(55.4)
\nPresent value of de\ufb01ned bene\ufb01t obligation
23.5
39.4
\nSurplus
(13.1)
(16.0)
\nUnrecognised amount due to effect of IFRIC 14
\n1
\n12.9
15.2
\nDe\ufb01ned bene\ufb01t asset recognised in balance sheet
(0.2)
(0.8)
\n1
The trustees have certain rights to grant bene\ufb01t increases to members and accordingly it has been concluded the Group does not have an unconditional right to the surplus by way of a refund.
\nStatement of amount recognised in the income statement
\n2022
\n$ million
\n2021
\n$ million
\nCurrent service cost
0.1
0.1
\nNet interest on the net de\ufb01ned bene\ufb01t liability (asset)
\u2013
\u2013
\nTotal
0.1
0.1
\n166
Reconciliation of de\ufb01ned bene\ufb01t obligation
\n2022
\n$ million
\n2021
\n$ million
\nOpening present value of de\ufb01ned bene\ufb01t obligation
39.4
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
41.5
\nCurrent service cost
0.1
0.1
\nInterest cost
0.6
0.5
\nActuarial (gains)/losses from changes in demographic assumptions
0.4
\u2013
\nActuarial (gains)/losses from changes in \ufb01nancial assumptions
(13.3)
(1.7)
\nChanges due to experience adjustments
1.5
0.4
\nBene\ufb01ts paid
(1.2)
(1.1)
\nCurrency translation effects
(4.0)
(0.3)
\nClosing de\ufb01ned bene\ufb01t obligation
23.5
39.4
\nReconciliation of fair value of assets
\n2022
\n$ million
\n2021
\n$ million
\nOpening present value of Scheme assets
55.4
\u2013
\nAdditions from business combinations and joint arrangements
\u2013
53.4
\nInterest income
0.9
0.6
\nReturn on assets less interest income
(12.9)
2.9
\nContributions by employer
\u2013
\u2013
\nBene\ufb01ts paid
(1.2)
(1.1)
\nCurrency translation effects
(5.6)
(0.4)
\nClosing fair value of Scheme assets
36.6
55.4
\nActual return on Scheme assets
(12.0)
3.5
\nStatement of amount recognised in comprehensive income
\n2022
\n$ million
\n2021
\n$ million
\n(Gain)/loss from changes in the \ufb01nancial assumptions for value of Scheme liabilities
(13.3)
(1.7)
\n(Gain)/loss from changes in the demographic assumptions for value of Scheme liabilities
0.4
\u2013
\nChanges due to experience adjustments
1.5
0.4
\nReturn on assets (excluding amounts included in net interest on the net de\ufb01ned bene\ufb01t liability (asset))
12.9
(2.9)
\nChange in the effect of the asset ceiling excluding amounts included in net interest on the net de\ufb01ned liability
(2.6)
4.2
\nCurrency translation effects
1.6
0.1
\nOther comprehensive income
0.5
0.1
\nStatement of amount recognised in pro\ufb01t and loss and other comprehensive income
\n2022
\n$ million
\n2021
\n$ million
\nAmount recognised in pro\ufb01t and loss
0.1
0.1
\nOther comprehensive income
0.5
0.1
\nTotal comprehensive loss
0.6
0.2
\nSensitivity of balance sheet at 31 December 2022
\nThe results of the calculations are sensitive to the assumptions used. The balance sheet position revealed by IAS 19 Employee Bene\ufb01ts
\ncalculations must be expected to be volatile, principally because the market value of assets (with signi\ufb01cant exposure to equities) is
\nbeing compared with a liability assessment derived from corporate bond yields.
\nThe table overleaf shows the sensitivity of the IAS 19 balance sheet position to small changes in some of the signi\ufb01cant assumptions,
\nas at 31 December 2022. The sensitivity analyses are based on a change in a signi\ufb01cant assumption, keeping all other assumptions
\nconstant. The sensitivity analyses may not be representative of an actual change in the de\ufb01ned bene\ufb01t obligation as it is unlikely that the
\nchanges in assumptions would occur in isolation from one another.
\n167
Notes to the consolidated \ufb01nancial statements
continued
\n26. Group pension schemes
continued
\nRevised (surplus)/de\ufb01cit
\n$ million
\nChange from disclosed
\n(surplus)/de\ufb01cit
\n$ million
\nDiscount rate less 0.1% p.a.
(12.8)
0.3
\nRPI in\ufb02ation and linked assumptions plus 0.1% p.a.
(12.8)
0.3
\nMembers living one year longer than assumed
(12.3)
0.8
\nProjected components of pension costs for period to 31 December 2023
\nBecause of the signi\ufb01cant volatility in investment markets, it is dif\ufb01cult to project forward the IAS 19 \ufb01gures for the next year with
\ncon\ufb01dence. The following projections should therefore be treated with caution.
\nAssumptions implicit in the following projections are:
\n\u00bc
The interest on the de\ufb01ned bene\ufb01t liability/(asset) from 31 December 2022 is 4.9 per cent p.a.
\n\u00bc
Contributions to the Scheme will continue throughout 2023 in accordance with the current Schedule of Contributions in place at the
\ndate of signing this report.
\n\u00bc
There will be no changes to the terms of the Scheme.
\nThe amounts recognised in the components of pension expense were nil for the year.
\nDe\ufb01ned contribution schemes
\nThe 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
\nmake 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
\nof $30.3 million (2021: $28.2 million) represents contributions payable to these schemes by the Group at rates speci\ufb01ed in the rules of the schemes.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f20920": {
"value": "27. Notes to the statement of cash \ufb02ows Net cash \ufb02ows from operating activities consist of:
\n2022
\n$ million
\n2021
\n$ million
\nPro\ufb01t before taxation
2,461.8
314.5
\nAdjustments to reconcile pro\ufb01t before tax to net cash \ufb02ows:
\n\u2013 Finance cost, excluding foreign exchange
358.2
309.4
\n\u2013 Finance income, excluding foreign exchange
(77.1)
(48.8)
\n\u2013 Depreciation, depletion and amortisation
1,545.8
1,371.0
\n\u2013 Fair value movement in unrealised carbon swaps
2.6
\u2013
\n\u2013 Net impairment of property, plant and equipment
(169.6)
117.2
\n\u2013 Taxes paid
(551.5)
(279.8)
\n\u2013 Share-based payments
16.5
8.4
\n\u2013 Decommissioning payments
(217.0)
(244.8)
\n\u2013 Onerous contract provision
\u2013
(2.3)
\n\u2013 Exploration costs written-off
64.4
255.0
\n\u2013 Write-off of non-oil and gas assets
\u2013
4.7
\n\u2013 Pre-merger costs
\u2013
7.0
\n\u2013 Onerous contract payments
(2.3)
(9.2)
\n\u2013 Increase in royalty consideration receivable
\u2013
(0.5)
\n\u2013 (Gain)/loss on termination of IFRS 16 lease
(0.2)
0.3
\n\u2013 (Gain)/loss on disposal
(12.1)
0.1
\n\u2013 Movement in realised cash \ufb02ow hedges not yet settled
(104.3)
361.6
\n\u2013 Unrealised foreign exchange (gain)/loss
(237.9)
57.3
\nWorking capital adjustments:
\n\u2013 Decrease/(increase) in inventories
65.0
(13.0)
\n\u2013 Increase in trade and other receivables
(75.7)
(607.4)
\n\u2013 Increase in trade and other payables
63.2
13.5
\nNet cash in\ufb02ow from operating activities
3,129.8
1,614.2
\n168
Reconciliation of net cash \ufb02ow to movement in net borrowings
\n2022
\n$ million
\n2021
\n$ million
\nProceeds from drawdown of borrowing facilities
\u2013
(1,617.5)
\nProceeds from issue of bond
\u2013
(500.0)
\nShort-term debt arising on business combination
\u2013
2,219.3
\nRepayment of debt \u2013 equity allocation to borrowings
\u2013
(942.8)
\nRepayment of debt \u2013 cash allocation to borrowings
\u2013
(1,276.5)
\nConversion of D loan notes to equity
\u2013
134.7
\nProceeds from EFF loan
(11.5)
(45.9)
\nRepayment of RBL facility
1,662.5
697.5
\nRepayment of junior debt
\u2013
400.0
\nLoan notes redemption
\u2013
135.7
\nIFRS 9 modi\ufb01cation gain
\u2013
13.9
\nRepayment of EFF loan
38.6
14.7
\nRepayment of \ufb01nancing arrangement
15.4
9.3
\nArrangement fees and related costs capitalised
\u2013
88.5
\nFinancing arrangement interest payable
(9.5)
(11.6)
\nAmortisation of arrangement fees and related costs capitalised
(54.9)
(38.9)
\nCurrency translation adjustment on EFF loan
7.3
0.6
\nLoan notes interest capitalised
\u2013
(5.6)
\nMovement in total borrowings
1,647.9
(724.6)
\nMovement in cash and cash equivalents
(199.0)
253.3
\nDecrease/(increase) in net borrowings in the year
1,448.9
(471.3)
\nOpening net borrowings
(2,187.3)
(1,716.0)
\nClosing net borrowings
(738.4)
(2,187.3)
\nAnalysis of net borrowings
\n2022
\n$ million
\n2021
\n$ million
\nCash and cash equivalents
499.7
698.7
\nRBL facility
(702.3)
(2,312.0)
\nBond
(491.3)
(489.5)
\nEFF loan
(10.5)
(44.6)
\nNet debt
(704.4)
(2,147.4)
\nFinancing arrangement
(34.0)
(39.9)
\nClosing net borrowings
(738.4)
(2,187.3) ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCashFlowStatementExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f21112": {
"value": "28. Related party disclosures Transactions between the company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not
\ndisclosed in this note.
\nIn late 2021, the company agreed a secondment agreement with EIG to second two employees, familiar with Harbour\u2019s business and
\nassets, to provide additional support and expertise for Harbour for an initial period of six months from 1 December 2021. The
\nsecondment agreement provided that the secondees would work for Harbour on a substantially full-time basis which could be terminated
\nor extended with the agreement of the parties. In May 2022, the company and EIG agreed to terminate the agreement for one secondee
\nand to extend the second for a further period which was subsequently terminated before the end of the year.
\nHarbour Energy\u2019s Viking CCS (formerly V Net Zero), the CO
\n2
\ncapture, transport and storage network, entered into an arrangement with
\nWest Burton Energy, the independent power generation company based in Nottinghamshire which is a subsidiary of EIG, Harbour\u2019s
\nlargest shareholder. The intention is to capture, transport and permanently store CO
\n2
\nemissions from the West Burton B power station.
\nHarbour Energy and West Burton Energy have recently begun the necessary engineering design to connect West Burton B to the
\nhigh-capacity Viking CCS storage sites located deep beneath the Southern North Sea.
\n169
Notes to the consolidated \ufb01nancial statements
continued
\n28. Related party disclosures
continued
\nCompensation of key management personnel of the Group
\nThe remuneration of directors during the year is set out in the directors\u2019 remuneration report (pages 78 to 99).
\nRemuneration of key management personnel, including directors of the Group, is shown below:
\n2022
\n$ million
\n2021
\n1
\n$ million
\nSalaries and short-term employee bene\ufb01ts
14.6
18.6
\nPayments made in lieu of pension contributions
0.8
0.7
\nTermination bene\ufb01ts
0.4
\u2013
\nPension bene\ufb01ts
\u2013
\u2013
\n15.8
19.3
\n1
2021 data includes remuneration of key management personnel for the Chrysaor Holdings Group in the three months to 31 March 2021.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f21147": {
"value": "Compensation of key management personnel of the Group The remuneration of directors during the year is set out in the directors\u2019 remuneration report (pages 78 to 99).
\nRemuneration of key management personnel, including directors of the Group, is shown below:
\n2022
\n$ million
\n2021
\n1
\n$ million
\nSalaries and short-term employee bene\ufb01ts
14.6
18.6
\nPayments made in lieu of pension contributions
0.8
0.7
\nTermination bene\ufb01ts
0.4
\u2013
\nPension bene\ufb01ts
\u2013
\u2013
\n15.8
19.3
\n1
2021 data includes remuneration of key management personnel for the Chrysaor Holdings Group in the three months to 31 March 2021.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f21175": {
"value": "29. Distributions made and proposed A \ufb01nal dividend of 11 cents per ordinary share in relation to the year ended 31 December 2021 was paid on 18 May 2022 pursuant
\nto shareholder approval received on 11 May 2022. Pursuant to shareholder approval received on 11 May 2022 an interim dividend of
\n11 cents per ordinary share in relation to the half year ended 30 June 2022 was paid on 19 October 2022.
\n2022
\n$ million
\n2021
\n$ million
\nCash dividends on ordinary shares declared and paid:
\nFinal dividend for 2021: 11 cents per share (2020: no dividend)
98.3
\u2013
\nInterim dividend for 2022: 11 cents per share
93.2
\u2013
\n191.5
\u2013
\nProposed dividends on ordinary shares:
\nFinal dividend for 2022: 12 cents per share (2021: 11 cents per share)
100.0
100.0
\nProposed 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f21186": {
"value": "0.11",
"decimals": 2,
"dimensions": {
"concept": "ifrs-full:DividendsRecognisedAsDistributionsToOwnersPerShare",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2021-01-01T00:00:00/2022-01-01T00:00:00",
"unit": "iso4217:USD/xbrli:shares"
}
},
"f21190": {
"value": "0.11",
"decimals": 2,
"dimensions": {
"concept": "ifrs-full:DividendsRecognisedAsDistributionsToOwnersPerShare",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00",
"unit": "iso4217:USD/xbrli:shares"
}
},
"f21197": {
"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"
}
},
"f21198": {
"value": "0.11",
"decimals": 2,
"dimensions": {
"concept": "ifrs-full:DividendsProposedOrDeclaredBeforeFinancialStatementsAuthorisedForIssueButNotRecognisedAsDistributionToOwnersPerShare",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2021-01-01T00:00:00/2022-01-01T00:00:00",
"unit": "iso4217:USD/xbrli:shares"
}
},
"f21200": {
"value": "100000000",
"decimals": -5,
"dimensions": {
"concept": "ifrs-full:DividendsProposedOrDeclaredBeforeFinancialStatementsAuthorisedForIssueButNotRecognisedAsDistributionToOwners",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00",
"unit": "iso4217:USD"
}
},
"f21202": {
"value": "100000000",
"decimals": -5,
"dimensions": {
"concept": "ifrs-full:DividendsProposedOrDeclaredBeforeFinancialStatementsAuthorisedForIssueButNotRecognisedAsDistributionToOwners",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2021-01-01T00:00:00/2022-01-01T00:00:00",
"unit": "iso4217:USD"
}
},
"f21206": {
"value": "30. Events after the reporting period On 14 February 2023, the Scheme\u2019s trustee effected a bulk annuity buy in policy with Just Retirement Limited. This policy secures the
\nbene\ufb01ts of all the Scheme\u2019s members and eliminates mortality and investment risk from the company\u2019s balance sheet. This decision was
\nmade principally in light of the substantial improvement to the Scheme\u2019s funded status over 2022 and the favourable market conditions
\nfor such transactions. The company was not required to pay any additional contributions to the Scheme in respect of the annuity purchase.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f21214": {
"value": "31. Investments At 31 December 2022, the subsidiary undertakings of the company which were all wholly owned were:
\nName of company
Area of operation
Country of incorporation
Main activity
\nChrysaor (U.K.) Alpha Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor (U.K.) Beta Limited
UK
UK
\n2
\nDecommissioning activities
\nChrysaor (U.K.) Delta Limited
UK
UK
\n2
\nNon-trading intermediate holding company
\nChrysaor (U.K.) Sigma Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor (U.K.) Theta Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor (U.K.) Zeta Limited
UK
UK
\n2
\nNon-trading intermediate holding company
\nChrysaor CNS Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Developments Limited
UK
UK
\n2
\nDecommissioning activities
\nChrysaor E&P Finance Limited
UK
UK
\n2
\nFinancing company
\nChrysaor E&P Limited
UK
UK
\n2
\nIntermediate holding company
\nHarbour Energy Services Limited
\n(formerly Chrysaor E&P Services Limited)
UK
UK
\n2
\nService company
\nChrysaor Holdings Limited
\n1
\nUK
Cayman Islands
\n13
\nIntermediate holding company
\n170
Name of company
Area of operation
Country of incorporation
Main activity
\nChrysaor Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Marketing Limited
UK
UK
\n2
\nGas trading
\nHarbour Energy Norge AS
\n(formerly Chrysaor Norge AS)
Norway
Norway
\n3
\nExploration, production, and development
\nChrysaor North Sea Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Petroleum Company U.K. Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Petroleum Limited
UK
UK
\n2
\nDecommissioning activities
\nChrysaor Production (U.K.) Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Production Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nChrysaor Production Limited
UK
UK
\n2
\nIntermediate holding company
\nChrysaor Resources (Irish Sea) Limited
UK
UK
\n2
\nExploration, production, and development
\nChrysaor Resources (UK) Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nEbury Gate Limited
Guernsey
Guernsey
\n11
\nRisk mitigation services
\nEnCore (NNS) Limited
UK
UK
\n2
\nIntermediate holding company
\nEnCore Oil Limited
UK
UK
\n2
\nIntermediate holding company
\nFP Mauritania A BV
Mauritania
Netherlands
\n7
\nDecommissioning activities
\nFP Mauritania B BV
Mauritania
Netherlands
\n7
\nDecommissioning activities
\nPremier Oil (EnCore Petroleum) Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil (Vietnam) Limited
Vietnam
British Virgin Islands
\n8
\nExploration, production, and development
\nPremier Oil Aberdeen Services Limited
UK
UK
\n2
\nService company
\nPremier Oil and Gas Services Limited
UK
UK
\n2
\nService company
\nPremier Oil Andaman I Limited
Indonesia
UK
\n2
\nExploration, production, and development
\nPremier Oil Andaman Limited
Indonesia
UK
\n2
\nExploration, production, and development
\nPremier Oil ANS Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil ANS Limited
Alaska
UK
\n2
\nExploration, production, and development
\nPremier Oil Barakuda Limited
Indonesia
UK
\n2
\nExploration, production and development
\nPremier Oil do Brasil Petroleo e Gas Ltda
Brazil
Brazil
\n9
\nExploration, production, and development
\nPremier Oil E&P Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil E&P UK Energy Trading Limited
UK
UK
\n2
\nGas trading
\nPremier Oil E&P UK EU Limited
UK
UK
\n2
\nExploration, production, and development
\nPremier Oil E&P UK Limited
UK
UK
\n2
\nExploration, production, and development
\nPremier Oil Exploration (Mauritania) Limited
Mauritania
Jersey
\n6
\nDecommissioning activities
\nPremier Oil Exploration and Production Mexico S.A.de C.V.
Mexico
Mexico
\n10
\nExploration, production, and development
\nPremier Oil Far East Limited
Singapore
UK
\n2
\nService company
\nPremier Oil Finance (Jersey) Limited
\n1
\nJersey
Jersey
\n6
\nInvestment management
\nPremier Oil Group Holdings Limited
\n1
\nUK
UK
\n2
\nIntermediate holding company
\nPremier Oil Group Limited
UK
UK
\n5
\nIntermediate holding company
\nPremier Oil Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil Mauritania B Limited
Mauritania
Jersey
\n6
\nDecommissioning activities
\nPremier Oil Mexico Holdings Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil Mexico Investments Limited
UK
UK
\n2
\nIntermediate holding company
\nPremier Oil Mexico Recursos S.A. de C.V.
Mexico
Mexico
\n10
\nExploration, production, and development
\nPremier Oil Natuna Sea BV
Indonesia
Netherlands
\n7
\nExploration, production, and development
\nPremier Oil Overseas BV
Netherlands
Netherlands
\n7
\nIntermediate holding company
\nPremier Oil South Andaman Limited
Indonesia
UK
\n2
\nExploration, production, and development
\nPremier Oil Tuna BV
Indonesia
Netherlands
\n7
\nExploration, production, and development
\nPremier Oil UK Limited
UK
UK
\n5
\nExploration, production, and development
\nPremier Oil Vietnam 121 Limited
Vietnam
UK
\n2
\nExploration, production, and development
\nPremier Oil Vietnam Offshore BV
Vietnam
Netherlands
\n7
\nExploration, production, and development
\nChrysaor (U.K.) Britannia Limited
\u2013
UK
\n2
\nDormant company
\n171
Notes to the consolidated \ufb01nancial statements
continued
\n31. Investments
continued
\nName of company
Area of operation
Country of incorporation
Main activity
\nChrysaor (U.K.) Eta Limited
\u2013
UK
\n2
\nNon-trading
\nChrysaor (U.K.) Lambda Limited
\u2013
ROI
\n4
\nDormant company
\nChrysaor Energy Limited
\u2013
UK
\n2
\nNon-trading
\nChrysaor Investments Limited
\u2013
UK
\n2
\nDormant company
\nChrysaor Supply & Trading Limited
\u2013
UK
\n2
\nDormant company
\nEnCore (VOG) Limited
\u2013
UK
\n2
\nDormant company
\nEnCore CCS Limited
\u2013
UK
\n2
\nDormant company
\nEnCore Natural Resources Limited
\u2013
UK
\n2
\nDormant company
\nEnCore Oil and Gas Limited
\u2013
UK
\n2
\nDormant company
\nHarbour Energy Developments Limited
\u2013
UK
\n2
\nDormant company
\nHarbour Energy Production Limited
\u2013
UK
\n2
\nDormant company
\nHarbour Energy Secretaries Limited
\n(formerly Premier Oil Ebury Limited)
\u2013
UK
\n2
\nNon-trading
\nChrysaor Petroleum Chemicals U.K. Limited
\n(formerly Harbour Energy Services Limited)
\u2013
UK
\n2
\nDormant company
\nPremier Oil B Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil Belgravia Holdings Limited
\u2013
UK
\n2
\nNon-trading Intermediate holding company
\nPremier Oil Belgravia Limited
\u2013
UK
\n2
\nNon-trading
\nPremier Oil Bukit Barat Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil Buton BV
\u2013
Netherlands
\n7
\nNon-trading
\nPremier Oil CCS Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil Congo (Marine IX) Limited
\u2013
Jersey
\n6
\nDormant company
\nPremier Oil Exploration and Production (Iraq) Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil Exploration Limited
\u2013
UK
\n5
\nNon-trading
\nPremier Oil Exploration ONS Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil International Holding BV
\u2013
Netherlands
\n7
\nNon-trading
\nPremier Oil Investments Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil ONS Limited
\u2013
UK
\n2
\nDormant company
\nPremier Oil Paci\ufb01c Limited
\u2013
Hong Kong
\n12
\nDormant company
\nPremier Oil Pakistan Offshore BV
\u2013
Netherlands
\n7
\nDormant company
\nPremier Oil Philippines BV
\u2013
Netherlands
\n7
\nDormant company
\nPremier Oil Vietnam North BV
\u2013
Netherlands
\n7
\nNon-trading
\nPremier Overseas Holdings Limited
\u2013
UK
\n2
\nDormant company
\nXEO Exploration plc
\u2013
UK
\n2
\nDormant company
\nNotes:
\n1
Held directly by the company. All other companies are held through a subsidiary undertaking.
\n2
Registered of\ufb01ce \u2013 23 Lower Belgrave Street, London SW1W ONR, United Kingdom.
\n3
Registered of\ufb01ce \u2013 Haakon VII\u2019s gate 1, 4
\nth
\nFloor, 0161 Oslo, Norway.
\n4
Registered of\ufb01ce \u2013 Riverside One, Sir John Rogerson\u2019s Quay, Dublin 2, Ireland.
\n5
Registered of\ufb01ce \u2013 4
\nth
\nFloor, Saltire Court, 20 Castle Terrace, Edinburgh EH1 2EN, United Kingdom.
\n6
Registered of\ufb01ce \u2013 46/50 Kensington Place, 1
\nst
\nFloor, Kensington Chambers, St. Helier JE4 0ZE, Jersey.
\n7
Registered of\ufb01ce \u2013 Herikerbergweg 88, 1101 CM, Amsterdam, Netherlands.
\n8
Registered of\ufb01ce \u2013 Commerce House, Wickhams Cay 1, Road Town, Tortola VG1110, British Virgin Islands.
\n9
Registered of\ufb01ce \u2013 Rua Lauro Muller, 116 \u2013 Sala 3201, Botafogo, Rio de Janeiro, CEP: 22.290-160, Brazil.
\n10 Registered of\ufb01ce \u2013 Presidente Masaryk 111, Piso 1, Polanco V Seccion, Mexico City CP 11560, Mexico.
\n11 Registered of\ufb01ce \u2013 Level 5, Mill Court, La Charroterie, St Peter Port GY1 1EJ, Guernsey.
\n12 Registered of\ufb01ce \u2013 31/F, Tower Two, Time Square, 1 Matheson Street, Causeway Bay, Hong Kong.
\n13 Cricket Square, Hutchins Drive, PO Box 2681, Grand Cayman KY1-1111, Cayman Islands. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"f21769": {
"value": "Company balance sheet As at 31 December
\nNote
\n2022
\n$ million
\n2021
\n$ million
\nAssets
\nNon-current assets
\nInvestments in subsidiaries
3
2,301.7
4,965.6
\nLong-term employee bene\ufb01t plan surplus
7
0.2
0.8
\nLong-term receivables
4
2,208.9
2,782.6
\nTotal non-current assets
4,510.8
7,749.0
\nCurrent assets
\nTrade and other receivables
4
4.5
4.8
\nTotal current assets
4.5
4.8
\nCurrent liabilities
\nTrade and other payables
5
(14.8)
(10.9)
\nNet current liabilities
(10.3)
(6.1)
\nNon-current liabilities
\nBorrowings
6
(491.3)
(489.5)
\nLong-term employee bene\ufb01t plan de\ufb01cit
7
(0.5)
(0.7)
\nNet assets
4,008.7
7,252.7
\nEquity and reserves
\nShare capital
9
171.1
171.1
\nShare premium account
\u2013
1,504.6
\nRetained earnings
3,829.5
762.6
\nOther reserves
8.1
4,814.4
\nTotal equity and reserves
4,008.7
7,252.7
\nLoss for the year ending 31 December 2022 was $2,703.9 million (2021: $104.3 million pro\ufb01t).
\nThe \ufb01nancial statements, including the notes, of Harbour Energy plc (registered number SC234781) on pages 173 to 176 were approved
\nand authorised for issue by the board of directors on 8 March 2023 and signed on its behalf by:
\nAlexander Krane
\nChief Financial Of\ufb01cer
\n173
Company statement of changes in equity
\nFor the year ended 31 December
\nShare capital
\n$ million
\nShare premium
\n$ million
\nMerger reserve
\n$ million
\nCapital
\nredemption
\nreserve
\n$ million
\nRetained
\nearnings
\n$ million
\nTotal equity
\n$ million
\nAt 1 January 2022
171.1
1,504.6
4,806.3
8.1
762.6
7,252.7
\nPurchase and cancellation of own shares
\n1
\n\u2013
\u2013
\u2013
\u2013
(360.6)
(360.6)
\nLoss for the \ufb01nancial year
\u2013
\u2013
\u2013
\u2013
(2,703.9)
(2,703.9)
\nCapital restructuring
\n2
\n\u2013
(1,504.6)
(4,806.3)
\u2013
6,310.9
\u2013
\nExpense for share-based payments
\u2013
\u2013
\u2013
\u2013
33.9
33.9
\nPurchase of ESOP Trust shares
\u2013
\u2013
\u2013
\u2013
(21.6)
(21.6)
\nPension \u2013 actuarial losses
\u2013
\u2013
\u2013
\u2013
(0.3)
(0.3)
\nDividend paid
\u2013
\u2013
\u2013
\u2013
(191.5)
(191.5)
\nAt 31 December 2022
171.1
0
0
8.1
3,829.5
4,008.7
\nAs at 1 January 2021
171.1
517.5
374.3
8.1
650.3
1,721.3
\nMerger shares issued
\u2013
\u2013
4,432.0
\u2013
\u2013
4,432.0
\nDebt settlement non top-up
\u2013
987.1
\u2013
\u2013
\u2013
987.1
\nPurchase of ESOP Trust shares
\u2013
\u2013
\u2013
\u2013
(4.9)
(4.9)
\nPro\ufb01t for the \ufb01nancial year
\u2013
\u2013
\u2013
\u2013
104.3
104.3
\nExpense for share-based payments
\u2013
\u2013
\u2013
\u2013
13.1
13.1
\nMovement in cash \ufb02ow hedges
\u2013
\u2013
\u2013
\u2013
(0.2)
(0.2)
\nAt 31 December 2021
171.1
1,504.6
4,806.3
8.1
762.6
7,252.7
\n1
Includes $2.1 million costs in relation to fees and stamp duty.
\n2
Share premium and merger reserve balances recategorised to retained earnings following the capital reduction effective 3 August 2022. Of the reserves capitalised $1.65 billion is
\nnon-distributable until 31 March 2028. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfConsolidatedAndSeparateFinancialStatementsExplanatory",
"language": "en",
"entity": "scheme:213800YPC42DYBKVPF97",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
}
}
}